WELL CONTROLDevelopment Drilling STANDARD OPERATIONS MANUAL for JACK-UP / PLATFORM / BARGE DRILLING First Edition May 2003 FOR COMPANY USE ONLY Houston, Texas U.S.A. ExxonMobil Development Company P.O. Box 4876 Houston, TX 77210-4876 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 32 Developm ent May 2003 Manual Drilling EMDC Drilling Standard Operations for Jack-Up/Platform/Barge To: ExxonMobil Drilling Employees The enclosed manual is the First Edition of our EMDC Drilling Standard Operations Manual for Jack-Up/Platform/Barge Drilling. This manual replaces the Transition Version 1 manual dated October 1999. Many changes and upgrades have been made to this manual based on comments from the Drill Teams and Drilling Support Groups. The preface of the manual describes how the manual will be used in our operations. In short, the manual: 1) provides guidelines for conducting drilling operations using jack-up, platform and barge rigs, 2) is used in conjunction with specific well programs and other procedural manuals, including OIMS and SMP, to provide the basic framework and principles required for planning and conducting drilling operations, and 3) shall be reviewed and understood by all drilling personnel. Important to note is that significant changes (any change that increases health, safety, public, environmental or financial risk) from the manual need the consent of the Operations Superintendent and/or Field Drilling Manager. Also, the guidelines in the manual must be appropriately interfaced with those established by the Drilling Contractor and conflicts addressed by the Operations Superintendent. Special appendices are included in each section of the manual for drill teams to customize the manual for their operating area. The tabs for these appendices are labeled “G” for general information and forms/documents that are used company wide and “S” for specific information and forms/documents that are unique to individual drill teams. We appreciate the time and effort by the Drill Teams and Drilling Support Groups in reviewing and commenting on the draft manual. Over 150 comments were received with about 90% adopted in the new manual. The remaining comments referred to requests to include local practices, sections in the draft manual that were removed, general comments with no suggested changes, items not applicable to this manual, and a very few number of items not agreed to. In order to close the loop, Drill Teams that suggested changes not agreed to will receive feedback. This manual will be revised and upgraded in accordance with the revision process in the OIMS manual. In general, this process will involve review of comments received from the Drill Teams, annual review of MOCs, and reviews at periodic intervals. Please take the time to review this manual and understand the guidelines contained within. Signature on file D. R. Anglin Signature on file J. W. Kiker Signature on file____ C. W. Sandlin WELL CONTROL Operations Manager Manager Operations Manager Operations An ExxonMobil Subsidiary PREFACE The ExxonMobil Development Company, Standard Operations Manual for Jack-Up/Platform/Barge Drilling has been prepared to provide guidelines for conducting drilling operations using jack-up, platform and barge rigs in ExxonMobil Drilling's realm of activities. This manual, used in conjunction with well-specific Drilling and Completion Programs and other procedural manuals, including the Drilling OIMS Manual and the Safety Management Program Manual, will provide the basic framework and principles required for the Operations Supervisors and Drilling Engineers for planning and conducting drilling operations. Because of the numerous possible variables and conditions which can occur, this manual cannot replace the knowledge and good judgment of key drilling personnel on the drilling rig or in the office. The guidelines contained within this manual are the logical sequence of steps necessary to efficiently conduct drilling operations in a safe and environmentally sound manner on a global scale while complying with applicable regulatory requirements. Although many of the references to U.S. laws and regulations were removed from the previous version due to the global intent of this manual, some remain as examples and may be valuable for international operations. The guidelines contained herein shall be reviewed and understood by all involved drilling personnel. In accordance with the OIMS "Management of Change" element, significant changes (any change that increases health, safety, public, environmental or financial risk) from these guidelines are not to be undertaken without the express consent of the Operations Superintendent and/or Field Drilling Manager. The guidelines contained in this manual shall also be appropriately interfaced with those established by the Drilling Contractor and contained in the Drilling Contractor's operations manuals. Identified procedural conflicts shall be addressed by the Operations Superintendent and any resulting resolutions shall be provided to the Operations Supervisors. Special appendices are included in each section of the manual for drill teams to customize the manual for their operating area. The tabs for these appendices are labeled “G” for general information and forms/documents that are used company wide and “S” for specific information and forms/documents that are unique to individual drill teams. The manual shall be kept current by including recommended improvements/changes in accordance with the change process described in the EMDC Drilling OIMS Manual. In general, this process will involve review of comments received from the Drill Teams, annual review of MOCs, and reviews at periodic intervals. This process is critical in keeping Drilling abreast of new ideas, advancing technology and regulatory changes. This manual was prepared in an attempt to combine the best practices of our drill teams into one manual. Although it does contain a good bit of information from multiple sources, it does not contain all the information needed to drill and complete drill wells in all situations. Good sound DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 32 judgement should always be exercised in any task and should never be discarded just to follow an outlined step in any process or procedure DRILLING OPERATIONS MANUAL – JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 1 SAFETY CREDO We, the Management and Employees of ExxonMobil Development Company: • Will relentlessly pursue our ultimate objective of an injury and illness free work place • Will not compromise our focus on safety in order to achieve any other business objective And We Believe: • Our safety actions are most effective when we genuinely care about each other • Each of us has a personal responsibility for our own safety and the safety of others -- both on and off the job • All injuries and illnesses can be avoided when we practice safe behaviors STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 1.1 GENERAL INFORMATION 1.2 Drilling Operations Manual1 1.3 Organization 2 1.4 EMDC Reports 3 1.5 Drilling Contractor Reports6 1.6 Third Party Service Contractor Reports 9 2.1 GENERAL OPERATIONS 2.2 Contracts Administration 1 2.3 Prespud Meeting 2 2.4 Security 3 2.5 EMDC Drilling Operations Personnel Responsibilities 2.6 Drilling Contractor Personnel Responsibilities 8 2.7 Third Party Service Contractor Personnel Responsibilities 2.8 Special Operations Precautions 3 9 14 2.7.1 Helicopter Operations 14 2.7.2 Mooring Vessel Operations 14 2.7.3 Casing pressure Monitoring 14 2.7.4 Back Pressure Valves 2.7.5 Rotary Table Insert Bushing Locks 2.7.6 Christmas Tree Equipment 2.7.7 Mud Logging Units 14 14 14 15 Appendix G-I EMDC-DO Risk Assessment Form Appendix G-II Risk Assessment Package (example) Appendix G-III EMDC-DO BOPE Exception Form Appendix G-IV Drilling Environmental Performance Indicators Report Form 3.1 MARINE OPERATIONS 3.2 Site Survey / Bottom Sweep / SIMOPs review 3.3 Moving 1 2 3.2.1 Moving Jack-up Rigs 2 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 3.2.2 Moving Platform Rigs 4 3.2.3 Moving Barge Rigs 5 3.3 Moving And Positioning 6 3.4 Pre-Loading (Jack-up Only) 3.5 Cargo Transfers 3.6 7 8 3.5.1 Precautions 9 3.5.2 Weather Limits 9 3.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 3.5.4 Lifting Operations 10 3.5.5 Rigging Guidelines 11 3.5.6 Equipment Maintenance 15 9 Transportation & Personnel Transfers 3.7 Marine Training 3.7.1 3.7.2 3.7.3 3.7.4 3.7.5 3.7.6 3.7.7 3.7.8 3.7.9 3.7.10 20 3.6.1 Cargo Transport 20 3.6.2 Helicopter Operations 21 3.6.3 Personnel Transport-Helicopter 22 3.6.4 Personnel Transport-Supply or Stand-By Boat 24 General Reporting & Drill Frequency Marine Drill Process Fire Drills Fire Drill-Example Abandon Rig Drills Abandon Rig Drill-Example Man Overboard Drill Specialized Drills Principal Aspects of Drills 3.8 Ship Collision Avoidance 3.8.1 Detection 3.8.2 Radar Watch Procedures 24 24 25 26 27 29 30 33 34 35 37 38 38 Appendix G-I SIMOPs Checklist Memo Appendix G-II SIMOPs Deviation Form Appendix G-III Study of Pile Interaction with Jack-Up Rig Operations Appendix G-IV Pre-Startup Inspections for New to Fleet Jackup Drilling Rigs DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 4.0 DRILLING OPERATION 4.1 Introduction 1 4.2 General Operations Guidelines 1 4.3 Pre-Spud Operations 3 4.4 Structural Drive Pipe 4 4.5 Conductor and Surface Casing Interval 5 4.6 Diverter Operations 6 4.7 Intermediate / Protective Casing Interval 6 4.8 Production Casing / Liner Interval 7 4.9 Slot Recovery / Whipstock / Section Mill / Cutt & Pull 7 4.10 Wellbore Anti-Collision Guidelines 9 4.10.1 Requirements for "Collision Risk" Wells 9 4.10.2 Requirements for All Directional Wells 10 4.11 Directional Surveying and Deviation Control 11 4.12 Drill String Design 12 4.13 Bottom Hole Assemblies 14 4.14 Hydrogen Sulfide Considerations 17 4.15 Hydrogen Sulfide Contingency Plan 19 5.0 BIT CLASSIFICATION AND HYDRAULICS 5.1 General 5.2 Drill Bits 5.3 IADC Bit Classification System 5.4 IADC Bit Grading System 5.5 Running Procedures for Fixed Cutters 5.6 Hydraulics Program 5.7 Guidelines for Hydraulics Optimization 5.8 Hydraulics Optimization 5.9 Reference Material 6.0 DRILLING FLUID SYSTEM 1 1 3 6 8 10 12 17 18 6.1 General 1 6.2 Solids Control 1 6.3 Drilling Fluid Treatments 3 6.4 Drilling Fluid Checks 5 6.5 High Temperature Drilling 6 6.6 Stuck Pipe Pills 6 6.7 Lost Circulation 7 6.8 Non-Aqueous Fluid Operations 15 6.9 Rig-Site Dielectric Constant Measurement 33 6.10 Drilling Fluid System Guidelines 34 Appendix G-I Fluid Transfer Checklists Appendix G-II NAF/Oil Base Mud Readiness Checklist DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 7.0 ABNORMAL PRESSURE DETECTION IN CLASTICS 7.1 Background 1 7.2 Pressure Indicators While Drilling 2 7.3 Abnormal Pressure Detection Team Responsibilities 10 7.4 Mud Logging 11 7.5 Operational Guidelines 15 8.0 FORMATION EVALUATION 8.1 General 1 8.2 Conventional Coring 1 8.3 Wireline Logging Program 8 8.4 Sidewall Coring Operations 11 8.5 Wireline Radioactive Sources 12 8.6 MWD/LWD Logging 12 8.7 Mud Logging and Cuttings Samples 14 9.0 CASING OPERATIONS 9.1 Casing Running 1 9.2 Casing Connection Make-Up 5 9.3 Casing Checklist 5 10.1 General 1 10.2 Cementing Guidelines 1 10.3 Primary Cementing 3 10.4 Remedial Cementing 5 10.5 Cementing Checklist 6 10.6 Reference 7 10.0 CEMENTING Appendix G-I Exxonmobil Cement Testing Guidelines 11.0 PRESSURE INTEGRITY TESTS 11.1 3 General 1 11.2 Casing Test 2 11.3 Leak-Off Test 11.4 Jug Test (Limited PIT) 12.0 PRODUCTION TESTING DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 12.1 Production Testing Objectives 1 12.2 Well Test Design 1 12.3 Test String 3 12.4 Surface Equipment 4 12.5 Measurement Equipment 4 12.6 Safety 5 12.7 Personnel Responsibilities 6 12.8 Pre-test Planning and Preparation 9 12.9 Information Retrieval 10 12.10 Well Killing and Zone Abandonment 11 12.11 Emergency Procedures 11 12.12 Hydrogen Sulfide 11 12.13 Hydrates 12 13.0 PLUG AND ABANDONMENT 13.1 General 1 13.2 Permanent Plug and Abandonment 1 13.3 Temporary Plug and Abandonment 4 13.4 Site Clearance Verificationa 4 14.0 WELL CONTROL 14.1 Well Control – General 1 14.2 Hole Monitoring 5 14.3 Equipment Testing 8 14.4 Equipment Specifications 10 14.5 Well Control Drills 16 14.6 Well Control Procedures 19 5 of 5 1.0 GENERAL INFORMATION 1.1 Drilling Operations Manual 1 1.2 Organization 2 1.3 EMDC Reports 3 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 1.4 Drilling Contractor Reports 6 1.5 Third Party Service Contractor Reports 9 2.0 GENERAL OPERATIONS 2.1 Contracts Administration 1 2.2 Prespud Meeting 2 2.3 Security 3 2.4 EMDC Drilling Operations Personnel Responsibilities 3 2.5 Drilling Contractor Personnel Responsibilities 8 2.6 Third Party Service Contractor Personnel Responsibilities 9 2.7 Special Operations Precautions 14 2.7.1 Helicopter Operations 14 2.7.2 Mooring Vessel Operations 14 2.7.3 Casing pressure Monitoring 14 2.7.4 Back Pressure Valves 14 2.7.5 Rotary Table Insert Bushing Locks 14 2.7.6 Christmas Tree Equipment 14 2.7.7 Mud Logging Units 15 Appendix G-I EMDC-DO Risk Assessment Form Appendix G-II Risk Assessment Package (example) Appendix G-III EMDC-DO BOPE Exception Form Appendix G-IV Drilling Environmental Performance Indicators Report Form 3.0 MARINE OPERATIONS 3.1 Site Survey / Bottom Sweep / SIMOPs review 1 3.2 Moving 2 3.2.1 Moving Jack-up Rigs 2 3.2.2 Moving Platform Rigs 4 3.2.3 Moving Barge Rigs 5 3.3 Moving And Positioning 6 3.4 Pre-Loading (Jack-up Only) 7 3.5 Cargo Transfers 8 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 3.5.1 Precautions 9 3.5.2 Weather Limits 9 3.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 9 3.5.4 Lifting Operations 10 3.5.5 Rigging Guidelines 11 3.5.6 Equipment Maintenance 15 3.6 Transportation & Personnel Transfers 20 3.6.1 Cargo Transport 20 3.6.2 Helicopter Operations 21 3.6.3 Personnel Transport-Helicopter 22 3.6.4 3.7 Marine Training 3.7.1 3.7.2 3.7.3 3.7.4 3.7.5 3.7.6 3.7.7 3.7.8 3.7.9 3.7.10 Personnel Transport-Supply or Stand-By Boat 24 General Reporting & Drill Frequency Marine Drill Process Fire Drills Fire Drill-Example Abandon Rig Drills Abandon Rig Drill-Example Man Overboard Drill Specialized Drills Principal Aspects of Drills 24 24 25 26 27 29 30 33 34 35 37 3.8 Ship Collision Avoidance 3.8.1 Detection 3.8.2 Radar Watch Procedures 38 38 Appendix G-I SIMOPs Checklist Memo Appendix G-II SIMOPs Deviation Form Appendix G-III Study of Pile Interaction with Jack-Up Rig Operations Appendix G-IV Pre-Startup Inspections for New to Fleet Jackup Drilling Rigs 4.0 DRILLING OPERATION 4.1 Introduction 1 4.2 General Operations Guidelines 1 4.3 Pre-Spud Operations 3 4.4 Structural Drive Pipe 4 4.5 Conductor and Surface Casing Interval 5 4.6 Diverter Operations 6 4.7 Intermediate / Protective Casing Interval 6 4.8 Production Casing / Liner Interval 7 4.9 Slot Recovery / Whipstock / Section Mill / Cutt & Pull 7 4.10 Wellbore Anti-Collision Guidelines 9 4.10.1 Requirements for "Collision Risk" Wells 9 4.10.2 Requirements for All Directional Wells 10 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 4.11 Directional Surveying and Deviation Control 11 4.12 Drill String Design 12 4.13 Bottom Hole Assemblies 14 4.14 Hydrogen Sulfide Considerations 17 4.15 Hydrogen Sulfide Contingency Plan 19 5.0 BIT CLASSIFICATION AND HYDRAULICS 5.1 General 5.2 Drill Bits 5.3 IADC Bit Classification System 5.4 IADC Bit Grading System 5.5 Running Procedures for Fixed Cutters 5.6 Hydraulics Program 5.7 Guidelines for Hydraulics Optimization 5.8 Hydraulics Optimization 5.9 Reference Material 6.0 DRILLING FLUID SYSTEM 1 1 3 6 8 10 12 17 18 6.1 General 1 6.2 Solids Control 1 6.3 Drilling Fluid Treatments 3 6.4 Drilling Fluid Checks 5 6.5 High Temperature Drilling 6 6.6 Stuck Pipe Pills 6 6.7 Lost Circulation 7 6.8 Non-Aqueous Fluid Operations 15 6.9 Rig-Site Dielectric Constant Measurement 33 6.10 Drilling Fluid System Guidelines 34 Appendix G-I Fluid Transfer Checklists Appendix G-II NAF/Oil Base Mud Readiness Checklist 7.0 ABNORMAL PRESSURE DETECTION IN CLASTICS 7.1 Background 1 7.2 Pressure Indicators While Drilling 2 7.3 Abnormal Pressure Detection Team Responsibilities 10 7.4 Mud Logging 11 7.5 Operational Guidelines 15 8.0 FORMATION EVALUATION 8.1 General 1 8.2 Conventional Coring 1 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 8.3 Wireline Logging Program 8 8.4 Sidewall Coring Operations 11 8.5 Wireline Radioactive Sources 12 8.6 MWD/LWD Logging 12 8.7 Mud Logging and Cuttings Samples 14 9.0 CASING OPERATIONS 9.1 Casing Running 1 9.2 Casing Connection Make-Up 5 9.3 Casing Checklist 5 10.1 General 1 10.2 Cementing Guidelines 1 10.3 Primary Cementing 3 10.4 Remedial Cementing 5 10.5 Cementing Checklist 6 10.6 Reference 7 10.0 CEMENTING Appendix G-I Exxonmobil Cement Testing Guidelines 11.0 PRESSURE INTEGRITY TESTS 11.1 11.3 Leak-Off Test 11.4 Jug Test (Limited PIT) General 1 11.2 Casing Test DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 5 of 5 STANDARD OPERATIONS MANUAL JACK-UP/PLATFORM/BARGE RIG DRILLING TABLE OF CONTENTS 12.0 PRODUCTION TESTING 12.1 Production Testing Objectives 1 12.2 Well Test Design 1 12.3 Test String 3 12.4 Surface Equipment 4 12.5 Measurement Equipment 4 12.6 Safety 5 12.7 Personnel Responsibilities 6 12.8 Pre-test Planning and Preparation 9 12.9 Information Retrieval 10 12.10 Well Killing and Zone Abandonment 11 12.11 Emergency Procedures 11 12.12 Hydrogen Sulfide 11 12.13 Hydrates 12 13.0 PLUG AND ABANDONMENT 13.1 General 1 13.2 Permanent Plug and Abandonment 1 13.3 Temporary Plug and Abandonment 4 13.4 Site Clearance Verificationa 4 14.0 WELL CONTROL 14.1 Well Control – General 1 14.2 Hole Monitoring 5 14.3 Equipment Testing 8 14.4 Equipment Specifications 10 14.5 Well Control Drills 16 14.6 Well Control Procedures 19 5 of 5 GENERAL INFORMATION 1.0 GENERAL INFORMATION DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1.1 1.2 1.3 1.4 1.5 Drilling Operations Manual Organization EMDC Reports Drilling Contractor Reports Third Party Service Contractor Reports ______________________________________________________________________________ DRILLING OPERATIONS MANUAL-JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION-MAY 2003 1 2 3 6 9 GENERAL INFORMATION 1.1 DRILLING OPERATIONS MANUAL The EMDC Jack-Up/Platform/Barge Rig Drilling Standard Operations Manual is applicable to production and exploration wells. The drilling guidelines, principles, and procedures contained in this manual represent drilling practices that ensure the Company's highest commitment to safety, health, and the environment. Manual Organization This manual is organized into sections covering critical aspects of Jack-Up/Platform/Barge Rig drilling. Each section is divided into subsections, which address the relevant aspects of each section topic. In each section, one subsection is devoted to operations specific Drill Team operations. Appendices that apply to general drilling operations regardless of area of operation are denoted by a "G" before the appendix number. Appendices relating to a specific drill team are denoted by an "S" prefix before the appendix number. Where applicable, this manual will reference other company and industry documents that contain additional information to supplement the guidelines contained here-in. This manual will present drilling practices common to numerous drilling operations, irrespective of rig type. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 10 GENERAL INFORMATION 1.2 ORGANIZATION EMDC - Drilling Organization EMDC Drilling is responsible for ExxonMobil's world-wide production and exploration drilling activities. The Drilling Organization is responsible for the contracting of services and materials suppliers, the planning and preparation of drilling engineering work, and the direct supervision of drilling operations. The Drilling Organization shall prepare guidelines and procedures, as necessary, so that operations are conducted in a safe and environmentally sound manner. These responsibilities will be met by the following personnel: • • • • • • • • • • • • • • Manager, Drilling Drilling Operations Manager Procurement Manager Drilling Technology Manager Field Drilling Manager Operations Superintendent Engineering Manager Operations Supervisor Supervising Engineer Drilling Engineer Drilling Materials & Services Supervisor Procurement Services Advisor SHE Manager, Drilling Environmental Coordinator, Drilling Drilling Contractor and Other Critical Third Party Service Contractors The Drilling Contractor is an independent contractor who will execute the drilling program to the satisfaction of the Operations Supervisor on location. The drilling contractor is also responsible for operating and maintaining the drilling rig in safe working condition and in full compliance with EMDC technical specifications and local regulatory requirements, including those requirements as specified in the drilling contract. Other critical third party service contractors are independent contractors that will assist in executing the drilling program. These contractors are responsible for operating and maintaining their equipment in full compliance with EMDC technical specifications and/or contract requirements, and local regulatory requirements. The drilling contractor and other critical third party service contractors provide services where inadequate performance could result in a Level 1, 2, or 3 incident (OIMS Element 9). These contractors must meet or exceed EMDC requirements in the area for which the contract is issued. This includes the following: • Safety, Health, and Environmental Policy Statement DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 10 GENERAL INFORMATION Drug and Alcohol Policy Contractor Safety Program Technical Equipment Documentation Work Permit System Hazardous Material Handling/Storage Procedures Procedure to Control Equipment/Safety Policy Changes • • • • • • Service Companies/Third Party Services Service companies/third party service contractors are independent contractors who will assist in executing the drilling program to the satisfaction of the Operations Supervisor on the drilling rig. These contractors are also responsible for operating and maintaining their equipment in full compliance with EMDC technical specifications and local regulatory requirements, including those as specified in the various contracts. 1.3 EMDC- DRILLING REPORTS Critical drilling operations information and relevant aspects of the daily drilling activities will be documented in the standard reports developed by EMDC and its contractors. This manual describes the preparation and distribution of these reports. Daily Drilling Report The Operations Supervisor will record drilling activities on the DRS and transmit it, usually via the LAN or telephone line (modem), to the Drilling Information Management Center (DIMC) each morning. The Daily Drilling Report will cover a 24 hour period with the current day's drilling activities. Minimizing drilling cost per foot and achieving an overall increase in the efficiency of a drilling operation requires that Management, the Operations Superintendent, and Engineering receive accurate, factual, complete reports from the rig Operations Supervisor on a daily basis. Effective management control of the drilling operation cannot be effected without input from the entire drilling organization, and the daily drilling report is the base document from which most information is drawn. The following are guidelines on some aspects of the Daily Drilling Report: • • • • • • • Drilling operation events should be time separated to correspond with EMDC rig-time distribution codes (not IADC). The DRS manual contains a guide on the coding of operations. Depth of the well is determined by steel line measurement of the drill string. There should be reasonable agreement between the DDR and the IADC report. A better report will result if each Operations Supervisor writes the operations summary for his/her tour. Do not report opinions or guesses unless they are so identified. If an opinion is reported as fact, the rig supervisor will know this, but the office staff may not. Use only standard abbreviations. Do not make up abbreviations. Electric logging: specify logs run, depth interval logged, bottom hole temperature, and tight hole depth. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 10 GENERAL INFORMATION Circulation: specify why the mud is being circulated, and circulation rate/ pipe rotation if any . Daily Cost Report • The Operations Supervisor should complete the DRS Daily Cost Report and transmit it to the DIMC each morning. The Daily Cost Report should capture all substantial drilling costs including services utilized, rental equipment, and consumed materials. Where exact costs are not known, reasonable estimates should be made and included in the Daily Cost Report. Some contractor costs will not be known exactly until the end of a month. The rig should not attempt to estimate what the discounted charge will be; the rig is to enter the ticket charge on the cost screen. The Drilling Engineer is responsible for monitoring discounted materials and services costs and communicating any adjustments to the Operations Supervisor for modification of cost sheets. It is the Drilling Engineer's responsibility to include the cost of all materials and services in appropriate procedures for Operations Supervisor use in completing the Daily Cost Report. The Drilling Engineer is also to provide initial fixed costs to Operations Supervisor and to check the entries for errors or omissions. ATF Bomb Threat Checklist Operations Supervisors need to be prepared to respond effectively should they receive a bomb threat over the telephone. It is very important to take the caller seriously. Ask the person to repeat the message. Record every word spoken by the person. Complete the bomb threat checklist and transmit to the Operations Superintendent. Reference OIMS manual (10-5) for further information. Casing Tally Report The Casing Tally Report should be prepared for every casing string run. A copy of the report will be kept on the drilling vessel for reference during logging, production testing, completion, plug and abandonment operations, etc. The Operations Supervisor is responsible for completing the casing run tally report and forwarding it to the Drilling Engineer after each casing string is run. While it is not necessary to transmit the off-load tally from the rig, it is necessary to create a DRS off-load tally to be able to complete the casing description part of the DRS "as run" tally. OIMS requires a DRS casing tally report where possible. Environmental Performance Indicators (EPI) Report At the end of every well, the Drilling Engineer and EMDC Domestic Regulatory Technician will complete the Environmental Performance Indicators (EPI) Report for inclusion in the Final Well Report. This form contains four sections; Well Information, Emissions Data, Environmental Regulatory Compliance Data, and Waste Data. Drilling Reporting System (DRS) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 10 GENERAL INFORMATION When the DRS system is in place, the following DRS reports will be maintained and transmitted from the rig daily or when pertinent, 1) Daily Drilling Report, 2) Casing Report, 3) Cementing Report, 4) Lithology, 5) Logging Run, 6) Milestones, 7) Mud, 8) Mud Product Usage, 9) Perfs, 10) RFT, 11) Drillstring, 12) Weather, 13) Well Test, 14) Stratigrophy. Equipment Failure Report An equipment failure report will be prepared to document equipment failures which result in significant economic impact or failures which could have safety implications. The equipment failure report should adequately describe the nature of the failure, identify the cause of the failure, document the associated downtime due to the failure, and recommend ways to prevent the failure from occurring in the future. The Operations Supervisor is responsible for preparing the report and forwarding it to the Operations Superintendent. Engineering will review the report to determine if further analysis or action is required. Hand-Over Notes Hand-over notes will be prepared by the Operations Superintendents (when working on a rotational schedule) and Operations Supervisors prior to their respective crew changes. The purpose of these notes is to document all situations and/or activities that will require follow-up by the relieving personnel, as well as to address significant operational events that took place during the hitch. Material Transfer/Cargo Manifest A material transfer/cargo manifest should be prepared for all material shipments to and from the drilling rig. Manifests should be prepared by the Base Manager/Materials Coordinator for all to-rig shipments and by the drilling rig's storekeeper (if on contract) for all from-rig shipments. The cargo manifest should list all materials transferred, giving quantity, description, weight, and the container number in which it is stored. Material transfers are prepared for EMDC material and will usually list the commodity number. Hazardous material should be identified on the manifest. Under no circumstances should used casing thread protectors be sent to the United States in a container unless all thread compound is removed. There will be venture specific materials procedures. Once completed, the manifest should be signed by the originator and forwarded to the receiver of the goods by the most expedient means (usually via fax). A copy of the manifest should be given to the captain of the transferring vessel. The Operations Supervisor should sign the manifest for the goods received at the rig. Rental tools should be tracked, preferably in a rental tool log book or in a clipboard maintained on the rig. Pressure Integrity Test Record DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 10 GENERAL INFORMATION Pressure Integrity Tests are covered in Section 11 of this manual. The pressure integrity test (PIT) form will be prepared for all tests conducted. Additional information regarding PIT procedures and analysis is contained in the EPRCo publication "Pressure Integrity Test - Field Guide". The Operations Supervisor is responsible for completing the PIT form and forwarding it to the Operations Superintendent and Drilling Engineer as soon as practical after completing the test. Safety Incident and Spill Reports Refer to the Drilling Safety Management Program (SMP) and OIMS Manual for guidelines on incident reporting. A Reportable Safety Incident is defined by OIMS as being a Lost Time Incident, Restricted Work Incident, or a Medical Treatment Incident. An oil spill is any liquid hydrocarbon release greater than 1 barrel (or affiliate/regulatory required minimum) which falls onto water or onto the ground that could enter the ground water. A copy of the report will be provided to the Operations Supervisor for forwarding to the Operations Superintendent. Safety Meeting Record The Operations Supervisor should record the issues addressed/discussed at the general safety meeting, as well as the topics of the drill crew pre-tour safety meeting and any critical operations safety meeting in DIMS and the IADC report. The minutes of the general safety meeting can be hand written and do not have to be duplicated on the DIMS report. Forward copies of the contractor's safety meeting minutes to the Operation Superintendent. Well Killing Worksheet After the BOP stack is installed, the Well Killing Worksheet will be prepared in accordance with the guidelines specified in Section 14 of this manual. The worksheet will be maintained for the current wellbore configuration and updated at least daily (or as well conditions change) while drilling is in progress or maintain the KIK PC program data up to date. The Operations Supervisor is responsible for completing the worksheet. There are multiple acceptable formats including the traditional EPRCo form, Randy Smith form, EUSA form, and KIK PC program. Other Reports Additional reporting requirements should be followed/completed as detailed in the Drilling OIMS Manual and the Safety Management Program. 1.4 DRILLING CONTRACTOR REPORTS BOP Test Record DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 10 GENERAL INFORMATION The results of all BOP tests and any deficiencies should be recorded on the Daily Drilling Report and IADC Report. Detailed test data will also be recorded by the Drilling Contractor on a BOP test form designed specifically for the drilling rig. This report should include the information specified in Section 14 of this manual. The completed BOP test form, signed by the test pump operator, tool pusher/OIM, and Operation Supervisor, will be provided to the Operation Supervisor. All pressure test charts will be dated, and properly labeled as to each component tested in accordance with applicable EMDC and regulatory requirements. All records pertaining to the BOP tests should be retained on the drilling rig until completion of the well. The records should then be forwarded to the nearest production facility or host platform for retention in accordance with applicable regulatory requirements or forwarded to Operations Superintendent for inclusion in the well file (international exploration drilling operations). Current Status Board A current status board should be maintained at the driller's station. It should include the BOP ram elevation and other helpful information and regulatory mandated postings or documentation. Daily Personnel Record A listing of all personnel on the rig (POB list) and their positions will be scrupulously maintained by a designated representative of the Drilling Contractor. The POB list will be updated and distributed daily. A copy of the POB list will be provided to the Operations Supervisor at midnight. This list will be available to be faxed to the Operations Superintendent when needed. A copy of the current POB list will be maintained on the drilling rig. Drilling Recorder Chart The Drilling Contractor should annotate all major drilling activities (drilling, tripping, circulating, running casing, cementing, etc.) on the continuous recording strip chart which records depth, time, hookload, pump pressure, rotary torque, and weight-on-bit, as a minimum. The strip chart should also be annotated by the Drilling Contractor to note significant activities such as filling hole, flow check, connection, tight hole, mechanical problems, stuck pipe, etc. A copy of the chart will be provided to the Operations Supervisor for forwarding to the Operations Superintendent when requested. IADC Reports The IADC Report will be prepared daily by the Drilling Contractor and signed by both the drilling contractor's senior drilling representative and the Operations Supervisor. The IADC Report will detail the events of each day's drilling activities, giving a time breakdown for each major event. Events which are subject to different rig cost rates, as specified in the drilling contract, should be clearly separated. Significant events such as safety incidents, safety meetings, BOP tests, major DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 10 GENERAL INFORMATION equipment failures, etc. will be documented on the IADC Report. Drilling Contractor personnel should be identified by name, position and hours worked (including any overtime). The Operations Supervisor will send the original (white) and pink copies to the Operations Superintendent weekly. The blue copy should be kept in the Operations Supervisors office onboard the drilling vessel. The green and white (last) copy will be left for the Drilling Contractor. The Operation Superintendent will forward the original to the accounting department and retain the pink copy in the drilling office files. Safety Incident Reports Refer to the Drilling Safety Management Program for a description of reports required from the contractors. The Drilling Contractor will prepare an incident report for all lost time incidents, fatalities, restricted work incidents, medical treatment incidents, first aid treatments, regional illness events, near misses, and significant near misses onboard the drilling rig. The incident report will, as a minimum, describe the nature of the incident, list the names of all persons involved (both witnesses and victims), describe the contributing circumstances, and identify remedial steps and recommendations to prevent further occurrences. Safety Meeting Reports The Drilling Contractor will prepare a report summarizing discussions held in the general safety meeting. The safety meeting report should, as a minimum, describe safety topics discussed, identify the status of any outstanding safety items and provide a list of all meeting attendees. A handwritten report is acceptable. A copy of the report will be provided to the Operations Supervisor for forwarding to the Operations Superintendent. Trip Book The primary monitoring of the volume of mud added to the hole to replace the drill string displacement on trips is the responsibility of the drilling crew. When full service mud logging is available, the mud loggers shall provide a backup trip book log. The trip tank will be used for all trips unless otherwise addressed by the field drilling manager. The trip book must compare measured volume with theoretical volume as well as previous trip volume. Refer to Section 14. Well Control Readiness Checklist At the Operations Supervisor's option, this checklist can be used as an aid in establishing rig floor crew well control competency. This checklist is in Section 6 of the OIMS Manual and guidelines are in Section 14 of this manual. 1.5 THIRD PARTY SERVICE CONTRACTOR REPORTS Cementing Chart DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 10 GENERAL INFORMATION A cementing recorder chart (pressure vs. time) will be prepared for all operations, such as casing cementing, equipment pressure testing, PITs, etc. The chart will be annotated with all significant events such as pumping spacers, pumping lead and tail cements, bumping the plug, etc. (as required by local affiliate and regulatory agencies). The chart will be provided to the Operations Supervisor for forwarding to the Operations Superintendent and Drilling Engineer when requested or retained as required by local regulations. Daily Drilling Fluids Report The Drilling Fluids Engineer will prepare a Daily Drilling Fluids Report in accordance with the guidelines specified in Section 6 of this manual. Unless otherwise specified by the Operations Supervisor, a minimum of two complete "In" and "Out" checks of the drilling fluid should be made daily during drilling operations. The report will be provided to the Operations Supervisor for forwarding to the Drilling Engineer each morning. Directional Data For directional wells, the Directional Drillers will prepare a bottom hole assembly sheet and BHA checklist for all BHAs run in the well in accordance with the guidelines specified in Section 4 of this manual. The directional driller will also maintain a wellbore trajectory record and current wellbore plot in the Operations Supervisor's office. The Directional Driller and Operations Supervisor should collaborate to complete and sign the directional drilling pre-job survey data sheet (PJSDS) and forward to the directional drillers coordinator as well as to the Drilling Engineer. A pre-job checklist for directional wells should be used to verify that all operational concerns have been addressed. Both the above items are OIMS required documents. Anticollision/well interference calculation should be updated at each survey point and a minimum of two directional contractor representatives should be onboard when wellbore interference issues exist. The minimum curvature calculation technique should be used. A copy of the wellbore trajectory record will be provided to the Operations Supervisor for forwarding to the Drilling Engineer each morning. Mud Logger's Reports The Mud Loggers will prepare a Mud Log and Daily Mud Logging Report in accordance with the abnormal pressure detection guidelines specified in Section 7 of this manual. A copy of the log/report will be provided to the Operations Supervisor and wellsite geologist for forwarding to the Operations Superintendent and operations geologist each morning. Pit Volume Totalizer Chart DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 10 GENERAL INFORMATION A properly labeled and dated Pit Volume Totalizer (PVT) chart should be maintained by the company contracted to provide same. Radiation Safety Checklist, Well Site Periodic assessment will be made of the adequacy of the safety programs of rig site contractors who use radioactive sources. Refer to the Drilling Safety Management Program and the OIMS checklists. Vessel Daily Log A Daily Log will be completed by all supply/standby vessels on contract and forwarded to the Base Manager/Materials Coordinator on a weekly (or other timely) basis. GENERAL OPERATIONS 2.0 GENERAL OPERATIONS 2.1 Contracts Administration 1 2.2 Prespud Meeting 2 2.3 Security 3 2.4 EMDC Drilling Operations Personnel Responsibilities 3 2.5 Drilling Contractor Personnel Responsibilities 8 2.6 Third Party Service Contractor Personnel Responsibilities 9 2.7 Special Operations Precautions 14 2.7.1 Helicopter Operations 14 2.7.2 Mooring Vessel Operations 14 2.7.3 Casing pressure Monitoring 14 2.7.4 Back Pressure Valves 14 2.7.5 Rotary Table Insert Bushing Locks 14 2.7.6 Christmas Tree Equipment 14 2.7.7 Mud Logging Units 15 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 10 GENERAL INFORMATION Appendix G-I Appendix G-II Appendix G-III Appendix G-IV EMDC-DO Risk Assessment Form Risk Assessment Package (example) EMDC-DO BOPE Exception Form Drilling Environmental Performance Indicators Report Form ____________________________________________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACKUP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION - MAY 2003 2.1 CONTRACTS ADMINISTRATION After the execution of the various contracts between EMDC-Drilling and the individual contractors, the Operations Superintendent and Operations Supervisor will administer the contracts based on the following responsibilities: Operations Superintendent 1. Administer the contract terms and provisions between EMDC-Drilling and the Drilling Contractor and other critical and non-critical third party service contractor. 2. Copies of applicable contracts are maintained by the EMGSC procurement group for various drilling operations. 3. Address questions from the Operations Supervisors regarding contract terms or exceptions. Operations Supervisor 1. Become familiar with each contract as necessary to conduct drilling operations and abide by the terms of the contracts. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 10 GENERAL INFORMATION 2. Ensure that all equipment on the Drilling Rig is in accordance with contract terms. 3. Ensure that a representative of each service company completes service tickets in accordance with the contract terms. 4. Conduct a safety/operational ("prespud") meeting prior to the start-up of drilling operations with the appropriate management of the Drilling Contractor and other critical third party service contractors. Refer to Drilling Safety Management Program for meeting guidelines 5. Document safety meetings in the DRS and keep attendance list and presentation materials in the field well file. Note any special problems addressed and/or discussed at these meetings in a memo to the Operations Superintendent. Critical Service Contractor's Responsibilities 1. Have in place a safety and environmental program and discuss this with EMDC-Drilling Management when requested. 2. Identify the disposal method/sites used for contractor waste. This is a contractual requirement of third party contractors for US East Development Drilling Operations. 3. Provide personnel with adequate qualifications consistent with the qualifications in the Responsibility section (Section 2.4) and if applicable comply with 3 rd party SSE policy and requirements. 4. Have in place maintenance programs, inspection programs, internal control programs, etc., and review these with EMDC-Drilling Management as requested. 5. It is desirable to have acceptance inspection checklist for the following third party services: mud logging, production testing equipment, waste transportation, storage, disposal, selfcontained breathing equipment, cementing unit, wireline logging, perforating, and LWD with radioactive source. 2.2 PRE-SPUD MEETING A pre-spud meeting will be held prior to the start of drilling operations on each drilling campaign. Key personnel (Operations, Engineering, Geology, Drilling Contractor, Third Party Contractors, etc.) should attend this meeting. During the meeting, the following points should be addressed: 1. Safety, health, and environmental policies. 2. Expectations in the following areas: • • Safety Job Planning DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 10 GENERAL INFORMATION • • • • Communications Regulatory Compliance Emergency Procedures and Contingency Plans Security of well data 3. Ensure that contractors clearly understand their responsibility for transportation and disposal of contractor waste. 4. Ensure that both EMDC-Drilling and contractor's personnel clearly understand the chain of command and the personnel responsible for various decisions. 5. Discuss well drilling plans including relevant geology and drilling hazards. 6. Communicate results of the risk assessment. 7. Copies of the Drilling Program should be furnished to the Drilling Contractor and third party contractor personnel at the pre-spud meeting, as required. 8. Operations Integrity Management Systems, especially Management of Change. 9. Drilling Safety Management Program 10. Non proprietary pre-spud meeting materials can be circulated to all personnel for their reference. 2.3 SECURITY All personnel (EMDC-Drilling and contractors) must obtain, maintain, and retain well data, especially information relating to depths, operational problems, and formation evaluation according to their job requirements and release such information to others on a strictly "needto-know" basis. All personnel will be reminded of the proprietary nature of the geological and critical well data. 2.4 EMDC DRILLING OPERATIONS PERSONNEL RESPONSIBILITIES Operations Superintendent Responsibilities 1. Communications: • • • • Provide communications, as necessary, between the Operations Supervisor on the Drilling Rig and EMDC-Drilling Management. Keep Field Drilling Manager and other off-site personnel informed of all aspects of the operation. Interface daily with Production Management to ensure operational continuity. Attend daily coordination meeting with Production Supervisor on manned platforms DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 10 GENERAL INFORMATION 2. Supervise Operation: • • • • • • • • • • Ensure that all operations are in compliance with OIMS, Drilling Safety Management Program, Drilling Operations Manual, and approved Drilling, Completion, and Production Testing Programs and Procedures. Confer with Geological Personnel to ensure maximum data acquisition at minimum time and cost. Communicate with accounting group and EMDC-DFS group to ensure proper documentation and validity of charges. Work with Engineering staff to compile manuals, programs, and procedures. Assist the Operations Supervisors with daily decisions necessary to help the Drilling Contractor implement the approved Drilling, Completion, and Production Testing Programs and Procedures. Conduct audits, inspections, and safety programs in accordance with OIMS and the Drilling Safety Management Program. Coordinate materials requests and logistics with Materials Group and/or Production Organization to facilitate timely arrival of required supplies. Advise Field Drilling Manager when to initiate rotation of Operations Supervisor to ensure sufficient lead time for full implementation of OIMS. Attend rig site safety meetings and pre-tour safety meetings. Attend daily coordination meeting with Production Supervisor on manned platforms. 3. Local Coordination of Manuals, Programs and Procedures: • Communicate requests from the Operations Supervisor to make exception(s) to certain guidelines or procedures in the Drilling Operations Manual. • Request verbal approval from the Field Drilling Manager for exception(s) to certain guidelines or procedures in accordance with the Management of Change Process described in OIMS. Note: Using good judgement, Operations Superintendent may take exception to a guideline or procedure worded with "should" and "ought" without prior approval. • • • • Solicit change(s) to the Drilling Operations Manual from the Operations Supervisors according to the change process described in this manual. Review and approve procedures as necessary to implement the approved Drilling, Completion, and Production Testing Programs and Procedures. Ensure that Operations Supervisors receive drilling procedures in a timely manner. Notify the Field Drilling Manager, as soon as practical, of exception(s) made to guidelines or procedures of the Drilling Program or Drilling Operations Manual. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 10 GENERAL INFORMATION Note: All requirements worded with "will", "shall", or "must", will be approved by the Field Drilling Manager prior to the exception. • • Ensure that all safety and operating manuals are available at the rig site. Review and approve operations safety plan. 4. Compliance with ExxonMobil and Government Regulations: • • • • • • Become familiar with applicable laws and regulations, and ensure compliance. Ensure that all applicable regulatory permits are on the Drilling Rig to conduct operations. Ensure that required reports (as identified in approved Drilling, Completion, and Production Testing Programs and Procedures) and/or operations permits are sent to applicable regulatory bodies. Request any regulatory exceptions either from the necessary regulatory agency or the appropriate regulatory contact within ExxonMobil. Report incidents of non-compliance. Maintain current knowledge of authority guides. 5. Contractor Supervision: • • • • Steward contractors and suppliers to maximize cost-effectiveness and safety. Coordinate contractors and suppliers to ensure timely arrival of equipment, supplies and personnel. Ensure contractor compliance with all contract terms. Monitor contractor compliance with safety, environmental, and drug and alcohol policies stated in contract. Operations Supervisor Responsibilities 1. Supervise Operations at Drill Site: • • • • • Ensure the Drilling Program is executed by contract personnel in a safe and efficient manner. Work with Engineering Staff to ensure technical goals are operationally feasible. Make recommendations for changes to Drilling, Completion, and Production Testing Programs and Procedures to increase safety and/or efficiency. Work with Drilling Contractor to develop procedures and plans to implement Drilling Program. Review daily plans of the Drilling Contractor and coordinate the activities of Third Party Contract Personnel (i.e. Service Companies) to implement approved Drilling, Completion, and Production Testing Programs and Procedures. Ensure compliance of Drilling Contractor and Third Party Contractors with terms of appropriate contracts. Ensure that all parties understand their responsibilities per this Manual. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 10 GENERAL INFORMATION • • Communicate materials requirements to Operations Superintendent and follow up on delivery; assist in logistics as necessary. Coordinate transportation of equipment and personnel to and from the drilling rig as necessary. Ensure Contractors are maintaining the required equipment and conducting efficient operations in a safe and environmentally sound manner. 2. Ensure Compliance with OIMS and the Drilling Safety Management Program • • • • • • • Communicate ExxonMobil requirements and expectations regarding safety and performance to all rig site personnel. Assist Drilling Contractor with implementing the Safety Program in accordance with the Drilling Safety Management Program. Ensure that equipment and procedures meet OIMS guidelines. Recommend change(s) to OIMS or the Drilling Operations Manual as necessary to improve or correct certain operations. Notify the Operations Superintendent, of exception(s) that need to be made to certain guidelines or procedures of the Drilling Operations Manual. Once proper approval is granted, document the exceptions on DIMS and maintain a record of all significant changes on the rig. Monitor daily operations to ensure Regulatory compliance. Report any incidents of noncompliance. Ensure that all required reports and records are accurate and complete and issued in a timely manner. Drilling Engineer Responsibilities 1. Ensure the Application of the Best Available Technology in Drilling Operations: • Prepare the Site Construction Plan considering surface constraints such as local population, logistics, environmental impact, archaeological surveys, bottom sweeps, and rig positioning. • Prepare the Drilling, Completion, and Production Testing Programs and Procedures based on all available geologic and drilling information from nearby offset wells in the area. This Drilling and Evaluation Program shall include the best available technology for drilling operations. Be knowledgeable of the operating and construction characteristics of all components in the drilling system to be used and be knowledgeable about alternative systems and procedures that might be implemented to improve operational efficiency. Ensure operations staff understands the fundamentals behind successfully implementing the new technology. • 2. Prepare Standards and Procedures: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 10 GENERAL INFORMATION • • • • Prepare a site specific Emergency Response/SIMOPS (if applicable) attachment for the Operations Manual Prepare the Drill Well Data Package to meet Regulatory requirements. Ensure that all Standards and Procedures are in compliance with OIMS. Prepare Operations Safety Plan in accordance with Safety Management Program 3. Coordinate a Risk Assessment for all drillwells: • • • • • Organize meetings with the Operations Supervisor, Operations Superintendent, Field Drilling Manager, Production personnel, Third Party Contractors, and others (as required) to assess and mitigate the particular hazards associated with the planned operations. During the course of the Risk Assessment process, the Drilling Engineer is to ensure that the Risk Assessment Form /Action Status Report (Section 2 – G-I) is completed and routed for endorsement. EMDC-DO has compiled a list of base case failure event scenarios that are common to most of our activities. This list should be reviewed during the Risk Assessment and if any additional risk scenarios are identified, these should be documented using the format supplied and routed for endorsement with the RAF. A cover memo is used to concisely communicate the results of the Risk Assessment. An example Risk Assessment package has been included in Section 2 – Appendix G-II. The base case risk scenarios can be referenced in the OIMS manual. An additional requirement is the assessment of the rig's BOPs to determine compliance with the Surface Blowout Prevention And Well Control Equipment Manual. The Blowout Preventer Equipment Exception form (Section 2 – Appendix G-III) is to be completed and routed with the RAF. Any requested exceptions regarding the rig's BOP configuration will be approved through endorsement of this form. All follow-up items will be documented in the Risk Assessment package. 4. Provide Engineering Support: • Provide surveillance of day-to-day drilling progress to ensure that the Drilling and Evaluation program is conducted to apply the best available technology and propose modifications, as necessary. • • Evaluate and recommend materials and equipment. Analyze drilling performance at intermediate well depths and work with the Operations Superintendent and Operations Supervisor to implement changes in procedures and equipment based on the results of this analysis. Develop and write supplemental procedures for all major drilling and completion operations. If applicable use the Standard or Core Procedure templates found in this Operations Manual. Prepare cost estimates for the selection of optimum procedural alternatives and equipment modifications. • • DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 10 GENERAL INFORMATION • • • • • • • • • • • • • • 2.5 Counsel the Operations Superintendent and Operations Supervisor on critical activities and problems such as equipment failures, mud and hole problems (including tectonics and wellbore stability), etc. Provide rig site technical assistance in abnormal pressure detection, running and cementing critical casing strings/liners, production testing operations, and well control. Monitor well costs and ensure that all costs are kept up to date and accurate (including DRS). Review DRS Report and ensure that input data are accurate and complete (coding, etc.). Participate in wellsite incident investigations, as required in SMP. Perform bid preparations and analysis in conjunction with the EMDC Procurement Group. Keep the Supervising Engineer / Engineering Manager informed of all activities. Prepare AFEs and Supplements. Complete a Final Well Report package at the conclusion of each well. Generally, this will include: Final well cost summary sheet EPI form Final Well Report form Production Casing and Tubing Tallies Acquire technical support from Drilling Technical and/or URC as necessary. DRILLING CONTRACTOR PERSONNEL RESPONSIBILITIES Drilling Contractor Responsibilities: Refer to the Safety Management Program for a listing of additional responsibilities 1. Operate as an independent contractor and execute the Drilling Program to the satisfaction of the Operations Supervisor on the Drilling Rig. 2. Operate and maintain the Drilling Rig in a safe working condition and in full compliance with EMDCDrilling technical specifications and local regulatory requirements, including those requirements as specified in the drilling contract. 3. Develop and use safe working procedures. Ensure that the following programs and/or systems are in place and functioning properly (Drilling OIMS Manual Element 8, Section E and Safety Management Program): • • • • • • • Safety Program Quality Assurance/Quality Control Program Emergency Preparedness Program Preventative Maintenance Program Risk Assessment Program Work Permit System Appropriate Affiliate Simultaneous Operations (SIMOPs) program for development drilling operations adjacent to production facilities. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 10 GENERAL INFORMATION • SSE program if applicable 4. Provide qualified personnel that can efficiently operate the Drilling Rig in a safe and environmentally sound manner. Offshore Installation Manager (OIM) Representative 1. Represent the Drilling Contractor as the person in charge and responsible for the overall operation and safety of the Drilling Unit and personnel. 2. Ensure that the rig operation meets all applicable regulatory requirements. 3. Implement the Drilling Contractor Safety Program 4. Ensure that all safety equipment is in proper working condition. 5. Secure necessary training for Drilling Contractor personnel. 6. Plan and supervise training drills. 7. Ensure compliance/supervise SSE program if applicable Toolpusher Responsibilities 1. Supervise the Drilling Contractor personnel that perform drilling related operations. 2. Monitor the wellbore for hole problems and abnormal pressure indicators. 3. Provide a communication link between the Operations Supervisors and Drilling Contractor. 4. Make recommendations to the Operations Supervisor as appropriate. 5. Ensure that daily planning meetings are held which focus on conducting the required operations in a safe and efficient manner. 6. Conduct drills, safety meetings, and training. 7. Ensure that Drilling Contractor personnel document drilling operations properly and that all reports are complete (IADC, BOP test forms, marine deck logs, etc.) Safety Coordinator Responsibilities Refer to Drilling Safety Management Program 2.6 THIRD PARTY SERVICE CONTRACTOR PERSONNEL RESPONSIBILITIES Service Company Responsibilities DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 10 GENERAL INFORMATION 1. Operate as independent contractors that will assist in the executing the Drilling Program to the satisfaction of the Operations Supervisor onboard the Drilling Rig. 2. Operate and maintain service equipment in full compliance with EMDC-Drilling technical specifications and local regulatory requirements, including those requirements specified in the contract. 3. Develop and use safe working practices (including written JSAs for applicable critical tasks). 4. Provide qualified personnel that can efficiently perform the required services in a safe and environmentally sound manner. Comply with contractual personnel requirements and Short Service Employee (SSE) program requirements. 5. Each service company is to designate a representative on location, to coordinate the operations and services directed by the Company. 6. Ensure that all service company personnel attend and participate in safety meetings, drills, and critical operations safety meetings (including pre-tour safety meetings). Drilling Fluids Engineer Responsibilities 1. Maintain the drilling fluid system in accordance with the Drilling Program and Section 6 of this manual. 2. Conduct a minimum of two (2) complete "In" and "Out" checks of the drilling fluid daily during drilling operations. 3. Notify the Operations Supervisor of any significant changes in the "In" or "Out" properties of the drilling fluid system. 4. Notify the driller and toolpusher of changes in weight, chloride content, gas, or any other property that may indicate a significant change in formation or entry into abnormal pressure. Ensuring mud is in condition to log by static – ageing a sample of "in" fluid 24-48 hours prior to logging and check properties. Report results to Operations Supervisor 5. Take an "Out" sample of the circulating drilling fluid prior to pulling out of the hole (POOH) for logging and give to the Wireline Logging Engineer along with, a fluid filtrate sample, and the associated filter cake. This information will be recorded on the Electric log. 6. Maintain the drilling fluid weight in the active pits during trips and any time that the drill string is out of the hole. 7. Ensure that Drilling Contractor personnel are weighing the drilling fluid and measuring the funnel viscosity of the drilling fluid with properly calibrated equipment. 8. Ensure that Drilling Contractor personnel are recording drilling fluid weight and funnel viscosity on 1530 minute intervals as measured at the flow line and the suction pit. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 10 GENERAL INFORMATION 9. Monitor and assist Drilling Contractor personnel when continuously weighing drilling fluid at the flow line and downstream of the degasser when circulating high gas cut fluid from wellbore. 10. Advise the Operations Supervisor daily of the performance of all solids control equipment. 11. Assist in optimizing the solids control equipment (e.g., recommend screen sizes for the shale shakers, etc.). Advise drilling contractor about screen inventory. 12. Obtain approval from the Operations Supervisor prior to diluting the drilling fluid system to maintain the drilling fluid properties specified in the Drilling Program. 13. Communicate all planned changes to pit levels in the active system to the Mud Logger and driller. 14. Monitor drilling fluid properties daily to help identify trends or sudden changes from drilling fluid treatments. 15. Prepare a Daily Drilling Fluids Report in accordance with the guidelines specified in Section 6. 16. Maintain an inventory of all drilling fluid products onboard the Drilling Rig. 17. Assist the Operations Supervisor when ordering appropriate quantities of drilling fluid products. 18. Ensure that a Material Safety Data Sheet (MSDS) is available for each drilling fluid product on drilling rig. Directional Driller Responsibilities 1. Recommend Bottom Hole Assemblies (BHAs) to the Operations Supervisor for each hole section of a directional well as specified in the Drilling Program. 2. Oversee the assembly of all directional BHAs by Drilling Contractor personnel. 3. Ensure that directional drilling practices conform with anti-collision standards contained in this manual. 4. Complete the directional drilling pre-job survey data sheet, sign, and present to the operations supervisor. 5. Complete a BHA report form for all BHAs run in the well that includes connection type, ODs, IDs, lengths, and serial numbers for each component. 6. Assist Drilling Contractor personnel, as directed by Operations Supervisor, when adjusting drilling parameters to achieve the desired BHA performance. (Bit weight, RPMs, etc.) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 11 of 10 GENERAL INFORMATION 7. Maintain a wellbore trajectory record in the Operations Supervisor's office by calculating the azimuth and inclination of the wellbore from surveys. 8. Maintain a current wellbore plot in the Operations Supervisor's office using the wellbore trajectory record. 9. Provide a daily cost to the Operations Supervisor for directional equipment/tools and services provided by the Directional Company. 10. Maintain an inventory of directional equipment/tools on the Drilling Rig. MWD/LWD Engineer Responsibilities 1. Maintain the MWD/LWD unit and related equipment on location as specified in the contract. 2. Ensure that sufficient MWD/LWD tools are on site as specified in the contract. 3. Maintain 24 hour surveillance of the wellbore from the MWD/LWD unit during drilling operations. 4. Maintain a record of all MWD surveys taken. 5. Assist the Directional driller, as directed by the Operations Supervisor, when calculating the azimuth and inclination of the wellbore from MWD surveys. Ensure that survey correction factors are understood and endorsed by Drilling Engineer, Operations Supervisor, and Directional Driller. 6. Complete the directional drilling pre-job survey data sheet, sign, and present to the operations supervisor. 7. Maintain a pipe tally which is separate from the driller's pipe tally. 8. Provide the Operations Supervisor a copy of the MWD/LWD log daily and fax a copy of the log to ExxonMobil personnel as directed by the Operations Supervisor/Wellsite Geologist. 9. Protect personnel from exposure to radioactive sources if such sources are present on location for LWD services. Mud Logger Responsibilities 1. Maintain the Mud Logging unit and related equipment on the Drilling Rig as specified in the contract. 2. Maintain 24 hour surveillance of the wellbore from the Mud Logging unit during all drilling operations. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 12 of 10 GENERAL INFORMATION 3. Notify the driller and the Operations Supervisor of all drilling breaks, unreported changes in pit level, increases in flow, and high gas units. 4. Notify the driller and the Operations Supervisor of any changes in cuttings, such as quantity, size and shape or any parameter that may indicate an increase in pore pressure or the presence of hydrocarbons. 5. Monitor the trip tank while on trips, logging, and any other time that the trip tank is used. 6. Maintain a pipe tally which is separate from the driller's pipe tally. 7. Maintain a current wellbore sketch that includes volumes and capacities of each hole section in the wellbore. 8. Calibrate the gas detector a minimum of once every 12 hours and after circulating out gas units near saturation. 9. Provide the Operations Supervisor a copy of the Mud Log and Mud Logging Report daily and fax a copy to EMDC personnel as specified by the Operations Supervisor/Wellsite Geologist. 10. Ensure that a Material Safety Data Sheet (MSDS) is available for each mudlogging product on the drilling rig. Note: Where mud logging units have hydrogen gas feeding the Flame Ionization Detector (FID), post warning signs indicating the flammable/explosive characteristics of the gas. Inspect the hoses (typically polyflow) every 2-3 months, and replace if it has been pinched, is brittle, or is discolored from normal clear or white color (OIMS manual element 6). Cementer Responsibilities 1. Maintain the cementing unit and related equipment as specified in the contract. 2. Advise the Operations Supervisor of any deficiencies in cement storage/transfer equipment. 3. Calculate the cement slurry volumes, mix water, and displacements for cementing operations as specified in the Drilling Program. 4. Verify cement volume calculations with the Operation Supervisor prior to starting the cementing operation. 5. Calibrate the liquid additive system (LAS), if applicable, prior to starting the cementing operation. 6. Collect cement and cement additive samples from the necessary cement P-tanks and liquid additive system prior to starting the cementing operation. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 13 of 10 GENERAL INFORMATION 7. Operate the cementing unit during cementing operations as directed by the Operations Supervisor. 8. Maintain an inventory of all cement additives and cementing equipment on the Drilling Unit. 9. Assist the Operations Supervisor when ordering appropriate quantities of cement products. 10. Document all pumping/cementing activities in accordance with regulatory requirements using recording equipment (chart recorders, densiometers, etc.) and provide the Operations Supervisor with properly documented charts. 11. Ensure that a Material Safety Data Sheet (MSDS) is available for each cement product on the drilling rig. 2.7. SPECIAL OPERATING PRECAUTIONS 2.7.1 Helicopter Operations Provide accurate cargo and weight manifests for all helicopter transportation. Lower and secure all crane booms before helicopter landing/departure. (Crane operator must step out of the crane cab until the pilot has stopped the rotation of the rotor blades.) Make public announcement of helicopter landing/departure. Provide safety orientation/ditching instructions for passengers. Establish flight tracking procedures. Helideck fire fighting system shall be manned during refuelling. Rapid/hot refuelling is not authorized. See Safety Manual for exceptions. 2.7.2 Mooring Vessel Operations Use a "Clear Deck of Personnel" policy on work boat when work wire is under tension. 2.7.3 Casing Pressure Monitoring Casing annulus pressures shall be monitored weekly at all rigs with surface wellheads. If casing pressure is detected, it shall be reported on the Daily Drilling Report. The situation shall be reviewed with the Operations Superintendent to determine if any corrective actions, are warranted, e.g. bleed off, increased monitoring, etc. 2.7.4 Back Pressure Valves Whenever a back pressure valve (BPV) is to be removed from a tubing hanger, a lubricator shall be installed and anchored. Prior to retrieving the plug, confirmation of DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 14 of 10 GENERAL INFORMATION pressure equalization shall be made, if possible. If working on a well with H 2S gas, all workers in the area shall mask up while retrieving the plug. 2.7.5 Rotary Table Insert Bushing Locks Rotary table insert bushings shall be kept locked at all times (or removed) except when procedures specifically require them to be temporarily unlocked. A means of visually determining locked status shall be provided. 2.7.6 Christmas Tree Equipment Have an OEM (Original Equipment Manufacturer) service representative on location during installation and pressure testing of all christmas tree equipment. All wellhead and christmas tree equipment has the potential to trap unexpectedly deadly pressure between seals, in gate valve cavities, under pipe plugs, lockdown screws, grease fittings and in small porting which has become plugged. Some models of gate valves are especially prone to trapping pressure in the gate valve cavities. Trapped pressure most commonly occurs in the split gate style valves and especially the WKM models. Any valve that has service fittings, which access the valve body, should have a permanent warning sign stating "WARNING: This valve has the potential to internally trap pressure!" 2.7.7 Mud Logging Units Where mud logging units have hydrogen gas feeding the Flame Ionization Detector (FID) post warning signs indicating the flammable/explosive characteristics of this gas. Inspect the hose (typically Polyflow) every 2-3 months, and replace if it has been pinched, is brittle, or is discolored from normal clear or white color. Responsibility: Operations Supervisor Approval Authority for exceptions: Operations Superintendent. GENERAL INFORMATION SECTION 2 - APPENDIX G-I DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 15 of 10 GENERAL INFORMATION DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 10 GENERAL INFORMATION DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 SECTION 2 - APPENDIX G-II MEMORANDUM EMDC DRILLING ORGANIZATION TO: Clyde J. Baldwin FROM: Grand Isle 16 OCSG 031 R-22 ST#1 "Sandberg" Drilling Team DATE: February 17, 2000 SUBJ: OIMS Risk Assessment for GI 16 OCSG 031 R-22 ST#1 "Sandberg" Drillwell Consistent with Operations Integrity Management, the drilling team has completed a “Risk Assessment” for the upcoming GI 16 OCSG 031 R-22 ST#1 "Sandberg" drillwell. Enclosed please find the scenario worksheets for the four incidents identified as potential hazards by the team. Please note that these four scenarios addressed in the attached worksheets are unique to this location and are not covered by the existing EMDC Base Case Risk Assessment. The EMDC Base Case Failure Event Scenario List is included for your reference. If you should have any questions regarding this assessment, please do not hesitate to contact any member of the team for clarification. xc: H. J. Longwell, III Ensco 99 Drilling Superintendents Element 2 Risk Assessment Custodian ELEMENT 2 RISK ASSESSMENT FAILURE EVENT SCENARIO LIST - BASE CASE Description Barge DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 Land Platform Jack-up ** 2 of 10 GENERAL INFORMATION Surface blow-out with BOP stack on drillwell. X X X Surface blow-out with Diverter on drillwell. X X X Surface blow-out due to surface equipment (drillpipe connection, safety valve, control head) failure during underbalanced perforating, perforation surging, or well lifting/jetting operations. Surface blow-out while conducting completion operations in clear fluids with open perforations. X X X X X X X X Explosives (perforating guns, string shots, etc.) detonated at the surface. X X X X Drilling rig crane failure/operator mishap. X X X Rig hoisting equipment failure/mishap. X X X X Drill rig support vessel/vehicle accident. X X X X Helicopter/seaplane crash/mishap. X X X Hazardous chemical accident/mishap. X X X X Fuel, oil-based drilling fluid, or oil transfer spill. X X X X Critical supply or personnel transfer is prohibited by weather. X X X X Severe weather impacts drilling operations. X X X X Drilling regulatory noncompliance or infraction. X X X X Derrick barge lift accident/mishap. X X Jack-up rig punch-through. X Barge rig capsizing during sinking/refloating operation. X Marine vessel collision with rig/platform. X Lifeboat launch failure. X X X X Worker incident on rig. X X X X Fire/explosion on rig. X X X X Person overboard. X X X X X Diver incident. ** applicable to R-22 ST#1 "Sandberg" drillwell ADDITIONAL FAILURE EVENT SCENARIOS SPECIFIC TO ENSCO 99 and R-22 ST#1 "Sandberg" DRILL WELL Description Barge Land Platform Jack-up ** Oil Based Drilling Fluid Annular Injection Accident/Mishap Oil Based Drilling Fluid Spill X Oil Based Drilling Fluid Fire in Pits X DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 X 3 of 10 GENERAL INFORMATION X Well Control Incident Due to Striking Offset Well. ** applicable to R-22ST#1 "Sandberg" drillwell R-22 ST#1 "Sandberg"-SPECIFIC OPERATIONS RISK WORKSHEET #1 RISK MATRIX HYPOTHETICAL FAILURE EVENT SCENARIO: Unplanned Shallow Gas Problems during Conductor-less Drilling A B C D I EMDC E H II E III P F IV LOCATION: Jack-up Drilling Rig DESCRIPTION: Unexpected shallow gas is found when drilling surface hole without conductor. CONSEQUENCES: HEALTH/SAFETY PUBLIC DISRUPTION ENVIRONMENTAL IMPACT I III RESPONSE TIME: Minutes for rig personnel to respond to initial event. II ALTERNATE TO OPERATION: Drill and set a 13-3/8" conductor at about 1000'. PREVENTATIVE MEASURES: All prudent precautions will be taken to prevent this occurrence. 1. A thorough review of the most recent ST54 drilling program was performed to observe expected gas units, mud weights used,etc. B21 ST-1 in 2/98 was last drillwell prior to this current planned 3 well program. B-31, "Hesperides," is the 1st well in this current 3 well program. R-22 ST#1, "Sandberg," will be the 2nd well in the program. 2. Preventative measures noted and planned for R-22 ST#1 include (1) control drilling to maintain low mud weight "out" to preventlost returns and (2) preparation of a Lost Returns plan. 3. A thorough review of the well logs near surface indicated no presence of shallow hydrocarbon-bearing sands. Both the originalB-1 logs, the more recent B-21 and B-31 logs have been evaluated. 4. Casing pressures have been measured on all annuli. The one well with notable pressure (110 psi) on the surface casing was bledto zero and remained at zero after 24-hr monitoring; B-21 will continue to be monitored and reported until spud. 5. An evaluation of well interference indicates that (a) most wells from the "B"-platform were drilled vertically and therefore inparallel to depths near 5000', and (b) directional driller will drill vertically to ~4,500' MD , which is below the surface casing setting depth for "Sandberg," and then kick-off MITIGATION PLANS: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 10 FINAN GENERAL INFORMATION As a result of the SIMOPS meeting with drilling, production, and operations personnel in attendance, the following plans were established: 1) The PIC is the EMDCDO Drilling Superintendent. 2) Emergency shutdown links are established by NOPO field operations. 3) Communication links are established with the NOPO field foreman and GI 16 P platform base, which is the G platform. The diverter will be nippled up and tested while drilling surface hole. Diverter drills will be performed with all crews. The offset drive pipe for the B-30 well, Adonis, which is yet to be drilled, will be blanked off at the surface to prevent an alternate conduit to the surface. RISK WORKSHEET #1 HYPOTHETICAL FAILURE EVENT SCENARIO: Oil Based Drilling Fluid Annular Injection Accident/Mishap A B C D E I LOCATION: GI 16 R-Platform and Ensco 99 II DESCRIPTION: Mishandling, mechanical failure results in exposure of personnel to Oil Based Drilling Fluid III and to potential additives. IV H P,E,F ENVIRONMENTAL HEALTH/SAFETY PUBLIC DISRUPTION IMPACT CONSEQUENCES: III IV IV RESPONSE TIME: Minutes to respond to personnel injury. Potential for extended response to fire incident. ALTERNATE TO OPERATION: Store oil based drilling fluid cuttings in boxes and ship via boat back to land. This would impose significant cost increases on this well. This alternative operation carries with it its own risks. PREVENTATIVE MEASURES: Personnel training (HAZCOM). MSDS available. Proper PPE. Equipment inspection, and maintenance. Hydrotesting / leak testing of all injection well facilities. Injection of seawater prior to any oil based mud / cuttings. JSA's. Rig will be set up for "Zero-Discharge Operation," with appropriate plugs set in all jack-up deck drains. Contracting with competent contractors, either Apollo or National Injection Services. Injection skirt installed around the top of the surface casing MITIGATION PLANS: Medic on-site for water locations. Emergency equipment. Proper PPE. Fire fighting teams and training. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 10 GENERAL OPERATIONS EMDC RISK MATRIX RISK WORKSHEET #2 HYPOTHETICAL FAILURE EVENT SCENARIO: Oil Based Drilling Fluid Spill LOCATION: GI 16 R Platform and Ensco 99 A DESCRIPTION: Oil spill in water during any oil transfer and/or human error. B C E operation due to mechanical failure I II E,F III HEALTH/SAFETY D IV E,F P PUBLIC DISRUPTION H ENVIRONMENTAL III(a) IMPACT IV II(b),III(b) CONSEQUENCES: (a) - This potential failure event has potential for adverse media attention. FINANCI AL IMPACT II(b),III( b) (b) - Spill size dependent. RESPONSE TIME: Hours to days to contain and clean up oil transfer spill. ALTERNATE TO OPERATION: Do not use oil based mud (potential differential sticking, higher torque, and ultimate inability to reach target objectives) PREVENTATIVE MEASURES: Oil transfer Policies & Procedures. Ensco 99 will be in "Zero Discharge Operation". Oil based drilling fluid disposal company personnel on board. Recent vibrator hose upgrades. Equipment to be checked and tested for leaks prior to first shipment of OBM. Transfer hoses shall have appropriate certification and testing records prior to first shipment of OBM. Transfer hoses shall be checked periodically and shall be replaced if any deficiencies are noted. An exercise will be conducted with all transfer personnel prior to first shipment of OBM. All appropriate personnel will be in constant communication during OBM transfers, especially with boat captain, and no activity associated with OBM movement will be unsupervised. Weather conditions shall be favorable for any transfer from vessel and mooring DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 9 GENERAL OPERATIONS EMDC RISK MATRIX lines shall be checked periodically. Fire protection equipment will be located in strategic positions to protect personnel inside of the change room and offices. JSAs for all activities will be prepared and thoroughly reviewed prior to any activity associated with OBM. Proper PPE will be utilized when handling OBM. MITIGATION PLANS: Oil Spill Contingency Plan for water locations, emergency response drills. RISK WORKSHEET #3 HYPOTHETICAL FAILURE EVENT SCENARIO: Oil A LOCATION: Ensco 99 while drilling at GI 16 R platform. DESCRIPTION: Fire/Explosion on drilling rig caused by fluid. This could be caused by welding, electrical spark, B C I III Based Drilling Fluid Fire in Pits accidental ignition of oil based drilling etc. H H IV PUBLIC DISRUPTION CONSEQUENCES: I, II, III IV(a) (a) - This failure event has potential for adverse Media attention. E H II HEALTH/SAFETY D E, F E,F,P ENVIRONMENTAL FINANCIAL IMPACT IMPACT III,IV III,IV RESPONSE TIME: Minutes to hours to extinguish. Potential for protracted response to major incident. ALTERNATE TO OPERATION: Do not use oil based drilling fluid (too detriment of drilling performance and costs). Other risks inherent to drilling operations. PREVENTATIVE MEASURES: Pits and shakers have a Skelton Foam Deluge System. Foam Deludge System: Test procedure will be reviewed, complete water test the system & review of foam deluge shut down & startup procedure. Exxon Safety Manual, JSAs. Proper venting and purging of enclosed spaces. Specification of safe welding areas and electrical classification areas (see API RP 500). Good DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 9 GENERAL OPERATIONS EMDC RISK MATRIX housekeeping practices. Gas and fire detection systems. Independent electrical inspection of rig. Contractor preventive maintenance program. Personnel training on hazards of oil based mud. Oil mud has high flash point. Adequate fire equipment. MITIGATION PLANS: Onsite medic for water operations. Contractor fire fighting training and equipment. Emergency evacuation plan. Fire drills. Escaid 110 invert emulsion oil mud typically has flashpoint > 220° F RISK WORKSHEET #4 HYPOTHETICAL FAILURE EVENT SCENARIO: Well Offset Well. A B C D E Control Incident Due To Striking LOCATION: Ensco 99 while drilling at GI 16 R platform. DESCRIPTION: While drilling, a kick occurs as a result lost returns during well control operations causes a I H II F III PE of striking an offset well. Subsequent blowout and spill at the surface. COMMENT: Only one live wellbore on the R platform, R-21. IV ENVIRONMENTAL HEALTH/SAFETY PUBLIC DISRUPTION IMPACT CONSEQUENCES: I III (a) (a) - This failure event has potential for adverse Media attention. III FINANCIAL IMPACT II RESPONSE TIME: Minutes to respond to initial event, days to several weeks to control blowout. ALTERNATE TO OPERATION: Inherent risk. Drill free standing well away from current wellbores. PREVENTATIVE MEASURES: Well path design with an emphasis on collision avoidance. Use two directional drillers plotting collision course when close to offset wellbores. Critical well will be temporarily P&A'd above the depth of closest approach and GLG bled off the well. Will use Op Tech Bulletin #99-111 as a guide to avoid wellbore collision. EMDC well control practices and policies. Technically and operationally sound drilling practices. EMDC BOP testing guidelines and EMDC BOP function testing standards. Casing design specifications, casing inspection DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 9 GENERAL OPERATIONS EMDC RISK MATRIX programs, casing connection make up procedures, casing pressure tests, wellhead QA/QC program. Rig supervisor well control training, NODO technical and operational personnel staffing requirements. Ensco personnel well control training, drilling crew tour proficiency drills, drilling rig critical alarms and instrumentation. NODO critical valve "soft-lock" program. Adequate offset well drilling and formation pressure information. MITIGATION PLANS: Onsite medic. Oil spill response plan. Critical operations and curtailment plan. Fail-safe surface and subsurface ESD systems. Fire fighting equipment/training. Joint drilling/production evacuation drills. DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 9 GENERAL INFORMATION SECTION 2 - APPENDIX G-III ExxonMobil Development Company – Drilling Organization BOPE EXCEPTIONS Well Name: Risk Supv. ppm Category: Field/Prospect: Depth:Engr. County, State 2 Engineer H2S: Opt. Supt. Rig:250 ppm H S ROE: Drlg. Engr. Mgr. Field Drlg. Mgr. Casing Size Depth Drilled Interval Max. MW Required to Balance Pore Pressure HC Exposed? Y/N Type Exception 1. 2. 3. b) c) d) e) f) Exception Requested Flexible hoses for BOP opening & closing lines not consistent with API RP 16D. Flexible hoses for choke and kill lines not consistent with API RP 16C. Low risk well package: a) Typ e RX rin g g asket reuse allowed after visual p. by ins ExxonMobil Supervisor (BOP WP psi). ≤ 3,000 Low carbon steel Type R ring gasket use and reuse allowed in non-load bearing API Type 6B flanges with Type R flat bottom grooves. (Flange bolt tightening check required, BOP WP ≤ 3,000 psi). Low carbon steel ring gaskets allowed in gas or sour oil environments (BOP WP ≤ 3,000 psi). Only one outlet valve required on each wellhead section (Xmas tree WP ≤ 3,000 psi). BOP control panel at accumulators only. Accumulator capacity sufficient if all preventers can be MASP PSI BOP Type Flowline Type Choke Type Justification for Exception Choke Min. WP DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 1 GENERAL INFORMATION SECTION 2 - APPENDIX G-IV ExxonMobil Development Company Drilling Environmental Performance Indicators Report Well: Offshore or Onshore: Location: Rig: Days: TD Depth (MD/TVD): FRR Date: Emissions Data Rig Fuel Consumption gallons (U.S.) Regulatory Compliance Data Exceedances reported to regulatory agencies* No. to air No. to No. to No. of NOV's waterNo. R.Q. Exceedances LandNo. Fines OtherFines Amount ($US) Total Exceedances Oil Spills* > 1 bbl. No. to landVol. to land bbls. No. to waterVol. to waterbbls. Chemical Spills* > 100 kg. No. to landVol. to landkgs. No. to waterVol. to waterkgs. [Vol.(gal.)*Specific Gravity *(8.3 lbs./1 gal)*(1kg/2.2 lbs.)] =Mass(kg) *Please send all spill or exceedance reports to Drilling Environmental Coordinator fax 281-423-4337 Waste Data Drilling Fluid Type: SW, FW, NAF (OBM/SBM/OTHER) Drill Cuttings (Only complete for drill cutting with NAF discharged to sea) NAF Drill Cuttings disposed at sea Vol. bbls. %NAF on Cuttings Use gauge hole volume Hazardous Waste (classified as Hazardous Waste by regulatory authorities) Net Generated (lbs.) External Recycled (lbs.) Ongoing (lbs.) Periodic (lbs.) Engineer: Eng. Manager: Include completed record in Final Well Report and send copy to EMDC Drilling Environmental Coordinator. DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 1 MARINE OPERATIONS 3.1 MARINE OPERATIONS 3.2 Site Survey / Bottom Sweep / SIMOPs review 1 3.3 Moving 2 3.2.1 Moving Jack-up Rigs 3 3.2.2 Moving Platform Rigs 4 3.2.3 Moving Barge Rigs 5 3.3 Moving and Positioning 6 3.4 Pre-Loading (Jack-up Only) 7 3.5 Cargo Transfers 8 3.5.1 Precautions 9 3.5.2 Weather Limits 9 3.5.3 Heavy Lifts (Jack-Up Lifts in Excess of 10 MT) 3.5.4 Lifting Operations 10 3.5.5 Rigging Guidelines 11 9 3.5.6 Equipment Maintenance 15 3.6 Transportation & Personnel Transfers 3.6.1 Cargo Transport 20 3.6.2 Helicopter Operations 21 3.6.3 Personnel Transport-Helicopter 22 3.6.4 Personnel Transport-Supply or Stand-By Boat 3.7 Marine Training 3.7.1 General 24 3.7.2 Reporting & Drill Frequency 25 3.7.3 Marine Drill Process 26 3.7.4 Fire Drills 3.7.5 Fire Drill-Example 29 3.7.6 Abandon Rig Drills 30 3.7.7 Abandon Rig Drill-Example 33 3.7.8 Man Overboard Drill 34 3.7.9 Specialized Drills 20 24 27 35 3.7.10 Principal Aspects of Drills 37 3.8 Ship Collision Avoidance 3.8.1 Detection 3.8.2 Radar Watch Procedures Appendix G-I Appendix G-II Appendix G-III Appendix G-IV 24 37 38 38 SIMOPs Checklist Memo SIMOPs Deviation Form Study of Pile Interaction with Jack-Up Rig Operations Pre-Startup Inspections for New to Fleet Jackup Drilling Rigs ______________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION - MAY, 2003 MARINE OPERATIONS 3.1 SITE SURVEY/BOTTOM SWEEP/SIMOPS REVIEW For applicable marine operations, a site specific operability study can be conducted by the EMDC Technology Group or an approved Marine Engineering contractor. Before a new rig is added to the fleet, a series of inspections must be performed on the new rig. Section 3 -Appendix G-V is a guide to the specific inspections that must be done. Additional inspections may be completed as required by the specific rig or drilling program requirements. Prior to moving the rig onto a new or preexisting location, a shallow hazards assessment of the site (OIMS Element 3) is to be conducted. The assessment will aid in the location of submarine cables, pipelines, buoys, boulders, shallow gas, etc. should such obstructions exist in the vicinity of the proposed location. The assessment should include a review of existing information for any evidence of shallow hazards. Sources may include the following: • Offset well/soil data, previous bottom sweeps, site surveys, appropriate geological and geophysical data, and offset well casing pressure. • Up-to-date maps of pipelines (including platform vent/flare lines) and data regarding the position and characteristics of previous rigs that worked in the area. • Up-to-date drawings of production platform and facilities to assess interference potential and identify SIMOPs requirements associated with conducting Jack-Up Drilling Operations over production platforms. • Diagrams of Production Platform support piling positions and driven depths to assess JUR spud can and platform pile interference potential (be sure to account for production platform leg batter). Section 3 -Appendix G-IV (" Amoco/McClelland Study "Jack-Up Rig Soil Disturbance") is the subject of a memo written by E. J. Henkhaus. The Drilling Engineer is to reconcile all MIRU plans with this memo (and ExxonMobil's Civil Technology Group, if required). • Regional seismicity (i.e., number and intensity of earthquakes) in earthquake prone areas. • Existence of natural seeps. • Literature (company and public). Based on results of the shallow hazard assessments, a site survey may be conducted. The site survey may include: • Bathymetry Profile via Echo Sounder • • 2-D high resolution multifold seismic • Side Scan Sonar • Magnetometer Sub-bottom profiler • Soil Boring (100' -150') For JU rigs, adequacy of JUR leg length must be considered. This will include spud can penetration based on maximum previous penetration or soil boring analysis estimate (if first time at a location), water depth, required JUR hull air gap, production platform deck, and equipment elevations. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 41 MARINE OPERATIONS Review the potential for JUR leg run or punch through during pre-load operations. Previous preload experience in the area and/or soil boring analysis will be good predictors of this. A bottom sweep of the area in which the JUR will be positioned adjacent to the production platform shall be conducted for each JUR/Production drilling program. • The area swept should include all area where the Jack-Up rig could set its legs onto the seafloor (generally, this is within 500' of the platform). • All pipelines within 490' of the JUR spud cans shall be marked with sonar reflectors and surface buoys, a safe entry/exit area cordoned off with markers, or proper waivers will be obtained-from appropriate EMDC and EMPC management and regulatory agencies. • Company providing bottom sweep will provide a diagram of bottom sweep area identifying pipelines marked and any underwater obstructions or previous spud can hole identified. This should be included in the MIRV Procedure. • If there is significant delay between when the sweep is performed and when the rig will actually move onto location (e.g. greater than 30 days) or if there is any significant activity near the platform (e.g. construction), review with Production and the rig contractor to determine if another bottom sweep should be performed. A SIMOPs Checklist Memo (Section 3 - Appendix G-I) and review between appropriate EMDC Drilling Op. Supt. and EMPC Op Supt shall be completed prior to JUR mobilization for each JUR/Production drilling program. • If the decision is made to make any deviations from the guidelines set out in the SIMOPs manual, this may be accomplished by routing a SIMOPs deviation for approval by Production. A blank form is attached as Section 3 -Appendix G-II. A platform survey meeting will be held to discuss platform specific issues (e.g., moving stairways, moving cranes, process equipment protection near the cantilever, etc). This meeting should include a representative from EMDC Drilling, EMPC, and the rig contractor. 3.2 MOVING 3.2.1 MOVING – JACK-UP RIGS Prior to commencement of any marine movement operations it is imperative that a review of local regulations for notices be conducted to ensure the necessary permission has been obtained. This information can then be used to evaluate the potential impacts of exploration operations and identify mitigating options. Valid discharge and drilling permits, from state and or federal agencies, must be posted at the rig prior to the rig MIRU on location. Other permits DOCD, APD, MMS, and State O&G Boards’ “Plans for Exploitation” should also be available. The following general operational guidelines apply to the Jack-Up barge during preparation for and execution of transit operations. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 41 MARINE OPERATIONS 1. A marine procedure must be documented in accordance with the drilling contractor’s Marine Operation Manual. 2. Towing arrangements will be made well in advance. 3. Size and number of tow vessels required considering: • Government regulations • Contractor’s insurance requirement • Expected currents and weather • Distance of tow • Positioning requirements at the mobilization location and final drilling site. 4. Prior to initiating the move, inspection of all towing vessels shall include: • Towing wire and accessories • Tow winch • Tow rigging such as towing eyes, etc • Communications equipment (must include two separate systems) • General condition of the tow vessels 5. All equipment onboard must be properly secured prior to rig moves. Particular attention will be given to the BOP stack and tubular goods. 6. Jack-Up vessel stability calculations after loading Company and third party equipment. 7. Function test the jacking equipment. 8. Description and or map of tow route. 9. A contingency procedure will be in place for heavy weather including: • Pre-determined safe shelter location or locations along route. • Mitigating towing procedures such as slowing and turning into heavy weather. 10. In areas where applicable rig moves, should consider a “lump-sum” mobilization cost quote to be obtained from the drilling contractor and an economic analysis should be conducted to determine if EMDC Drilling will accept the lump sum proposal or choose to mobilize the JUR on dayrate. 3.2.2 MOVING – PLATFORM RIGS Prior to commencement of any marine movement operations it is imperative that a review of local regulations for notices be conducted to ensure the necessary permission has been obtained. This information can then be used to evaluate the potential impacts of drilling operations and identify mitigating options. Valid discharge and drilling permits, from state and or federal agencies, must be DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 41 MARINE OPERATIONS posted at the rig prior to spud. Other permits DOCD, APD, MMS, and State O&G Boards’ “Plans for Exploitation”. The following general operational guidelines apply to the platform during preparation for and execution of transit operations. 1. A marine procedure must be documented in accordance with the drilling contractor’s Marine Operation Manual. 2. A person designated by the project team conducts an onsite inspection to determine the preferred placement of all rig packages in relationship to pipelines, facility process equipment, drain systems, blowdown vent lines, and any other equipment that may be affected. 3. Towing arrangements will be made well in advance. 4. Crane barge arrangements will be made well in advance. 5. Check platform loading as it relates to the rig package equipment and secure Structural Engineering’s concurrence with the rig mobilization plan. 6. Review the proposed locations of living quarters, escape routes, diesel storage tanks, etc. and determine what fire protection is necessary. A load down sequence should be planned & documented to determine the sequence in which rig components should be loaded onto the platform based on priority. 7. Locate all fire protection equipment stations on the main deck, and assess the need to relocate. 8. Survey the platform’s firewater system to determine where a tie-in can be made to supply water to the rigs fire main, and that piping pressure design is compatible. Ensure that the platform’s firewater pumps meet the GPM requirements for that facility. 9. Inspect all main deck drains to ensure they are clear of any obstruction, and determine if any drains need to be isolated/modified due to the positioning of the rig packages. 10. A scale drawing depicting platform/rig equipment layout shall be developed highlighting the designated safe welding area, as well as areas in which Hot Work is prohibited. 11. Locate all incoming and outgoing pipeline risers, and determine what protection these require during the MIRU and drilling phase. 12. Ensure that a communication link is established between the barge and platform, particularly between the barge crane operator and those persons spotting equipment on the main deck of the platform. 13. Ensure that the contractor crane complies with the inspection requirements of API RP2D. Documentation of this inspection is required. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 41 MARINE OPERATIONS 14. Review critical processes (i.e., NGL/high pressure injection lines) and assess the need for special considerations in regards to emergency situations. 15. Review all electrical classifications applicable to the planned locations of the living quarters and rig components. 16. Inspect the platform’s diesel storage tanks, potable water storage, and various transfer pumps to determine if they meet the needs of the rig. If the platform has a helicopter refueling system, examine the piping and determine if the pump can be used if refueling station installation on the rig's heliport is required. 17. Inspect all deck grating, plating, and handrails and arrange for repair or replacement a needed. Examine the condition of any downcomers that may be installed for previously mobilized platform rigs, and assess whether they can be reused. 18. Size and number of tow vessels required considering: • Government regulations • Contractor’s insurance requirement • Expected currents and weather • Distance of tow • Positioning requirements at the mobilization location and final drilling site. 19. Description and or map of tow route. 20. A contingency procedure will be in place for heavy weather including: • Pre-determined safe shelter location or locations along route. • Mitigating towing procedures such as slowing and turning into heavy weather. 3.2.3 MOVING – BARGE RIGS Prior to commencement of any marine movement operations it is imperative that a review of local regulations for notices be conducted to ensure the necessary permission has been obtained. This information can then be used to evaluate the potential impacts of drilling operations and identify mitigating options. Valid discharge and drilling permits, from state and or federal agencies, must be posted at the rig prior to spud. Other permits DOCD, APD, MMS, and State O&G Boards’ “Plans for Exploitation”. The following general operational guidelines apply to the barge during preparation for and execution of transit operations. 1. A marine procedure must be documented in accordance with the drilling contractor’s Marine Operation Manual. 2. If historical data is absent, a soil bore sample may be analyzed in order to facilitate design/building of a rockpad. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 41 MARINE OPERATIONS 3. Surveying and dredging arrangements will be made well in advance. 4. Towing arrangements will be made well in advance. 5. Size and number of tow vessels required considering: • Government regulations • Contractor’s insurance requirement • Expected weather • Distance of tow • Positioning requirements at the mobilization location and final drilling site. 6. All equipment onboard must be properly secured prior to rig moves. Particular attention will be given to the BOP stack and tubular goods. 7. Description and or map of tow route and location of pipeline crossings and other facilities that could impact rig move. 8. A contingency procedure will be in place for heavy weather including: • Pre-determined safe shelter location or locations along route. 9. For barge rig moves the payment details should be specified in the drilling contract (i.e., dayrate or lump sum). 3.3 MOVING AND POSITIONING A procedure for moving and positioning at the drilling site shall include: Towing 1. A lead vessel and tow master will be clearly established. 2. Obtain weather from the weather service and/or surrounding rigs/vessels along the proposed tow path. Note: The tow is not to be undertaken if winds and seas are expected to exceed 25 knots and/or 5 feet at the mobilization location, the tow route, the final location, or during the final jack-up and pre-loading operations. The Rig Contractor's insurance requirements should be considered. 3. Attending tow vessels are to be attached by towing wires to the Jack-Up prior to the final jackdown. This operation should be carried out in good weather and in daylight when possible. GOM production JUR night move-in and positioning requires approval of appropriate EMDC and EMPC management through the SIMOPs checklist/review process and appropriate waivers/approvals from the MMS (if all pipelines are not adequately marked). 4. Actual draft, after all the legs are free of the sea bottom, will be compared to the calculated number to ensure stability calculations are correct. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 41 MARINE OPERATIONS 5. The crew must ensure that a continuous check is maintained on the draft of the hull during the tow. 6. All navigation lights on the rig will be operational. 7. The fog horn will be tested to ensure that it is operational. 8. A 24 hour watch will be maintained, during the entire tow, for shipping traffic and obstacles (buoys, platforms, etc.). Note: Specific individuals are to be assigned watch duty and such duty shall not be for more than 2 hours continuous without a break. Positioning A surface positioning system will be utilized to monitor the drilling rig's position as it is navigated onto the proposed location. The specific navigation procedure will be dependent upon the well location and will be specified in the Move-In Rig-Up Procedure. The final position of the drilling rig is to be verified after the legs have been pinned. The drilling rig's exact location, determined after an adequate number of satellites passes, is to be within the stated tolerance as specified in the MIRU procedure. For a rig cantilevered over an existing platform, the position will be deemed acceptable if the hookload requirement can be met after positioning the drill package over the appropriate slot(s). The drilling rig's heading will be specified in the Move-In Rig-Up Procedure drilling program or supplemental procedure. This will generally be determined by cantilever/rotary table accessibility of the desired well conductor slot on the production platform and the direction of the prominent winds and wave forces for the proposed location and time of year. Engineer will specify the maximum cantilever loads that will be available in the skidded- out position in the Move-in Rig-Up Procedure and confirm that these will meet maximum well design loads both before and after final JUR positioning. In a multi-well drilling program, the hookloads for all wells and positions must be acceptable. Factors such as crane position, workboat logistics, etc. may also affect the programmed heading of the rig. Note: Anchors will not be used to hold the Jack-Up barge on location prior to pinning the legs. Any use of anchors will require use of a detailed procedure and will necessitate an exception to the standard (approval of the Field Drilling Manager). 3.4 PRE-LOADING (JACK-UP ONLY) Prior to leg penetration of the sea floor (pinning), an inspection of the sea bottom may be carried out to ensure that pipelines, shipwrecks, spent armaments, and other debris are not present. This inspection may be included in the site survey if one is conducted. Prior to jacking-up to the predetermined work height, a pre-load must be applied. In general, preloading must be conducted consistent with the rig contractors and rig manufacturer's standard operating procedures. However, the following general guides apply as a checkpoint. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 41 MARINE OPERATIONS 1. The pre-load for the first cycle is to be applied with the bottom of the hull approximately 3-5 feet above the wave action line. Once the hull of the barge touches the wave action line during pre-loading, all of the ballast water is discharged and the Jack-Up barge can subsequently be jacked up to a 5 feet air gap above the wave action line. Continue pre-loading until the Jack-Up stands firmly with no subsidence. The final pre-load will be held for a minimum of 3 hours without further subsidence. 2. The preload requirements are to be in compliance with the Drilling Contractor's Standard Operating Procedure, typically at or near maximum loading. Note: Preload weights are to be included in the Core Jack-Up Move-In Rig-Up Procedure. 3. The actual leg penetrations are to be compared to the calculated values and previous Jack- Up rig positions at the same production platform, and, if significantly different, additional sea bed cores should be considered to determine the reason for the discrepancy and the actual sea bed integrity. 4. During jacking operations, the sea water tower must operational at all times, with the normal supply of sea water available in an emergency situation. 3.5 CARGO TRANSFERS Cargo Transfer Cargo transfer between supply vessels and offshore rigs/platforms represents one of the more hazardous undertakings in the offshore environment. A Back-Down Buoy when servicing a Jack-Up rig is recommended, especially during strong current/wind conditions. When setting a Back-Down Buoy, ensure that it is not set on a pipeline or other subsea hazard. Do not use a production platform to store drilling equipment without involving EMPC to ensure the structure can handle the planned load with acceptable safety factors. Guidelines in this section cover some of the major transferring operations. While there is no substitute for good common sense, Marine and Jack-Up rig personnel are to use these guidelines and good judgment to conduct transferring operations in a safe manner. A JSA (Job Safety Analysis) is required prior to all lifting operations. A JSA is mandatory for all blind lifts and personnel lifts. Definition: 3.5.1 Heavy lift is defined to be any lift greater than 10 (ten) MT. PRECAUTIONS Certification/Communication Guidelines JackUp Contractor is to have and provide: 1. Third Party certification for all Jack-Up cranes in accordance with API RP 2D. 2. Certification documents for all Jack-Up crane operators. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 41 MARINE OPERATIONS 3. All slings are to have been certified and marked as to their ratings inclusive of end termination and are to be re-certified every 6 months. 4. Crane hooks equipped with functioning safety latches, which are in good workable condition. 5. Crane operators who are properly trained and certified for Jack-Up work. 6. Good communications during all cargo-transferring operations (i.e., radio headsets, walkietalkie, etc.). 3.5.2 WEATHER LIMITS Cargo Transfer Weather Guidelines 1. A void general cargo transfers in heavy weather conditions, particularly heavy lifts. 2. Consider suspending drilling operations until weather conditions improve before transferring heavy cargo in heavy weather. 3. Only transfer small pieces of equipment, necessary to avoid suspension of operations, from a supply vessel in heavy weather conditions and only if the boat captain, DIM, and Operations Supervisor are all in agreement it is safe to do so. Note: "Snatch Lifts" are to be undertaken only with pre-slung lifts where a sling attached to the cargo can be attached to the crane hook. Shackling slings to cargo when the sling is attached to the crane is not permitted for snatch lifts. 3.5.3 HEAVY LIFTS (JACK-UP LIFTS IN EXCESS OF 10 MT) The following shall apply for heavy lifts: 1. Lifts in excess of 10 MT are to be supervised by an Operations Supervisor and the Contractor OIM or his designate. 2. Heavy lifts should be planned for daylight hours when possible. 3. Heavy lifts should have pre-slung, certified lifting slings and shackles. 4. Hold a coordination meeting for heavy lifts (i.e., over 10 MT) with the Crane Operator, Toolpusher, and Operations Supervisor present and discuss: • Type of rigging necessary. • Visual inspection of the rigging. • Signaling methods. • Overall plan for off loading and placement of lift. Note: The above applies to any lift means, i.e., crane, BOP trolley, or any other lifting device. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 41 MARINE OPERATIONS 3.5.4 LIFTING OPERATIONS Crane Operator Responsibilities 1. Operate cranes in a safe and reasonable manner. 2. Complete daily crane inspections and present complete inspection reports to supervisors. 3. Perform daily maintenance on cranes and rigging equipment. 4. Maintain good house keeping in cargo areas. 5. Use adequate and safe slinging arrangements. 6. Participation in crane inspections by Company Personnel. 7. Ensure good communications are used between the signaler and himself. 8. Obtain Work Permit for heavy lifts or any lift over platform facilities (if applicable). Lifting Guidelines 1. Handle cargo so that it remains visible to the Crane Operator whenever possible. 2. Use relay personnel in situations where cargo is not visible to Crane Operator (JSA Mandatory). Note: Crane Operator and the relay personnel are to have visual contact with each other and communications via radio (walkie-talkie). 3. Break down heavy lifts into smaller lifts if at all practical. 4. Hold a coordination meeting for heavy lifts (i.e., over 10), with the crane operator, toolpusher, and Operations Supervisor present and discuss: • Type of rigging necessary. • Visual inspection of the rigging. • Signaling methods. • Overall plan for off-loading and placement of lift. 5. Obtain approval from the Operations Superintendent and OIM before performing dual lifts (i.e., use of two or more cranes for a single lift). 6. Plainly mark all lifts over 1 MT at dockside prior to loading onto the workboat. 7. Keep loads vertically below the boom hook to avoid swinging as much as practical. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 41 MARINE OPERATIONS 8. Ensure that crane hook is vertically centered over a lift prior to lifting off of supply vessels picking up from rig decks. 9. Use tag lines on all lifts. 10. Attach loose slings to any load, which is not pre-slung on the supply vessel before connecting load to the crane hook. Note: The crane is not to support a sling while connecting the sling to the load. Note: The only exceptions are the use of pallet bars for off-loading pallets and casing hooks for off-loading casing. 11. Use a minimum of two (2) deck hands when handling cargo and attaching slings on the supply vessel. 12. Ensure that all personnel wear Life Vests/Jackets while on the vessel deck while transferring cargo from a supply vessel. 13. Take precautions to avoid binder slap back when removing chain binders on cargo from supply vessel. Note: Supply vessels will use chain binders to secure cargo and keep it from shifting during rough seas conditions. 3.5.5 RIGGING GUIDELINES Lifting Equipment Policy Proper equipment is to be used to off-load cargo (i.e., slings and shackles of adequate size, manufactured pallet bars and casing hooks, etc.). Off-Loading Policy Pipe bundles are not to be off loaded from a supply vessel under any circumstances if any of the following conditions exists: • • Pipe bundle has slings that have only a single wrap around the pipe bundle, Pipe bundle has short slings, which result in a crane hook angle of more than 30 degrees. • Pipe bundle has slings around the pipe bundle, which is more than 25% of the pipe length from the end of the pipe bundle. Sling Rigging Policy Slings that have a plastic covering are not to be used under any circumstances. Covering may allow corrosion to occur which can go undetected. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 11 of 41 MARINE OPERATIONS Tubular Off-Loading Guidelines Dependent on the size of tubular, utilize the following sling arrangements: • 30" Use only slings attached to shackles, 1 joint per lift maximum • 20" Use only casing hooks, 1 joint per lift maximum • 13-3/8" " Use only casing hooks, 2 joints per lift maximum • 9-5/87" Use only casing hooks, 2 joints per lift maximum • 5" Use either casing hooks or slings, 4 joints per lift maximum Use pre-slung, reasonable number of joints (or smaller) Note: Pre-slung bundles are to have two slings, each having two wraps around the pipe with a minimum of five pipe joints per bundle for sizes up to and including 5". Note: Pre-slung bundles for casing larger than 5" up to 7" casing is to have a minimum of four joints per bundle. Note: Do not pre-sling casing 7" and larger. General Rigging Guidelines 1. Use manufactured pallet bars to lift pallets (i.e., not styles made at the rig site.). 2. Lift a maximum of two pallets at a time and do not exceed 6 ft in height (i.e., total for two pallets). 3. Use slings with the same number of legs as the number of straps on the bags to lift big bags. Connect all bag straps individually to the sling legs. Note: Do not shackle together the bag straps on the same sling leg and do not lift a bag unless using all straps on the bag to share the load between straps. 4. Off-load only one bag per lift. 5. Leave bags that have damaged straps on the supply vessel. 6. Use a four-leg sling arrangement for lifting cargo containers and baskets. 7. Shackle each sling leg to the designated lifting padeyes on cargo containers and baskets. 8. Use slings, chains, and links that are adequate for the particular lift. 9. Use the Tables at the end of this section for additional information and specifications. • Table No. I - • Table No.2- Chain Sling Safe Working Loads Wire Rope Sling Safe Working Loads DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 12 of 41 MARINE OPERATIONS • Table No.3- • Table No.4-Installation of Wire Rope Clips Master Link Safe Working Loads Cargo Transportation Guidelines 1. Ensure cargo containers are the primary method for transporting drums. Drums should be placed on and secured to pallets inside of a cargo container for forklift capability. Note: Removing drums from a basket is difficult and hazardous. Note: In critical or emergency situations and if a cargo container is not available, sling only one drum at a time per lift using proper drum hooks. 2. Transport gas bottles (i.e., oxygen, acetylene, nitrogen, etc.) using a proper bottle rack which has a single point lifting padeye. Note: Do not transport loose gas bottles. 3. Only transport radioactive and explosive materials in proper containers that are made specifically for such material. Sling Rigging Guidelines 1. Calculate the safe working load of slings by dividing the catalog breaking strength of the lifting gear by a Safety Factor. 2. Use the following to determine which Safety Factor applies. Operation Safety Factor Wire Rope Slings 5.0 Chain and rigging tackle 3.5 Personnel baskets 10.0 3. Calculate the load per sling leg by dividing the total vertical load by number of slings then dividing again by the cosine of the lift angle (i.e., angle between slings at crane hook). 4. Ensure that the slings are of sufficient length so that the maximum angle between the slings at the crane hook is 60 degrees for containers, etc. and a maximum of 30 degrees for bundled pipe (i.e., 50 ft sling lengths for 40 ft pipe bundles and 40 ft sling lengths for 30 ft pipe bundles). Note: If the sling leg length equals or exceeds the horizontal distance between load attachment points (i.e., padeyes), the lift angle is 60 degrees or less. 5. Locate each sling leg a distance equal to 15 percent of the bundled pipe length when lifting a pipe bundle (i.e., 6 ft. from the end for 40 ft pipe joints). 6. Use wire rope slings. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 13 of 41 MARINE OPERATIONS Note: Wire rope slings break one strand at a time whereas chain slings break with little or no warning. Also, chains are less resistant to shock loading. 7. Use galvanized wire rope when possible. 8. Ensure that galvanized chain is not used in offshore environments as the strength deteriorates to some unknown value over time. 9. Use wire rope choker hitches that utilize a slip through or reeve eye thimble. 10. Only use sliding choker hooks that are of the safety latch design. 11. Do Not use a safety shackle through a soft-line eye to make a hitch connection. 12. Ensure that sling hooks as well as crane hooks have a fail safe hook latch. 13. Ensure loads engage fully about the throat of the hook and that point loading does not occur for the sling on the crane hook. 14 Use shackles that are either the screw type or pin-bolt-nut type. Note: Loads, which have permanently dedicated shackles, are to have a cotter pin outside the shackle nut. 15. Use casing hooks that are self-tightening with a pressure lock and manual release. Note: If open type hooks are necessary, use an interconnecting pull line longitudinally between the hooks. 3.5.6 EQUIPMENT MAINTENANCE Definition: Good maintenance is frequent inspection, cleaning, and lubrication of rigging equipment. Equipment Maintenance Guidelines 1. Maintain chains, wire rope, shackles, hooks and all other rigging equipment on a periodic basis. 2. Inspect all rigging equipment upon operation start-up and every 3 months thereafter. Slings must be recertified every 6 months. 3. Destroy any rigging equipment that has corrosion, excessive wear, stranded wires, or is in otherwise suspect condition. 4. Lubricate all rigging equipment during each inspection. 5. Ensure rigging equipment is clean and dry prior to the lubricant application. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 14 of 41 MARINE OPERATIONS 6. Apply proper lubricants correctly to rigging equipment. 7. Brush light oils directly on rigging equipment from the oil container. 8. Heat medium to heavy oils prior to applying to rigging equipment. 9. Use lubricants that do not contain metals (i.e., not used crankcase oil). 10. Use lubricants that are water repellent and have a good penetrating ability. 11. Consider a lubricant for slings, shackles, chains, etc. from the following list: • Rocal Rd 105 • Sea King Sk 620 • Advanced Lubricant Svcs. Esso Surett Fluin 4k • Rocal Rd 05 Aerosal Esso Rustban 395 • Esso Petroleum il 795 Mobil Oil Mobiltac 81 • British Ropes Britlube IOb/69b Wire Rope Guidelines 1. Lubricate wire ropes more frequently than just during inspections. Note: Wire rope is in need of a lubricant when the following characteristics are noted: • Creaking noise while the rope is spooling. • Breaking of wires in the valley of the rope without any indication of uniform strand nicking. Note: The following is an example of the strength reduction in "rust-bound" wire rope assuming the wire rope diameter remains constant (i.e., no reduction due to corrosion). • New 7/8", 6 x 36, IWRC wire rope with original lubrication Minimum breaking strength is 34 tons with 4.51 percent stretch. • Same wire rope in an unused condition but with mild corrosion Will break at approximately 22 tons with only 1.63 percent stretch. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 15 of 41 MARINE OPERATIONS TABLE NO. 1 WIRE ROPE SLING SAFE WORKING LOADS Galvanized, BS 6166:1981 Uniform Load Method/Extra Imp. Plow Steel (180 kgf/mm2) Maximum Lift Angle = 60 Deg. - (All wire rope 6x36 IWRC) Max. Safe Working Lds (Metric Tons) (Safety Factor = 5) - Max Safe Working Ld (Mt) Rope Dia. Single-Leg Two-Leg Two-Leg Four-Leg mm (in) Hitch Double Choker Hitch Hitch 9 (3/8") 1.0 MT 1.1 MT 1.4 MT 2.1 MT 13 (1/2") 2.1 MT 2.2 MT 2.9 MT 4.4 MT 16 (5/8") 3.3 MT 3.4 MT 4.6 MT 6.9 MT 19 (3/4") 4.6 MT 4.8 MT 6.4 MT 9.6 MT 22 (7/8") 6.2 MT 6.5 MT 8.7 MT 13.0 MT 26 (1") 8.6 MT 9.0 MT 12.0 MT 18.0 MT 28 (1-1/8") 10.0 MT 10.5 MT 14.0 MT 21.0 MT 32 (1-1/4") 13.1 MT 13.7 MT 18.3 MT 27.5 MT 38 (1-1/2") 18.5 MT 19.4 MT 25.9 MT 38.8 MT 51 (2") 34.8 MT 36.5 MT 48.7 MT 73.1 MT TABLE NO. 2 CHAIN SLING SAFE WORKING LOADS Heat Treated Alloy Steel (800N/mm2)-BS 6166: 1981 Uniform Load Method Max. Lift Angle = 60 Deg DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 16 of 41 MARINE OPERATIONS Max. Safe Working Loads (Metric Tons) - (Safety Factor = 4) Chain Dia Single-Leg Two-Leg Two-Leg mm (in) Hitch Double Choker Hitch Four-Leg Hitch 6 (1/4") 1.5 MT 1.6 MT 2.1 MT 3.1 MT 8 (5/16") 2.0 MT 2.1 MT 2.8 MT 4.2 MT 10 (3/8") 3.2 MT 3.3 MT 4.4 MT 6.7 MT 13 (1/2") 5.4 MT 5.6 MT 7.5 MT 11.3 MT 16 (5/8") 8.0 MT 8.4 MT 11.2 MT 16.8 MT 19 (3/4") 12.5 MT 13.1 MT 17.5 MT 26.3 MT 22 (7/8") 16.0 MT 16.8 MT 22.4 MT 33.6 MT 26 (1") 20.0 MT 21.0 MT 28.0 MT 42.0 MT 32 (1-1/4") 32.0 MT 33.6 MT 44.8 MT 67.2 MT Stock Diameter TABLE NO. 3 MASTER LINK SAFE WORKING LOADS Single Master Link Master Link Assembly (one or two sling legs) (three or four sling legs) Safety Factor = 6:1 Safety Factor = 3.5:1 13 mm (1/2") 1.8 MT -- 16 mm (5/8") 2.5 MT -- 19 mm (3/4") 3.9 MT 4.8 MT 26 mm (1") 9.2 MT 8.6 MT 32 mm (1-1/4") 13.3 MT 15.2 MT 38 mm (1-1/2") 18.1 MT 24.0 MT DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 17 of 41 MARINE OPERATIONS 45 mm (1-3/4") 23.6 MT 34.5 MT 51 mm (2") 36.9 MT 47.2 MT 57 mm (2-1/4") 45.1 MT -- 64 mm (2-1/2") 55.7 MT -- 70 mm (2-3/4") 67.4 MT -- TABLE NO. 4 INSTALLATION OF WIRE ROPE CLIPS Wire Rope Diameter Minimum No. Clips Rope Turn back From Thimble Torque 6 mm (1/4") 2 121 mm 2 kgm (15 ft-lb) 9 mm (3/8") 2 165 mm 6 kgm (45 ft-lb) 13 mm (1/2") 3 292 mm 9 kgm (65 ft-lb) 16 mm (5/8") 3 305 mm 13 kgm (96 ft-lb) 19 mm (3/4") 4 457 mm 18 kgm (130 ft-lb) 22 mm (7/8") 4 483 mm 31 kgm (225 ft-lb) 25 mm (1") 5 660 mm 31 kgm (225 ft-lb) 29 mm (1-1/8") 6 864 mm 31 kgm (225 ft-lb) 32 mm (1-1/4") 6 940 mm 50 kgm (360 ft-lb) 38 mm (1-1/2") 7 1219 mm 50 kgm (360 ft-lb) 51 mm (2") 8 1803 mm 104 kgm (750 ft-lb) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 18 of 41 MARINE OPERATIONS 3.6 TRANSPORTATION & PERSONNEL TRANSFERS Transportation & Personnel Transfer Foreword This section contains guidelines for transporting cargo and personnel to and from offshore sites. For more detailed guidelines when transferring personnel from an offshore facility, refer to EMPC Safety Manual. Safety of personnel is the primary objective when moving personnel and cargo offshore. When there is doubt about any aspect of personnel safety, transfers must not occur until the hazard(s) causing the doubt are eliminated or effectively managed. For most operations, helicopters will be the preferred means of transporting personnel between Shore Base and the rig. Supply vessels may be the primary means on some operations and may be used on other operations if weather conditions prohibit helicopter flights. Transfers should only be made during calm sea conditions (i.e., 5 feet or less). 3.6.1 CARGO TRANSPORT Supply Vessels 1. Coordinate the loading and unloading of the supply vessels at the base through the Materials Supervisor. 2. Notify the Materials Supervisor of the cargo type and the expected arrival time to ensure efficient handling of equipment and tools at the Base. 3. All returned material must be shown on a Material Transfer Cargo Manifest (MTCM) and sent on the supply vessel with the materials showing the following information: • Description of Item • Condition of Item (1 -New, 2 -Used, 3 -Needs Repair,4 - Junk) • Owner of Item (Affiliate or Contractor Name) • Disposition of Item (return to stock, return to Contractor, repair) Note: Any hazardous cargo is to be clearly marked as such on both the MTCM and the item container. Note: Separate MTCMs should be used for different material owners, i.e., rental tools to be returned to different Contractors should be shown on separate manifests. 4. All cargo on supply vessel decks departing the base shall be secured. 5. Weather permitting, all cargo on supply vessel decks departing from offshore shall be secured. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 19 of 41 MARINE OPERATIONS 6. Vessels shall have gates across their stem at all times except when handling anchors or setting out buoys. 7. No individuals shall be allowed on the deck of supply vessels while the vessel is underway or standing by when there is cargo on deck. 8. Tubulars 5" and smaller shall be pre-slung in appropriate numbers per bundle both outbound and inbound. Helicopters 1. Transport of cargo via helicopters is limited to small lightweight items unless critical to the operation. Proper approvals must be in place prior to transporting any cargo other than small lightweight items. Typically, procedure/equipment used for airlift of heavy, non- standard items will require consultation with Aviation Department contact and Field Drilling Manager. 2. Potentially hazardous material such as batteries, paints, acidic or corrosive chemicals, etc. are not to be transported via helicopter. 3. An accurate cargo and weight manifest for all helicopter transportation, including passengers, must completed prior to boarding (OIMS Manual Element 6). 3.6.2 HELICOPTER OPERATIONS Helideck 1. Pilots are to lock brakes while on the helideck if the helicopter has wheels. 2. Helideck is to have rope mats or non-skid surface. Note: Rope mats must be of the proper size to avoid entanglement of helicopter skids/wheels. 3. Rope mats must be securely tied down. 4. Helideck must be marked clearly with landing circle and have the location name clearly visible from the air. Landing & Takeoff 1. Only the Jack-Up helideck shall be used for helicopter operations. Any exception to use the platform's helideck must be cleared with Operations Superintendent & Production. 2. All cranes are to be shut down 10 minutes prior to landing/takeoff (OIMS Manual Element 6). DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 20 of 41 MARINE OPERATIONS 3. Supply boat/standby boat should be off anchor and ready to respond during landing and departing. 4. Fire stations are to be manned with a trained fire team ready to respond whenever a helicopter is landing, refueling, or departing, and during engine startup/shutdown. (OIMS Manual Element 6). 5. Helideck is to be cleared of all arriving/departing passengers and/or cargo prior to moving passengers and/or cargo onto the helideck for boarding. 6. Notify Shore Base of Helicopter arrivals and departures. (OIMS Manual Element 6). Note: Shore Base is responsible for the "Flight Tracking System". (OIMS Manual Element 6). 7. Trained personnel shall be designated to initially approach helicopters after landing to open and shut the helicopter's doors and then only after receiving permission from the pilots. 8. An announcement shall be made of all helicopter landing/departure on the rig's public communication system (OIMS Manual Element 6). Refueling -Emergency Situation Only 1. Shut down the helicopter, clear the helideck of all non-essential personnel and man the helideck fire fighting equipment during refueling operations. (OIMS Manual Element 6). 2. Only use approved refueling equipment. 3. Pilots are to personally: • Supervise the refueling operation. • Test fuel for water and sediment immediately prior to refueling. • Ground helicopter with an approved ground wire during refueling operations. 4. All refueling equipment is to be maintained in excellent condition. 5. Helideck fire fighting systems will be manned during refueling operations (OIMS Manual Element 6). 3.6.3 PERSONNEL TRANSPORT-HELICOPTER Scheduling & Manifests (OIMS Manual Element 6) 1. A fax will be sent to the Shore Base Dispatcher the day before flights, except in emergencies, listing; DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 21 of 41 MARINE OPERATIONS • Passengers names • Company Affiliation • .Weight of Passenger and Baggage 2. Offshore bound fax lists will be sent from the Shore Base and shore bound fax lists will be sent from the offshore site. 3. Manifests will accompany all flights listing the passengers and their Company; (OIMS Manual Element 6) a. Outbound Flights: Manifest will be prepared by Shore Base Dispatcher and a copy given to the offshore site dispatcher upon arrival of the helicopter. b. Inbound Flights: Manifest will be prepared by Offshore Site dispatcher and given to the helicopter prior to its departure from offshore. 4. Helicopters are not to be scheduled at night unless a medical emergency exists (some geographic night flights may be necessary due to limited daylight hours). Responsibilities Helicopter Passenger 1. Approach the helicopter from the 3 or 9 o'clock position only after directed by the pilot. 2. Wait for escort at rig/shorebase prior to embarking/disembarking. 3. Walk as close to the nose of the helicopter as possible when crossing in front of the helicopter paying attention to pivot tubes which may be hot. 4. Never walk under the tail section or around the rear of the helicopter. 5. Wear PFD's or inflatable life jackets while on the helicopter when flying over water. 6. Fasten seat belts before takeoff and keep seat belt on until the helicopter arrives at its destination. 7. Never move about the cabin when the helicopter is in flight. 8. Be certain that the helicopter landing is complete before unfastening the seat belt. 9. Do not smoke any time while on or near the helicopter. Helicopter Pilot 1. All passengers will be given a safety orientation/ditching instructions prior to boarding helicopters at the shore base location. (OIMS Manual Element 6) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 22 of 41 MARINE OPERATIONS 2. Instruct passengers to remain on board until the rotor blade is at a complete stop if shutting down the helicopter. 3. Load and unload passengers with the rotor blade in motion only after announcing to the passengers that the helicopter will not shut down and to proceed with caution. Offshore Installation Manager 1. Ensure passengers sign in and record body weight and luggage. 2. Ensure manifest is complete. (OIMS Manual Element 6) 3. Ensure personnel meeting helicopters (i.e., fire teams and dispatchers) are trained personnel, properly organized, and in position prior to helicopter arrival/departure. 4. Ensure that a public announcement is made prior to all helicopter landing/departures. (OIMS Manual Element 6). 3.6.4 PERSONNEL TRANSPORT -SUPPLY OR STAND-BY BOAT In general, the preferred method of transport, even in an emergency, is via helicopter. However, when boats are used, a JSA should be prepared and reviewed with all personnel prior to boarding. 3.7 MARINE TRAINING 3.7.1 GENERAL Marine Drill Objective The objective of marine drills on a mobile offshore drilling unit is to train all on- board drilling contractor personnel (i.e., night and day crews) to respond appropriately when faced with an emergency situation. An equally important objective is to train and ensure that all other on-board personnel (typically temporarily or transient to the rig) how to identify emergency signals, how to respond, and how to safely evacuate. General Marine Training Guidelines 1. Ensure that each drill demonstrates crew's ability to respond to an emergency and correctly operate required safety equipment. 2. Schedule drills to allow full participation of crews while minimizing interference with drilling operations. 3. Plan drills, which simulate realistic emergencies and demonstrate necessary steps to mitigate a real emergency. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 23 of 41 MARINE OPERATIONS 4. Ensure that each drill crew member understands their emergency designated assignment for drill scenario (i.e., securing well). 5. Walk through drills and coach key personnel as necessary to ensure crew is familiar with their designated assignments and that all others know signals, muster points, and evacuation procedures. 6. Utilize announcements over public address system as necessary. 7. Hold a discussion session after completing drill and critique areas for improvement. 8. Each drill, including a group discussion and critique, should take approximately one hour. 3.7.2 REPORTING & DRILL FREQUENCY Reporting 1. Record all drills on Daily Drilling Report. 2. Record all drills on Daily IADC Report. 3. Forward a Marine Emergency Drill Report Form to the Operations Superintendent. Note: See the "Blank Form" in this manual (Section 3 -Appendix G-III) for the Marine Emergency Drill Report Form. Marine Drill Frequency 1. "Fire Drills" -Initial drills as required to plan and organize Fire Fighting Squads and weekly thereafter. Note: Conduct fire drill during hours of darkness and/or hold drill without priors notice to crew once every month. 2. "Abandon Rig Drills" -Frequently until all personnel know their stations and the abandonment procedure and muster checks are satisfactory (i.e., all personnel report to muster points). Conduct the drills weekly thereafter. Note: Conduct" Abandon Rig Drills" during hours of darkness and/or hold drill without prior notice to crew once every month. 3. "Man Overboard Drills" -Initially as required to plan and organize Response Teams and every two weeks thereafter. Note: Conduct man overboard drill during hours of darkness and/or hold drill without prior notice to crew once every month. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 24 of 41 MARINE OPERATIONS 4. "Specialized Drills" -As required to train designated response teams to ensure team members are proficient at their assigned duties. This type of training does not in itself satisfy the requirement for weekly drills since only part of crew participates. It is, however, valuable in developing a well-trained crew. Note: Hold Fire Drill and Abandon Rig Drill concurrently as a weekly drill when practical. Note: Conduct training in the use of rescue equipment and assignment of duties in lieu of man overboard drills on days of inclement weather. 3.7.3 MARINE DRILL PROCESS Marine Drill Process Plan Drill: Carefully plan drills to focus on training for a particular need. Conduct Drill: Realistic drills simulate an actual condition and require crews to perform as though an actual emergency situation existed. Critique Drill: Discussion: session will identify problem areas and help identify areas for improvement. Marine Drill Planning Guidelines 1. Design each drill to emphasize a single aspect of responding to an emergency situation. This should increase the chance of this aspect being recalled during an emergency. 2. Emphasize the principal aspects listed in Section 3.7.1 during the drills. 3. Choose appropriate location to emphasize a particular aspect during drill. 4. Write down scenario for the drill and distribute to the various team leaders. 5. Follow through with planned drill trying not to change conditions of the drill 6. Vary day and times of drills to ensure that all crew members are prepared to react efficiently to a real emergency. 7. When practical, plan safety meeting to follow a drill to encourage discussion of drill. Marine Drills Guidelines 1. Avoid exposing crew or Jack-Up to situations that may place them in jeopardy. For example, do not use toxic gases when training crew members in the use of selfcontained breathing apparatus nor start fires to test fire fighting system. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 25 of 41 MARINE OPERATIONS 2. A void placing crew in high risk situations; however, avoiding all risk should not be the basis for failing to test some safety equipment. For example, launching lifeboats in mild seas can entail some risk; however, this risk is acceptable since operating this equipment increases the chance of successful deployment in a real emergency. Critiquing Guidelines Ensure that key supervisory personnel critique drill and lead a discussion, which focuses on the principal aspect of drill immediately following all drills. All Jack-Up personnel should be encouraged to participate in the discussion session following a drill. Critique and discussion sessions should: 3.7.4 • Review the emphasis of drill. • Discuss problems, which occurred during drill. • Assess whether drill focused on the particular aspect as planned. Determine if drill was conducted in realistic manner. • Discuss situations that could have developed if this had been a real emergency situation. • Establish agreed upon areas for improvement that need practice during future drills. FIRE DRILLS Purpose of Fire Drill Prepare Response Teams (i.e., Fire Fighting Squads) for mitigating a fire and rescuing injured and/or trapped personnel. Also, demonstrate that members of the Fire Fighting Squads understand their designated assignments and perform them in an acceptable manner. Fire Fighting Squad Members • One (I) Fire Fighting Squad leader • Four (4) Fire Fighters Fire Drill Guidelines 1. A five person Fire Fighting Squad is to be organized for each 12-hr shift. 2. Each member of Fire Fighting Squads must have on the job training. 3. The Fire Fighting Squad Leader must have completed a fire fighting training course. 4. Assign the on-board medic to a Fire Fighting Squad as practical. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 26 of 41 MARINE OPERATIONS 5. One member on each Fire Fighting Squad is to be appointed assistant Squad leader. 6. Off-duty personnel should participate in this drill when feasible. 7. Conduct an unannounced fire drill and/or night drill once every month 8. Drills should include a mock injury and/or a rescue situation. 9. Occasionally designate the Squad leader as the injured person during a rescue situation so that assistant Squad leader is leading the Fire Fighting Squad. 10. Fire locations should be varied. Fire Drill Procedure The following steps constitute an effective fire drill: 1. The observer of the fire should sound the alarm and advise the facility of the location of the fire. 2. The Person In Charge (PIC) or his delegate should immediately go to the pre-designated command center (e.g., radio room, bridge, control room, etc.). 3. The rig communication equipment and procedures are to be tested by alerting designated shore base that a "fire drill" is in progress. 4. The Fire Fighting Squads are to muster at the scene of the fire. 5. The Person In Charge (PIC) or his delegate will notify the drill crew to secure the well and activate the Emergency Shut Down (ESD)/Deluge system. 6. Drill crew secures well (i.e., when drilling/tripping, position pipe to well shut-in position and close BOP except when in open hole). 7. Mobilize a stand-by boat or supply vessel, if available, to a standby position. 8. Communicate reports during each phase of drill to designated "command center" 9. All personnel not involved in fighting the fire or in critical rig operations are to muster at their designated muster stations. 10. A muster shall be taken to ensure that all personnel are accounted for and the results reported to the Person In Charge (PIC). 11. The Fire Fighting Squad response is to include a simulation of actions necessary to mitigate the fire if an actual emergency was in progress. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 27 of 41 MARINE OPERATIONS 12. Squad leader is to communicate hazardous material situations to Person In Charge (PIC) or his delegate. 13. Designated personnel are to standby for action necessary to support Fire Fighting Squad. This will include such duties as stretcher bearers, etc. 14. Post a fire watch after fire is out to guard against ignition. 15. Person In Charge (PIC) is responsible for de-watering operations and monitoring standby vessel throughout fire fighting operations. 16. Squad leader is to prepare a critique after fire drill and hold a discussion session. 17. Complete the Drill Report and forward to the Operations Superintendent. 3.7.5 FIRE DRILL -EXAMPLE SCENARIO DATE/TIME: 4-25-84/0030 LEVEL: Serious LOCATIONS: Cementing Room FIRE: Class B w/heavy smoke INJURED: No.2 EMPHASIS: Effective search for missing crew members. FIRE SCENARIO: Leaking fuel line sprays diesel on manifold causing fire to engulf engine. Two operators seek refuge in office whose only exit is on fire. LOCATION: Trapped in space near fire CONDUCT SOUND ALARM - Sound Alarm - Announce Drill -Fire location. - Check Communications. Call shore base & boats. ASSEMBLE - Unassigned crew to muster at assigned areas. - Call Roll at Jack-Up abandonment stations. - Notify Person In Charge (PIC) of anyone missing from roll. - Fire crew to assemble near fire area. INVESTIGATE - Assigned fire team member to check fire area. - Brief fire team on fire conditions. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 28 of 41 MARINE OPERATIONS RESTRICT RESCUE Call for rescue party -include medic. - Fire Crew to contain fire to allow rescue of injured. - Rescue crew to move injured to safe area. - Medic to attend injured personnel. EXTINGUISH - Deploy fire teams to extinguish fire. - Extinguish Fire. CRITIQUE DISCUSS - Assemble all supervisors and fire fighting squad. - Discuss objective of drill - was it accomplished? - Discuss any procedure or equipment problems. REPORT - Complete Drill Report and send copy to office. - Document drill in IADC and Daily Drilling Report - 3.7.6 Forward Drill Report to Operations Superintendent. ABANDON RIG DRILLS Purpose of Abandon Rig Drill Ensure that rig personnel can perform their assigned duties and demonstrate operation of lifeboats and associated equipment and that all on-board personnel (especially non-Rig contractor personnel) know how/when to safely muster and evacuate. Minimum Life Boat Complement: • One (I) Boat Commander -Certified as Commander • One (I) Release Mechanism Operator -Certified as Life Boatman (Coxswain) • Two (2) other crew members -Certified as Life Boatman (Coxswain) • One (I) Electrician or Mechanic -Operate the life boat winch In order to assist in reconnection of lifeboat lowering lines after drill is complete and to assist in correcting unforeseen mechanical problems, this is the minimum complement required for drill launching. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 29 of 41 MARINE OPERATIONS Abandon Rig Drill Guidelines 1. Ensure that rig radio frequencies, rig location, and headings to safe refuges are posted in each lifeboat. 2. Occasionally hold drill without prior notice to crew. 3. Partially lower (i.e., 10-15 feet) all lifeboats once each week, weather permitting. 4. Launch lifeboats, navigate in open water, and retrieve monthly if possible but at least once per quarter. 5. Only launch lifeboats during reasonable weather/sea conditions and when a supply/standby vessel is prepared to rescue if necessary. 6. Conduct an unannounced abandon rig drill and/or night drill once every month, and at least once per month, the drill should include a mock injury or a rescue situation. 7. Personnel are not required inside lifeboat while partially lowering and raising. 8. Test engine and sprinkler system on lifeboats weekly when water can be supplied. 9. Do not lower a lifeboat into water until engine(s) is running. 10. Ensure that a minimum of four (4) men are in lifeboat when launched. 11. Man lifeboat winches with qualified individual (e.g., rig electrician or mechanic) during launching and recovery of the lifeboats. 12. Simulate securing the well and activating the rig ESD/Deluge system. The following steps constitute an efficient Abandon Rig drill: 1. Ensure that a supply/stand-by vessel is moved to the vicinity of lifeboat landing area prior to lowering lifeboat if actual launching is to be conducted. 2. Sound designated alarm for abandon rig. The type of alarm is on rig station bills in numerous locations. Announce that this is a drill over public address system. 3. Rig communication equipment and procedures are tested by alerting designated shore base that a "Lifeboat Launching Drill" is in progress. 4. All personnel are to report promptly to their station bill assignment and collect their abandonment cards from the card holder unless excused to continue operations. Excuses require prior approval of the Operations Supervisor and are by exception only. 5. All personnel are to wear appropriate attire and carry survival gear to drill (i.e., either life jacket or survival suit depending on environment). DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 30 of 41 MARINE OPERATIONS 6. Life Boatmen prepare Life Boat for boarding (i.e., attach grips and safety pendants), 7. Personnel enter Life Boat following instructions by Boat Commander and fasten their seat belts immediately. 8. Persons whose cards remain in the cardholders at the abandonment stations are located. 9. Radio contact is made before launching and maintained at all times on a predetermined clear frequency between Boat Commander and Person In Charge (PIC) or his delegate who has overall charge of drill. 10. Engine(s) is started and operated for several minutes. 11. Boat Commander is to explain the operation and lowering procedure. 12. If NOT LAUNCHING the Life Boat, all personnel aboard the Life Boat are to exit in an orderly fashion and muster for drill discussion. 13. If LAUNCHING the Life Boat, all personnel aboard the Life Boat except the "Minimum Life Boat Complement" are to exit in an orderly fashion and muster for drill discussion. 14. Boat commanders are to ensure a clear landing area below lifeboat before lowering. 15. Once lifeboat leaves davits, no one other than the Boat Commander shall do anything to affect lowering of lifeboat. 16. The order to release lifeboat from lowering lines shall not be given by anyone other than the Boat Commander and shall not be given by him until he ensures by visual means that lifeboat is waterborne. 17. Boat Commander will release and maneuver lifeboat away from rig to a pre- designated rallying point. As practical, operate all equipment to ensure proper functioning. 18. Boat Commander is to maneuver lifeboat along side of rig, attach lowering line hooks to lifeboat. 19. Raise lifeboat back up to davits and secure before personnel exit lifeboat. 20. Boat Commander is to conduct a verbal critique with his crew upon completing drill. Discussion should focus on areas for improvement and alternate abandonment procedures. 21. Person in charge is to critique drill with Boat Commanders. 3.7.7 ABANDON RIG DRILL -EXAMPLE DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 31 of 41 MARINE OPERATIONS SCENARIO DATE/TIME: 4-25-84/0030 LEVEL: MAJOR LOCATIONS: Aft lifeboats FIRE: None INJURED: No. 0 DAMAGE: Forward lifeboat inoperable EMPHASIS: Orderly abandonment with one lifeboat damaged. SITUATION: Storm has damaged forward lifeboat and vessel is listing. Abandonment must utilize aft lifeboat and two life rafts. LOCATION: CONDUCT SOUND ALARM - Sound Alarm. - Announce forward boat not operable. - Check Communications. Call shore base/boats. ASSEMBLE - Muster at aft boat area. - Board Life Boat shifting fwd crew to rafts. - Call Roll. - Search for persons missing from roll. LAUNCH BOATS (Simulate) - Instruct on Launching Boats. - Operate All Equipment. - Start Engine. - Instruct on Alternate Abandonment. LAUNCH BOATS - Disembark all personnel except life boat crew (4). (Actual) - Station Electrician at winch. - Launch lifeboat. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 32 of 41 MARINE OPERATIONS CRITIOUE DISCUSS - Assemble all supervisors and lifeboat commanders. - Discuss objective of drill -was it accomplished? - Discuss any procedure or equipment problems. REPORT - Complete Drill Report and send copy of office. - Document drill in IADC and Daily Drilling Report. 3.7.8 MAN OVERBOARD DRILL Purpose of Man Overboard Drill Ensure that rig personnel can perform their assigned duties when someone goes into water. Rescue Team Members: • One (I) Rescue team leader • One (I) Rescue Boat Commander • One (I) Rescue Boat Release Mechanism Operator (Coxswain) • Two (2) other crew members who are qualified Coxswains • One (I) Electrician or Mechanic to operate rescue boat winch Man Overboard Drill Guidelines 1. Organizes a (6 man) Rescue Team for each crew. 2. As practical, assign the rig medic to one of the Rescue Teams. 3. Plan drills to emphasize key point(s) or areas for improvement. 4. Only launch rescue boat during reasonable weather and sea conditions when a supply/standby vessel is prepared to rescue if necessary. 5. Conduct an unannounced man overboard drill and/or night drill once every month, and at least once per month, the drill should include a mock injury or a rescue situation. Man Overboard Procedure The following steps constitute an efficient Man Overboard drill: 1. To simulate a man overboard, throw buoyant dummy into water that is the approximate size, shape and weight of a man. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 33 of 41 MARINE OPERATIONS 2. Pass the words "Man Overboard" upon throwing dummy overboard. 3. Post a look-out(s) at the best point possible with binoculars whose sole responsibility is to keep sight of the person overboard, as long as possible, and continually point toward him. 4. Rig communications equipment and procedures are tested by alerting designated shore base that a "man overboard drill" is in progress. 5. Throw a life ring in the vicinity of man overboard (i.e., buoyant dummy) as soon as practical. Periodically, use lights and smoke flares to add realism to drill. 6. Person in charge is to muster Rescue Team at rescue boat. The rig medic is to provide first aid to man overboard. 7. If a supply or stand-by vessel is available, notify vessel for assistance. Vessels are to deploy scramble nets as soon as practical. 8. If retrieval is possible by crane, crane operator is to lower a personnel basket with two crew members, wearing lifejackets, to retrieve the man overboard. 9. When weather permits, launch rescue boat and retrieve Man Overboard. Ensure that the Electrician or Mechanic is operating the rescue boat winch on the rig. In this scenario, assume individual(s) are not able to assist themselves and determine the suitability of retrieval tools and techniques to recover an injured or unconscious individual after going overboard. Assess suitability of technique if weather conditions were significantly worse. 10. If rescue boat is not launched, retrieve Man Overboard dummy with supply/standby vessel. 11. Muster entire crew to a pre-designated location. Perform roll call to determine the number and names of missing crew member(s). Report results to person in charge. 12. Upon completion of drill, make appropriate log entries including the time required to recover the man overboard. 13. Rescue Team Leader is to prepare a critique and hold discussion session with the Rescue Team and rig Personnel. 3.7.9 SPECIALIZED DRILLS Purpose of Specialized Drill Involve response teams and/or small groups of crew in specialized training so that training can focus on specific skills in areas that need improvement and develop effective response teams. Some examples of the types of skills suited to this training are: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 34 of 41 MARINE OPERATIONS • Life boat Launching -Small number of the crew launch and operate the boat. • Rescue Operations -Rescue Teams practice man-overboard drill or rescue or fire victim. • Helicopter Fires -Fire Fighting Squad tests foam systems for a helicopter fire. • Ballast Control -React to failed equipment. • Specialized Fires -Fire Fighting Squad practices mitigating a fire in an enclosed space using breathing equipment. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 35 of 41 MARINE OPERATIONS 3.7.10 PRINCIPAL ASPECTS OF DRILLS Drill scenarios should empathize skills listed below. Fire Drills: Abandon Rig Drills: Coordinating communication Coordinating communication Coordinating Fire Fighting Squads Abandoning -one lifeboat disabled Coordinating Rescue Teams Abandoning -escape routes blocked Handling Complex Fire Situations: Operating lifeboats in a sea lane • Enclosed spaces Muster & personnel accountability • Limited access Man Overboard Drills: • Combination of the above • Fighting different fire types Initial response for man overboard • Injured personnel Using life boats and rescue boat Use of Equipment such as: Administering first aid • Breathing Equipment Coordinating Communications • Stretchers Coordination of other craft in the area • Fire hoses • Radios 3.8 Posting and maintaining lookout SHIP COLLISION AVOIDANCE Ship Collision Avoidance Foreword Drilling Units should not be located near a shipping lane nor between shipping lane boundaries if possible. If necessary, directional wells can be drilled to avoid these areas. If a Drilling Unit must be stationed in such an area, the risk assessment for the operations must include the proximity of the Drilling Unit to ship traffic areas. All proposed Drilling Unit locations should be researched for shipping lane proximity and traffic in the area and appropriate "Detection Procedures" prepared and risk assessments completed. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 36 of 41 MARINE OPERATIONS The only way to avoid collisions is to spot errant ships early and issue warnings. Procedures and guidelines described below should be followed. 3.8.1 DETECTION General Detection Guidelines -For MODU in or near shipping lane All personnel on-board the Drilling Unit are responsible for vigilance in detecting errant ships approaching the site. However, the level of formal detection program implementation will depend on the proximity of the Drilling Unit to shipping lanes and/or heavy ship traffic. There are many "unofficial" shipping lanes used by ships as short-cuts and some detection program is always necessary. 1. Ensure all radar reflector beacon systems are functional at all times. 2. During foggy conditions, post a radar watch on the Drilling Unit. 3. Continuous 24-hour radar watches and/or standby vessels should be used when in the vicinity of high ship traffic and shipping lanes. 4. Radar watch and/or standby vessel watch procedures when operating in close proximity to ship traffic should be completed and approved by the Field Drilling Manager to include; • Action plans for different approach radar and ship course headings. Ship notification plans • Abandonment procedures 5. Ensure that all navigational aids (lighting and foghorns) are operational. 6. Advise all Drilling Unit personnel during Safety Meetings to be on the lookout for approaching ships. 7. Immediately notify the Offshore Installation Manager after spotting questionable ships or vessel approaching 8. A sonar pinger will be installed and operational at all times once the rig is positioned. 3.8.2 RADAR WATCH PROCEDURES In areas of high risk, i.e., near shipping lanes or heavily traveled routes, radar procedures described below should be implemented on the drilling unit. Radar Operation 1. The Drilling Unit's radar installation is to be located: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 37 of 41 MARINE OPERATIONS • In an area providing visual contact with the surrounding outside seas, i.e., bridge, etc. • Away from heavily traveled and noisy areas, i.e., not to be located in a radio room. Near VHF Marine radio. 2. Qualified and trained radar operators are to man the radar station 24 hours per day and be relieved by qualified marine personnel at least every 3 hours for breaks. 3. Radar unit settings shall be maintained as follows: • Primary scanning set to 12 nm. • Audio alarm set for 5 nm. • Inner Guard Ring set for 2 nm. 4. Radar Watch Operator's duties shall include: • Continuously man the radar station except when relieved for breaks. • Maintain radar unit settings described above. • Track all ships within a 12 nautical mile range and determine their course heading. • Contact ships reaching 5 nautical mile range of Drilling Unit's position and request ships maintain 2 nautical mile separation. • Maintain logbook of all contacts with ships. Alert Procedures 1. Ships within the 12 nautical miles primary radar range will be marked with the "EBL" by the Radar Operator who will track the vessel heading and determine the course heading. 2. Ships reaching the 5 NM range will be contacted by the Radar Operator: Radio Contact Established • Verify the vessel crew is aware of the Drilling Unit installation's position. • Confirm that the vessel is not in mechanical difficulty. • Request the vessel maintain a 2 nautical mile separation from the Drilling Unit. Radio Contact Not Established DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 38 of 41 MARINE OPERATIONS • Radar Watch Operator will notify the Offshore Installation Manager (OIM). • OIM will dispatch supply/standby vessel to attract the ship's attention (e.g., fire hose, ships horn, radio). 3. Ships reaching the 4 NM range and on a course: Radar Watch Operator • Notify the OIM. Offshore Installation Manager • Contact the vessel to divert its course and/or determine if ship has mechanical difficulty. • Notify the Operations Supervisor on duty that a collision is possible. • Notify supply/standby vessel to intercept ship. 4. Ship reaching the 4 NM range and on a collision course which cannot be contacted and/or has mechanical difficulty (engine/steering failure): Offshore Installation Manager • Notify supply/standby vessel to return to rig if ship cannot be intercepted. • Notify the Operations Supervisor on duty. • Sound alarm and muster rig personnel at their abandonment stations. Operations Supervisor • Notify Drill Crew to secure the well. • Notify Shore Base that a collision is possible and imminent. 5. Ships reaching the 2 NM range radar guard ring on a collision course: Offshore Installation Manager • Determine need for abandonment. • Sound the abandonment alarm for the Drilling Unit. • Broadcast navigational warnings continuously. • Notify supply/standby vessel to assist in rig abandonment. • Abandon rig. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 39 of 41 MARINE OPERATIONS SECTION 3 - APPENDIX G-I MEMORANDUM ExxonMobil Development Co. Drilling DATE: TO: FROM: SUBJECT: PRODUCTION AND DRILLING OPT. SUPTS OFFICE ENGINEERING TEAM " " Platform Drilling Program SIMOPS/MIRU Meeting BACKGROUND The jack-up drilling rig is scheduled to begin operations at the " " Platform on about . On , a SIMOPS meeting was held to evaluate the risks involved with simultaneous drilling and production operations at the platform. Following is a summary of the review of the SIMOPS Move-In/Rig-Up Checklist for Jack-Up Drilling Rigs. SIMOPS MIRU CHECKLIST REVIEW 1) A mudline survey with divers and/or side scan sonar may be necessary to check for any obstacles or debris that might be in the immediate area where the rig is to be positioned. Determine if area pipelines need to be buoyed for the planned approach of the rig. At those platforms where a jack-up rig has previously operated, the footprint of the rig is to be studied to determine if it can be reused. (NOTE: The side scan sonar is typically performed if a jack-up rig has not been at the location within 12 months, or if any substantial construction or workover work has been performed within the last year). Note, if any pipelines are within 490 ft of the rig, the MMS requires buoys, unless a waiver is obtained. Global positioning is usually sufficient to obtain a waiver unless the spud cans are very close (~50 ft) to the pipeline. • 2) Evaluate the punch-through potential of the rig legs. • 3) Evaluate the platform leg batter and positioning of dolphins for potential interference with rig legs. Drilling/Subsurface engineering will provide scale drawings of the rig, spud cans, etc. • 4) Review the location of all pipelines, underwater flare lines, process equipment vent lines, pipeline risers, etc. and determine if any relocation or protection work is necessary. Active pipelines that are expected to be located beneath the jack-up barge shall be depressurized during the MOB/DEMOB. For those lines to be reactivated following MIRU, a joint decision by Drilling and Production Operations Management is made regarding any special precautions necessary to ensure that an appropriate level of safety is maintained. • 5) Determine if the main deck production processing equipment located beneath the cantilever requires protection or relocation. (NOTE: There are to be no unprotected pressurized process vessels, such as separators, glycol contact towers, etc., located beneath the cantilever, nor any gas venting in this area). • 6) Unprotected process equipment located within 10 ft. of the cantilever shall have a fire monitor, operated from the rig, directed on it. • 7) Locate all fire protection equipment stations on the main deck, and determine if they require relocation. • DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 1 of 3 First Edition - May, 2003 MARINE OPERATIONS 8) If the platform has a firewater system, ensure that it is operable and meets the deliverabilityrequirements for that facility. • 9) Ensure that the location of the rig's designated safe welding area meets all MMS and ExxonMobil regulations (consider distances from existing combustible material or any process equipment containing hydrocarbons). • 10) A scale drawing depicting platform/rig equipment layout shall be developed highlighting the designated safe welding area, as well as areas in which Hot Work is prohibited. • 11) Inspect all platform deck grating, plating, boards, and handrails, and arrange for repair or replacement as needed. • 12) Ensure that all aids to navigation are operating properly. • 13) Record all casing pressures on both producing and non-producing wells. This information is transmitted to the Drilling or Workover Engineer. • Casing pressures on ALL are as follows: Well Name Inside Drive Pipe Inside Conductor Inside Surface Note: NA means that there is no pressure seal & gauge on the annulus. 14) Review with the Field Superintendent the rig move schedule to coordinate Production Operations while the rig is being mobilized/demobilized and cantilevered into position over the platform. • Field Supts: & , x- or EMDC Drilling Supts: at ( ) - 15) A scale drawing showing the position of the rig and cantilever in relation to the platform process equipment, fire protection equipment, lighting, escape routes, etc. is developed and distributed. • 16) Ensure the contractor crane complies with the inspection requirements of API RP2D. Documentation of this inspection is required. • 17) An Emergency Evacuation Plan (EEP) data sheet is completed and submitted for approval to the local Officer in Charge of Marine Inspection of the United States Coast Guard prior to spud. The Field Superintendent shall gather the data for the EEP and forward it to the Regulatory Affairs Engineer. • 18) If the rig is located on a platform with production quarters, the rig's emergency alarm system is connected to the production alarm system and these alarms are to be compatible. • 19) Ensure that sufficient emergency lighting is available at all living quarter exits, along escape routes, and at the escape capsules to provide safe transit to the muster areas. • DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 2 of 3 First Edition - May, 2003 MARINE OPERATIONS PERSON IN CHARGE (PIC) • The will be the PIC. The Drilling and Field Superintendents will work together to coordinate tying the rig and platform ESD systems together, utilizing the I&E Technician, per the SIMOP's Manual. • The PIC and Field Superintendent should communicate each day prior to the 6:00 AM Production safety meeting regarding safety issues and work status. APPROVALS Drilling Ops. Supt. Production Ops. Supt. SIMOPS Meeting Attendees: MARINE OPERATIONS SECTION 3 - APPENDIX G-II US-EAST SIMULTANEOUS OPERATIONS DEVIATION REQUEST DATE: LOCATION: ORIGINATOR: FIELD PIC: TYPE OPERATION: TYPE ACTIVITY: REQUIREMENT NO: IDENTIFY TYPE OF REQUIREMENT: MMS MUST SHOULD DURATION OF DEVIATION: FROM TO DESCRIPTION OF DEVIATION: SPECIAL PRECAUTIONS TAKEN: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 3 of 3 First Edition - May, 2003 MARINE OPERATIONS APPROVAL REQUIRED: FIELD SUPERINTENDENT: ORIGINATOR'S OA ID: DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 1 of 3 First 1 of 1 Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 2 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 3 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 4 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 5 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 6 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 7 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 8 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 9 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 10 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 11 of 3 First Edition - May, 2003 MARINE OPERATIONS MARINE OPERATIONS SECTION 3 – APPENDIX G-IV PRE-STARTUP INSPECTIONS FOR NEW TO FLEET JACKUP DRILLING RIGS 1.0 Purpose To document current practice of compliance with the Mobile Offshore Unit Marine Safety Section of the ExxonMobil Upstream Design Guidance Manual 1.1 Inspection of Critical Marine and Emergency Equipment / Marine Safety Survey These inspections ensure that the MOU equipment complies with the Upstream Design Guidance Manual, is maintained, and is operational. Additionally, it will address personnel competency and personnel performance in critical marine functions and emergency response. The inspections are performed in accordance with the following guidelines: 1. Upstream Design Guidance Manual Mobile Offshore Unit Marina Safety 2. Offshore Installation Escape, Evacuation, and Rescue Analysis Assessment Guidelines, EPR.61PR.96 3. Exxon Guidelines for Preparing and Conducting Effective Drills on MOUs. A third party company (ModuSpec) with surveyors trained in these guidelines has been contracted to perform the inspections and report findings. 1.2 Structural Integrity 1.2.1 Assessment For MOUs or designs that have had a structural integrity assessment in the past. The assessment consists of: 1. A review of previous hull and leg inspections including the Classification Society (ABS, D&V, Lloyd's) Special Periodic Survey. Technical assistance in reviewing these documents is available from Stan Christman in the Drilling Technology Group. 2. A review of previous operating history 3. A review of the specific site environmental conditions. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 12 of 3 First Edition - May, 2003 MARINE OPERATIONS For new MOU designs a structural and fatigue analysis is required and should be completed with the technical assistance of the Upstream Research Company. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 2 MARINE OPERATIONS 1.2.2 Inspection The inspection if required consists of visual and NDT of the following areas: cantilever, crane pedestals, helideck, jacking system, jackhouse structure, spud cans, and legs. Inspection plans for routine inspections can be developed by Bennett & Associates or ModuSpec. The URC should be contacted for inspection plans for unusual jackup applications such as sea ice, high seismicicty, unusual soil conditions, etc. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 13 of 3 First Edition - May, 2003 MARINE OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 2 4.0 DRILLING OPERATION 4.1 4.2 4.3 4.4 4.5 4.6 4.7 4.8 4.9 4.10 4.10.1 4.10.2 4.11 4.12 4.13 4.14 4.15 Introduction General Operations Guidelines Pre-Spud Operations Structural Drive Pipe Conductor and Surface Casing Interval Diverter Operations Intermediate / Protective Casing Interval Production Casing / Liner Interval Slot Recovery / Whipstock / Section Mill / Cut & Pull Wellbore Anti-Collision Guidelines Requirements for "Collision Risk" Wells Requirements for All Directional Wells Directional Surveying and Deviation Control Drill String Design Bottom Hole Assemblies Hydrogen Sulfide Considerations Hydrogen Sulfide Contingency Plan DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 14 of 3 First Edition - May, 2003 MARINE OPERATIONS ____________________________________________________________________________ __ DRILLING OPERATIOS MANUAL - JACK-UP/PLATFORM BARAGE RIG DRILLING FIRST EDITION - MAY 2003 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING 15 of 3 First Edition - May, 2003 DRILLING OPERATIONS 4.1 INTRODUCTION This section provides guidelines for conducting a safe, efficient, and environmentally sound drilling operation. These guidelines may be modified based on actual well conditions after approval as specified in OIMS. Specific requirements for each well will be covered in core drilling procedures designated by each drill team for their specific drilling operation. For details on the installation of the various wellhead components, refer to the wellhead manufacturer's operations manual. Applying proven drilling technology to efficient rig operations is essential to minimizing drilling cost. Since every hole drills differently, the drilling supervisor should remain flexible and exercise good judgement in requesting permission to make changes to an approved procedure. Extensive planning and design criteria has gone into the makeup of an approved drilling procedure. If upgrades are required because of onsite learning's or firsthand knowledge, the MOC (Management of Change) process must be used (see Section 4 – Appendix VII for suggested MOC Form). This process ensures that all drill team members have had the opportunity for input and are aware of all changes. There are a number of factors which contribute to fast, trouble free drilling: 1) consistently follow good practice, 2) complete rig acceptance tests and crew safety training prior to spudding, 3) set up communications and reporting systems prior to spudding, 4) have all material and equipment necessary for a job on location and checked, 5) have environmental protection systems installed and functioning prior to spudding, 6) select the proper bit, 7) properly design bottom hole assemblies, 8) run low solids drilling fluids, 9) optimum hydraulics, 10) drill team members maintain an awareness of hole conditions, 11) implement and follow stuck pipe prevention practices, and 12) recognize well control early warning signs immediately. The intent of this manual is not to give specific recommendations for every situation but to give guidelines. Drilling personnel must also rely upon their experience and training to supplement this manual. 4.2 GENERAL OPERATIONS GUIDELINES 1. All depth measurements are to be made from a consistent reference point, the top of the kelly drive bushing. "RKB" when determined on a rig with a top drive system shall mean the surface of the rotary table. After nippling up the casing head, record on the daily drilling report the elevation of the spool flange relative to RKB. 2. The slip handles are to be tied together to prevent accidental dropping of the pipe during the following conditions: • • Whenever the BHA is close to or above the wellhead. Any other time there is a possibility of the elevators hitting the pipe in the slips. 3. During routine drilling in normal pressure zones, WOB and RPM's are to be varied as required to maintain maximum performance. When drilling near anticipated abnormal DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 20 DRILLING OPERATIONS pressure zones, the drilling parameters are to be maintained constant to allow for more accurate pressure detection. 4. Below each string of casing, except conductor, a pressure integrity test is to be conducted after 10' of new hole has been drilled to determine the formation integrity. The PIT will normally be taken to leak-off or jug tested to the pressure specified in the procedure, but will not exceed the casing test pressure (see Section 11 of this manual). 5. On trips, the blind rams will be closed when the drill string is removed from the wellbore. Caution will be used when the blind rams are opened, due to the potential for trapped pressure. Each rig must have a procedure in place to monitor pressure below the blind rams when they are closed. 6. When pipe is out of the hole, a rotary cover will be installed. 7. The locking mechanism to lock the master bushing in the rotary and bowls in the master bushing must be free and functional for the rotary to be considered operational. The kelly bushing shall be locked at all times (or removed) except when procedures specifically require them to be temporarily unlocked . 8. While tripping in the hole, fill the drill string frequently. Frequency is to be determined by the drilling superintendent based on current mud weight, hole conditions, and depth. The trip tank will be used while running in the hole unless otherwise addressed by the Field Drilling Manager. If it is used, pump the trip tank mud across the shale shaker when emptying. It is preferable to use the maximum acceptable mud level drop in the annulus instead of the number of stands run as a drill string fill up guideline while tripping the hole. For example, assume five inch 19 1/2 ppf drill pipe is being run in a hole and the drill pipe float allows no mud to enter the drill string. After running 1,860 feet, the drill pipe float fails allowing the mud to U-tube and balance in the drill pipe and annulus. Depending on the hole size, the mud level would drop as follows: Hole Size, inches 8½ 12 ¼ 17 ½ 19 ¼ Mud level drop, feet 520 238 114 94 An equation specifically for 5 inch 19 1/2 ppf drill pipe to calculate the fluid level drop for the above scenario is: d = L x [ 18.32 / ((D x D) - 6.68) ] where: d is the mud drop in the annulus, in feet L is the length of 5 inch drill pipe run without filling, in feet D is the hole diameter, in inches A general equation to calculate the mud drop for a different size string being run in the hole is: d = (C x L) / (A + C) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 20 DRILLING OPERATIONS where: d is the mud drop in the annulus in feet C is the drill string capacity in bbl/feet L is the length of drill string run without filling in feet A is the annulus capacity in bbl/feet The drilling engineer can easily generate a series of tables for a specific well and an optimum fill up schedule based on an acceptable downhole pressure drop which would be based on pore pressure estimates while drilling. 9. The completion or plug and abandonment program should be developed while drilling proceeds. This allows equipment to be procured in a timely manner and completion or P&A considerations, such as casing pup joints run to aid in perforation depth control, to be implemented during the drilling phase. 10. A non-ported float will be run when drilling through casing set at insufficient depth to allow for the well to be shut in. After sufficient casing is set to allow the well to be shut in, a ported float will be run. Modification to the drill pipe float, including porting, must not be done on the rig. Field modification of drill pipe floats is not allowed. Either a Model "F" (plunger) or Model "G" (flapper) may be used as a solid float. Only a Model "G" may be used with a hardened port in the flapper. The common sizes of float valves are: Bit Size 6 inch 8 1/2 inch 12 1/4 inch Tool joint 3 1/2 Regular 4 1/2 Regular 6 5/8 Regular Float valve size 2F-3R 4R 5F-6R A safety valve (ball open) and inside BOP (plunger locked down) will be on the rig floor. A safety valve and an inside BOP will be available, on the rig floor, for each size drill pipe that is currently used. Prior to running or pulling any casing liner or tubing, a cross-over back to the safety valve and a safety valve must be on the rig floor. The safety valve must be function tested and the test must be documented on the IADC report and DMR. 11. The Crown-O-Matic will be checked daily and after slipping the drilling line. Results of this inspection must be recorded daily in accordance with MMS Regulations. 12. Flow check all connections. 13. The fast (hard) shut-in method using the annular preventer to shut-in the well will be used. 14. Do not test a lubricator with perforating guns inside to a higher pressure than the perforating guns are rated. 15. Casing annulus pressure should be monitored daily on all rigs with surface wellheads. If casing pressure is detected, it should be reported on the Daily Drilling Report. The situation should be reviewed with the Operations Superintendent to determine if any corrective actions are warranted, e.g. bleed off, increased monitoring, etc. (OIMS Manual Element 6). DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 20 DRILLING OPERATIONS 16. Standpipe or mud pump suction screens are preferable to drill pipe screens. Only run downhole screens when no nuclear source tools are in the BHA. Always discuss use of DP or downhole screen with Operations Superintendent. 4.3 PRE-SPUD OPERATIONS 1. Develop a waste disposal plan which addresses the following: • Plastic and Styrofoam • • Metal (no used casing thread protectors are to be sent to the United States) Garbage (including ground food waste) in accordance with USCG MARPOL regulations Paper and cardboard Used engine oil - Contractor Responsibility Mud - Per applicable NPDES Manual Drill solids (where regulations require) -NPDES Manual Sewage and effluent - Per NPDES Manual or Discharge Compliance Program (ensure that the drilling unit's treatment plant is operational) Well Completion/Workover/Treatment Fluids - per NPDES Manual • • • • • • 2. Hold a pre-spud meeting. 3. Complete rig acceptance prior to picking up the rig and again at frequency specified by the Operations Superintendent. The minimum tests will be those required in the drilling contract. At a minimum all rigs entering the ExxonMobil fleet will be inspected by the Operations Superintendent or his designee prior to acceptance. 4. Ensure that the muster list has been completed and all personnel are accounted for. 5. Conduct a general safety meeting, review all of the pertinent Safety Alerts. 6. Ensure that the spud mud has been mixed as per the drilling program. 4.4 STRUCTURAL DRIVE PIPE The most time effective method of setting drive pipe is to drive it to refusal (usually less than 225 blows per foot) with a diesel/hydraulic hammer. Plain-end or quick connect pipe is employed and welded/made-up as the joints are added to the string. For a height estimate, use 45 feet for the diesel/hydraulic hammer and slings and 42 feet for a joint of drive pipe. Although not essential, use of a pipe bevel machine and two welding machines will greatly speed up the driving process for pipe that must be welded. It is important that driving not stop once started (e.g. an overnight shut down) as the pipe will probably not start moving again. Driving pipe with a diesel/hydraulic hammer entails higher than normal risk. The pipe will be lifted by padeyes that probably will not have had the welds inspected. While driving, the drive pipe could enter a soft zone and drop rapidly. A quick connect type connection allows use of a false rotary table and elevators, and speeds up the driving time while eliminating field welding. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 20 DRILLING OPERATIONS It is sometimes necessary to wash-out the drivepipe during driving operations if the drive hammer blows per foot reach the recommended maximum prior to achieving planned/adequate drive pipe penetration. Wash-out of drive pipe during driving operations requires risk assessment including consideration of shallow hazards, prior MMS approval, and appropriate EMDC and EMPC management approval. 4.5 CONDUCTOR AND SURFACE CASING INTERVAL The D&E procedure provides details for the following operations: conductor hole drilling; conductor casing running, cementing & hang-off; diverter procedures; surface hole drilling; surface casing running, cementing, hang-off, and wellhead installation. 1. The purpose of the conductor casing is to provide adequate Well Control integrity to allow drilling to the surface casing point. Conductor casing is typically required when: • • • An active drilling program has not been conducted on a specific platform within the previous 12 months. There is significant shallow gas and/or lost returns potential present. Offset well casing pressures and potential casing leaks present the possibility of encountering charged formations shallower than the surface casing depth. 2. The purpose of the surface casing is to provide adequate Well Control integrity to allow drilling to the next casing setting point (protective or production casing depth). Surface casing is the first casing string on which the full 5 preventer BOP stack is nippled-up. Surface casing supports the weight of all subsequent strings of casing, tubing and surface equipment (i.e. blowout preventers or the wellhead and tree). The setting depth will range from 2000 feet to several thousand feet. Surface casing is cemented to surface either during the primary cement job or after the primary job with a grout job. Unless otherwise specified in the drilling program, conductor and surface holes will be drilled from below the drive pipe shoe to ~20' below the planned shoe depth for the respective casing. Make sure to stop drilling prior to exceeding the maximum permitted depth for the hole interval. The rathole is less critical with a weld-on wellhead as it is probably desirable to set the conductor or surface pipe on bottom. The conductor and surface holes will generally be drilled with SW-gelCLS mud systems to total depth. Where significant shallow gas risk is identified, the conductor or surface hole may be drilled utilizing a pilot hole to facilitate well control operations. The primary means of well control during pilot hole drilling is a dynamic kill. The annular clearance between drill collars and the wellbore provides a friction pressure drop, to help increase the effective BHP at high circulating rates in the event of a well control problem. If the well kicks, circulate drilling mud at maximum rate. The bit should be within 200 feet of bottom. Spot one ppg heavier mud or barite plug if well flow cannot be killed with regular mud. Circulating heavier mud around may cause lost circulation. The following general guidelines are for pilot hole drilling operations: 1. A volume of one ppg heavier than drilling weight kill mud can be mixed and maintained in reserve until the pilot hole has been drilled. The minimum volume of mud to be mixed will DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 20 DRILLING OPERATIONS be specified in the drilling program and will generally be the sum of the annulus volume between the drill string and the pilot hole from TD to the flowline plus the volume required to stop reservoir flow as determined by dynamic kill simulations for the applicable hole geometry and reservoir conditions. In areas where the potential for the presence of shallow gas is low, dynamic kill simulations will not be required. If the dynamic kill calculations are made, a volume pumped versus pump rate plot will be produced which has a No Kill Region and Kill Region. 2. During critical operations (drilling, tripping, etc.) conducted while drilling the pilot hole, either the operations supervisor or the tool pusher should be on or near the rig floor. 3. If the rig is equipped with a top drive, rotating while pulling out of hole will reduce the swabbing effect and reduce the chance of influx. Pumping out of the hole is also an option. 4. Minimizing hole washout, avoiding excessive mud seepage, controlling return mud weight, and directional control/wellbore avoidance are more important than high rate of penetration for the conductor and surface hole sections. 4.6 DIVERTER OPERATIONS A diverter assembly composed of spacer spools, drilling cross, and an annular will be nippled up during all conductor and surface hole drilling. A kill line will be connected to one of the spool outlets and the diverter lines will be connected to the two 10" side outlets. The primary consideration is to have a straight diverter line with a non-restrictive valve (ball or gate valve). The diverter line must extend beyond the rig cantilever and must not be directed onto the platform or toward the drilling rig and should account for prevalent wind direction. Controls should be sequenced to prevent closing the annular prior to the down wind diverter line valve opening. Anchor the end of the diverter line. Consider need for installing a flare line remote ignitor. 4.7 INTERMEDIATE / PROTECTIVE CASING INTERVAL Drilling the Intermediate Hole Formation pressures in the hole below surface casing define the type of well being drilled - normal or abnormal pressure. In areas where abnormal pressure formations are encountered or hole conditions mandate formation isolation, intermediate or protective casing may be required prior to reaching total depth. Casing seat or TD Hunts may be required. Fracture gradients of the formations encountered should be estimated based on offset drillwells. If there are no applicable offset wells, estimates from empirical data such as Eaton's curves can be used. Running and Cementing the Intermediate Casing A full string of casing will be run and hung off in the wellhead. The casing string will include a float shoe, float collar, and possibly casing pup joints. The cementing assembly will include top and bottom wiper plugs, and cement head/manifold. The Casing and Cementing Sections of this manual should be referred to when planning this job. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 20 DRILLING OPERATIONS After tagging cement with the bit and prior to drilling out of the shoe, do well control drills. Review shut in procedure with both crews. Shut in well and circulate well through the choke manifold. Let drilling crew members work the choke. (Alternately this can be done after displacing the hole with mud to determine the choke line pressure drop for kick calculations.) A casing test will usually be mandated by the governing regulatory body prior to drilling out and after landing the BOP stack. Run a pressure integrity test after drilling out below the intermediate casing string. Update kick sheet daily while drilling. 4.8 PRODUCTION CASING / LINER INTERVAL Drilling the Production Hole The same guidelines given in the Drilling the Intermediate Hole section apply when drilling this hole section. If using a top drive, pick up sufficient drill pipe to drill to total depth. A ported drill pipe float will be used below surface casing once the well can be shut in on a kick. After tagging cement with the bit and prior to drilling out of the shoe, do well control drills. Review shut in procedure with both crews. Shut in well and circulate well through the choke manifold. Let drilling crew work the choke. (Alternately this can be done after displacing the hole with mud to determine the choke line pressure drop for kick calculations.) The casing/liner will be pressure tested in accordance with applicable Regulatory requirements. Update kick sheet daily while drilling. 4.9 SLOT RECOVERY / WHIPSTOCK / SECTION MILL / CUT & PULL The following discussion deals with methods of drilling new wells or hole sections from in or around existing wells. Slot recovery allows for new wells from the surface while whipstocks and casing cut & pulls reuse existing casing to reach new objectives. In general, deep whipstocks will be less expensive than cut & pulls (C&P), which are generally cheaper than slot recoveries and new drill wells. When deciding on whether or not to reuse a wellbore, factors to include are: the direction of the existing well compared to the desired objective(s), existing casing program vs. hole sizes and completion necessary, future life of the existing completion, ability to reach (and others on a multiwell program) and have needed hookload, and others. If an existing well is to have part of it reused, maximum effort should be taken to confirm the suitability of the well prior to moving the rig onto location. This includes a thorough researching of the well's history (e.g., drilling wear, noted pressure tests, cement records), inspection of the wellhead by a qualified service technician, pressure testing casing as possible, and performing all possible P&A work. If the cement job for a casing string is questionable, it is sometimes advisable to run a high-quality imaging tool (e.g., Schlumberger's USIT log) to determine cement quality and TOC behind the casing; this can aid in Whipstock placement and help decide if a C&P is possible. Many times, the various procedures described will be run together (e.g. C&P production casing to allow a Whipstock from the surface casing). It will be important to verify compliance with the appropriate regulatory guidelines and obtain approval for operations. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 20 DRILLING OPERATIONS Slot Recovery Slot Recovery is a method of opening space on a platform for a new drillwell that has had all of its conductor slots used by previous wells. This helps avoid costly platform modifications that could otherwise be required. Diver Divert and Drive Pipe Whipstock are the two types of slot recovery available for use once the subject well has been fully P&A'd (see Section 13 for details on P&A operations). For a Diver Divert slot recovery, all strings of casing (including drive pipe) are cut and recovered from ~5 feet above the mud line. The new drive pipe is lowered through the platform's conductor guides to below the water line where divers then guide the new drive pipe to the side of the existing casing stubs. The new drive pipe is then driven to the desired depth and well operations proceed as normal. It is often desired to have a deviated drive shoe on the bottom of the drive pipe to help ensure separation from the old well as quickly as possible. For a Drive Pipe Whipstock slot recovery, all strings of casing (including drive pipe) are cut and recovered ± 60 – 80 feet below the mud line. A whipstock is attached to the bottom of the new drive pipe and lowered through the platform's conductor guides to the existing casing stubs. Whipstocks are available with either a spear or an overshot and can be oriented to the direction desired. Once the whipstock is mated to the abandoned conductor, the new drive pipe is sheared off of the whipstock and the drive pipe is driven to the desired depth. Again, operations can now proceed as normal. Drive pipe whipstocks are generally the preferred option because there is no requirement for divers to be in the water. Both options require special evaluation of the anticipated drive pipe deflection to determine if one or more platform conductor guides will have to be removed. Whipstocks Casing Whipstocks are mechanical devices set inside of existing casing and are used to exit from previously drilled wells. The Whipstocks can be either single-trip or multiple trips. The difference in price between single-trip and multiple-trip should be evaluated for each situation (generally, single-trip systems will be more economical on deeper exits while the multiple-trip are better for shallow exits where trips are fast). The general plan of operations is that the Whipstock is run in hole, oriented, and set (either mechanically or hydraulically). The Whipstock should be oriented to the direction desired for sidetrack (generally ~30° – 45° from highside). Then, casing mills are used to exit the casing and make enough new hole to perform a PIT. Once this is complete, new drilling operations are able to proceed. It is important to never rotate anything across the face of the whipstock; this will help prevent the whipstock from turning and causing the new hole to be lost. The fluid system should be sufficiently viscous and have ditch magnets in place to help remove the metal shavings from the system. Section Milling Section milling is similar to whipstocking in that existing wellbore is exited by milling a hole in the casing. The main difference is that the means of exiting the casing is not a mechanical tool. To Section Mill, underreaming-type casing mills are run into the existing casing string and a hole is DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 20 DRILLING OPERATIONS milled in the casing (typically, ~100'). A cement plug is then placed across the milled interval and the well sidetracked off of this cement plug. This method is preferred over Whipstock operations when the new hole section will be long, directionally complex, or otherwise cause excessive wear and tear on the whipstock that could cause failure (and thereby lose the new hole). Casing Cut & Pull The benefit of casing Cut & Pulls for sidetracking new hole is the increased hole size available by removing one or more strings of casing. The basic plan for a C&P is to lower a casing cutter (generally hydraulic) into the hole to the desired cutting depth, cut the casing, then attempt to pull the old casing from the hole. Based on the depth of the cut, the removal of casing could either expose formation or the previous casing string. 4.10 WELLBORE ANTI-COLLISION GUIDELINES Wellbore anticollision guidelines in this section are a recommended minimum standard for all operations. These guidelines should be reviewed on a well by well basis. Any exceptions to these standards requires Operations Superintendent approval. 1. The most critical piece of information in the anti-collision arena is data quality. All platform surveys and RKB's should be reviewed by a qualified individual to ensure the data is correct, reasonable and free of errors. Pay particular attention to azimuth round-off error and RKB datum height (these have been incorrect in the past). 2. Once a well path has been generated, have the directional contractor run an anti-collision report. Review the report and identify the wells that will need to be addressed individually. Obtain the most recent wellbore sketches for every well on the platform and for all wells that pass near the proposed well (wells may originate from an adjacent platform or an open water location). Pay attention to tubingless wells, producing wells, gas lifted wells, and plugged wells. 3. In the SIMOPS meeting held between EMDC and EMPC, discuss the status of the previously identified wells. Plan to shut in, bleed off and or set plugs in wells close to the proposed well path. 4. During drilling operations near interference issues, survey every stand and use current technology to provide the best information possible (i.e., surface readout gyro). Have the directional contractor supply an additional directional driller to run projections and anticollision reports only. Use a jetting assembly to steer near interference. Minimize Drill string rotation (DO NOT USE A MOTOR) while near another well. Monitor constantly for torque, LR, metal cuttings, cement, or any other parameter that could indicate interference. 4.10.1 REQUIREMENTS FOR “COLLISION RISK” WELLS 1. Collision avoidance planning and operating requirements (Items 1-7) will apply to “Collision Risk Wells”. Collision Risk Wells are defined as: 2. Any well drilled from a multi-well pad or structure (includes abandoned wells). DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 20 DRILLING OPERATIONS 3. Single-well operations, if the planned trajectory is expected to pass within 100m (330 ft) of that of an offset well. 4. If SIMOPS or local regulatory collision avoidance requirements are more stringent than EMDC requirements, the more conservative requirements will be followed. 5. Either Wolff & DeWardt or ISCWSA models may be used to develop collision avoidance and EOU calculations. The vendor is responsible for selection of tool error factors and the performance of their proprietary software. 6. The least-distance method will be utilized to calculate the separation between ellipses. 7. Ellipse of uncertainty calculations will be based on 2 standard deviations (2σ). 8. Offset monitoring and shut-in requirements for Collision Risk Wells are determined by “Separation Distance” or “Separation Factor” requirements, whichever is larger. FDM approval is required to operate with an EOU Separation Distance < 10ft, or Separation Factor < 1.5. The FDM may approve exceptions to shut in requirements if risk can be reduced to acceptable levels through operational practices. SEPARATION DISTANCE • If the EOU Separation Distance projected to the next survey point is < 10 ft, monitor the applicable offset annulus continuously. • If the EOU Separation Distance projected to next survey point is < 5ft, shut in the offset and set a plug below the estimated intercept depth (or close SSSV if it’s below intercept point). Monitor annulus continuously. SEPARATION FACTOR • If the EOU Separation Factor projected to the next survey point is < 1.5, monitor the applicable offset annulus continuously. • If the EOU Separation Factor projected to next survey point is < 1.2, shut in the offset and set a plug below the estimated intercept depth (or close SSSV if it’s below intercept point). Monitor annulus continuously. 1. As a final planning check, the onsite directional driller is to run an independent collision avoidance profile for Collision Risk Wells prior to commencing work. 2. Anti-collision plots will be maintained for Collision Risk Wells at the rig site. Updates are required following each survey until the potential intercept point is passed. 4.10.2 REQUIREMENTS FOR ALL DIRECTIONAL WELLS 1. Written directional and proximity monitoring plans will be included in the program. The engineer, first line engineering supervisor, and operations superintendent must endorse the plan prior to field implementation. 2. FDM approval of MOC is required for changes in trajectory after final plan approval that create 1) a “Collision Risk Well”, or 2) a change in the shut in requirements of an offset well (per Separation Factor or Separation Distance rules). DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 20 DRILLING OPERATIONS 3. The drilling program will specify the type of survey tools and minimum frequency of surveys in each interval. 4. Critical pre-drill planning data will be summarized and transmitted to the survey anddirectional contractors in writing. The data will include, but not be limited to: • Well Name • Preliminary Reference Elevation • Slot/Well Surface Coordinates • Displacement from Slot to Platform Tie Point • Azimuth Reference Correction (True North, Grid North) • Magnetic Declination • Target description and hard line constraints • Survey tool types and frequency, by interval 5. All survey data will be communicated between parties at the rig site in a standardized format. Either the contractor or ExxonMobil may develop the format (electronic or written). 6. The drilling engineer will review the information in the final well survey for accuracy and initial it prior to distribution. 7. Geologic targeting requirements will be obtained from the client organization in writing. 8. The survey plan and trajectory will ensure that the wellbore’s two-sigma ellipse ofuncertainty fits fully within the specified geologic target on the planned line of approach. If this cannot be achieved, client management approval is required to drill a trajectory with a reduced probability of landing within the target area. 4.11 DIRECTIONAL SURVEYING AND DEVIATION CONTROL The purpose of the guidelines in this section is to maintain directional control on all wells (vertical and directional) as drilling progresses. Directional control ensures a known bottom hole location and well trajectory in order to avoid collisions/damage to offset wells and efficiently drill to the geologic objective(s) and relief well targets if necessary. For relief well purposes, it is important to know the position of the well to within 50 feet, which is the effective range of noise log and MagRange tools. For the purpose of applying the following general survey requirements, a vertical well is defined as a well that has less than three degrees of inclination from surface to total depth. The following table summarizes the minimum surveying requirements: Type of Well Requirement Vertical Well (less than 3°) Inclination Survey every 1000' Directional Well during normal Inclination and Azimuth every 500' drilling Directional Well during planned Inclination and Azimuth every 100' angle changes DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 11 of 20 DRILLING OPERATIONS Prior to setting surface and deeper casings in both directional and vertical wells Total Depth on both directional and vertical wells Inclination and Azimuth 500' from csg shoes Inclination and Azimuth 500' from TD A composite survey from either the drive pipe or conductor shoe to TD must be provided per MMS requirements. Surveying Guidelines 1. If well surveys are required beyond the minimum summarized above, they will be specified in the drilling program. 2. To determine surveying requirements, the following casing definitions will be used: Drive, or Structural, - pipe which is driven to support unconsolidated deposits and provide hole stability for initial operation (normally 20-30 inch). Conductor - Set below drive pipe and before surface pipe to mitigate some shallow drilling hazards. Surface - a blowout preventer stack is nippled-up on top of this string and a pressure integrity test is run after the casing shoe is drilled. Surface casing cannot be used as production casing, without a written exception from the field drilling manager. 3. A gyro deviation survey will be taken at the total depth of the drive pipe hole or shoe. Typically a gyro must be run because the pipe is driven in place. 4. Surveys taken with a MWD tool are definitive, and it is not necessary to confirm MWD surveys with a single shot survey. Standpipe or mud pump suction screens are preferable to drill pipe screens. Only run downhole screens when no nuclear source logging tools are in the BHA. Always discuss use of drill pipe screens with Operations Superintendent. 5. In cases where bottom hole location is critical, an electronic multi-shot or gyroscopic survey may be run. EPRCo's Wellpath program or vendor software can be used to estimate the amount of error that results from using various survey tools and aid in the decision to run a multi-shot or gyro survey. 6. The drilling superintendent should be provided directional data on a continual basis. For directional wells, the directional driller and drilling engineer are to maintain a wellbore trajectory record and a current wellbore plot. All directional plots are to be updated, and any significant deviation from the planned directional program is to be presented to the operations superintendent immediately. The minimum curvature calculation technique should be used. 7. Survey results are to be reported on the survey screen of the daily drilling report and IADC Report. All directional information should be converted to GRID measurements when reported and plotted. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 12 of 20 DRILLING OPERATIONS 4.12 DRILL STRING DESIGN Drill String Guidelines 1. All drill string connections are to be torqued to API recommended values except as identified in the appropriate procedures. Jet-Lube's Kopr-Kote can be used for every connection from bit to kelly/top drive. KoprKote does not contain zinc or lead. Prior to application of Kopr-Kote, the tool joint threads should be cleaned to bare metal. To prevent galling of the non-magnetic components when using Kopr-Kote, connections should be cleaned, inspected, and given a MAG-COAT. Without MAG-COAT, nonmagnetic connections will have a higher incidence of galling using Kopr-Kote. 2. Change the drill pipe stand breaks on every trip. 3. Maintain an accurate strap of the drill pipe on the rig floor. The well depth is determined by the driller's STM. 4. Use a drilling jar that has a large ID so that it is possible to use a wireline string shot or severing charge if required. 5. Drill string components should have the same basic connection OD unless a bottlenecked crossover is used to provide a transition. All drillstring component connection OD's must be externally fishable for the hole size they are used in. Exceptions must be approved by the Operations Superintendent. 6. If possible, the drill string is to be designed to withstand a minimum of 100,000 lbs. of overpull in a straight hole and 150,000 lbs. of overpull in a directional hole. 7. The drill string is to be designed to withstand predicted combined torque and tension loads using the FORCAL program (see Directional Drilling BHAs) for difficult directional wells and/or critical wells. 8. Limit the rotary torque during normal drilling operations to drill pipe connection makeup torque in order to prevent over-torquing the drill pipe connections. Check the actual makeup torques used by the Drilling Contractor. 9. If the drill pipe is new or refurbished, inspect tool joints for abrasive hard banding which could damage casing. 10. Perform proper break-in procedures for newly cut drill pipe connections. Drill String Inspections Drill string components will require periodic inspection based on rotating hours and type of drilling service (i.e. critical or standard). The following inspection frequency is recommended: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 13 of 20 DRILLING OPERATIONS Rotating Hours Between Inspections WELL SERVICE Drill Pipe Drill Collar/BHA Components CATEGORY 6" and Smaller 6-1/4" and Larger Critical Service 1500 150 200 Standard Service 2500 250 300 The above intervals should be adjusted based on experience and failure experience. The recommended inspection methods for drill string components are to be in accordance with Standard DS-1, Drill Stem Design and Inspection, Second Edition, by T. H. Hill and Associates, March 1998 manual. Inspection service categories, acceptance/rejection criteria, and exceptions to DS-1 are given in the ECIDO Drilling OIMS Manual. There are several classifications of well categories and OIMS requires that drill string inspection frequency as well as casing design be based on well categories. The OIMS manual designates well service categories as standard or critical in Element 3 and lists three conditions which qualify a well as critical. The top drive should have a magnetic particle examination of the exposed surfaces on all load bearing components annually to determine the presence of fatigue crack indications. 4.13 BOTTOM HOLE ASSEMBLIES General Guidelines in this section address the design, care, and makeup of bottom hole assemblies for drilling operations to meet the following objectives: • • • • • • • Control or Induce Changes in Hole Deviation Improve Bit Performance Provide Weight on Bit Ensure a Full Gauge Hole Reduce the Susceptibility to Differential Sticking and/or Key Seating Reduce Downhole Vibration Prevent/Reduce BHA Problems Such as Wash-outs and Twist-offs BHA Operational Guidelines 1. Three musts for good drill collar performance are: • • • Must properly lubricate shoulders and threads Must use proper torque - Must be measured Must immediately repair minor damage 2. Never make up drill collars or BHA components by reversing the rotary table. Tighten each connection separately. Do not double up to save time. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 14 of 20 DRILLING OPERATIONS 3. When breaking out drill collars, rotate slowly with a slight upward pull on the blocks. Do not allow threads to jump after the collar is backed out. 4. To avoid galling, a good rig practice is to "walk out" the drill collar joint using chain tongs. 5. Change the stand breaks on the BHA/drill collars on every trip. 6. Optimize jar placement by running jars near most likely stuck point. 7. Keep an accurate drawing of all BHA components including the dimension of each component (OD's, ID's, lengths, serial numbers, etc.). The dimensions should be measured in such a way as to contribute toward successful fishing. Outside diameter dimensions should be taken with a caliper that will just slip over the body by its own weight. 8. Gauging the bit after makeup will ensure that it was not pinched by the bit breaker. Refer to Section 5 (Bit Classification and Hydraulics) for gauging guidance. 9. Maintain stabilizer blade OD, according to the BHA programmed design, by gauging them every trip and replacing as needed. It is preferable to not change more than one stabilizer per trip. Follow the gauging guidelines given in the bit section. 10. Lift sub pins should be cleaned, inspected, and lubricated on each trip. If these pins have been damaged and go unnoticed, they will eventually damage all of the drill collar boxes. BHA Design The bottom hole assembly that is to be used in each hole section will be specified in the pertinent drilling procedure. The following considerations should be included when performing a BHA design: 1. HeviWate drill pipe run between the drill collars and drill pipe provides a transition zone as well as additional available string weight. In deeper wells with increasing angle, minimizing HWDP to assist in optimizing drilling hydraulics is a common practice. 2. Ensure that crossovers from large diameter drill collars to smaller drill collars or drill pipe do not exceed a 2" reduction in size, or that the stiffness ratio does not exceed 5.5 for a noncritical well or 3.5 for a critical well. 3. The acceptable drill collar and BHA tools bending strength ratio is 2.25 to 3.20. 4. These bending strength ratios may not be possible with small drill collar sizes such as 4 3/4 inch drill collars with 3 1/2 IF (NC 38) connections. Experience has shown that rotary shoulder connection failures have rarely occurred using 4 3/4 inch drill collars even with BSRs below 2.0. 5. Select components of the BHA considering lost circulation material requirements and potential for drill string sticking and subsequent fishing operations (nozzles, motors, MWDs, etc. may plug when pumping LCM). DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 15 of 20 DRILLING OPERATIONS 6. Ensure that all BHA connections have boreback stress relief box connections and stress relief grooves on pins. 7. Spiral drill collars are preferred to minimize differential sticking potential. 8. Straight welded blade stabilizers minimize swabbing in gumbo sections. Stabilizers with a longer contact area increase wall support area in soft formations. Stabilizers with a shorter contact area are preferable in hard formations. Consider use of spiral, integral blade stabilizers with adequate bypass area for high angle, directional well hole cleaning. Directional Drilling BHAs These guidelines are not intended to be policy or inflexible standards but should serve as a foundation on which to base decisions for well specific designs. From about 1950 to 1980, drill pipe and HeviWate drill pipe were never run in compression for fear of fatigue failures as a result of buckling. However, inclination of a wellbore was seldom taken into account in calculating the required drill collar weight. As a result most operators did not add collars as hole angle increased which undoubtedly caused drill pipe to be run in compression. Fatigue failures expected for drill pipe run in compression did not occur. Industry has determined that drill pipe can carry high compressive loads in high angle wells without buckling and fatigue failures. Buckling does lead to accelerated fatigue damage and tool joint wear which can be tolerated for short periods of time especially if it would save a trip or reduce the chance of a differentially stuck drill string. The basis for these conclusions is that a drill string laying on the low side of an inclined hole is very resistant to buckling since the hole supports and constrains the pipe throughout its length. An important benefit of running drill pipe in compression is that the length of HeviWate and drill collars can be reduced and hydraulics, hole cleaning, and ROP can be improved. FORCAL permits drill string design based on allowable drill pipe compression for deviated or straight wellbores. ROB predicts rates of build or drop for rotary bottom hole assemblies. Placement of stabilizers on the bottom of a BHA for directional control can be analyzed as well as how drill collars will bend between stabilizers. Directional service companies can provide similar drill pipe design software. Be sure to note the limitations of the particular software being used and check this against the situation being analyzed (e.g. FORCAL needs modified input when modelling casing running because it is based on string theory). The new BHA design methods which take advantage of the reduced BHA buckling tendency in directional wells have been used since the early 1980s with outstanding results. The short drill collar lengths required (frequently just MWD/LWD equipment for GOM operations) resulted in reduced torque and drag and reduced frequency of differentially stuck BHAs. The amount of drill pipe, HeviWate drill pipe, and drill collars run in compression is well specific and depends on hole size, mud weight, well angle, desired WOB, and torque and drag constraints. All drilling operations should take advantage of design methods which can minimize problems with torque and drag and stuck BHAs. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 16 of 20 DRILLING OPERATIONS When differential pressure exceeds about 1,500 psi, take special care to avoid differentially sticking the drill string. Implement special procedures such as making rotating connections, controlling mud fluid loss and mud cake quality, ensuring effective hole cleaning (i.e., limiting cuttings dune height, etc.), and pumping out of hole on rigs with a top drive system. For differential overbalance pressure greater than 2,500 psi consider use of the high overbalance, "Seal-While-Drilling" technique. For wells between 15-35 degrees of angle, apply the following general BHA guidelines. For wells with >45 degrees of angle special drilling practices may be required. 1. Minimize the number of drill collars and run the maximum amount of drill pipe and HeviWate drill pipe in compression as indicated by the FORCAL program. In most cases only non-mag collars are required in addition to MWD/LWD collars based on well angle, hole size, desired weight on bit, well angle, mud weight, and torque and drag constraints. 2. Do not run more than one unsupported drill collar above the top stabilizer in directional wells. This can also be eliminated if a non-mag spacer is not required, or if non-mag HWDP is available to be run in place of the non-mag collar. At high angles, additional DC's create a very high bending stress in the top stabilizer connection. They also create the potential for stuck pipe if they sag to contact the wall. 3. The computer program ROB in conjunction with the directional service company software/experience should be used to design stabilizer placement for the BHA. In most area, particularly in areas where differential sticking is a concern, stabilizers should be placed every 60 feet. 4. The directional drilling contractor should provide recommended BHAs for evaluation by the Drilling Engineer. 5. Keep up with differential pressure between the mud weight and pore pressure. Take special precautions to prevent stuck drill strings anytime differential pressures exceed about 1,500 psi regardless of the type formation drilled. 6. In harder formations, roller reamers are sometimes used in lieu of stabilizers. Roller reamers are often used when significant amounts of reaming is anticipated or rotary torque reductions are desired. Non-rotating drill pipe protectors or sleeves should be considered when torque reduction is desired. 7. For steerable PDM drilling assemblies, optimize mud motor and LWD tool configuration to anticipated well conditions including: drilling fluid type, flowrate, downhole temperature, anticipated time between trips, bit type, and drilling WOB and torque requirements. For GOM Directional wells use high performance, extended power section PDMs whenever possible. FORCAL V.5.02 software estimates the torque and drag on a tubular given the wellbore geometry, tubular configuration, direction of movement, and coefficient of friction. The movement can be axial, rotational, or combined. Two coefficients of friction may be used, one for cased portions of the well and the other for the open hole section. Tripping of tubulars into and out of the wellbore DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 17 of 20 DRILLING OPERATIONS can be modelled. Given the measured torque or hookload, FORCAL can calculate the coefficient of friction. ROB V.5.01 software predicts the build/drop and walk performance of rotary and motor assembly BHAs. The user can perform sensitivity analysis to predict the effects of various parameters on BHA performance. Geology effects such as bedding planes can also be included and a calibration module allows the user to take advantage of local experience. ROB performs drill ahead and well extend calculations along with 2-D and 3-D well planning. POWERPLAN V.3.8 is also utilized and has the capabilities of prediction both torque/drag and build/drop and walk of different BHA's. Torque and drag surveillance should be monitored for all protective and production holes in excess of 40° with greater than 1500' MD of openhole. An example is included in Section 4 – Appendix VIII. 4.14 HYDROGEN SULFIDE CONSIDERATIONS (OIMS Manual Element 10) Hydrogen sulfide is an extremely toxic gas. In drilling operations, a wide range of hydrogen sulfide concentrations may be found. The effects of these concentrations also range widely - from a disagreeable odor or eye irritation at low concentrations to serious illness or even death at higher concentrations. All personnel working in areas where they may be exposed to hydrogen sulfide should be trained to recognize and understand its hazards and to protect themselves from its harmful effects (contractor and service company personnel should be H2S certified before coming to the rig). Personnel should be trained to rescue victims and administer first aid to those who are overcome, without endangering themselves. All personnel on the rig should have access to an escape pack. Hydrogen sulfide is an extremely toxic, colorless, heavier than air (1.18 specific gravity) gas. It burns with a blue flame and produces sulfur dioxide gas which is slightly less toxic than hydrogen sulfide, but can cause eye and lung irritation and serious injury. In low concentrations, hydrogen sulfide has the odor of rotten eggs. It forms an explosive mixture with air at concentrations between 4.3% and 46% by volume. It is soluble in water and oil but becomes less soluble as the fluid temperature increases. When there is a potential for encountering hydrogen sulfide, the following must be considered and addressed: • • • • • • Monitoring Use of breathing apparatus Positioning of breathing apparatus Equipment training Hazardous locations Material selection - BOP and well control equipment H2S trimmed • • • Regulations First aid Coded air horn or bell alarms DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 18 of 20 DRILLING OPERATIONS • • • • • • • • • Response at various levels of hydrogen sulfide concentration Sensors - location, calibration, visual and audible signals, fixed and hand held Emergency procedures Periodic drills and safety meetings Operating guidelines Wind socks and safe assembly areas Transportation and evacuation Part of the Risk Assessment process MMS or other Regulatory Agency H2S Contingency Plan Development & Approval API RP 55 can provide guidance on operations involving hydrogen sulfide and contains a table on the physiological effects of various concentrations. An example guideline on facial hair and corrective lenses as pertains to respiratory equipment could be: • • • • Clean shaven in the face-piece-sealing area and must not have facial hair that could interfere with the function of the mask. Before donning a respirator with a full face piece, any head covering, glasses and foreign items in the mouth must be removed Wearing contact lens with a respirator is not permitted. Prescription eyeglass wearers who are assigned to areas where full-face respirators may be required should be provided with a means of attaching the prescription lenses to the face mask. Hooded Egress Units allow for the use of prescription eyeglasses during emergency evacuations. Guidelines For Drilling For all operations where H2S is being produced on the platform or where H2S may be encountered while drilling, a contingency plan will be developed and approved by the applicable regulatory agency as required. Hydrogen sulfide monitoring should be continuous while drilling anywhere covered by the contingency plan. Monitoring should be done with remote sensors which are located at a minimum near the bell nipple, on the rig floor, and above the shale shaker. Gas trap gas and vulnerable areas may also be monitored. The approved contingency plan will have details on where sensors should be placed. Maintenance and logged calibration is important. At the first indication of H2S, confirmation should be made with a hand held meter. If drilling in a H2S area, Garrett Gas Train sulfide readings on the mud filtrate will also be required. It is advisable to start five drilling days before entering predicted hydrogen sulfide zones to establish background concentrations. Draeger has recently changed the scale on their tubes, and the tube factor given in API RP 13B-1 should be carefully checked to ensure the tube factor matches the tubes being used. 4.15 HYDROGEN SULFIDE CONTINGENCY PLAN A typical hydrogen sulfide contingency plan has three phases: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 19 of 20 DRILLING OPERATIONS If the measured H2S levels is ten ppm or less, but greater than zero then, • • • Continue normal drilling Sensitize crew with drills and safety meetings Ensure H2S scavenger (zinc basic carbonate) is on location and discuss its addition to the mud system • • • • • • Maintain mud pH at 9.5 or higher Consider increasing the number of air packs on location Check calibration of sensors Limit visitors and unnecessary personnel on location Check igniter on gasbuster flare line Driller and mud loggers to keep in communication If the measured H2S level is twenty ppm or less, but greater than ten ppm then, • Suspend drilling operations and make an effort to suppress the H2S before proceeding with drilling. • Sound H2S alarm and illuminate flashing light • Rig crew immediately dons breathing apparatus and stops circulation to control source of hydrogen sulfide. Driller is to know if the well is to be shut in. Notify toolpusher and ECI drilling supervisor All non-essential personnel proceed to upwind assembly area. No non-essential personnel will be allowed in any area with possible H2S exposure. • • • • • • Conduct safety meetings and review plans to return to drilling. Plan response in the event hydrogen sulfide concentration exceeds twenty ppm. Repeat safety meeting before crews come on tour. All personnel check their safety equipment for proper operation and location. Persons without assigned breathing equipment cannot work in the Hazardous area. Treat mud with scavenger as necessary Notify the operations superintendent before returning to drilling Use the 'Buddy System' – no individual is to be allowed to work in affected areas by themselves If the measured H2S levels greater than twenty ppm then, • Sound H2S alarm • • • Rig crew dons breathing apparatus and closes in the well All personnel proceed to upwind safe assembly area Suspend drilling operations and reassess contingency plan with superintendent Guidelines For Well Control DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 20 of 20 DRILLING OPERATIONS In a kick situation, where H2S has previously been detected in the drilling fluid filtrate or by mud logging gas analysis, all personnel directly involved with the operation are to have readily available individual self contained breathing apparatus (SCBA). All other personnel are to be alerted and made aware of the designated safe briefing area(s) to be used during the well killing operation. During the kick circulation, the above personnel are to don their SCBA's, as a minimum, 30 minutes prior to the calculated arrival time of the kick fluid and remain in the SCBA's until 30 minutes after the kick fluid is vented down the flare line. Attempt to burn the kick gas if conditions allow, and appropriate Regulatory Approvals have been obtained. During the entire kick circulation, a designated member of the drill crew is to check (with a SCBA on) the shaker area for H2S concentrations. Also, the return drilling fluid is to be monitored for H2S throughout the entire well killing operation. If at any time during the kick circulation, H 2S concentration exceeds 20 ppm or more in the working atmosphere (air), the well is to be shut in and non-essential personnel are to be moved into the safe briefing area(s) or evacuated (depending upon the concentration of H2S ). In the event of any well control situation in which the occurrence of H2S is probable, considerations are to be made for bullheading the formation fluid back into the formation, rather than circulating the kick out and releasing the H2S at the surface. Guidelines For Coring And Production Testing Refer to Sections 8 and 12 of this manual for information/guidelines regarding H2S in coring and production testing operations. If working on a well with hydrogen sulfide gas, all workers in the area should mask up while retrieving the back pressure valve. BIT CLASSFICATION AND HYDRAULICS 5.0 BIT CLASSIFICATION AND HYDRAULICS 5.1 5.2 5.3 5.4 5.5 5.6 5.7 5.8 Reference General Drill Bits IADC Bit Classification System IADC Bit Grading System Running Procedures for Fixed Cutters Hydraulics Program Guidelines for Hydraulics Optimization Hydraulics Optimization DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 21 of 20 DRILLING OPERATIONS ______________________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION - MAY, 2003 5.1 GENERAL The Drilling Program shall specify a recommended bit selection and hydraulics program based on offset well data and (or) anticipated drilling conditions. The bit and hydraulics programs specified in the Drilling Program are to be viewed as guidelines only and adjustments are to be made as necessary in the field to account for actual drilling conditions. 5.2 DRILL BITS Bit Operational Guidelines 1. Establish optimum bit parameters early in the bit run. Drill-Off Tests should be used to determine the point at which ROP begins to decrease with increasing WOB. The flounder point in the drill-off test is the WOB at which the bit is beginning to ball. It may be possible to increase the WOB and ROP if bit cleaning is improved. Options for improving bit cleaning are increased hydraulics, reduced blades on PDCs, mud additives (ROP enhancer) if MW < 10 ppg, and inhibitive mud. Vary weight on bit (WOB) and rotary speed (RPM) as required to maintain maximum performance, taking into consideration abnormal pressure detection requirements, high drill gas, and the carrying capacity of the mud (ability to remove cuttings efficiently). 2. When drilling near anticipated abnormal pressure zones, the drilling parameters are to be maintained constant to allow for more accurate pressure detection. 3. Monitor bit ROP trends to determine when the break even point, based on increasing cost per foot, has been reached. Cost Per Foot (CPF) = Bit Cost + Rig Cost (Trip Time + Drilling Time) Footage Drilled 4. Use the automatic Driller, if available, when drilling below surface casing. 5. Grade each bit for wear and damage according to the IADC Dull Bit Grading System presented at the end of this section. Bit Selection The selection of bits provided to the Drilling Rig should be sufficient to cover a wide range of drilling conditions. The following guidelines are given for bit selection: 1. Bit selection will generally call for the most aggressive bit that will stand up to the anticipated lithology. Soft formation mill tooth bits will generally be the bit of choice for surface hole drilling. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 20 DRILLING OPERATIONS 2. Sealed bearing (and possibly journal bearing) tooth bits will generally be recommended for drilling the soft surface hole sediments in an attempt to drill this section in one bit run. 3. In deeper hole sections, where multiple bit runs are required, bit selection is to be based on bit performance optimization, unless potential upcoming operations (coring, intermediate logs, casing seat hunt, etc.) dictate otherwise. BIT SELECTION CHART FORMATIONS CHARACTERISTICS IADC BIT CLASSIFICATION TYPE st st 1 CHARACTER ROCK PDC M(S)1 M(S)2 M(S)3 S(M)4 DIAMOND 5 M(S)1 M6 M7 SOFT TO MEDIUM: Low Compressive strength interbeded with hard layers. Sand, Shale, Anhydrite, Soft Sandstone and Soft Limestone, Shaley Limestone 1 MEDIUM: Hard with moderate compressive strength. Shale, Chalk, Sand, Anhydrite, Shaley Limestone, Soft Limestone with Hard Streaks. Shale, Siltstone, Sand, Lime, Anhydrite, Dolomite, Calcareous Sandstone, Sandstone with Chert & Pyrite Streaks Sand, Siltstone, Quartzite, Granite, Dolomite, Chert Conglomerates, Abrasive Sandstone & Limestone. Quartz, Sandstone Conglomerates, Volcanics such as Basalt, Gabbo, Rholite, Granite. 2 EXTREMELY HARD: Very hard and abrasive. FIXED CUTTERS INSERT 4 Clay, Marl, Gumbo, Red Beds, Unconsolidated Sands & Shales, Halite HARD: Hard and dense with high compressive strength, some abrasive layers. CHARACTER BITS TOOTH 1 SOFT: Sticky, Low compressive strength and high drillability. MEDIUM TO HARD: Dense with increasing compressive strength but non or semi-abrasive. nd 1 &2 M(S)2 M(S)3 M(S)4 6 M(S)2 S(M)3 M(S)4 2 6 M2 M(S)3 M(S)4 3 7 M3 M4 8 M6 M7 M8 M6 M7 M8 M6 M7 M8 M7 M8 The table above correlates formation characteristics against bit type based on the IADC bit classification system. Although this is fairly straight forward for rock bits, it is more nebulous for fixed cutter bits (in particular, the PDC variety). PDC usage has only come into its own in the last few years; compared to rock bits this technology is still in the "toddler stage". Consequently, a good, compressive, clear-cut classification system has not yet been developed. To classify the fixed cutters, the World Oil’s 1995 Drill Bit Classification Tables were reviewed DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 20 DRILLING OPERATIONS to determine which bit types were recommended by manufactures for a particular formation. The bold characters indicate The bit classification which appears most often under a particular formation. The relative size is secondary indication of how often a particular bit type is recommended. A comprehensive discussion of the IADC classification system follows. 5.3 IADC BIT CLASSIFICATION SYSTEM IADC Bit Classification The IADC Bit Classification System identifies bits using a numbering system. For roller cone bits, these numbers identify the formation/tooth type, degree of hardness within the basic formation and bearing type. For fixed cutter bits, the characters identify body material, PDC cutter density or Diamond size, PDC size or Diamond type, and bit profile. The IADC Bit Classification System is described below. Roller Cone Bits For example, a typical IADC classification for a roller cone bit is 1-1-1. First Character: Cutting Structure Series (1-8). Refers to formation characteristics. Within the steel tooth and insert groups, the formations become harder and more abrasive as the series number increases. Mill Tooth Bits (1-3) 1 - Soft 2 - Medium to Medium Hard 3 - Hard, Semi-Abrasive / Abrasive Insert Bits (4-8) 4 - Soft 5 - Soft to Medium 6 - Medium to Hard, Semi-Abrasive 7 - Hard, Semi-Abrasive/Abrasive 8 - Extremely Hard, Abrasive Second Character: Cutting Structure Types (1-4). Refers to the degree of hardness within a formation type. 1 - Softest formations => 4 - Hardest formations Third Character: Type of Bearing / Gage Protection (1-9). 1 = Standard Roller Bearing 2 = Roller Bearing, Air Cooled 3 = Roller Bearing, Gage Protected 4 = Sealed Roller Bearing 5 = Sealed Roller Bearing, Gage Protected 6 = Sealed Friction Bearing 7 = Sealed Friction Bearing, Gauge Protected DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 20 DRILLING OPERATIONS 8 9 = Directional = Other, Reserved For Future Use Fourth Character: Special Features (Alpha characters). Defines additional features of roller cone bits with regard to cutting structures, bearings, seals, hydraulics, and specific applications. A = Air Application (Journal bearing with air nozzles) B = Special Bearing Seal C = Center Jet D = Deviation Control E = Extended Jets (Full length) G = Extra Gage / Body Protection H = Horizontal / Steering Application J = Jet Deflection L = Lug Pads M = Motor Application S = Standard Steel Tooth Model T = Two Cone W = Enhanced Cutting Structure X = Predominantly Chisel Tooth Inserts Y = Predominantly Conical InsertsZ = Other Shape Inserts Fixed Cutter Bits: New (Current) IADC Classification: For example, a typical IADC classification for a fixed cutter bit is M-1-2-1. First Character: Body Material (Alpha Character). Refers to the type of body construction. M = Matrix or S = Steel (only two designations) Second Character: Cutter Density. For PDC bits this refers to total cutter count, including standard gage cutters. For Diamond bits this refers to diamond size. As with rock bits, the larger the number the more suited for harder more abrasive applications. PDC Bits (1- 4) Designation of 1 represents a light set while 4 represents a heavy set. Cutter count is based on 1/2" cutter size, cutter (larger/smaller) sizes are projected as 1/2" cutter densities. 1 2 3 4 = 30 or fewer 1/2" cutters = 30 to 40, 1/2" cutters = 40 to 50, 1/2" cutters = 50 or greater 1/2" cutters DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 20 DRILLING OPERATIONS Diamond Bits (6 - 8) A designation of 6 represents larger diamonds while 8 represents smaller diamonds 6 7 8 = < 3 stones per carat = 3 to 7 stones per carat = > 7 stones per carat Note:(0, 5, & 9) are undesignated and reserved for future use. Special designs using additional gage cutters, such as sidetrack bits, or bits for horizontal drilling, are not considered for the purpose of classification. Third Character: Size or Type of Cutter. For PDC bits, the third character refers the size of the cutter while for Diamond bits, it refers to the type diamonds. PDC Bits (1- 4) Size 1 = > 24mm in diameter 2 = 14mm to 24mm in diameter3 = 9mm to 13mm in diameter 4 = < 8mm in diameter Diamond Bits (1- 4) Type 1 = Natural Diamonds 2 = TSP (Thermally Stable Polycrystalline) Diamonds 3= Combination Cutters (such as natural diamond and TSP) 4 = Impregnated Diamond Bit (Applies only the highest density Bits) Fourth Character Profile or Body Style. Gives an idea of the basic appearance of the bit, based on overall length of the cutting face of the bit. PDC Bits (1- 4) 1 = Fishtail 2 = Flat Face 3 = Long bit profiles 4 = Increasingly longer bit profiles Diamond Bits (1- 4) 1 = Flat Face TSP and Natural Diamond 2 = Long 3= Longer 4 = Increasingly Longer Old IADC Classification: For example, a typical IADC classification for a fixed cutter bit is D-2-1-2. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 20 DRILLING OPERATIONS Letter: Cutter Type and Body Material D = Natural Diamond S = Steel Body PDC O = Other (TSP) M = Matrix Body PDC T = Thermally Stable Polycrystalline First Number: Bit Profile (Gauge Point to Cone) 1 = Long Taper, Deep Cone 2 = Long Taper, Medium Cone 3 = Long Taper, Shallow Cone 4 = Medium Taper, Deep Cone 5 = Medium Taper, Medium Cone 6 = Medium Taper, Shallow Cone 7 = Short Taper, Deep Cone 8 = Short Taper, Medium Cone 9 = Short Taper, Shallow Cone Second Number: Hydraulic Design Type Body Changeable Jets Fixed Ports Open Throat Bladed 1 2 3 Ribbed 4 5 6 Open Faced 7 8 9 Alternate designations: R = Radial Flow, X = Cross Flow, O = Other Third Number: Cutter Size and Density Cutter Size Light Density Med. Density Heavy Density Large 1 2 3 Medium 4 5 6 Small 7 8 9 Impregnated 0 0 0 Note Size Distribution Definitions 5.4 Small Greater than 7 stones/carat for natural Diamond. Less than 3/8" diameter of usable height for PDC bit. Medium 3 to 7 stones/carat for natural diamond. 3/8" to 5/8" diameter of usable height for PDC bit. Large Less than 3 stones/carat for natural diamond. Greater than 5/8" diameter of usable height for PDC bit. IADC BIT GRADING SYSTEM DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 20 DRILLING OPERATIONS I.A.D.C. DULL BIT GRADING CODES CUTTING STRUCTURE INNER ROW 1 B OUTER ROW DULL CHAR. 2 3 (1) CUTTING STRUCTURE - INNER Inner 2/3 of bit. STEEL TOOTH BITS - A linear measure of lost cutting structure due to abrasion or damage. (0 no loss of cutting structure due to abrasion or damage, 8 - total loss of cutting structure due to abrasion or damage. (3) MAJOR DULL CHARACTERISTIC (These codes are also ROLLER CONE used for Column 7) * BC - Broken Cone N- Nose Row M - Middle Row G - Gage Rows A - All Rows LOCATION 4 G BEARING SEALS 5 INSERT BITS - A linear measure of lost, worn and/or broken inserts. (0- no loss, worn and/or broken inserts, 8-all inserts lost, worn and/or broken.) (4) LOCATION DIAMOND C - Cone N - Nose T - Taper S - Shoulder G - Gauge A - All Areas GAUGE 1/16" OTHER CHAR. 6 7 (2) CUTTING STRUCTURE - OUTER Outer 1/3 of bit. NON-SEALED BEARINGS A linear scale estimated bearing life used. (0 - no life used, 8 - all life used, i.e., no bearing life remaining REASON PULLED 8 DIAMOND, PDC and/or TSP BITS - A linear measure of lost, worn and/or broken cutting structure. (0-no loss, worn and/or broken cutting structure, 8-all of the cutting structure is lost, worn, and/or broken. (5) BEARING/SEALS CONE # OR #'S ROLLER CONE 1 2 3 REMARKS SEALED BEARING E - indicates seals effective F indicates seals failed X - indicates Fixed Cutter Bit BT - Broken Teeth/Cutters BU - Balled Up Bit (6) GAUGE I - in gauge 1/16 - 1/16" out of gauge 2/16 - 1/8" out of gauge 10/16 - 10/16" out of gauge (8) REASON PULLED BHA - Change Bottom Hole Assembly *CC - Cracked Cone DMF - Downhole Motor Failure DTF -Downhole Tool Failure DP - Drill Plug *CD - Cone Dragged DSF - Drill String Failure CI - Cone Interference DST - Drill Stern Test CR - Cored CM - Condition Mud CT - Chipped Teeth/Cutters ER - Erosion CP - Core Point FC - Flat Crested Wear HP - Hole Problems HC - Heat Checking HR - Hours JD - Junk Damage LN - Lost Nozzle *LC - Lost Cone LOG - Run Logs LN - Lost Nozzle LT - Lost Teeth/Cutters PN - Plugged Nozzle/or Fluid Passage PR - Penetration Rate OC - Off-Center Wear RP - Pump Pressure PB - Pinched Bit RR - Rig Repair PN - Plugged Nozzles/ Flow Passage RG - Rounded Gauge TD - Total Depth/CSG Depth TW - Twist Off - drill string RO - Ringed Out TQ - Torque SD - Shirttail Damage WC - Weather Conditions SS - Self Sharpening Wear WO - Washed Out - drill string FM - Formation Change TR - Tracking WO - Washed Out WT - Worn Teeth/Cutters NO - No Major/Other Dull Characteristic * - shown cone # or #’s under location 5.5 RUNNING PROCEDURES FOR FIXED CUTTERS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 20 DRILLING OPERATIONS The following are general guidelines to be used when running fixed cutter (PDC and Diamond) bits. PREPARING THE HOLE: • • • • Use PDC drillable float equipment. Inspect previous bit for junk damage and gage wear. Make cleanout trip if necessary with junk basket. MAKE SURE HOLE IS CLEAN. PREPARING THE BIT: • • • • • • Transport bit in box to the rig floor to avoid cutter damage. Carefully remove bit from the box. Do not set bit directly on steel decking. Use wood or a rubber mat. Inspect bit for damage. Record bit serial number. Check O-rings, nozzles, and bit gage (not applicable for diamond bits). Check inside bit for obstructions or foreign matter. MAKING UP THE BIT: • • • • Fit bit breaker to bit and engage latch. Clean and grease pin. Lower drill string to top of pin and engage threads. Locate bit and breaker in rotary table and make up to recommended torque. TRIPPING IN THE HOLE: • • • • • • • Remove bit breaker and carefully lower bit through the rotary table. Trip carefully through BOPs, casing shoes, and liner hangers. Trip slowly through ledges, dog legs, and tight spots. Wash last three joints to bottom with full flow at 50 - 60 RPM. Approach bottom observing weight indicator and rotary torque. Tag bottom gently and pick up 6 - 12 inches off bottom. Circulate 5 - 10 minutes with full flow at 50 - 60 RPM. REAMING: REAMING UNDERGAGE HOLE IS NOT RECOMMENDED. Ream tight spots with full flow to keep cutters cool. Use 2,000 - 4,000 pounds WOB and 50 - 60 RPM. REAM SLOWLY - AVOID HIGH TORQUE. BIT BREAK IN: • • • • • Lower bit to bottom with full flow at 60 - 80 RPM. Use of a motor will result in a higher rotation speed. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 20 DRILLING OPERATIONS • • • • • Compare expected vs. actual hydraulics. Record stand-pipe pressure and pump strokes. Drill a bottom hole pattern with 2,000 - 4,000 pounds WOB. BREAK BIT IN SLOWLY - DO NOT GET IN A HURRY. After three feet, add weight in 2,000 pound increments and increase rotary to optimum RPM. DRILLING AHEAD: • • • • • Determine optimum drilling parameters by changing WOB and RPM within recommended guidelines. Conduct drill-off tests to maximize ROP. Do not hesitate to adjust drilling parameters. Rotary torque should approximate that of rock bits at equal ROP and WOB. Faster ROP will normally result in higher torque values. If torque or RPM cycling is severe, control with lighter WOB or increased RPM. MAKING CONNECTIONS: • • • • After making a connection, lower to bottom slowly with full flow and 50 - 60 RPM. Check standpipe pressure and pump strokes on and off bottom. Increase RPM to previous level and add weight slowly. DO NOT JAM THE BIT BACK ON BOTTOM. PULLING OUT OF THE HOLE: • • • • • 5.6 Slow down through tight spots, casing shoes, liner hangers, and BOPs. Attach bit breaker and break out bit in rotary table. Avoid cutter damage when removing bit. Do not place bit directly on rotary table. Return bit to box after dull evaluation. HYDRAULICS PROGRAM The recommended hydraulics program for each hole section will be specified in the Drilling Program based on predicted drilling parameters such as mud weight, BHA configuration, pump capability, pressure losses, etc. Bit hydraulics are to be recalculated onboard the Drilling Vessel based on actual parameters. This design has three flow regions based on the critical flow rate QCrit, the flow rate at which the total available horsepower is utilized at the maximum allowable surface pressure, PSurf. CASE I: Unlimited surface pressure (conditions not limited by surface pressure constraints). Flow rates are high and surface pressure is low. In this region hydraulic impact is maximized when 74% of the available pressure is expended at the bit with flow rate above QCrit. This condition usually occurs at shallow depths in the conductor and surface casings sections of the hole where the total pressure losses in the system are low. Often larger liners and/or changes are not justified for the fast top DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 20 DRILLING OPERATIONS hole, precluding optimum hydraulics until drilling below surface hole. High flow rates are the parameter to key on. ∆PBit = 0.74 PSurf Flow Rate > QCrit CASE II: Intermediate between Case I & Case II. Flow rate remains constant while circulating pressure increases with depth. In this region the circulation rate remains constant at QCrit while surface pressure increases until 48% of the maximum allowable pressure is expended at the bit. This condition usually occurs in the intermediate/protective casing section of the hole. ∆PBit = (0.48 to 0.74) PSurf Flow Rate = QCrit CASE III: Limited surface pressure (conditions are limited by the maximum allowable surface pressure, Pmax). Surface pressure remains constant while circulating rates are reduced. In this region hydraulic impact is maximized when 48% of the maximum allowable pressure is expended at the bit. This condition usually occurs in the deeper section of the hole below surface or protective casing. Often a change in liner size is required below protective casing. ∆PBit = 0.48 PSurf Flow Rate < QCrit In the past ExxonMobil generally used the Reed Log-Log Graphical Method to calculate optimum rig hydraulics as described above. A detailed discussion of this method can be found in the EUSA Drilling Engineering School Manuals and the old EUSA Drilling Operations Manual (the Red Book). Currently the Reed Hydraulic computer program is utilized. Hydraulic Equations HHP = (HP)(Em)(Ev) HHP = (P)(Q) 1714 QCrit = 1714(HHP) PSurf VN = 0.32(Q) A2 ∆PN = (MW)(Q)2 12042(Cd)2A2 FB = (MW)(VN)(Q) 1932 AV = 24.5(Q) (DH)2 - (DP)2 Where: A AV Cd DH = = = = 2 TFA, total flow area of the nozzles (in ) Annular Velocity (fpm) Nozzle coefficient = 1.03 Diameter of the hole (in) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 20 DRILLING OPERATIONS 5.7 DP = Diameter of pipe in hole (in) Em = Mechanical efficiency of mud pump (%) Ev = Volumetric efficiency of mud pump (%) FB = Hydraulic impact force at the bit (lbs) HP = Input horse power from mud pump performance tables (hp) HHP = Mud pump output hydraulic horse power (hp) MW = Mud weight (ppg) P = Circulating pressure, standpipe pressure (psi) ∆PN = ∆PBit, pressure drop across the bit nozzles (psi) PSurf = PMax, maximum allowable circulation pressure (psi) Q = Circulating rate (gpm) QCrit = Circulation rate at which total available horsepower is utilized at the maximum allowable surface pressure, PSurf (gpm) VN = Nozzle velocity (fps) GUIDELINES FOR HYDRAULICS OPTIMIZATION The following guidelines, recommendations, and rules-of-thumb are intended to provide a means for monitoring conditions at the rig and to get a feel for how well things are going. They are not "the answer" but flags only, indicating whether further scrutiny is needed or as a starting point for hydraulic program planning Hole Cleaning The main symptoms of poor hole cleaning depends largely on hole angle. At low angles (< 20 ) the cuttings tend to fall downhole as soon as the pumps are stopped. The best sign of poor cleaning is fill on bottom, either on connections or after tripping. In extreme cases it may be difficult to pull off bottom with the pumps off. At high angles (>50 ) the cuttings fall to the low side of the hole forming a stationary cuttings bed. There is typically no fill on bottom and no trouble making connections. The main evidence of poor hole cleaning is seen on trips. The string may pull tight or get stuck off bottom while attempting to pull through this cuttings bed. At intermediate angles (40 60 ) the cuttings fall to the low side of the hole forming a cuttings bed. This bed is not stationary; consequently, when circulation is stopped the cuttings bed may begin to slide (avalanche) downhole. Symptoms of poor hole cleaning for the intermediate angle case, will range between those seen for the low angle and high angle wells. In any event, if the drag gets high, RIH 2-3 stands, put the top drive on and circulate and rotate at maximum allowable rates until the hole is cleaned up; don't try to pull through tight spots. It may be necessary to pump out or back ream out of the hole in the higher angle wells. Backreaming out of the hole requires Operations Superintendent approval. Utilizing a bit with a cross sectional area as low a possible, or an open area as high as possible, will provide benefits when tripping through intermediate and high angle hole cuttings beds. Carrying Capacity Index (CCI) For low angle and intermediate holes up to 35 , the CCI still appears to be the best indicator of hole cleaning. There is no mathematical derivation for CCI; field observations indicate that the numerical product of K, annular velocity, and mud weight should equal or exceed 400,000 for DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 11 of 20 DRILLING OPERATIONS good hole cleaning. The carrying capacity of a mud depends upon the difference in density between the cuttings and the drilling fluid, the annular velocity, and the viscosity of the fluid in the annulus. As any one of these numbers increases, the carrying capacity of the mud increases. NOTE: The CCI is only meaningful when circulating. A suspension capacity of the drilling fluid is also needed for making concoctions and immobilizing cuttings in washouts during trips. Adequate gel strengths are needed for trips. CCI = (MW)(K)(AV) 400,000 Good hole cleaning occurs when CCI > 1 K = (511)1-n (PV+YP) Where: MW = Mud Weight (ppg) AV = Annular Velocity (fpm) n = 3.322 log PV+YP 2PV+YP PV = Plastic Viscosity (cp) YP = Yield Point (lb/100 ft2) The K is the consistency index which corresponds to the viscosity of the mud at a shear rate of one reciprocal second, and n is the measure of the non-Newtonian flow behavior in the power law rheological model, SS = K (SR)n. The following graph provides a graphical solution for the K value utilizing PV and YP of the mud. Graphical Solution for Low Shear Rate Viscosity - K Hole Cleaning Ratio (HCR) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 12 of 20 DRILLING OPERATIONS For intermediate and high angle holes which develop cuttings beds, EMURC has developed a parameter called the Hole Cleaning Ratio (HCR) that is highly correlative with hole cleaning problems. Because of the many drilling variables and the complicated physical system involved, the simple "Recommended Annular Velocity" table which appeared in past EPR literature is no longer endorsed. In its place, EMDRC has developed a new tool from fluid mechanics theory, published laboratory data, new experimental data, and field data that provides an optimal combinations of drilling variables for efficient hole cleaning. It has been used for planning or well design to predict the likelihood of encountering hole cleaning problems based on drill string design (bit design, hole size, collars, drill pipe), drill pipe rotating speed, drilling fluid rheology, flow rates, and well profile. EMURC is currently developing a PC program for surveillance in the field. HCR = H/Hcrit. Good hole cleaning occurs when HCR > 1.1 Where: H = the equilibrium height of the free region over the cuttings bed and is a function of the variables listed in figure 1. below. Hcrit = the critical height is a primarily a function of bit geometry. Hole Cleaning Ratio (HCR) DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 13 of 20 DRILLING OPERATIONS (continued) Hole Cleaning Operations (Intermediate and High Angle Holes) Based on this work, the following pump out procedure is recommended for the deviated portion of the wellbore where problems due to cuttings bed are suspected. • Monitor torque and drag using the Torque & Drag Surveillance spreadsheet. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 14 of 20 DRILLING OPERATIONS • Circulate and rotate drillpipe at the maximum allowable flow/recommended rate prior to starting the trip. Experience has shown that 2 to 3 bottoms up volumes may be needed to clean the hole enough for tripping. If sidetracking is possible, move the bit slowly over a short interval • Rotate will help stir up and remove cuttings beds especially if lots of sliding is done. Refer to EMDC Technology Group for detailed guidelines. • In the deviated section, POH slowly as detailed in the drilling procedure (~2-1/2 to 3-1/2 minutes per stand). • If excess drag is indicated, stop pulling, slack off 1 joint, then circulate and rotate at least one bottoms up at the maximum allowable flow rate. Rotating aids significantly to hole cleaning in high angle holes (normal practice is 100-120 rpm). • Then, if a top drive is available, pump out of the hole at the maximum allowable/recommended flow rates while pulling at 2-1/2-3-1/2 minutes per stand or longer, continue until hole frees-up. • Once in the lower angle section of the wellbore (preferably inside casing), circulate at least two bottoms up at the maximum allowable flow rate until cuttings returns decrease. • Once the hole is clean, finish POH without pumping. For drilling operations with extended hole sections above 45 , backreaming may be necessary. Operational details will be provided in the applicable drilling procedure. Ensure that the dangers of backreaming in high-angle holes are thoroughly discussed prior to beginning the well so that everyone is clear on the strategy to be used. Rules-of-Thumb • 1. Flow rate: Normally offshore drilling flow rates fall between 50 to 70 GPM per inch of bit diameter. However, flow rates greater than 70 GPM per inch of bit diameter are not unheard of in high angle wells. • Do not sacrifice flow rate to get more horsepower, jet velocity, or bit pressure drop. • Too low a flow rate will ball the bit and reduce effective hole cleaning. • The annulus flow rate is too low to cause erosion. However, nozzle velocities which are typically 200-400 ft/sec may cause enlargement in low strength rock (<1,500 psi). Limit nozzle velocity to <400 fps in soft rock. • Fast drilling with low mud weights requires a minimum of 50 GPM per inch of bit diameter for holes < 20 ; higher angle holes may require more. 2. Hydraulic Horsepower: borehole area (HHP/in2). • Maintain 2 to 7 hydraulic horsepower per square inch of PDC bits with OBM require less HHP/in 2 than with WBM. Total flow rate is more important when drilling with PDC bits and OBM than HHP/in2 . DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 15 of 20 DRILLING OPERATIONS • Fast drilling generally requires high HHP/in 2 ; however, some PDC bits in OBM can get by with as little as 2 HHP/in2. • Larger bits require more HHP. However, many times in larger hole sizes high HHP is not possible. In these cases, pump the maximum volume possible. • Maximum HHP/in2 should be considered only when excess pump horsepower is available. 3. Bit Pressure Drop: When operating below QCrit, design hydraulics for 48% to 65% pressure drop across the bit; this is usually the case below surface casing. • Optimum Hydraulic Impact occurs when 48% of the system pressure loss is at the bit while optimum Hydraulic Horsepower occurs with 65% of the loss at the bit. • If the total of drill string and annulus pressure loss is greater than 52% of the available pump pressure, smaller nozzles are required. However, do not operate below 30 GPM per inch of bit diameter. Consider using larger drill pipe. • When running a PDM, it is recommended that the differential pressure across the bit not exceed 1000 psi to prevent accelerated wear of the rotor / stator assembly. 4. Jet Velocity: Good jet velocities are typically between 350 and 450 feet per second (use less than 400 fps in very soft rock to avoid washout). 5.8 • Jet velocity will influence chip hold down and ROP. Hydraulics Optimization (GOM Drilling for reference) Except in extremely soft rock, hydraulics don t literally drill. However, they do clean the bit so that cuttings build up does not start to carry the WOB that should be on the teeth (balling). Hydraulics extend the flounder point, which is the point at which the bit starts to ball. 1. In high ROP, directional, the primary hydraulic design criteria is hole cleaning. Optimum hydraulic horsepower at the bit can be utilized to provide effective cleaning of the bit. 2. Hydraulic optimization should be determined by the performance of the rig equipment and the results of the previous bit run(s). 3. Bit nozzles should be at least 12/32" to avoid plugging for normal drilling operations and ≥14/32" if lost returns are anticipated. MWD equipment and motors may also need to be specially designed if lost returns are anticipated to prevent plugging the drillstring with LCM. Downhole screens have been used if no nuclear source tools are being run. Use of any downhole or surface drill pipe screen must be approved by the Operations Superintendent. 4. In soft, unconsolidated formations, limit jet velocity to minimize hole wash-out (<400 fps) 5. In fast drilling and high angle holes, maximize flow rate for better hole cleaning. 6. Carefully analyze ECDs and frac gradients to determine appropriate circulation rates. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 16 of 20 DRILLING OPERATIONS 7. Frequently in GOM drilling operations, PDC bits are capable of ROPs in excess of our ability to clean the hole. For these situations, it is critical to optimize RPM and hydraulics to effectively clean the hole, not necessarily maximize ROP. Utilize HOLECLEAN software to achieve hydraulics design with HCR > 1.1. 5.9 REFERENCE MATERIAL: Bit Classification 1. 2. 3. 4. 5. World Oil’s 1995 Drill Bit Classifier. Trinidad’s Drilling Operations Manual, Drilling Operations Section, Page 2-7.„ Gulf of Mexico’s Drilling Operations Manual. Hughes Tool Company, Dull Bit Grading Codes chart. IADC Drilling Manual, Eleventh Addition, Chapter A, Section 2, Page 2&3; Section 3,Page 1; Section 4, Page 3&4. 6. EPR Drilling Mechanics, Section 4-Roller Cone Bits, Page 34. 7. Hycalog’s Fixed Cutter Handbook. 8. Geology, A Golden Guide, Frank H. T. Rhodes, Classification of Igneous Rocks Hydraulics 1. 2. 3. 4. EUSA Drilling Engineering School Manual, Hydraulics Section. EUSA Drilling Operations Manual (The Red Book) Rig Hydraulics Section. EPR Directional Drilling Workshop for ECI, Surveillance and Follow-Up Section. IADC/SPE Paper 27464 Hole Cleaning in Large, High-Angle Wellbores, Marco Rasi, EPR 5. Drilling Practices Manual, Preston L. Moore, Chapter 10-Hydraulics in Rotary Drilling. 6. Randy Smith Drilling School Handbook, TRUE-Well Plan Sec., Hydraulics Planning. 7. Reed Tool Company Hydraulics Program Manual. 8. Reed Tool Company Hydraulics Slide-Rule and Pump Performance Charts. 9. IADC Drilling Manual, Eleventh Addition, Chapter R, Section 13, Page 1. 10. Trinidad’s Drilling Operations Manual, Drilling Operations Section, Page 2-7. (available from R. E. Rivers (EMDC) 11. Dr. Leon Robinson’s Drilled Solids Management Seminar. DRILLING FLUID SYSTEM 6.1 DRILLING FLUID SYSTEM 6.2 General 1 6.3 Solids Control 1 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 17 of 20 DRILLING OPERATIONS 6.4 Drilling Fluid Treatments 3 6.5 Drilling Fluid Checks 5 6.6 High Temperature Drilling 6 6.7 Stuck Pipe Pills 6 6.8 Lost Circulation 7 6.9 Non-Aqueous Fluid Operations 15 6.10 Rig-Site Dielectric Constant Measurement 33 6.11 Drilling Fluid System Guidelines 34 Appendix G-I Fluid Transfer Checklists Appendix G-II NAF/Oil Base Mud Readiness Checklist ______________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003 6.1 GENERAL The most efficient drilling fluid system depends on a balance of cost (material and rig time), wellbore stability needs, formation characteristics and environmental issues. An effective drilling fluid system minimizes the number of different chemical components necessary to achieve the drilling fluid properties specified in the Drilling Program. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 20 DRILLING OPERATIONS Check local requirements for material to keep on hand. Drilling program development will incorporate an understanding of contingencies based upon the results of risk analysis in material types and requirements through the numerous stages of a well. 6.2 SOLIDS CONTROL Maintaining control of the low gravity solids content in any drilling fluid will maximize the performance of the drilling fluid system. The two common ways to maintain solids control are: (1) solids control equipment and (2) dilution. A balance between the two methods is necessary to maintain a drilling fluid system in a cost effective manner. Except when the drilling fluid is unweighted, the most economical method of solids control is to use solids control equipment. This requires maintaining the solids control equipment in optimum condition so that it performs in accordance with the manufacturer's specifications. However, solids control equipment is not 100% efficient and some solids control by dilution is always required. Shale shakers are the most efficient way to remove solids. They see the drilling fluid immediately as it comes out of the hole before the cuttings are reduced in size by the surface processing equipment. Use of high quality shakers, with fine screens maintained per the manufacturer's recommendation, is the most cost effective method of removing solids. A centrifuge is usually economical in high weight mud (> 14 ppg) or in low weight mud if the liquid phase is expensive (some polymer muds or non-aqueous muds). Dilution is the most costly method of solids control when using a weighted drilling fluid (> 11.0 ppg). Dilution Guidelines 1. Maintain the low gravity solids as specified in the Drilling Program primarily by the use of solids control equipment and only dilute when necessary. Some dilution is required on most muds. 2. If direct additions of dilution water are made to the active system, be aware that mud additives will also be needed to keep mud properties constant. 3. Dilute the active system to the desired solids content in one circulation by partial displacement (discarding a portion of the active mud system prior to diluting with whole mud). Note that mud discharges are usually regulated by the local governing bodies. Do not exceed maximum hourly mud discharge rate and always ensure that appropriate discharge conditions are met prior to discharge. 4. Dilute the active system prior to weighting up the drilling fluid to avoid dilution of higher cost drilling fluid. 5. Monitoring of the mud's particle size in light or unweighted mud may drive the decision to dilute more aggressively. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 20 DRILLING OPERATIONS Dilution - Premixed Drilling Fluid The advantages of using premixed drilling fluid (whole mud) when diluting the active system are as follows: • • • Easier for Drilling Fluids Engineer to keep up with product concentrations. Provides a more even concentration of chemicals in the drilling fluid system. Reduces the need to add bulk materials (salt, barite) to the active system while circulating. The disadvantages include: • • • Adding product that is not needed Prevents the practice of letting mud property trends drive which materials are used Ties up mud pit space continuously. Shale Shaker Guidelines 1. Use shale shakers as the primary means to control the solids content of the drilling fluid system. 2. Invest in a generous number of the newest technology shakers available. 3. Use screen sizes that enable the shale shakers to process the entire drilling fluid flow stream with the flow stream approximately two-thirds to end of screen. 4. Optimize solids removal by evaluating shaker screen sizes continuously and using the smallest screens possible considering the required pump rate and rate of penetration. 5. Keep shale shakers in good operating condition. Maintain proper screen tension and promptly replace torn screens. Corrugated ("Pyramid") style screens have proven effective for increasing processing capacity. Avoid using corrugated screens on the end panel or on any panel that is not mostly submerged. Hydrocyclones Guidelines 1. Use hydrocyclones continuously when circulating an unweighted drilling fluid in most situations. 2. Check cones every tour for plugging. 3. Ensure cones are operating in a spray discharge as much as possible. 4. Ensure that loss of drilling fluid from the bottom of the cones is not due to inlet plugging. 5. Feed rates to the hydrocyclones should be about 125% of the downhole pump rate. 6. Ensure cone inlet manifold has head gauge and is operating at 75 ft. of head. Mud Cleaner Guidelines DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 20 DRILLING OPERATIONS 1. Use a mud cleaner for weighted or expensive unweighted drilling fluids (high salt, PHPA polymers, etc.) only if high gravity solids to low gravity solids ratio, ppb, is less than 2 in the screen discharge (i.e. HGS, ppb < 150= 1.5). LGS 100 2. Check the cones every tour for plugging. 3. Ensure cones are operating in a spray discharge as much as possible. 4. Ensure that loss of drilling fluid from the bottom of the cones is not due to inlet plugging. 5. Wait one or two circulations before operating the mud cleaner when adding large quantities of barite to the system. 6. Running the mud cleaner when using screens finer than 180 mesh can result in excess discharge of barite. Typically, a mud cleaner is uneconomical when using screens over 180 mesh in high weight mud (>14 ppg). Centrifuge Guidelines 1. Feed the centrifuge with drilling fluid from the active system only. 2. Run the centrifuge only as much as necessary to maintain or restore acceptable mud rheology and filtration properties. 3. Do not exceed the maximum feed rate specified by the manufacturer. 4. Rinse and flush out the centrifuge after use to prevent damage from barite settling. 5. While drilling ahead, a centrifuge will not reduce LGS but will help maintain status quo. NOTE: Reference URC MANUAL -- Guidelines for the selection, use, and evaluation of Solids Control Methods. 6.3 DRILLING FLUID TREATMENTS Drilling Fluid Treatment Guidelines 1. Conduct a minimum of two (2) complete "In" and "Out" checks of the drilling fluid daily during drilling operations. 2. Process the drilling fluid returning from the wellbore so that the fluid properties of the drilling fluid going back into the hole are within the range as specified in the Drilling Program. 3. Pilot test any planned significant change to the drilling fluid system prior to making change. 4. Measure and record the drilling fluid weight and funnel viscosity on 15 minute intervals from the flow line and the suction pit. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 20 DRILLING OPERATIONS 5. Do Not add oil or any additive to the drilling fluid system that is not approved for discharge as long as fluid discharge is desired. 6. Notify the Driller and Mud Logger of planned changes to the active system volume. 7. Prehydrate all bentonite in fresh water before adding it to the active system in saltwater muds. 8. If available, use a shearing device to maximize yield of gel and polymers when prehydrating. 9. Mix all caustic additions in an enclosed barrel before adding to the active system (not from a hopper). 10. Presolubilizing all polymers in fresh water before adding to a high salt mud system is preferred. 11. Maximize utilization of all chemicals by pre-hydrating them in fresh water before adding to active system. 12. Ensure that hoppers are shut off when not in use for mixing. 13. Mud materials (especially bulk materials) should be periodically tested to assure that the qualities of the materials meet API standards, or the standards specified by the contract with the supplier. (i.e., specific gravity test for barite) Drilling Fluids Testing Equipment The Drilling Fluids Engineering Company is to maintain the following testing equipment on the rig: 1. One complete mud testing kit with testing chemicals and API press. 2. Six-speed Fann viscometer complete with heat cup. 3. HTHP filter press if appropriate for the mud type and downhole environment. 4. Digital pH meter and electrode and calibration buffers of pH = 7 and 10. 5. Pilot test kit complete with high speed Waring mixer (Hamilton Beach, Waring Blender or equivalent). 6. Portable roller oven and 2 - 3 heat-age cells. 7. Methylene blue test kit. 8. Pressurized mud balance complete with calibration kit. 9. Garrett Gas Train Kit for measuring carbonates and hydrogen sulfide for either a water mud or non-aquious fluid (NAF) if appropriate. Drilling Fluids Report Guidelines DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 20 DRILLING OPERATIONS The Drilling Fluids Engineer is to provide a Daily Drilling Fluids Report to the Operations Supervisor which includes the following: • Daily and Cumulative Usage of Drilling Fluid Products • Daily and Cumulative Costs of Drilling Fluid Products Used • Daily and Cumulative Dilution Volumes • Daily and Cumulative Drilling Fluid Volumes Lost (Estimated) Over Solids Control equipment, Lost Circulation, Or Not Accounted For in The Dilution Volumes • Cumulative Record of All Drilling Fluid Checks Properly Labelled as to Time and Depth of Bit 6.4 DRILLING FLUID CHECKS The Drilling Fluids Engineer is to make the following measurements for each mud check on a waterbase drilling fluid. • • • • • • • • • • • • • • • • • • • • • Drilling Fluid Weight Funnel Viscosity PV (Plastic Viscosity) @ 120º F YP (Yield Point) @ 120º F Rheometer Readings For 600, 300, 200, 100, 6, and 3 rpm Dial Readings at 120º F Gel Strengths @ 120º F (10 sec., 10 min., and 30 min.) API Water Loss at 100 psi and Room Temperature HTHP Fluid Loss at 500 psi Differential and Temperature Based on ExxonMobil mud program. Methylene Blue Test (MBT) pH Measurement Using a Digital pH Meter Pf, Mf, and Pm titrated with pH meter Chloride Content of Rig's Drill Water / Water additions (Barrels) Chloride Content for mud make-up water Chlorides and Total Hardness of mud filtrate Water, Oil and Solids Content (Retort) Low Gravity Solids Content / Sand Content KCl (wt%) and Potasium (mg/L) if using a KCl Drilling Fluid System PHPA (PPB) if using a PHPA Drilling Fluid System H2S if Specified in Drilling Program (Garrett Gas Train Measurement of Sulfides.) (mg/L) Carbonates using Garrett Gas Train (mg/L) Lime Content 6.5 HIGH TEMPERATURE DRILLING Hot Roll and Static Age Samples DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 20 DRILLING OPERATIONS Drilling muds can potentially have significant gelation problems when exposed to high temperatures for long periods. These problems can be especially acute in heavily weighted muds needed to drill abnormally pressured formations. The mud engineer or his assistant is to hot roll and static age mud samples at anticipated bottom hole temperatures on a frequent basis (minimum 1/week) any time static bottom hole temperatures exceed 250 degrees Fahrenheit. Unless otherwise specified in the Drilling Program, samples should be hot rolled for 12 hours and static aged for 24 hours both at estimated bottom hole temperature. Rheology, Gel strengths, pH, and HTHP fluid loss readings of the aged / hot rolled samples should be compared to pre-aged readings to evaluate the stability of the mud and to help determine if additional treatments are needed. 6.6 STUCK PIPE PILLS Stuck Pipe Pill Guidelines 1. For differentially stuck pipe, Mix a pill with a volume large enough to cover the BHA, including a 50% excess for hole washout, plus about 25-50 bbls. This volume is enough fluid to pump 0.5 - 1.0 barrel every 30 minutes for 24 hours. 2. Mix stuck pipe pills that are environmentally acceptable when practical. 3. Ensure that the hydrostatic pressure is not reduced below the pore pressure of the formation when displacing the pill. 4. Mix the pill in the slugging pit or reserve pit. 5. Spot the pill across the BHA as soon as possible using the cement pump. 6. Pump a barrel of spotting fluid every 30 minutes for 24 hours while jarring. 7. If a stuck pipe pill is to be premixed, ensure that it is rolled regularly to help prevent settling. This is especially important in high mud weight and in cold weather conditions. 8. For additional do's and don'ts on spotting fluids, review the "ExxonMobil Stuck Pipe Spotting Fluid Guidelines" – available from Drilling Technical Operations Support. 6.7 LOST CIRCULATION The first priority when encountering lost circulation is to fill the hole as quickly as possible with water or other light fluid to keep the hole full. It is the responsibility of the driller, mud loggers, and the mud engineer to be alert for lost circulation. Warning signs are as follows: 1. Loss in Pit Level 2. Complete Loss of Returns 3. Loss of Pump Pressure DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 20 DRILLING OPERATIONS A third party data acquisition system with data archiving and alarms should be considered if monitoring of lost returns is critical. Building Integrity Lost returns occur when the pressure in the wellbore exceeds the resisting stress in the rock. The integrity is determined by the closure stress (psi) in the fracture that is created. Closure stress is built by applying pressure to increase the fracture width, which compresses the rock so that it pushes back with greater force. The greater the width achieved, the greater the increase in integrity. However, in order to apply the pressure required to compress the rock, it is first necessary to isolate the fracture tip which would otherwise continue to grow at a very low pressure. Conventional LCM isolates the tip by becoming an unpumpable mass due to loss of its carrier fluid as it travels down the permeable fracture face. The LCM also serves to pack the fracture open so that the higher closure stress is maintained. Even relatively small particles are effective and will become an unpumpable mass if the leakoff is high. High leakoff and high solids concentration are the key features in the design of pills. Fracture growth is not stopped by blocking with large particles, it is stopped by the loss of carrier fluid and the development of an unpumpable mass. The pill may have an intrinsically high spurt loss and yet be ineffective if the permeability is low. Hesitation squeezing is critical in low permeability (< 500+ md) because it allows time for the carrier fluid to leak off. Multiple layers of LCM are eventually built up in the near wellbore region that achieve sufficient fracture width and closure stress to allow drilling to continue. Integrity cannot be built unless a fracture is created and its width increased. If the required increase in closure stress is very low, mud solids alone may achieve the required width when micro-fractures are just initiating and no loss is observed. If slightly more increase in width is needed, then the well may “take a drink” and then drilling may continue. When complete losses occur the most effective approach available should be used on the first attempt. This is justified by the high cost of rig time for multiple attempts to build integrity. Mix high fluid loss pills, use the highest concentration of LCM possible, and plan on hesitation squeezing. This may not be the best “first” response in cases where the loss zone isn’t a sand over about 100md or underbalanced by greater than 1000psi. Filling the Hole If lost returns occurs and the annulus fluid level drops it is essential to fill it immediately. When loss is observed: 1. Immediately pick up off bottom a minimum of 15 ft (clear kelly bushing if using a kelly). 2. Shut down the mud pumps. 3. Observe the fluid level in the annulus, (bell nipple) if visible. 4. If it does not stand full, fill initially with 0-20 bbls of drill weight mud to see if the loss is declining. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 20 DRILLING OPERATIONS 5. If the loss doesn’t decline, fill with water or base oil via the trip tank until losses stop. The annulus will be stable when the total head equals the fracture closure stress in the loss zone. Measure and record the volume of light fluid required to fill the annulus. 6. Calculate the fracture closure stress (integrity) in the loss zone based on the amount of fill and report the fill volume and FCS on the daily report. FCSppg = [(Light Fill Height)(Light Fill Density) + (Mud Height)(MW)] (Estimated Depth of Loss) 7. Observe the annulus. If the light fill attempts to flow back it is likely that underground flow is occurring. Shut in immediately to prevent flowback and monitor pressure. Contact the Operations Superintendent immediately. 8. Once the annulus is stabilized, it may continue to drop slowly due to seepage. Begin filling with whole mud rather than light fill to avoid underbalancing shallow zones with light fill. Attempting to Establishing Circulation 1. In most cases, it is desirable to pull the pipe into the previous casing shoe. 2. After pulling into the shoe, allow 2-4 hrs before attempting circulation to ensure the fluid in the fracture has leaked off, allowing it to close. Monitor on the trip tank. 3. Work the drill string slowly and use the standpipe choke if necessary when initiating circulation after waiting on fracture closure. 4. Circulate bottoms up from the casing shoe before tripping back into open hole. 5. Trip in the open hole slowly and break circulation frequently. Treatment Selection 1. Utilize Figure 6-1 to select the appropriate treatment for severe loss events. 2. Detailed procedures for each treatment type are contained in the EMDC Generic Lost Returns Procedure posted on Global Share. This posted document is continuously updated with learnings in operational practices and pill formulations. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 20 DRILLING OPERATIONS Figure 6-1 Lost Returns Treatment Selection Guide (See EMDC Generic Lost Returns Procedure for details) Lost Returns Occurs Are Losses Due to Seepage No Does Hole Stand Full Fill Annulus with Light Fluid (water or base oil) No Yes Yes Is FCS > Pore Pressure No Yes Losses are Fracture Propagation ( Most Common ) Losses are Likely Vugular Is Zone Permeable WBM Yes Seepage Control DOB2C Procedure No Cement or FlexPlug Procedure Yes Conventional LCM Procedure No WBM No Flexplug Procedure Yes DOB2C Procedure Conventional LCM Treatment for Severe Losses 1. If the well will not circulate, position the bit in the previous casing shoe and prepare for bullhead operations. If the well can be circulated place the bit below the loss zone and DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 20 DRILLING OPERATIONS circulate LCM entirely out of the bit to position it in the annulus. Pull the bit into the previous shoe to conduct squeezing. 2. If the pill is to be circulated outside, mix the LCM slightly heavier than the mud so that it falls back to fill the pipe displacement when pulling DP. Use a solid float to prevent backflow into the BHA. Fill the annulus with whole mud. The string will pull wet. 3. Mix pills by adding water, 15ppb Attapulgite, and LCM. If Attapulgite is not available, use 0.5 ppb Xanthan gum as viscosifier. After blending LCM, add barite to achieve required density. 4. Use the highest concentration of LCM that can be pumped through the drill string components. 5. Do not use materials that reduce spurt loss (e.g. fine calcium carbonate, microfibers, starch and bentonite). 6. Do not allow fluid to return from the annulus while squeezing LCM. Shut in prior to starting displacement and monitor and record pressures. Any change in annulus pressure is a direct measure of the change in fracture closure stress (integrity). 7. Hesitation squeezing maximizes fracture closure stress. Place approximately ¼ of LCM into fracture and shut down. Conduct at least two more squeezes with hesitations between each to allow the LCM carrier fluid to leak off. Hesitate for 1-4 hrs between each squeeze. Leave 1020 bbls of LCM above the loss zone after the final squeeze 8. Hold pressure between squeezes. If backflow is allowed prior to the carrier fluid leaking off, the fracture width and stress will decline. 9. Provide pressure and volume data to the drilling engineer for plotting and archiving in the well record. 10. After holding the final squeeze pressure for a minimum of 4 hrs, bleed off pressure and stage pumps up slowly. Stage the drill string to bottom, breaking circulation at each point and monitoring the returns for additional gains or losses. Pill Formulations Pill formulations continue to improve. Learnings are continually updated and published in the EMDC Generic Lost Returns Procedure, which is posted on Global Share. Contact Drilling Technical Operations Support for additional assistance in pill design. The pill should be the most economic design that will successfully build integrity. The ease with which integrity is built is dependent on the leakoff (permeability) and the required increase in fracture stress (width). If permeability is high or the required increase is small, relatively low concentrations of medium LCM may be effective (20-40 ppb). In very low permeability and severely drawn down sands concentrations of over 100 ppb have become standard practice. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 11 of 20 DRILLING OPERATIONS The concentration of LCM that can be pumped is limited by particle size and restrictions in drill string. Medium fibers have been pumped through MWD at 80 ppb. Smaller 400 micron LCM (e.g., Steel Seal, SweepWate) has been pumped through MWD at concentrations over 300 ppb. Higher concentrations of smaller particles are more effective than low concentrations of medium material, but it is also more costly. Field experience is required to determine which approach is the more cost effective. Because the spread rate for drilling rigs is high, preference should generally be given to the approach that is more likely to work on the first attempt (high concentrations of 400 micron). Regardless of particle size or type, the manner in which an LCM is used is more important than what is used. The combination of high fluid loss designs and hesitation squeezing greatly enhances the effectiveness of any material. Ballooning Ballooning refers to the loss and backflow of mud that is sometimes observed when circulation is begun and stopped. It is due to the expansion of a lost returns fracture due to the ECD associated with circulation, and then the contraction of the fracture when the ECD is removed. It is generally associated with soft, low permeability formations. It may occur in higher permeability if lowleakoff mud such as a NAF is in use. Prevention of Ballooning Ballooning can be prevented if the mud weight is reduced so that the total ECD is less than the fracture closure stress and the fracture cannot reopen. It may also be possible to stop ballooning by treating the fracture with Flexplug (NAF) or DOB2C (WBM) to build the closure stress to exceed the ECD. Cement has also been used successfully, but it creates the potential for sidetracking. This is more likely to be successful if the fracture is confined to a discrete sand than if ballooning is occurring in a shale. Other Conditions for Lost Returns 1. If the well will not stand full, the LCM pill will be overdisplaced by the hydrostatic head of drill-weight mud. Overdisplacement can be controlled by pumping sufficient light fluid at the end to place the drill pipe column underbalanced to the fracture closure stress in the loss zone. The light fill is referred to as a drill pipe “hydrostatic packer”. The calculations for designing a hydrostatic packer are provided in the Generic Lost Returns Procedures. 2. Discuss cutting mud weight with the Operations Superintendent. When returns are lost the BHP falls to the resisting force in the fracture, which is referred to as the fracture closure stress (FCS). If the annulus remains stable after filling, flow is not occurring with a BHP equal to the FCS. This is an important diagnostic that indicates that the mud weight may be safely cut to equal the calculated FCS without concern for flow. 3. By definition, seepage is the loss of whole mud into the pore throats of the formation (no fracture propagation). Seepage is stopped when fine solids plug the pore throats through which whole mud is escaping. In low weight mud (<10 ppb), add fine calcium carbonate at 5-8 ppb for this purpose (5 micron CaCO3). However, the addition of fine blocking material DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 12 of 20 DRILLING OPERATIONS is questionable at high mud weights where there is already a sufficient volume of barite particles of this size to block the pore throats. For example, a 13.0 ppg mud has over 100 ppb of particles the same size as fine calcium carbonate. Also, do not use “lost returns” LCM for seepage control. Larger materials such as medium fiber and nut plug do not fit the pore throats well and result in thicker cakes. While they slow the loss, they increase the potential for differential sticking. 4. Treatment of the entire mud system with lost returns LCM is discouraged. The detrimental effect of medium LCM on mud properties and solids control is significant. System treatment is sometimes recommended when very long intervals of lost returns are anticipated that cannot be treated with discrete pills. However, when this occurs it is generally possible to cut the MW and drill the entire interval prior to conducting a single treatment. 5. If seepage and filtrate control are critical, consider the use of Drill and Seal treatments. This process is described in detail in the Generic Lost Returns Procedures posted on Global Share. Drill and Seal is used when the filter cake associated with continued low seepage and filtration losses may result in differential sticking, torque and drag, or wireline sticking. 6. Conventional LCM does not work if the rock is impermeable and the carrier fluid cannot leak off (shales). The recommended alternatives for impermeable rock are DOB2C in water base mud or Halliburton’s Flexplug in oil base mud. Neither requires leakoff in order to function. DOB2C is a mixture of oil, bentonite, cement and water that forms a highly viscous slurry that eventually hardens. Flexplug is a proprietary product that forms a rubbery material at down hole temperature. Detailed procedures for each are provided in the Generic Lost Returns Procedures on Global Share. 7. By definition, vugular formations are those with > 1/16” openings. The practical definition is that they are formations with pore throats that cannot be blocked with conventional LCM (e.g., carbonates, oyster beds, gravel). The recommended treatment for vugular loss that will not respond to coarse LCM is cement in oil base mud, or DOB2C in water base mud. Cement may also be used in WBM but DOB2C has an advantage in that it can be drilled out without concern for sidetracking. DOB2C cannot be used in an NAF. Drilling Without Returns If cement or LCM pills fail to control the lost circulation, it may be possible, (in short durations) to drill without returns. A cuttings bed build-up in a directional well can result in stuck pipe due to inadequate hole cleaning. Dry drilling is used in many operating areas as an alternative when major lost returns are encountered. The drilling fluid is pumped at a reduced rate to: • • • Keep the bit lubricated and cool Keep the bit from plugging Carry the cuttings into the loss zone to aid in plugging. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 13 of 20 DRILLING OPERATIONS Care should be taken when dry drilling, each joint may have to be reamed several times to clean the hole sufficiently, and should only be done with Field Drilling Manager approval. The reduction in hydrostatic pressure should be considered while dry drilling. Drilling Bypassing the Shakers Carrying LCM in the system and bypassing the shakers. This (seal while you drill) method is good to keep from using the LCM for only one circulation thus reducing the cost, but could compound the problem if prolonged. If the shakers are allow to stay by-passed too long, the solids content of the mud system will eventually reach a point that the borehole cannot sustain the increased weight or viscosity. The small solids have a tendency to stick, (piggy-back) on the LCM and is circulated back downhole increasing the solids and thus increasing the mud weight. There are of course exceptions to both the above, this is not to say they shouldn't be used if needed, but experimenting with one or both and experience with them will increase their usefulness and successfulness. Cement Plugs If neat cement is used alone to fight lost returns, a slurry weight of 15.8 ppg has proven to be the most effective. Balanced plugs are to be spotted through open ended drill pipe positioned across the thief zone and the drill pipe pulled into the casing shoe. If the hole does not take any mud after spotting the cement plug, a gentle bradenhead squeeze may be applied after the drill pipe is in the casing shoe. Gel cements having lower densities may be necessary with zones that have very little integrity or may fracture using neat cement. In mixing this type of cement, the following slurry is recommended: 13.2 ppg Density 100 sxs Class G Cement 8% Gel 24.3 bbls Fresh Water 1/4 ppb Sodium Carbonate 1/4 ppb Caustic (The sodium carbonate and caustic are used to remove calcium and magnesium ions.) Cements such as Cal-Seal (contains gypsum), Thixotropic (containing clays and polymers), and Gilsonite (crushed-up limestone) can also be used, though they have not proven to be much more effective than regular cement in severe lost return occurrences. DOB2C DOB2C is effective in stopping fracture propagation in either low or high permeability rock. However, its primary advantage over conventional LCM is in lower permeability. Because conventional LCM requires leakoff of the carrier fluid, it doesn’t perform well in very tight formations or shale. DOB2C can only be used in WBM. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 14 of 20 DRILLING OPERATIONS DOB2C achieves integrity through a different process than conventional LCM. Because of its extremely high viscosity, the wellbore pressure required to squeeze it down an induced lost returns fracture is high. The high pressure at the wellbore increases the fracture width and fracture closure stress (FCS). The pressure is held while the cement in the DOB2C sets, and the fracture width and increased closure stress are maintained permanently. DOB2C is often also preferred to cement in blocking vugular losses because the low-strength material left in the wellbore is easily drilled out without risk of sidetracking. Another advantage is that because of its high viscosity it is possible to apply a high squeeze pressure to DOB2C that ensures that the material is forced into all of the vugular openings. Cement may flow freely into the largest of the openings without developing sufficient back pressure to force additional cement into the smaller vugs. Although diesel is most commonly used as the base fluid to carry the bentonite and cement, other low-toxicity oils and synthetic based muds have been used successfully. Flexplug Halliburton FlexPlug is a blend of latex and other additives that mix with mud to form a rubbery material under downhole conditions. Flexplug stops fracture growth by blocking the fracture near the wellbore, and then it deforms to maintain the blockage as the fracture widens under squeeze pressure. The extrusion pressure of the material is high enough that wellbore pressure is not transmitted to the fracture tip and fracture growth (lost returns) is prevented. The squeeze pressure is held until the temperature-activated set occurs. Because FlexPlug does not achieve significant compressive strength (as does DOB2C) there is probably some loss of fracture width and integrity when the squeeze pressure is released. However, field experience suggests that in many situations the sustained stress is adequate. FlexPlug is a candidate system in 1) NAF, and 2) low permeability, because it does not require leakoff in order to function, as does conventional LCM. It will also function in high permeability, however conventional LCM is less costly and equally effective I high permeability. 6.8 NON-AQUEOUS FLUID OPERATIONS General Guidelines Safety Considerations: 1. Slipping Hazards Stress cleanliness around the rig: Provide absorbent material to keep the rig floor and catwalk dry. A rig oil mud vacuum, similar to the "Max Vac" system should be installed with outlets connecting to the rig floor, shakers, pump room, BOP deck, etc. to contain mud that accumulates during trips, when working on pumps, or when spills occur. Rig floor non-skid, studded rotary mats should be used. Frequent use of steam cleaners is recommended. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 15 of 20 DRILLING OPERATIONS 2. Fire hazards Provide good ventilation in closed areas, especially on the below-deck pits offshore. The two periods of greatest fire risk are when the mud contains formation gas, and when the hole is first displaced and the lighter, more volatile ends of the base oil are being lost to the atmosphere. No open flames, cigarettes, welding, etc. should be allowed near oil mud. The rig should be checked for electrical shorts and for any equipment or operation which could create sparks; electric motors should be explosion-proof. A foam suppression fire fighting system should be considered for the pit room and shaker area. 3. Air quality Provide good ventilation in closed spaces, especially over mud pits, shakers and mud mixing areas. Air exchanges of 90 room volumes per hour are usually adequate. Have a room dedicated to mud testing available; the mud engineer's testing lab must also have good ventilation because volatile solvents are needed to break the emulsion during many oil mud tests. 4. Skin contact All contractor and EMDCDO employees who may get oil mud on their skin should be made aware that it is an irritant and should be removed as quickly as possible. Protective clothing, gloves, rubber boots, and safety glasses should be made available. Water soluble cleansing creams (for removal of mud from the skin) and barrier protective hand creams should be provided. Crews should be told of the health considerations and how to remedy them. This should be consistent with ExxonMobil's OSHA (applies to non-US East operations) Hazard Communication Program and communicated to the contractor's safety and First Aid leader on the rig. Protecting the Environment and Minimizing Mud Losses 1. A lower kelly, mud-saver valve should be installed (i.e. Drilco's Mud Check Valve or equivalent). 2. A mud bucket with a drain to the flow line should be used. The pneumatic type Mud Bucket has proved very beneficial when making wet trips or back reaming out of the hole. 3. Both OD and ID drill pipe wipers should be used when making trips unless well control problems prevent safe use of ID wiper. ID wiper should have the proper size fishing neck. 4. A drip pan should be used for the pipe rack and catch pans installed where appropriate (e.g., under centrifugal or transfer pumps). 5. The immediate working area on the rig floor should be combed with 3" flat bar welded on edge, or the equivalent, and drained to the flow line or sand trap with the option of going to a disposal sump. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 16 of 20 DRILLING OPERATIONS 6. Install oil resistant rubber goods in valving; BOPs (annular element and ram block seals); pump swabs; shaker screen mounts; and flexible hoses. Centrifugal pumps should be installed with mechanical seals. 7. Ensure rainwater cannot contaminate mud in exposed pits. 8. Blank off all sources of water around the mud pits. Water is a serious contaminant in oil mud. 9. A pump, supply line, and a nozzle to clean the shaker screens and shaker area are sometimes provided, but keep in mind the fire hazard generating a fine spray of an oil, particularly diesel with its low flash point +/- 140-150º F. 10. "No Smoking" signs should be placed in conspicuous locations around the mud pits. 11. A heavy duty explosion proof electric steam cleaner/pressure washer should be available. 12. Rig up a shut-off valve for the base oil supply tank away from the pits. 13. Cuttings removal and disposal systems must be installed. systems must meet all regulatory requirements. Cuttings boxes or bagging 14. The addition of oil-wetting agent and dilution with base oil should be considered when building OBM slugs in high-density mud systems. Lower viscosity slugs have proven to be more effective, especially when utilizing a tapered drill string. 15. A vacuum system provides many benefits. 16. Mud pit drains should be blanked off (skillets installed) to ensure that oil mud can not be directed overboard. OIL SPILL PREVENTION MEASURES Communications 1. There should be a written transfer procedure on the rig and the supply vessel which outlines the following (at a minimum): • • • • • • • • • product to transfer sequence of transfer operations transfer rate particulars of transferring and receiving systems emergency procedures cutting and welding permits are to be returned and put on hold until transfer of OBM or base oil is complete spill containment procedures watch and shift arrangements transfer shutdown procedure DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 17 of 20 DRILLING OPERATIONS • spill reporting requirements and procedures 2. A pre-transfer meeting must be conducted on the rig and the supply vessel to review the transfer procedures with all personnel involved. 3. While transferring base oil or OBM from the supply vessel to the rig, a designated crew member will be assigned to observe for leakage from the rig/supply vessel to the sea. 4. Radio communications will be available between the rig control room, rig observer, and the supply vessel at all times during the operations. 5. A work permit should be issued prior to transferring any hydrocarbon product. Transfer Hose 1. Hose must be rated for hydrocarbon fluids. 2. Hose design burst rating shall be one of the following, whichever is greater: a. at least 600 psi, or b. four times the transfer pump's pressure relief valve setting plus fluid hydrostatic, or c. four times the transfer pump's output plus fluid hydrostatic when no relief valve is installed. 3. Hose working pressure shall be one of the following, whichever is greater: a. at least 150 psi, or b. the transfer pump's pressure relief valve setting plus the fluid hydrostatic, or c. four times the transfer pump's output plus the fluid hydrostatic when no pressure relief valve is installed. 4. The hose will be visually inspected for tears, punctures, soft spots, or bulges in the hose exterior, immediately prior to the transfer. 5. It must be verified that the rig and supply vessel connections are mating pair. 6. A ball valve will be installed on supply vessel end of the transfer hose. 7. There will be a positive sealing cap on the end of the transfer hose. 8. The hose length must be sufficient for the supply vessel to move to the outer limits of the mooring lines. 9. The hose must be adequately supported to avoid excessive strain on the hose couplings 10. There must be no kinks in the transfer hose when connected to the supply vessel. 11. If the transfer hose is disconnected from the riser pipe, a sealing cap will be installed on the end of the riser. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 18 of 20 DRILLING OPERATIONS RIG PREPARATIONS PRIOR TO TAKING ON NAF MUD 1. There should be detailed procedures, with checklists, (refer to NAF/OBM Readiness Checklist in Section 6 – Appendix G-II) for preparing the rig to take on the oil-base mud. Procedures should heavily emphasize actions that must be undertaken to prevent spill occurrence prior to loading the product and while it is in use. 2. There should be mud piping schematics available on the facility for the circulating system. This schematic should highlight the location of all dump valves and any other potential spill source. 3. Consideration should be given to color-coding all dump valve operating handles by painting them a distinctive color (e.g., yellow and black stripes). Double valve with a gate valve on the end and a work permit sign to open valves. 4. Prior to closing each dump valve in the sand traps or mud pits, the seat and the valve O-ring should be visually inspected to verify that both are clean, free of debris or obstruction, and are not damaged. Each valve shall then be closed while visually observing the seating of the valve. After full closure, the valve should then be packed with a gel-water paste to further enhance the seal. 5. All mud pit and sand trap dump valves should be double-valved, locked in the closed position, and posted with a sign, printed in English and in the native language, stating "Work permit required to operate". In some instances, double-valving has been accomplished by installing a gate valve downstream of the dump valves in the common discharge line for the sand traps and/or mud pits. NOTE: If a gate valve is not already installed in the discharge line, installing one will most likely require approval by a regulatory agency such as ABS etc. Another method for deterring OBM from getting overboard is to install a skillet in all dump lines. 6. Consideration should be given to installing a pump-out line between the double-valved arrangement (i.e., between dump valve and the gate valve) to allow pumping out any pollutant which may leak by a dump valve. 7. Work permit requirements should be in place to operate the dump valves. A work permit should also be required before OBM can be transferred into any tank or pit that has had a dump valve operated, repaired, or resealed. 8. OBM transfers should not be made during hours of darkness, during meal time, or during a tour change unless emergency situations dictate or unless prior written policy has been established to effectively deal with the situation. 9. While transferring OBM from the supply vessel to the mud pits, a designated crew member should be assigned to observe for leakage from the bottom of the rig to the sea. 10. A checklist shall be completed for transfer to/from the rig of hydrocarbons (i.e., Oil Base Mud, Diesel, etc.) and shall include inspection of loading lines, pressure testing of loading DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 19 of 20 DRILLING OPERATIONS lines, fire protection, verbal communication system between source vessel and destination. Checklists have been included in Section 3 – Appendix G-I. Frequency Prior to connection of onloading hoses for each transfer cycle (Safety Management Program Section 5.4.1). 11. Rat holes/mouse holes should be sealed with a hose routed to a disposal tank. 12. Pump room drains should be routed to a disposal tank. 13. There should be a drain pan under the rotary table with a return line routed to the flow line. 14. All rig floor drains should be routed to a disposal tank. 15. Slip joint packing and flow line seals should be oil-resistant rubber. Slip joint barrels should be inspected to insure surfaces are smooth and free from scouring. 16. Base oil or OBM should not be stored in a pit longer than is actually required. Holding pits should be thoroughly cleaned at the conclusion of each job requiring OBM. 17. Check all BOP and rig valves for rubber and resilient seal compatibility with OBM. 18. Before loading Oil Mud into rig mud tanks, install new rubber products in all low-pressure mud valves and pump suction valves. 19. Stock up on spare rubber products for valves and mud processing equipment. 20. Double-check all valves in the circulating system before loading Oil Mud into rig tanks. 21. Create extra sumps around the pumps and rig substructure to trap oil. 22. Use a vacuum pump to clean out sumps, and to clean out pumps during repair work. 23. Ensure that all mud handling equipment and mixing pumps have drip pans. 24. Add a 2" drain line between the mouse hole and the trip tank (or any tank with the capability to pump mud to shakers). With this drain, mud that drains from the kelly can be saved and pumped across the shakers. 25. Double valve all tank lines. If possible, use hard piping (welded Schedule 40) for lines rather than hoses. 26. Install a common overflow between storage tanks to prevent spills during loading and transferring. NAF DRILLING FLUIDS Treatment Guidelines DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 20 of 20 DRILLING OPERATIONS 1. Perform a minimum of two (2) complete (In and Out) checks of the drilling fluid every 24 hours during drilling operations. 2. Process the drilling fluid returning from the wellbore so that the fluid properties of the drilling fluid going back into the wellbore are within the acceptable range per the specifications in the approved Drilling Program. 3. Pilot test any planned significant change to mud system before making change. 4. When drilling, measure and record at 30-minute intervals the drilling fluid weight and funnel viscosity from the flow line and the pump suction pit. 5. Notify the Driller and Mud Logger of planned changes to the active system volume. 6. Use a shearing device to maximize yield of emulsifiers, gelling agents, and to get a tight oil/water emulsion. 7. Make sure that hoppers are shut-off when not in use for mixing. Test Equipment The test equipment listed in Exhibit B of the Mud Materials and Mud Engineering Services Contract shall be maintained at the rig. See contract for details. Specific items necessary for testing oil-base muds include: 1. Equipment for chemical analysis of oil muds as stated in API RP 13B-2. 2. Reference Manual - API RP 13B-2 "Recommended Practice - Standard Procedure For Field Testing Oil Based Drilling Fluids", December 1991 Edition or newer. 3. Pressurized Mud Balance with Calibration Kit. 4. Fann 6-speed VG Meter. 5. Thermostatically-controlled viscometer cup. 6. Thermometer (32-220° F). 7. HTHP filter press. 8. 10 or 20 cc mud retort. 9. Electrical stability meter with calibration kit. 10. Electrohygrometer with calibration kit. Further details on test equipment are given in ExxonMobil Oil and Synthetic Mud Testing Guidelines. Mud Check Guidelines DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 21 of 20 DRILLING OPERATIONS Unless otherwise specified in the Drilling Program, the Drilling Fluids Engineer shall make the following measurements for each "Mud Check" on an oil-base drilling fluid. 1. Mud Weight. 2. Funnel Viscosity. 3. Plastic Viscosity (PV) at 120° F. 4. Yield Point (YP) at 120° F. 5. Gel Strengths at 120° F. 6. API Filtration at 100 psi differential. 7. HPHT Filtration at 500 psi differential at temperature specified in the Drilling Program. 8. Alkalinity and Excess Lime. 9. Water Phase Salinity. 10. Calcium. 11. Activity by electrohygrometer. 12. Electrical stability. 13. Water, oil, and solids content (retort). 14. Oil Water Ratio. Further details on mud checks are given in ExxonMobil Oil and Synthetic Mud Testing Guidelines. Drilling Fluids Report Guidelines The Drilling Fluids Engineer is to provide a Daily Drilling Fluids Report to the operations supervisor daily which includes the following: • • • • Daily and Cumulative Usage of Drilling Fluid Products Daily and Cumulative Costs of Drilling Fluid Products Used Daily and Cumulative Dilution Volumes Daily and Cumulative Drilling Fluid Volumes Lost (Estimated) Over Solids Control Equipment, Lost Circulation, Or Not Accounted For in The Dilution Volumes • Cumulative Record of Drilling Fluid Checks Labelled as to Time and Depth of Bit Personal Protective Equipment and Facilities DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 22 of 20 DRILLING OPERATIONS 1. Ensure that workers report to work each tour in clean work clothes and that each worker has extra clean work clothes on site. In general, oil-soaked clothing should be changed as soon as practical. 2. Provide an adequate means of clean-up for workers who have skin contact with oil mud. 3. Provide hand cleaners and barrier creams to remove oil from the skin and to protect the skin. These items should be kept at all eye wash stations. 4. The following personal protective equipment (PPE) should be available for use by personnel working with oil muds: • • • • • • • • Work gloves (replace when oil-saturated). Chemical resistant gloves worn underneath work gloves may be used to minimize skin contact. (Latex-type surgical gloves work well) Crew members that work with the mud or mud pumps should wear chemical-resistant (e.g. Neoprene) gloves. Safety glasses with side shields. Hard hat. Complete slicker suit or chemical apron. Extra PPE should be kept in dog house for other personnel frequently called to work on the drill floor. Rubber boots. Paper towel dispensers, hand cleaner, barrier cream dispensers, and wash water in mud pit area. "ZEE" skin cream has worked well in preventing skin irritation. Industrial Hygiene-Related Training 1. Before beginning an oil mud job, a training program for rig personnel should be conducted to explain health hazards associated with exposure to oil muds. 2. Drilling Contractor must ensure that workers are familiar with MSDS (Materials Safety Data Sheets) for base oil and all oil mud additives. 3. Training program should explain proper use of PPE. Requirements regarding use of PPE should be clearly stated before using an oil mud. Oil Mud Displacement Successful displacement of Water-Base Mud by an Oil-Base Mud can be difficult. Unless covered in the Drilling Program, a Supplemental Procedure that describes the necessary procedures will be written by the Drilling Engineer. An example procedure completed using the EMDC US East Drilling Group Core OBM Displacement Procedure can be found in Section 6 – Appendix S-I. 1. Use a spacer. Consider using dye. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 23 of 20 DRILLING OPERATIONS a. Where differential pressure allows, a simple spacer such as a pure base oil often works best. b. If a weighted spacer is required, oil mud without calcium chloride is best. In cementing operations the spacer must not contain calcium chloride or flash setting could occur. 2. Spacer Volume recommendations: a. Use the volume necessary to achieve a spacer height of 200-500 ft in the annulus. Use greater heights for open hole, lesser heights inside casing. b. WELL CONTROL CAUTION: Calculate effect of spacer on hydrostatic pressures. 3. The displacing fluid should be heavier than the fluid to be displaced. The density of both fluids should be checked at the same temperature. 4. Condition water mud by deflocculating to lower yield point and gel strengths. Circulate bottoms-up at high pump rate immediately before beginning displacement. Displacement Procedures It is very important to plan the displacement carefully. Have thin, freshly circulated water base mud in the hole just before displacement. 1. Circulate and thin the water base mud thoroughly before shutting down to change out the water mud in the pits with oil mud. On some rigs, the returns can be diverted down a metal trough (mud ditch) from the shakers to the suction pit; if so, circulation with water mud can continue while the remaining pits are drained of water mud and cleaned out. 2. Clean out pits after removing water mud. 3. Put 40-60 mesh screens on shale shakers to handle thick oil mud. Have finer screens ready for installation after the oil mud has circulated around. 4. Put spacer in slugging pit and fill other pits with oil mud. 5. Zero pump stroke counter after spacer is pumped and before the first good oil mud starts downhole. Record stroke count when water mud and water mud/oil mud interface has been displaced and reasonably good oil mud returns are visible. Start shakers, direct mud to pits. 6. Rotate and reciprocate pipe during displacement. 7. Pump at fast rates during displacement . Reduce rate if pressures increase. Do not stop pumping once the displacement has commenced unless absolutely necessary. 8. Dump water mud or move to storage while pumping. 9. Catch spacer/water mud/oil mud interface and dispose per the approved requirement. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 24 of 20 DRILLING OPERATIONS 10. Circulate around once, and after determining that the water mud and spacer have come back divert returns over the shakers and begin remedial oil mud treatments with emulsifier and wetting agents. Typical treatments are in the 0.5-1.0 ppb range for each additive during the next circulation. 11. Run a check for flow properties, E.S., and HTHP as soon as practical after good mud has come back (remedial treatments should already have been initiated) and assess the condition of the mud. Continue treating as necessary, and do not stop circulating until acceptable mud properties are attained. 12. Change out shaker screens to the smallest mesh possible as soon as the shakers can handle it. 13. Use pump stroke count to estimate the degree of channelling by the oil mud. This will help determine how much water mud was left in the hole. 14. Commence drilling when the oil mud exhibits stable rheology, electrical stability, and shows little or no water in the HTHP filtrate. Testing and Conditioning During Displacement 1. Test for water mud/spacer interface every 15-20 minutes until 75% of displacement has been pumped, then test continuously. 2. Record pump stroke count when reasonably good oil mud returns are visible at the shakers. Use stroke count to calculate how much water mud was left in the hole. If a significant amount of water-base mud was left in the hole, it may have been caused by severely washedout open hole. Water mud can bleed into an oil mud for several days after the displacement; this mixing can weaken the oil mud emulsion. 3. HANDLING CONTAMINATION: After good oil mud returns are directed over the shakers, emulsifier and wetting agent can be added at the shakers, in the suction, or in both places. Continue to circulate and condition the mud for several circulations and test flow properties, and Electrical Stability. Check the High Temperature / High Pressure fluid loss for the presence or absence of water; drilling should not commence until the HTHP is < 1.0 cc or water free. This process of displacing and then conditioning may take 24 hr or more and should not be rushed. Ensure the mud is well treated-before drilling ahead. 4. FLUID IDENTIFICATION: To help identify when good oil mud is coming back, run Dispersibility and Electrical Stability Tests as follows: Dispersibility Test 1. Fill one clean glass or plastic container with base oil, the other with water. 2. Place a few drops of the returning fluid in each and observe for signs of dispersibility: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 25 of 20 DRILLING OPERATIONS • • • If the fluid disperses in water and not in the oil, it is water mud. If the fluid disperses in oil and not in the water, it is oil mud. If an oil slick forms on the surface of the water or some fraction does not mix, it is a mixture of water and oil. Electrical Stability Test 1. Periodically check the E.S. on a sample of the returning fluid. 2. If there is appreciable water mud in the fluid, E.S. will be zero (very conductive). 3. When the amount of water mud declines to about 20-25% in the oil mud, the E.S. meter will begin giving a low reading (100-200 volts). At this time, slow the pumps and prepare to put the mud over the shakers. A. Rig Preparation 1. All welding repairs on pumps, pits, and rig floor should be completed before taking on Oil Mud. 2. Change swivel packing and blank off all water lines to the pits. Maintain on site a supply of 55-gallon disposal drums for oily wastes. B. Base Oil Storage 1. Bull plug ends of tank lines when not in use. 2. Maintain adequate base oil on location or boat. 3. Use an air-driven wash-down pump for washing shaker screens and other equipment. Ensure that pump suction is protected with a screen. C. Whole Mud Storage 1. Maintain a minimum of 500 bbl weighted mud in tanks on location. 2. Whole mud storage tanks should be continuously agitated if possible. 3. Monitor gel strengths on stored mud; higher gel strengths are necessary to prevent barite settling. D. Solidification 1. Utilize a Drying Shaker to get the drill cuttings as dry as possible and to recycle as much of the base oil as possible (e.g. Sweco LM-3 Shaker, Derrick Hi-G Shaker, etc.). 2. Utilize a screw type conveyor(s) or vacuum unit for cuttings gathering, collection and discharge from the Mixing Unit to the storage area. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 26 of 20 DRILLING OPERATIONS OIL BASE UTILIZATION CHECKLIST Use the OBM checklist in the Safety Management Program 1. EPR - Oil Mud Manual 2. EUSA - Oil Mud Lab Manual / Oil Mud Testing Guidelines 3. NODO - OBM operations Practices Manual 4. NODO Operations & Technical Bulletin No.# 94-21/How to build high-density OBM slugs. 5. Drilling Safety Management Program LOADING OIL BASE MUD OR BASE OIL FROM SUPPLY VESSEL TO RIG Responsibility 1. OIM or Barge Engineer/Captain to be in charge of operation. 2. Tool pusher is to be responsible for rig related preparations. Assistant Driller and Derrick man are to assist the Tool pusher. Preparations 1. OIM or Barge Eng./Captain to hole pre-transfer meeting with involved crew members. 2. Visually inspect transfer hoses for any damage immediately prior to transfer. Transfer hoses must be rated for hydrocarbon fluids and have a safe working pressure of 150 psi. Verify that the supply vessel's pumping pressure will not exceed safe working pressure of the hoses. 3. Transfer hoses have a valve on the end, at the supply vessel side, and has been checked for damage. 4. All others outlets on the load line are sealed off with a blind flange or a valve that is properly closed and padlocked (i.e., list specific valves). 5. Valves on sample outlets at each loading stations are closed. 6. Valves on all opposite side loading stations are closed and secured (i.e., padlocked). 7. Tool pusher and ExxonMobil drilling supervisor will verify that all preparations listed herein have been made before initiating the transfer. Also, the Tool pusher and ExxonMobil drilling supervisor will ensure that the "checklist" is fully completed prior to commencing the operation. A copy of the completed "checklist" will be provided to the ExxonMobil drilling supervisor. 8. Transfer hoses will be visually checked for damage prior to transfer. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 27 of 20 DRILLING OPERATIONS 9. Mud pits, shaker pits and shaker box have been emptied and cleaned out per mud engineer approval. All dump valves have been closed, secured, and tagged. 10. Main mud valve on overboard discharge line is closed and padlocked (specify valves). 11. Trip tank is to be cleaned out. The trip tank dump valves are to be closed and secured. 12. Overboard valves from the rig floor drain are closed and secured. Rig floor drains are lined up to drain tank. 13. Drains in pump room, mud treatment room, shaker room, mud mixing area, and cement room are sealed. 14. All valves to cement unit are closed. Dump valves from cement unit displacement and mixing tanks are closed and padlocked. 15. Isolation valves in mud pit room between OBM line and drill water line are closed and secured. 16. Main valve on sea water supply line and all water valves at mud pits, pump room, and shale shakers are closed and tagged. 17. Main diesel supply line valve has been closed, padlocked and tagged. 18. Transfer pumps are available for use in the event of a spill on the deck or to transfer at the pits. 19. Desander and desilter feed line manifold valves are closed and secured. 20. Valves on possum belly discharge are closed and secured. 21. Water flushing system on shakers screens are closed and secured. 22. Cuttings overboard gate in shale shaker cutting trough is sealed. 23. Cuttings transfer augers are operational. 24. Shaker bypass line to mud pits is closed. 25. Gumbo box bypass line is closed. 26. Gumbo box view hatch is sealed. 27. Cracks in rig floor are sealed with "Builders Foam". 28. Choke manifold discharge line is closed and tagged. 29. Large garbage bags are on rig if needed. 30. Cutting boxes are on rig. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 28 of 20 DRILLING OPERATIONS 31. Absol is on rig. 32. Vacuum system is operational. 33. Extra personnel on rig for cutting handling as needed. 34. Drillpipe inside and outside wipers are on rig. Communications 1. All involved rig and supply vessel personnel to have VHF radios. 2. One designated rig crew member to be assigned as lookout during the transfer to observe for leakage from the rig or supply vessel and to monitor transfer hoses. 3. Transferring of oil base mud should be done in daylight hours only, unless ExxonMobil operations superintendent approves a night transfer. Additional planning steps will be necessary to address problems that could be encountered with a transfer during darkness. 4. OIM, tool pusher, ExxonMobil drilling supervisor, mud engineer, mud logger and control room operator will be informed prior to the transfer of OBM. Transferring 1. OIM or Barge Eng./Captain and the derrick man will double check line up from loading station to mud pits. 2. Work permit will be completed prior to the transfer. 2.a Cutting and welding permits are to be returned and put on hold until transfer of OBM or base oil is complete. 3. Connect transfer hose to supply vessel. OIM or Barge Eng./Captain to confirm with supply vessel captain that transfer hose connection flange is a proper mate to the flange on supply vessel. 4. Transfer is now ready to be started. The derrick man will monitor volume pumped and change over as required, opening valves on next pit to be filled before closing valve on pit just filled. Derrick man and mud loggers will monitor volume received periodically throughout the operation and upon completion of fluid transfer. 5. If any difference between volume pumped and volume received should occur, stop the transfer immediately. The tool pusher and ExxonMobil drilling supervisor are to be informed of the discrepancy and an investigation will be conducted to find the reason for the deviation. An acceptable solution to the problem will be implemented prior to continuing the operation. 6. The mud engineer will perform quality checks of the transferred fluid periodically during the operation. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 29 of 20 DRILLING OPERATIONS 7. When transferring is completed, stop transfer pump and close valve on loading line in pit room. Close the valve at the loading station, the transfer hose must then be bled to the supply vessel. The valve on the end of the transfer hose at the supply vessel must be closed prior to disconnecting the hose from the flange on the vessel. 8. All mix lines, suction lines and transfer lines to the cement unit and trip tank are to be flushed. All water mud/oil mud interface from the flushing operation must be captured and pumped to a slop tank. After flushing, all valves are to be closed. DISPLACING WATER BASE MUD FROM THE WELLBORE WITH OIL BASE MUD Responsibility 1. Tool pusher and ExxonMobil Drilling supervisor to be in charge of displacing operations. Preparations 1. Tool pusher and Mud Engineer will hold pre displacement meeting with all involved crew members. 2. Ensure flowline adapter connections are tightened. 3. Shaker bypass line to mud pits is closed. 4. Shaker bypass line into the gumbo box is inspected, closed, tagged and secured. 5. Gumbo box view hatch is closed and inspected. 6. Dump valves on degasser are inspected, closed, tagged and secured. 7. Trip tank has been emptied and cleaned. 8. Trip tank dump valve is inspected, closed, tagged and padlocked. 9. Rig floor drains are lined up to the slop tank. 10. Valves on overboard lines from the rig floor/slop tank are to be inspected, closed, tagged and padlocked. 11. Shaker pit and shaker box are cleaned to meet mud engineer approval. 12. Shaker pit dump valves must be inspected, closed, tagged and padlocked. 13. Valves on possum belly discharges are inspected, closed, tagged and secured. 14. Shaker discharge lined up to bypass the sand traps. 15. All drains where OBM could be discharged will be plugged or directed to a slop tank. 16. Air transfer pumps available on rig. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 30 of 20 DRILLING OPERATIONS 17. Water flushing system valves for shaker screens will be closed and tagged. 18. Cuttings overboard gate in shale shaker cuttings trough is sealed. 19. Hatches on cuttings auger in correct position. 20. Cuttings transfer augers are operational. 21. Drains in shaker, sack, cement and treatment rooms sealed. 22. Desander and desilter feed line manifold valves are inspected, closed, tagged and secured. 23. Overflow tubes and cement unit displacement tank drain lines valves are inspected, closed, tagged and secured. 24. Cracks/openings in rig floor are sealed with "Building foam". 25. Choke manifold discharge line valves are closed and tagged. 26. Air operated mud bucket is on the rig and operational. 27. Drill pipe inside/outside wiper is on the rig. 28. Large bags are on rig if needed. 29. Vacuum system is on rig and is operational. 30. Additional personnel available to handle cuttings auger/cuttings boxes. 31. Plans have been developed to handle the water base mud displaced from the wellbore. 32. A plan is in place to catch the water base mud/OBM interface. 33. Chemicals onboard to treat OBM once displacement is completed. 34. Both mud engineers are on tour. 35. If displacement operations are to be conducted during darkness, ensure adequate lighting is available. Communications 1. All personnel involved in the displacement will have VHF radio access. 2. The tool pusher, ExxonMobil drilling supervisor, mud engineer and mud loggers will be involved in the displacement operation. 3. One designated rig crew member will be assigned as a lookout during displacement operations to observe for leakage. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 31 of 20 DRILLING OPERATIONS 4. OIM, tool pusher, ExxonMobil drilling supervisor, mud engineer, mud logger and control room operator will be informed prior to displacement operations. Displacing 1. Tool pusher and derrick man will confirm with each other that all valves are lined up properly prior to starting displacement operations. 2. If any leakage or spills are detected, stop the displacement operations immediately. Implement corrective measures and ensure all involved personnel are notified prior to restarting displacement operations 3. The mud engineers will periodically check the E.S. of the returning mud to determine whento put the return flow across the shale shakers. 4. After displacement, all mix lines, suctions lines and transfer lines will be flushed and any interface will be disposed of in the slop tank. 6.9 RIG-SITE DIELECTRIC CONSTANT MEASUREMENT General Approach In general, wellbore stability models are constructed based on cuttings analysis (to determine surface areas) from several offset wells. The surface areas are then stratigraphically correlated, data consistency is evaluated, and a surface area profile is generated. To apply an offset surface area profile to a prospective well, correlativity of stratigraphy must be determined (i.e., How do the offset wells tie to the prospect well?). Typically, simple adjustments to stratigraphic tops are made to correlate the surface areas. Sometimes, the depths of offset surface areas are "stretched" or "compressed" to accommodate anticipated interval thickening or thinning. This surface area profile is used as input data to a wellbore stability model that is used for well planning. Cuttings surface areas can be measured at the rig-site to verify or modify the wellbore stability model while drilling. Qualitatively, one can determine if the wellbore should be drilling more or less stable than the modeled well depending on the comparison of real versus assumed surface areas. Quantitatively, the real surface areas can be used to revise the model and mud weight schedule. Measurement Options Real-time surface area measurements can be made with a portable, on-site DCM kit. The decision of whether to mobilize on-site surface area measurements should consider the following: • • DCM requires a trained, dedicated mud logger. A DCM kit costs about $16,000, plus an incremental cost for consumable supplies Alternatively, cuttings have been shipped from wellsite to EMURCo in Houston or to Σª Labs in Aberdeen for analysis. Transportation time (to Houston or Aberdeen) is generally the critical path item for off-site analysis. A typical analysis cost is $15-20 per sample. Independent of the DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 32 of 20 DRILLING OPERATIONS measurement option, approximately 30-50 samples can be analyzed each day. The normal sample frequency is about once every 30 feet. Limitations The purpose of any measurement is to enable some response, if necessary. In some cases, the options for acting on rig-site surface area measurements may be limited. • • Certain wells face the difficult situation where the collapse gradient approaches, or even crosses the fracture gradient. Such a circumstance can be caused by abnormally high or unusually anisotropic tectonic stresses, or when rock strength is very weak compared to even normal stresses. Due to the conflicting requirements for stabilizing the wellbore (higher mud weight) and avoiding lost returns (lower mud weight) the only option is to manage the symptoms of instability while approaching the fracture gradient as closely as practical. Recent encounters with this situation (see examples below) have motivated current URC research on improved leakoff prediction and lost returns mitigation. While the EPR shale strength correlation incorporated in the WBSD software is accurate for the large majority of shales, the strength behavior of certain lower surface area shales has been observed to fall outside the database from which the correlation was delivered. Shales in Malaysia and the Irish Sea, for example, record surface areas of 100-200 m²/gm while exhibiting mechanical properties consistent with 400-500 m²/gm. Laboratory work is in progress to resolve such exceptions to the present database. Applications The following summarizes how real-time (on-site) surface area measurements have been or could be used to impact drilling operations: • • 6.10 Elli: The actual mud weight used took advantage of a 1 ppg "conservatism" (based on North Sea experience) in mud weight predictions from the wellbore stability model. Realtime surface area measurements indicated slightly stronger shale than initially assumed, which reinforced confidence in the selected mud weight. Bolivia: The pre-drill wellbore stability model was constrained to data from distant nearsurface core holes to bracket the expected surface areas. Real-time surface area measurements were used to qualitatively check shale sensitivity and monitor the inhibitive effects of glycol. DRILLING FLUID SYSTEM GUIDELINES On-site measurements of surface areas are recommended when: • • • Offset data are sparse. Correlation with offset wells is suspected, and or Preliminary modeling indicates operational flexibility to act on wellbore stability model predictions (i.e., mud weight and/or chemistry can be altered without losing returns). On-site measurements of surface areas provide useful data, but may not influence operational decisions when: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 33 of 20 DRILLING OPERATIONS • • • Mud weight is constrained by the leakoff gradient. Mud chemistry is constrained by hydrate inhibition requirements, and/or Shale strength is not consistent with the data base correlation. If these latter conditions are suspected beforehand, off-sit measurements of surface areas may be more convenient and cost-effective since the data will be used primarily to: • • Update/calibrate a stability model for future wells, and/or Conduct a post-mortem analysis for hole problems in the current well. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 34 of 20 SECTION 6 - APPENDIX G-I Prior to the transfer of fluid, all Rig and Boat personnel will meet and review the appropriate JSA's, MSDS Sheets. Fluid Transfer Procedure, and establish two-way communications. Upon the completion of the pre-job transfer meeting, all persons involved in the transfer will sign this document indicating this procedure has been reviewed. I. TRANSFER FROM MUD COMPANY TO BOAT A. Prior to Loading Boat Inspect All Hoses, Couplings, and Lines Look for cracks and frayed hoses Ensure connections are tight Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans) Individuals are assigned to monitor transfer (have radios available) Absorbents pads are available on location B. Location and Review ESD Operation and Procedure Review and formulate (if necessary) ESD Procedure Ensure ESD works Individual is assigned to ESD station during transfer C. Locate and Inspect Fire Fighting Equipment Review Fire Fighting procedure Ensure that the Fire Fighting Equipment is in working order and close at hand D. Inspect Receiving Vessel Open hatches and inspect for cleanliness (if weather permits) Note if the tank is isolated from sea-chest with a skillet or blank Inform the Captain and crew that the fluid is not to be rolled or moved during transit E. II. Loading the Boat Ensure all personnel are at their assigned station (do not leave unless relieved) Monitor for leaks when the transfer begins - shut down and repair if necessary verify volume to be transferred Prior to pumping, a sample will be taken at the Mud Company's storage site Catch a composite sample on boat while transferring of the first 10%, middle, and last 10% of the product and split the sample between the boat and Exxon representative Verify the Transfer volume at completion TRANSPORTING FLUID DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 4 Stress that fluid is not to be rolled, moved of transferred while transporting to location If weather permits, periodically sound the tanks to verify no change III. TRANSFER FROM BOAT TO LOCATION (DRILLING RIG) A. Hold Pre-Job Safety Meeting and Review JSA, MSDS, and Transfer Policy Secure boat to receiving Rig Look for cracks and frayed hoses Ensure connections are tight Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans) Individuals are assigned to monitor transfer Absorbents pads are available on location Review and be familiar with spill procedure. B. Location and Review ESD Operation and Procedure Review and formulate (if necessary) ESD procedure Ensure ESD works Individual is assigned to ESD station during transfer C. Locate and Inspect Fire Fighting Equipment Review Fire Fighting Procedure Ensure that Fire Fighting Equipment is in working order and close at hand D. Receiving Tanks Ensure tanks are clean and sealed Verify volume to be transferred E. Transferring Mud to Rig Catch a sample of mud at the start of the transfer to verify the composition At the completion of the transfer shut the valve at the rig to prevent siphoning Drain the transfer hose back to the boat Signature/Company/Date _________________ Signature/Company/Date ______________________ Signature/Company/Date _________________ Signature/Company/Date ______________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 4 SECTION 6 - APPENDIX I (continued) Prior to the transfer of fluid, all Rig and Boat personnel will meet and review the appropriate JSA's, MSDS Sheets. Fluid Transfer Procedure, and establish two-way communications. Upon the completion of the pre-job transfer meeting, all persons involved in the transfer will sign this document indicating this procedure has been reviewed. IV. TRANSFER FROM RIG TO BOAT A. Prior to Loading Boat Inspect All Hoses, Couplings, and Lines Look for cracks and frayed hoses Ensure connections are tight Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans) Individuals are assigned to monitor transfer (have radios available) Absorbents pads are available on location B. Location and Review ESD Operation and Procedure Review and formulate (if necessary) ESD Procedure Ensure ESD works Individual is assigned to ESD station during transfer C. Locate and Inspect Fire Fighting Equipment Review Fire Fighting Procedure Ensure that the Fire Fighting Equipment is in working order and close at hand D. Inspect Receiving Vessel Open hatches and inspect for cleanliness (if weather permits) Note if the tank is isolated from sea chest with a skillet or blank Inform the Captain and crew that the fluid is not to be rolled or moved during transit E. V. Loading the Boat Ensure all personnel are at their assigned station (do not leave unless relieved) Monitor for leaks when the transfer begins - shut down and repair if necessary verify volume to be transferred Prior to pumping, a sample will be taken at the Mud Company's storage site Catch a composite sample on boat while transferring of the first 10%, middle, and last 10% of the product and split the sample between the boat and Exxon representative Verify the Transfer volume at completion TRANSPORTING FLUID DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 4 Stress that fluid is not to be rolled, moved of transferred while transporting to location If weather permits, periodically sound the tanks to verify no change VI. TRANSFER FROM BOAT TO MUD COMPANY DOCK A. Hold Pre-Job Safety Meeting and Review JSA, MSDS, and Transfer Policy Secure boat to receiving Rig Look for cracks and frayed hoses Ensure connections are tight Ensure pollution equipment is in place (e.g., 5-gal bucket, drip/catch pans) Individuals are assigned to monitor transfer Absorbents pads are available on location Review and be familiar with spill procedure. B. Location and Review ESD Operation and Procedure Review and formulate (if necessary) ESD procedure Ensure ESD works Individual is assigned to ESD station during transfer C. Locate and Inspect Fire Fighting Equipment Review Fire Fighting Procedure Ensure that Fire Fighting Equipment is in working order and close at hand D. Receiving Tanks Ensure tanks are clean and sealed Verify volume to be transferred Catch a sample to verify composition prior to transferring fluid Catch a composite sample on boat while transferring of the first 10%, middle, and last 10% of the product and split the sample between the boat and Mud Company representative Signature/Company/Date _________________ Signature/Company/Date ______________________ Signature/Company/Date _________________ Signature/Company/Date ______________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 4 SECTION 6 - APPENDIX G-II OIL BASE MUD READINESS CHECKLIST Form D-200 Air Quality & Explosions: (areas exposed to oil base mud, i.e., shakers, pits) Adequate ventilation – change-out air every 5 min. or less Y N Mud Lab – dedicated to mud testing only Y N Mud Lab – explosion Proof Fixtures Y N Mud Lab – away from mud pits or Pressurized Y N Signs Posted – “No Smoking & No Hot Work” Y N Electrical equipment explosion proof – motors, lights Y N Personal Protective Equipment: Mud area – PPE locker stocked with apron, gloves (heavy duty), boots, face Y N shield, respirator Rig floor area – slicker suits (or aprons), work gloves, latex gloves, boots Long pants / long sleeve shirt worn Safety glasses with side shields worn Deluge shower – mud mixing area, rig floor Deluge shower – rig floor Eyewash Stations – rig floor, mud mixing area, other areas of potential exposure Wash Basins with hand cleaner available – rig floor, mud mixing area, mud pit area, pipe rack area, other affected areas Shipping Hazards: Stair steps wrapped with burlap or have non-skid surfaces Floor mats placed at all entrances to living quarters Rotary has non skid matting Absorbent material available for rig floor, other spill areas Steam cleaner or high pressure wash-down unit available Discharges: Ratholes/Mouseholes sealed with hose to disposal basin Pipe Rack Drains – drained to disposal basin Catch Pan under Rig Floor – drained to disposal basin Kick Plates around main deck/pipe rack area Kick Plates around the rig floor Dump valves double valved, locked, and signs posted with “Work permit require operate” Drill pipe wipers used – inside and outside Lower kelly mud saver used Mud bucket seals in good condition Y Y Y Y Y Y Y N N N N N N N Y Y Y Y Y Y Y Y Y Y Y Y N N N N N N N N N N N N Y Y Y Y N N N N Y Y N N Y Y N N Y N Water Contamination: Open mud pits covered Pits cleaned and isolation valves tested Base oil mud lines with hose and nozzles installed – rig floor, mud pit room, shaker area Sources of water isolated – rig floor, mud pit room, shaker area, mud mixing area Packing Elements on centrifugal pumps grease cooled, not water cooled – trip tank, mixing pumps Medium and coarse non-water absorbing LCM on rig Y DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 N 1 of 2 OIL BASE MUD READINESS CHECKLIST (continued) Deterioration of Rubber goods: Form D-200 Y N Y N Y N Y N Y N Y N Y N Y N Y N Base oil low in aromatic hydrocarbons, i.e. aniline above 145 Deg. F Oil Resistant (nitrile) rubber elements, i.e., mud pit valve seals, shaker valve seals, shaker mounts, and hoses Oil Resistant (nitrile) elements used in BOP, ram seals, annulars Personnel and Training: Two mud engineers on location Extra roustabouts for clean up duty Work-hour restrictions scheduled General Safety Meeting – explain OBM hazards and preventative actions explained, i.e., clean clothes, deluge showers, hand cleaners Use and need for PPE explained General Comments: Report By:Position: Location: Contractor: Date: Rig: Distribution: Operations Superintendent Rig file DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 ABNORMAL PRESSURE DETECTION IN CLASTICS 2 of 2 7.0 ABNORMAL PRESSURE DETECTION IN CLASTICS 7.1 7.2 7.3 7.4 7.5 Background Pressure Indicators While Drilling Abnormal Pressure Detection Team Responsibilities Mud Logging Operational Guidelines ______________________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003 1 2 10 11 15 7.1 BACKGROUND For all Drilling Operations a casing seat or TD hunt will be prepared in conjunction with the Operations Geologist. Conventional abnormal pressure detection parameters as described in this chapter generally apply to clastic sequences. There are no reliable methods to detect the onset of abnormal pressure in carbonate sections. When drilling predominantly carbonate sequences, extreme care must be exercised including controlled drilling, frequent flow-checks, preparedness for lost returns/fractures and consideration of correlation (whenever possible). Conversely, in clastics, the detection techniques contained in this section may be relied upon with a much higher degree of success. Definitions Normal Pressure - pressure equal to the hydrostatic pressure exerted by a column of water of a specific density extending from the surface to the depth of the formation. Normal pressure typically refers to 8.5 9.2 ppg formations that can be drilled safely with 9 - 10 ppg muds. Abnormal Pressure - any pressure greater than the normal pressure for a given basin. Hydrostatic Pressure - the pressure exerted by the vertical height of a column of fluid. Transition Pressure - the interval in which the normal fluid pressure gradient changes to an abnormal fluid pressure gradient. When does abnormal pressure occur Abnormally high pressures are found worldwide. Such pressures occur when fluid in the pore space begins to support more overburden than just fluid weight; i.e., not all of the compressional forces are transmitted by the rock matrix. Causes of abnormal pressure Many factors can cause abnormally high formation pressures. In some areas, a combination of factors prevails. The most commonly described cause of abnormally pressured or over-pressured sediments is under-compaction. Other causes are thought to be: • Chemical diagenesis • Uplift • Fluid density contrast • Recharged or re-pressured formations, and • Faulting. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 16 Because conditions can vary widely, special care should be taken not to assume that the cause of abnormal pressure established from experience in a well-known area necessarily is the cause of a similar condition in another basin which has not yet been adequately tested by drilling. Documentation of known welloperational specific abnormal Pressure 7.2 Ideally, Operations Geology should define well-specific abnormal pressure causes for any well to enhance understanding and planning to deal with the pressure when it is experienced. Pressure Indicators While Drilling The following tools & parameters, listed in their order of reliability, are used to monitor for abnormal pressure in clastic sections while drilling: • • • • • • • • Rate of Penetration (ROP) Interpretation Rate of Penetration Curves (includes d and dc exponents) Total Drilled Gases (BGG, CG, TG, etc.) Mud Properties (chlorides, viscosity, flowline temperature, etc.) Cuttings Analysis (lithology, shale density) Paleontology and Paleobathymetry Borehole Instability (hole fill, torque and drag) Correlation (Mud log & LWD with offset logs) Real Time Pore Pressure Plots (LWD Sonic, Density or Resistivity) An increase in ROP with constant parameters indicates a drill-off trend and generally indicates an increase in pressure. However, maintaining a constant ROP over a long interval may also indicate increasing pressure since the expected bit dulling trend (decrease in ROP) did not occur. Depending on bit type, increased ROP in the transition zone has consistently been one of the most definitive indicators of entry into overpressures when other drilling parameters are maintained constant. Factors affecting ROP Successful use of ROP to detect dulling trends and drill-off trends is dependent on maintaining constant drilling parameters. The following factors all affect ROP: DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 16 • weight on bit • • • • • • • rotary speed bit type/size bit condition mud viscosity hydraulics differential pressure, and lithology Reference: See Section III of the Abnormal Pressure Technology manual for additional information. Note: The referenced manual should be reviewed before interpreting these parameters during an abnormal pressure hunt. ROP plotting Plotting of ROP is used to differentiate pressure-induced drill-off trends from normally expected bit dulling trends. These trends are based on the common assumption that when a bit is first run in the hole and begins to rotate, it begins to wear out or dull which results in a slower ROP (dulling trend). ROP and lithology It is important to note lithology changes when plotting ROP. Normally, a drill-off (drilling break) will occur in a silty-shale or sandstone. Thus, when looking for drill-off and dulling trends, "clean" shale intervals should be used. "d" exponent curve Another curve used to predict increasing pore pressure is the "d" exponent curve. This drilling exponent is used to normalize ROP data and changes in bit weight, rotary speed, and hole size to detect increasing formation pressure. Reference: See Section III of the Abnormal Pressure Technology manual for additional information. Note: The referenced manual should be reviewed before interpreting these parameters during abnormal pressure hunt. "dc" exponent Another curve used in the corrected "d" exponent ("dc"). This value is curve the "d" value corrected to the gradient of the basin in which the well is drilled, and for the mud weight. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 16 Reference: See Section III of the Abnormal Pressure Technology manual for additional information. Note: The referenced manual should be reviewed before interpreting these parameters during an abnormal pressure hunt. Gas units One of the most important surface measurement parameters used to indicate abnormal pressure is the "gas unit". There is no quantitative correlation between gas units and pore pressure. Interpretati on of gas readings Detection of abnormal pressure, and even the evaluation of a zone of interest, is a matter of comparing parameters through the interval in question with the previously established trends. The key to interpretation is not the magnitude of the gas readings but the relative change in the readings. Types of gas The different types of gas are as follow: • • • • • • Background Gas (BGG), also called Drill Gas Trip Gas (TG) Connection Gas (CG) Circulating Gas (Circ BGG) Show Gas, and Shutdown Gas. Background Gas (BGG) aka Drill Gas Background Gas (BGG), or Drill Gas is the average gas observed while drilling, exclusive of shows. Background gas represents the gas liberated from the pores in the rock that is being ground up by the bit. Effect of drill pipe pulling speed on trip gas Pulling pipe can create a swabbing effect, which lowers the effective bottom hole hydrostatic pressure during tripping. Drill pipe pulling speeds must be reduced in critical sections of the well to a level which minimizes swabbing to ensure that trip gas will be a valid parameter reflecting the actual degree of overbalance of the pore pressure by the static mud weight. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 16 Trip Gas (TG) Trip GAS (TG) is the maximum gas observed on bottoms up after a trip. Trip gas represents the amount of gas feeding into the hole when the pumps are shutdown and the pipe is tripped. Connection Gas (CG) Connection Gas (CG) is the maximum gas observed on bottoms up after a connection. Connection gas represents the amount of gas feeding into the hole when the pumps are shutdown while making a connection. When the pumps are shutdown, the effective mud weight, or equivalent circulating density (ECD) is decreased because of loss of the annulus flow friction effect. Some portion of the connection gas may also be due to swabbing when picking up for the connection. Connection consistency To be a meaningful parameter, connections should be made consistently, requiring the same amount of time and pick-up speed to complete each connection. When picking up to make a connection, the pumps should be left on until the tool joint is at the break-out point. When drilling with a top-drive, it is often desirable to simulate connections to increase the frequency of the connection gas indicator. Kelly cut gas A phenomenon sometimes associated with connections is kelly cut gas. It results from air getting into the drill string during a connection. When this "void" in the drill pipe is circulated around (bottoms up capacity plus drill pipe capacity), it sometimes shows a gas peak. These phenomena should be distinguished from connection gas. Circulating Gas (Circ BGG) Time for circulating gas to stabilize Circulating Gas (Circ BGG) is the stabilized level of gas observed after all of the cuttings have been circulated out of the hole. It represents residual gas in the mud system after recent cuttings gas has been circulated out of the well. Background gas (when drilling) or bottoms-up gas (after tripping) should drop quickly to a stabilized level after circulating out the cuttings or trip gas. If significant time is required to reach the stabilized level, gas could be feeding in because of insufficient mud weight. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 16 Show Gas Reactions show gas Show Gas is cuttings gas observed while drilling a potential reservoir interval (usually associated with a drilling break). to Mud weight should not be raised solely in response to show gas from cuttings. When in doubt, circulate out to determine the circulating background gas level. If the excessive gas units drop rapidly to below drilling background levels, the gas came from drill cuttings. If the gas units continue to be excessive after circulating out, the well could be at or very near balance conditions. Shutdown Gas Shutdown Gas is gas resulting from pump shutdown period; i.e., for equipment repair, etc. The table below describes how to report the various types of gas. Gas type Report as Example Background BGG (Depth to Depth) BGG 40 units from 7000' to 7500' Gas (BGG) aka and 60 units from 7500' to 8000'. Drill Gas Trip Gas (TG) Maximum gas observed from trip Background Gas before trip: 50 depth minus background gas prior units Maximum gas observed from trip to trip. Also note the time depth: 150 units between B/U trip gas peak and Report Trip Gas as: 100 units or return to background gas level 100 units over BGG and report if more than normal. Connection Maximum gas observed from Background Gas before connection: 50 units Gas (CG) connection depth minus Maximum gas observed from background gas prior to connection depth: 75 units connection. Also note the time between the B/U gas peak and the Report Connection Gas as: 25 units or 25 units over BGG return to the prior gas level and report if more than normal. Circulating Stabilized gas units without drill BGG while drilling is 50 units, after picking up off bottom and Gas (Circ gas or trip gas. circulating out bottoms up, the gas BGG) level falls to 25 units. Report Circ BGG as 25 units or 25 units over BGG. Gas reporting DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 16 Show Gas Shutdown Gas Mud properties to plot Maximum gas observed from the drilling break minus background gas. Background Gas before drilling break: 50 units Maximum gas observed from drilling break: 750 units Report Show Gas as: 700 units or 700 units over BGG Maximum gas observed from Background Gas before shutdown: shutdown period minus 50 units background gas prior to Maximum gas observed from shutdown. shutdown period: 75 units Report Shutdown Gas as: 25 units or 25 units over BGG The mud properties to be plotted include: • • • • • mud density total chlorides (titrated or resistivity) temperature ion change (calcium and sodium) mud viscosity (funnel, plastic, yield point and gels) and • pH factor. Frequency of mud properties check When looking for abnormal pressure, the mud properties should be kept as constant as possible. The mud properties (both in and out samples) should be checked every four (4) hours or more often if the mud is gas cut. Bottoms up after each trip should also be checked. Plotting method The mud properties should be plotted in a graphical or columnar form. Changes in rheological properties Any significant change in the rheological properties of the drilling fluid (especially a freshwater mud) when drilling over-pressured formations may be an indication of an under-balanced wellbore condition. Changes in chlorides An increase in the total chlorides over the average for the normal pressure portion of the hole may indicate a formation water influx and entry into higher pore pressure. An increase of chlorides causes drilling fluid chemical changes that show up as an increase in: • funnel viscosity • plastic viscosity, and • yield point. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 16 Oil / water ratio If drilling with an oil based mud , the oil/water ratio may be an indicator of an influx of formation water. Temperature gradient changes A temperature gradient change as indicated by the temperature of the mud returns at the flowline may indicate that over-pressured sediments are being drilled. Generally, this change will be an increase in the flowline temperature due to a higher geothermal gradient in the overpressured zone. However, a change in the temperature gradient may alsomud indicate: When considering circulating temperature to detect a transition zone, it is very important to remember that these temperatures • the crossing a fault •items: depend upon theof following an unconformity, or • a• change in lithology. ambient temperature • circulation rate • system volume (mud tanks, etc.) • time since circulation • solids content in mud • addition of fluids and additives (humidity, heavy rains if pits are open), and • penetration rate. Factors affecting temperature Temperature plotting guidelines The following guidelines are recommended in order to obtain meaningful temperature data that can be assimilated into pressure indicator form. • Monitor and record simultaneously inlet (suction) and outlet • • • • • (shakers) temperature. Plot with other parameters. Consider lag time to correlate temperature with depth. Establish gradient for each bit run. Do not establish the mud temperature gradients until after the effects of tripping have normalized (usually 30' to 40' of drilling). Observe sudden increase in the outlet/inlet differential. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 16 Changes in physical properties of cuttings Cuttings from the transition zone will have different physical properties from normally pressured cuttings. Some of the physical changes are: • • • • • • • Composition Color Texture Size Shape Fracture • quantity, and bulk density. Color change Color change is often noted from multi-colored green, reddish brown, tan and light gray non-marine shales in normally pressured sediments to a darker gray and often dark brown to gray marine shales in abnormally pressured zones. Texture change Textural change in shale may be from silty and rough to waxy, slick or soapy. Shape change A change in shape may occur from semi-flat, rounded cuttings to angular, flat, splintery and often jagged and elongated (propeller shaped) concave curved cuttings. Sometimes large cuttings several inches long, known as spalling shale, are noted when drilling underbalanced. Quantity of cuttings often increases when the overpressure becomes change greater than the mud column pressure. This occurs when the formation begins to implode into the wellbore. Occasionally, there is simultaneously torquing of the drill pipe and the pump pressure increases. Also, this is generally when you get fill on bottom after making a connection. Quantity Density change 7.3 A decrease or departure from the normal compaction trend in the sale density of the cuttings is another indication of drilling overpressured shales. Abnormal Pressure Detection Team Responsibilities DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 16 Team make-up When deployed an abnormal pressure detection team should consist of the following members: • • • • • Rig Supervisor Wellsite Geologist Drilling Engineer (if required) Paleontologist (if required) Mudloggers, and MWD personnel • Rig Hands Driller, and Shaker hand Mud Engineer When should All team members should be at the well site ±24 hrs before the team arrive transition zone is expected. This allows time to monitor all the indicators so that a "normal trend" reference line can be established. Mission of team Team members The table below describes the responsibilities of each member of the responsibilities team. Role Rig Supervisor Wellsite Geologist Drilling Engineer Paleontologist MWD Engineer Mudlogger Responsibilities The Rig Supervisor is responsible for the drilling rig and all on-site activities and is designated as the Team Leader. The supervisor has the ultimate onsite authority on when to raise the mud weight, stop drilling, and log based on the advice of the other team members. The Wellsite Geologist's duties are to plot and interpret various geological abnormal pressure indicators, interpret and correlate logs (MDS/LWD logs, electric wireline logs, mud logs, etc.), and calculate estimated pore pressure from logs and shale density plots. The Drilling Engineer's duties are to interpret drilling parameters. The Geologist and Drilling Engineer must maintain close communication and closely analyze the various indicators as the hole is drilled. The Paleontologist's duties (if required) are to identify correlative microfossil zones, construct paleobathymetric maps, and help the team better understand the geology. The MWD Engineer's duties are to maintain QC of LWD logs, and estimate pore pressure changes from log plots. The Mudlogger's duties are to record all abnormal pressure parameters, make lithologic descriptions of the cuttings, watch for hydrocarbon shows, and maintain a lithology/drilling parameter log plotted up to DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 16 date continuously as the well is being drilled. Driller Mud Engineer Shaker Hand The driller's duty is to maintain the drilling parameters (WOB and RPM) as constant as possible and as specified by the Rig Supervisor. He should immediately notify the Rig Supervisor of any changes. The Mud Engineer's duty is to measure the mud weight at intervals specified by the Operations Supervisor and keep the other team members updated. The shaker hand's duties are to assist the mud engineer in monitoring mud properties, monitor cutting size and volume, and monitor for flow when pumps are down. * Most abnormal pressure detection operations are conducted by contract Geologist with no EMDC Geologist or Engineer on site. Proper communication should be made through with the team members at the rig site and office. 7.4 Mud Logging Where are specifications found Mud logging services and interval will be specified in the Drilling Program. Abnormal pressure parameters to be monitored Abnormal pressure parameters are to be monitored by the mudloggers and may include the following: • rate of penetration • d/dc • gas detection background gas connection gas trip gas, etc. • chromatograph readings • lithologic descriptions • shale density, surface area and description • "In" and "Out" mud properties, and weight temperature chlorides, etc. • hole conditions torque drag fill, etc. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 11 of 16 Plotting Data While drilling, the Mudloggers will plot the specified data on a mud log on a continuous basis and maintain 24 hour surveillance of the wellbore. Distribution/ frequency of reports The Mudloggers will: • • provide the Drilling Supervisor a copy of the mud log and mud logging report daily, and fix a copy to Company personnel as specified by the Drilling Supervisor/Wellsite Geologist. Note: It may be required to fax the mud log to the office more often when drilling in or near possible transition zones (typically, a minimum of twice a day to office for Operations Geologist, and Superintendent's review). Mud logging unit specifications The mud logging unit should met the following specifications: • A pressurized logging unit large enough to accommodate the required personnel should be use. This could include: Mudloggers Wellsite Geologist Pressure engineer (if required), and other required personnel. • All instruments in non-pressurized sections of the unit will be intrinsically safe. • The unit should have an alarm to detect depressurization. Detailed specifications for the mud logging unit and associated equipment will be in the mudlogging contract. Gas detection • A Hydrogen Flame Ionization Gas Detector (FID) and equipment Hydrogen Flame Ionization Gas Chromatograph system will be supplied on the unit with a second system provided as backup. • An integrator will be supplied for gas percentage calculations from the chromatograph. • Gas readings will be calibrated to : 2% methane balance in air (2% = 100 units), and 20% methane balance in nitrogen (2% = 1000 units). DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 12 of 16 • A carbide lag (or in Oil Base Mud some other type of lag) will be made each 24 hours to check operation of gas detectors and lag time. • The primary gas trap must be constructed so that mud enters equipment through a 1.5" to 2" hole in a bottom plate on the trap. Two (2) opposed, open stirrup (curved or straight) agitator blades should be used. An air motor is preferred. • A backup gas trap should be available on location at all times. • The secondary gas trap extracts a precise quantity of mud from the possum belly and automatically extracts gas entrained in the mud. It should be self-calibrating and incorporate two (2) FIDs as sensors. Gas trap Computer equipment • A minimum of three (3) monitors are to be installed as indicated below: one in the Drilling Supervisor's office one (Div 1, Class 1, intrinsically safe) on the rig floor, and one in the mud logging unit. • Computer software and instrumentation capable of measuring and displaying the following data are ideal: ROP Torque pump pressure total gas pit levels Dxc exponent (calculated) mud resistivity temperature RPM WOB Pump strokes flow rate trip tank levels rotary torque, and mud density This software and instrumentation should be independent from the rig's instrumentation and have alarms with high/low levels. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 13 of 16 Lithology • UV light box with tow (2) 3600 angstrom UV lights plus one equipment (1) white light. • High quality binocular microscope with high intensity light. • Lithology determining chemicals (e.g., HCL, Alizarin Red). • Probes, tweezers, sample trays and sieves. description DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 14 of 16 Guidelines Guidelines for drilling in abnormal pressure areas are: • • • • • • • • • • Guidelines The BOP must be tested and functioned, and the drill crews determined to be qualified and competent (via training and drills) on flowcheck and well shut-in procedures in accordance with the Well Control Section of this manual. Reference: See the Well Control Section of this manual for additional information. The drilling fluid should be stabilized at the pre-determined weight. Adequate barite must be on the drilling rig to weight up to at least the expected mud weight (minimum: the higher of 1000 sacks or 1 ppg increase over current mud weight). Barite needed should be addressed in lost return areas. The barite quantity on-site must comply with the regulations of the MMS or State Agency. Check mud company inventory of barite at their base and how rapidly it can be mobilized to the rig site. The PVT and FLO-SHO alarms should be set to the lowest practical limits. The abnormal pressure detection parameters specified in the Drilling Program must be monitored continuously. The drilling parameters should be stabilized as soon as possible during each bit run and maintained constant to allow for more accurate pressure detection. If mud weight must be raised in response to abnormal pressure indicators, drilling should cease and the well should be circulated until the system is stabilized at the new mud weight. After consultation with the Operations Superintendent, the mud weight may be increased gradually while drilling if conditions allow. Consideration should be given to using mill tooth bits as they have been the most reliable in responding to abnormal pressure indicators. Successful abnormal pressure hunts have been conducted with insert bits, and PDC bits in areas with significant local knowledge and where offset experience exists. Guidelines for drilling in abnormal pressure areas are: • The BOP must be tested and functioned, and the drill crews determined to be qualified and competent (via training and drills) on flowcheck and well shut-in procedures in accordance with the Well Control Section of this manual. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 15 of 16 • • • • • • • • • Reference: See the Well Control Section of this manual for additional information. The drilling fluid should be stabilized at the pre-determined weight. Adequate barite must be on the drilling rig to weight up to at least the expected mud weight (minimum: the higher of 1000 sacks or 1 ppg increase over current mud weight). Barite needed should be addressed in lost return areas. The barite quantity on-site must comply with the regulations of the MMS or State Agency. Check mud company inventory of barite at their base and how rapidly it can be mobilized to the rig site. The PVT and FLO-SHO alarms should be set to the lowest practical limits. The abnormal pressure detection parameters specified in the Drilling Program must be monitored continuously. The drilling parameters should be stabilized as soon as possible during each bit run and maintained constant to allow for more accurate pressure detection. If mud weight must be raised in response to abnormal pressure indicators, drilling should cease and the well should be circulated until the system is stabilized at the new mud weight. After consultation with the Operations Superintendent, the mud weight may be increased gradually while drilling if conditions allow. Consideration should be given to using mill tooth bits as they have been the most reliable in responding to abnormal pressure indicators. Successful abnormal pressure hunts have been conducted with insert bits, and PDC bits in areas with significant local knowledge and where offset experience exists. FORMATION EVALUATION 8.1 FORMATION EVALUATION 8.2 General 1 8.3 Conventional Coring 1 8.4 Wireline Logging Program8 DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 16 of 16 8.5 Sidewall Coring Operations 11 8.6 Wireline Radioactive Sources 12 8.7 MWD/LWD Logging 12 8.8 Mud Logging and Cuttings Samples 14 ________________________________________________________________________________ ______ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003 8.1 GENERAL Formation evaluation takes many forms and in many respects is the province of the wellsite geologist. However, operation of the equipment and its effect on well safety, DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 16 is the responsibility of the operations supervisor. Therefore, each major method of formation evaluation will be discussed in view of operational considerations. 8.2 CONVENTIONAL CORING For all Drilling Operations, a supplemental procedure will be prepared detailing the coring operations. The objective of coring is to obtain a formation sample for geological or reservoir evaluation, determine permeability, porosity, composition of the rock, and to conduct flow studies. Because of the valuable information, which the cores provide, the drilling objective is to furnish the maximum core recovery, minimal core damage, and minimum operational cost. In order to do this, planning is the crucial first step to ensure that a core analysis program is successful and that the money used to obtain and analyze the core is well spent. Deciding on the coring objective, mud type, core cutting method, and core handling procedures at the surface are the first steps in the planning process. The most widely used coring method today is the conventional double tube (inner and outer) core barrel with a PDC or diamond core head. Diamonds cut with a shearing action and thus greatly reduce the fracturing of the core. This enhances the recovery because a non-fractured core is less like to jam the core barrel before a full-length core has been cut. Standard core catchers are routinely used successfully in areas with consolidated formations. Closed catcher core systems such as Baker Hughes Inteq's "Hydro-Lift", used almost exclusively in the Gulf of Mexico, are used in coring unconsolidated formations to enhance recovery. In these cases, use of a face discharge bit (in which the inner core barrel can extend into the bit throat area) is recommended to minimize erosion of the core as it is cut. Pre-Coring Meeting A pre-coring meeting should take place a week or two before coring, and should be attended (if possible) by all personnel that will be involved. At the meeting, the coring objectives and the coring plan can be reviewed and minor changes can be made if necessary. The role and responsibilities of all personnel should also be discussed. This will help everyone realize that coring is a team effort, and that each person's role is vital. Conventional Coring Equipment Core Bits Diamond core bits are available in numerous designs for drilling various types of formations. In general, for soft formations, large diamonds are spaced relatively far DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 16 apart, whereas in hard formations, smaller diamonds are set closer together. The cost of the core bit depends on the total carat weight of the diamonds plus the setting charge. Used bits are returned for salvage of the diamonds and to receive credit for the reusable stones. Beside the PDC/diamond placement, the main difference in core head design is the location, size, and number of drilling fluid passages for cleaning and cooling the bit. This design depends on the formation to be cored along with the available pump horsepower. Relatively large fluid courses permit higher fluid circulation rates for flushing the hole while cutting sticky shales. Smaller, numerous fluid courses provide better cooling of the diamonds while coring hard abrasive formations. When coring in soft formations, EMDC may elect to have the coring company manufacture the core bits with their "throats" 1/8" smaller than the inner barrel or liner inside diameter. This clearance will allow the shales to swell and hopefully prevent the barrel from jamming and resulting in poor recovery. Face discharge core heads may also reduce erosion due to fluid flow past the core. In hard formation wellbores, the initial trip in the hole with a core bit should be done with careful monitoring for excessive drag, particularly in the lower portion of the last bit run. As a bit drills hard formations, the gauge protection of the bit can wear creating an under gauged hole. As the full gauge coring assembly enters this part of the hole, the bit and full gauge stabilizers on the core barrel could stick. If the drag becomes excessive, the assembly should be pulled from the hole and a hole opener or reamer run to open it to full gauge. Core Barrel The conventional core barrel for diamond coring consists of an outer barrel which houses a free, non-rotating, inner core barrel that is made of either light weight steel, aluminium, or fiberglass. In order to obtain a good core, the inner barrel must not rotate with the outer barrel. This is accomplished by suspending the inner barrel on a swivel assembly which utilizes a mud lubricated anti-friction bearing. The core bit is made up on the bottom of the outer barrel while the inner barrel is fitted with a core catcher assembly at its bottom. Conventional wall thickness barrels are generally available in the following sizes: Outer Barrel Diameter Core Diameter 4-1/8" 2-1/8" 4-3/4" 2-5/8" 5-3/4" 3-1/2" 6-1/4" 4" 6-3/4” 4" 7" 4-3/8" 8" 5-1/4" DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 16 If either barrel becomes bent, the unit should be replaced because the inner tube will probably rotate with the outer tube. The inner barrel must have a smooth uniform bore to allow passage of the core and to prevent wedging. The unit should always be checked before starting in the hole. The assembly can be hung in the derrick and the inner barrel hand-rotated before making up the core head. Inner Barrel Plastic Liners When coring in soft, unconsolidated formations, a plastic liner can be run that will help prevent the inner barrel from jamming, and help protect and preserve the core during removal and transport. In medium to hard formations, these liners are normally not run. There are three types of plastic liners: 1) Polyvinyl chloride (PVC) with temperature limitations up to 150 degrees F, 2) Acrylonitrile Butadiene Styrene (ABS) with temperature limitations up to 180 degrees, and 3) Butyrate, a clear plastic liner that has a temperature limitation of 140 degrees F. The PVC plastic liner is typically run when coring soft formations, though aluminium liners have been used in hotter holes where the BHT exceeds 180 degrees F. The use of these plastic liners will reduce the size of core that can be cut, by 3/8" to 1/2" depending on the size barrel being used. Fluted Aluminium Inner Barrel Very high recovery of long cored intervals has been achieved with fluted aluminium inner barrel in Norway. The design is believed to reduce core to inner barrel friction and therefore reduced jamming. Stabilizers Full gauge (1/32” under) integral bladed stabilizers near the top and just above the bit will keep the barrel from wobbling while coring, and should be replaced when worn down more than 1/8". If under gauged stabilizers were used in drilling the section of hole immediately above the core point, these full gauge stabilizers may cause excessive drag while going in the hole that could stick the assembly. An additional trip with a reamer or hole opener may be necessary before coring can commence. Safety Joint A safety joint at the top of the core barrel enables recovery of the inner barrel and core should the outer barrel become stuck. This will leave only the outer barrel and core bit to be fished from the hole. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 16 It should be noted that the safety joint is made with a left-hand thread that only requires 50% of the make-up torque to release. In high angle directional wells it may be impossible to work down enough left hand torque to the safety joint without backing-off the drill string at a higher point. Pump-Out Sub A pump-out sub (circulating sub) should be run above the coring assembly that can be opened in the event that the flow passages around the bit should become plugged during coring operations. A ball is normally dropped and the drill string pressured-up rupturing a disk that opens flow ports in the sub. Various pressure rated disks can be run, normally using those set to rupture at 3500 psi. Circulation can then resume and the hole cleaned prior to pulling out of the hole. The coring company provides these pump-out subs. Coring Jars Mechanical jars should NOT be run when coring because they can do serious damage to a core barrel assembly. If the drill string is stuck at the bit, mechanical jars have been known to tear the throats out of a core bit. A hydraulic jar (such as Bowen or Houston Engineering) is preferred by most core companies because the jarring blow can be controlled by the overpull from the rig floor. These jars are placed either towards the bottom of the HeviWate drill pipe, or in the upper portion of the drill collars. CONVENTIONAL CORING TECHNIQUES Preparing to Core It is very important that the hole be clean of any debris (rock bit teeth, bearings, etc.) to prevent damage to the PDC or diamonds. If necessary, a junk boot basket can be used during the last bit run prior to coring. If there is junk suspected on bottom after the last bit run before coring a boot basket run is recommended. The drilling engineer should work closely with the core bit manufacturer to select the best design and type of bit for the type of formation to be cored, anticipated mud properties, and available hydraulic horsepower. As with all drilling assemblies, accurate measurement of the core barrel assembly including the BHA should be made before going in the hole. After touching bottom while circulating, the bit should be held approximately 3 foot off-bottom and circulation continued to wash the hole clean of any fill that might have accumulated during the bit trip. Mud Properties DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 16 While drilling just prior to PDC/diamond coring, the mud viscosity should be reduced as much as possible without sacrificing hole cleaning. A low water loss mud will reduce filter cake build-up and minimize the chances of sticking. Low viscosity and low water loss will also help reduce pump pressures. In studies performed by Conoco in 1986, they found that very good core recovery (100%) was obtained in their offshore operations when the pressure of the mud column was kept at least 300 psi above the formation pressure using a Saltwater/New Drill type mud system. Coring runs in holes using a freshwater lignosulfonate mud were not as successful (the shales became swollen causing them to become sticky and jamming the core barrel), and in those operations done with very low differential pressures, no core was recovered. LCM can be pumped through a core barrel, but the material should be restricted to fine material only. Limit LCM to a maximum concentration of 15-20 ppb. Coring Operations Guidelines Cutting The Core Prior to dropping the ball to begin coring, circulate bottoms-up. A steel ball is pumped down the drill string and is seated in the top of the inner barrel. Coring fluid is then diverted between the inner and outer barrels and emerges at the fluid ports of the bit. For maximum performance, the core barrel should be stabilized as best as possible in the hole. A stabilizer just above the bit will normally give sufficient stabilization if it is not allowed to get more than 1/8" under the bit diameter. When starting the core, it is a good practice to cut the first 12 to 18 inches with only 2,000 to 4,000 lbs bit weight and with reduced rotary speed. After the stabilizer is buried in the core hole, bit weight and rotary speed may be increased. While coring, the bit weight should be maintained continuously and the weight must never be allowed to drill-off. Allowing the weight to drill-off will produce pounding on bottom and can result in severe damage to the core head and coring assembly. The rotary speed should remain constant during the coring operation. Coring Operations Guidelines WOB, RPMs and pump rate should be in accordance with the core bit manufacturer's recommendations. General guidelines are as follows: • For 8-1/2" hole, WOB should generally be between 4,000 and 6,000 lbs. in soft to medium-hard formations and 10,000 to 20,000 lbs. in harder formations DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 6 of 16 • The maximum circulation should be limited to a rate that will not erode the core bit matrix or undercut the core. Circulation rates of 200 to 500 GPM are most common when cutting a 4" core. • Rotary speeds should generally be between 50 and 100 rpm. Rotary speeds above 100 rpm could damage the core barrel from excessive torque. • Drilling parameters (pump pressure vs. pump rate, rotating torque vs. rpm, ROP vs. WOB, etc.) should be monitored closely during coring operations. A change in any parameter may be significant to coring success. When the core is being cut and begins to enter the inner barrel, the pump pressure will increase from 200 to 300 psi and is the result of the pressure drop across the diamond bit. This pressure should be monitored during the coring operation, an increase or decrease normally indicates that something abnormal is occurring and the cause must be determined. Coring operations should cease, the bit should be pickedup off bottom, and the standpipe pressure observed. • If the pressure drops but then returns immediately to the abnormally high pressure when the bit is set back on bottom, the bit has probably failed. A ring of diamonds that has been damaged will allow the formation to cut into the matrix, restricting the watercourses and causing the pressure increase. When this occurs, pull the bit to prevent further damage. • If the pressure increase remains when the bit is raised off bottom, plugging of the fluid passages in the bit or circulatory system may be the cause. Continued high pressure may also be an indication of swivel failure resulting in lowering of the inner barrel and closing of the fluid passages. In either condition pull the bit. • An abrupt increase in standpipe pressure may be caused by plugging of the core barrel from an accumulation of foreign particles in the mud system such as rubber, LCM, or pipe scale. • A pressure decrease while coring may be due to a number of factors, including a leak in the surface equipment, or a hole in the drill string. If this pressure decrease is accompanied by a decrease in penetration rate AND less torque, a wedged core has probably developed holding the bit off bottom. If this condition continues after picking up and setting down the bit, pull out of the hole and recover what core has been cut. • When pump pressure fluctuates continuously and the ROP is erratic, it is possible that alternate wedging and crushing of the core is occurring. The barrel should be pulled to avoid loss of recovery. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 16 Making Connections and Pulling the Core A complete set of drill pipe pup joints should be available when coring to prevent making an extra connection. It is a good practice to leave a foot up on the kelly joint before making a connection. If more than a 30 foot core is being attempted and a connection is necessary, stop the rotary table and pick the core barrel off bottom slowly. A noticeable jump on the indicator will result when the core breaks. If the core is hard to break, pull 15,000 to 30,000 lbs above the weight of the string, set the brake and slowly rock the rotary until the core breaks. After making the connection, return to bottom and rotate slowly until the bit is again cutting and the new core is entering the inner barrel. This same procedure should be used before pulling the core to avoid leaving a section of core in the hole. It should be noted that not all core barrels have the ability to cut more than 30 foot of core. When coming out of the hole with the core, it is very important that the drill string be pulled slowly and not rotated to prevent losing the core. Do not pump a slug, and use the trip tank to ensure that the wellbore takes the proper amount of mud. Killing a well with a coring assembly in the hole will be difficult and complicated because of the full core barrel in the string. Core Handling When the core barrel is pulled to the surface, there are two methods that are commonly used to remove a core. In hard formation areas where a plastic inner liner is not used, the inner barrel can be removed from the top of the core barrel and laid on the catwalk where the core is recovered. The core can also be removed while the barrel is left hanging in the derrick a few inches above the rig floor. The core catcher and lower shoe are removed and the core is slid out of the inner barrel and cut into 3 foot sections. In areas where soft, unconsolidated formations are cored, the plastic liner is pushedout of the inner barrel and cut into sections as it is removed on the catwalk. These sections are marked with orientation stripes, the well name, and coring depth. Small holes are normally drilled into each 3 foot section through the PVC/fiberglass/aluminium liner to vent any trapped gas. These holes are later taped closed prior to transport. The core is packed in dry ice to immobilize the formation fluids and prepared for shipment. Freezing the core at the well site and keeping it frozen throughout the shipping and sampling phases will minimize sample disturbance. The core can also be stabilized with resin or gypsum. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 16 When pulling the core through the rotary table, Draeger Tube detectors will be used to determine if the core contains H2S. If working in an H2S area, all personnel on the rig floor will don a self contained breathing apparatus (SCBA) prior to pulling the core through the rotary table. Coring High Angle Holes Coring high angle and horizontal wells will necessitate a change in the typical coring assembly. When using downhole rotary drive mechanisms, MWD tools, etc., the conventional ball to seal off the inner barrel cannot be pumped down. Special inner relief valves must be installed at the surface because it is unlikely that a ball would remain seated in a horizontal well. Do not use MWD or motors when coring. Additional thrust and radial bearings must be built into the coring assembly as well to prevent the inner barrel from rotating. Internal stabilization of the inner barrel to minimize its bending inside the outer barrel may also be needed. It is prudent to run only a 30 foot long core barrel in most instances, unless conditions are extremely favorable. Fiberglass inner barrels should be considered to reduce friction of the core on the bottom side of the inner wall where the core rests as it enters. A core barrel with high torque threads is recommended for coring in higher angle wells. This type of barrel allows coring in more difficult formations, and will allow more torque to be supplied to the core head. These high torque threads do not alter the strength of the body or decrease the core size. A detailed core handling procedure will be provided by Geology based on the coring objectives of the well and the type of core analysis required. 8.3 WIRELINE LOGGING PROGRAM A wireline logging program, which specifies the types of logs to be run, the logging intervals, and the order in which to run the logs will be included in the applicable drilling procedure. Logging Sequence To reduce rig time and complete as many logging runs as possible prior to a conditioning trip, the Operations Supervisor and wellsite geologist should thoroughly discuss the various logs and the proper sequence in which they are to be run. If there is any question, the Operations Supervisor should notify the Operations Superintendent. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 16 A logical running order is, with GR run on each log for depth control, is: 1. 2. 3. 4. 5. 7. 8. IES or IES-Sonic as required; GR and /or FDC/CNL as required; Conditioning trip if necessary; MDT/RFT's as needed; Dipmeter as required; 6. Velocity survey if required. Conditioning trip if necessary; Sidewall cores as required; The correct scales (5" or 1") for each log should be discussed with the logging engineer and checked to prevent having to re-log the well. The logging engineer should be instructed to report to the Operations Supervisor any drag on successive logging runs and any sticking or spudding with the logging tools. Wireline Logging Guidelines 1. Pre-job meetings will be conducted with the logging engineer prior to beginning each logging job. The Company technical requirements for logging and the specific logging program should be discussed, along with safety procedures for handling radioactive tools and sidewall core guns (SWCs). 2. The logging Engineer will record digital logging data and provide the required number of final log copies in accordance with the logging program and to the satisfaction of the wellsite geologist. 3. Two thermometers will be present on each logging run. 4. A running cable-head-tension device, if available, to read actual tension on the rope socket ("weak point" of system) should be run. 5. A station time limit should be established prior to running an RFT tool taking into consideration the hole condition and previous experience in the area. Typically samples should be taken at the deepest zone of interest first and subsequent samples taken as the tool is pulled up the wellbore to reduce the potential for wireline sticking. However, it may be appropriate to vary the sequence, to ensure the highest priority intervals are tested, in the event that adverse hole conditions reduce or prevent all desired testings. 6. The periods during which welding and radios must be shut down (when handling explosives, during certain logs, etc.) will be determined. Always shut down radios when these tools are at or above BOP stack. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 10 of 16 7. A wiper trip to the casing shoe should normally be made and the hole should be circulated clean prior to pulling out of the hole for logging. A high viscosity gel sweep to remove any loose cuttings may be necessary during this circulation. A logging pill may be spotted on bottom to help suspend any cuttings left in the hole during logging operations. These pills will be detailed in the appropriate drilling procedures. 8. The Drilling Fluids Engineer will take an "Out" sample of the drilling fluid before stopping circulation prior to POOH for logging and give samples of the drilling fluid, fluid filtrate, and a filter cake to the Wireline Logging Engineer to record on the log. 9. The trip tank will be used while logging to keep the hole full. The Drill Crew will record trip tank levels at scheduled intervals (15-minute maximum). The Mud Loggers will also record trip tank levels at the same intervals as a crosscheck. The amount of drilling fluid required to fill the hole will be reported on the Daily Drilling Report. 10. The Operations Supervisor will be notified of any abnormal changes in trip tank level(considering the line volume) when running in/out of the hole during logging operations. 11. Non-essential personnel will keep away from all logging tools, wireline, and related equipment at all times. 12. Only authorized personnel will enter the logging unit during wireline operations. 13. Loads will not be moved across the wireline cable when logging is in progress. 14. A wireline wiper will be used to clean the cable when it is being removed from the hole. Wash down water will not be used as this will complicate trip tank level readings. 15. Hole caliper information (if available) and bottom hole logging temperatures will be sent to the Drilling Engineer and Geologist as soon as practical during logging operations. 16. All tight spots and ledges in the hole will be noted for possible reaming prior to running casing. 17. Only logging company personnel will handle any tool that contains a radioactive source (e.g., neutron density tool) or explosives. A work permit is required for radioactive/explosive tool handling. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 11 of 16 18. Logging company personnel will wear appropriate radioactive monitoring devices and take the necessary safety precautions when running logging tools with radioactive sources. 19. All personnel on the rig floor will don a self contained breathing apparatus (SCBA) in H2S areas before removing samples from sampling tools such as the MDT/RFT (Atlas FMT). 20. Sample containers which may contain H2S gas will be marked as such. Wireline Company Responsibilities 1. Maintain the Wireline Logging Unit and related equipment onboard the drilling rig as specified in the contract. 2. Ensure that sufficient tools (primary and back-up) are onboard the drilling rig as specified in the contract. 3. Ensure that all tools are in operating order immediately after arriving at the wellsite. Provide service history of the W.L. detailing environment worked in and last service. 4. Provide the Operations Supervisor with overall dimensions and drawing of each logging tool run in the hole. 5. Ensure that overshot grapples and cut and strip equipment is available on the drilling rig for each different size of fishing neck before running the logging tool. 6. Ensure that logging tools are not stationary in the wellbore except when taking a sample/pressure using an MDT/RFT tool. 7. Notify the operations supervisor of any hole problems (excessive drag / sticking tendencies). 8. Ensure that the prospect geologist has all of the logs, tapes, and/or film strips, sidewall cores, etc., prior to leaving the location. 9. Ensure that the area surrounding the logging unit is clean of all debris, trash, and traces of any oil or lubricants prior to leaving the location. 10. Ensure that all equipment is stored properly (radioactive tools in designated storage area, explosives in approved magazine, etc.). 11. Use radioactive and explosive readiness checklists in Safety Management Program. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 12 of 16 Stuck Wireline Operations The basic philosophy for recovery of stuck logging tools is to cut and strip in most cases, particularly in directional wells and for any radioactive source tool. The following guidelines will be observed when attempting to free stuck tools: 1. A 75% criteria will be used for maximum overpull of stuck tools/wireline (i.e., overpull will not exceed 75% of the rating of either the rope socket or the wireline). If a cable head tension surface read-out is available, surface line tension will be used to determine the pull on the wireline, and the cable head tension surface readout can be used to determine the amount of pull on the rope socket. NOTE: If the float equipment has been drilled out with an undersized bit that results in a core of cement remaining in the shoe joints, watch for line key seating. If the logging tool becomes stuck, refrain from repeated pulls on wireline, to prevent damaging and cutting the line. Even though it is time consuming, a strip-over job has less risk than a wireline-fishing job. 2. All personnel will be cleared from the rig floor and from any areas under the wireline when pulling on stuck wireline. 3. Approval will be obtained from the Operations Superintendent prior to exceeding the 75% overpull criteria. 8.4 SIDEWALL CORING OPERATIONS The following guidelines will be observed during sidewall coring operations: 1. After the core gun is loaded, the area around the gun (catwalk, etc.) will be cordoned off and flagged as "Hazardous - Explosives In Use" until run in the hole. 2. Radio silence will be maintained on all radios and any welding is to be shut down on the drilling rig when picking-up, laying-down and tripping in the hole with the sidewall core guns until the guns are well below the mudline. 3. All helicopters and boats in the immediate area will be notified to maintain radio silence until further notice. 4. The shore base will be advised of the radio silence start and end times. 5. All non-essential personnel will be cleared from the rig floor when handling the core gun on the rig floor. 6. All personnel working below the rig floor (e.g., Texas deck area of the rig and well bay/+15 area of a platform) will be alerted and removed from the area when DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 13 of 16 running a sidewall core gun into the wellbore. Once the gun is below the mud line, normal work can continue. When pulling the SWC gun from the wellbore and the gun is at or above the mud line the precautions mentioned above will be taken. *NOTE: See EMDC Safety Manual for recommended safe working practices in Wireline Perforating and Other Electrically Detonating Operations section. Wellsite Geologist Responsibility: 1. Select side wall core points in relatively gauge sections of the hole to avoid "shooting off bullets" and leaving debris in the hole. 2. Make a description of the sidewall cores at the Wellsite immediately after unloading the guns. 3. Ensure that the Operations Supervisor has a report on bullet recovery that includes number of misfires, number of bullets left in hole, number of cores recovered, any other gun parts left in the hole, and depths of all shots. 8.5 WIRELINE RADIOACTIVE SOURCES Refer to Safety Management Program 8.6 MWD/LWD LOGGING Logging While Drilling (LWD) objectives are: • Provide real time correlation and pressure detection. • Obtain information for early operational decisions. • Use as a replacement or insurance for wireline logs that may be more costly. • Use to evaluate highly deviated wells where wireline logging is not possible. LWD logs are the most common log in the Gulf of Mexico because of hole angle and directional constraints. Tool Placement/Stabilization 1. MWD/LWD tools should be placed as close to the bit as practical in order to obtain high quality data prior to hole erosion and invasion, and to facilitate abnormal pressure hunts, casing seats, and core points. 2. MWD/LWD tools with integral blade stabilizers should be used if a near bit stabilizer is necessary. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 14 of 16 Stuck Pipe MWD/LWD tools should be run near the bit since the inside diameter of the tools will prevent wireline access for free-pointing stuck pipe. Several systems allow wireline passage after retrieving the electronics package. Use of downhole screens just above the MWD to prevent jamming may be used but could eliminate retrieving sources or electronics in the event of a stuck BHA. DP screen decision should be approved by the Operations Superintendent. Filter Screens & Flow Rates 1. Filter screens on the mud pump's discharge should be sized to remove any debris that may cause a problem within the LWD tool (see Op Tech Bulletins). 2. Do not use a filter screen inside of the drill pipe at each connection. Placing a filter screen inside drill pipe at each connection will prevent the use of wireline tools if the drill pipe becomes stuck or during well control operations. Use of downhole filter screens just above the MWD are permitted, but may prevent retrieval of sources or electronics. Use of downhole screens must be coordinated with the Operations Superintendent. 3. The MWD/LWD power turbine (if not battery operated) should be sized to obtain the range of flow rates needed for drilling the hole section expected to be penetrated on that run (coordinate with service company personnel). Additionally, MWD/LWD equipment hydraulic pressure requirements should be modeled and incorporated into drilling hydraulics. Handling 1. The MWD/LWD transport tray will be used for movement of LWD tools from the supply vessel and around the drilling rig. 2. Extreme care should be exercised when moving MWD/LWD tools onto the rig floor to prevent any unnecessary blows or jars that could cause internal damage. These tools do not have the wall thickness of drill collars and they can bend quite easily. Rough handling can damage the internal electronic packages of the tools. 3. Only MWD/LWD service personnel will handle the tools as some LWD logs have radioactive materials. Lost Circulation Material (LCM) Lost circulation treatment options are limited with MWD/LWD tools in the hole (check with LWD personnel for specific tool details). If severe lost circulation is DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 15 of 16 expected, MWD/LWD tools should not be used. These tools are very expensive and lost circulation can easily result in stuck pipe and the loss of the tools or damage to the tools. Should lost circulation occur with an MWD/LWD tool in the hole, the following steps should be taken • If lost returns are expected, size and set-up the MWD/LWD and motor as applicable to accommodate high concentrations of fine to medium LCM. • Pull to the casing shoe and let the hole heal sufficiently to POOH and lay down the tools if at all possible. • If necessary, pump fine or medium grade LCM well mixed. Limit LCM (nutplug) to a maximum concentration of about 30 ppb fine, or 20 ppb medium when pumping through an MWD/LWD tool. • For specific LCM material or concentrations consult with the service company and refer to the applicable drilling procedure. Newer generation MWD/LWD tools have a higher tolerance for lost circulation material; service personnel can give a good estimate on the concentration of material each tool can withstand before plugging. Some tools can be "turned off" by adjusting flow rate. This may reduce the jamming potential when pumping LCM. Well Control MWD/LWD tools should have the ability to circulate a minimum flow rate of 1000 GPM when used in the upper part of the hole where a dynamic kill may be necessary. 8.7 MUD LOGGING AND CUTTINGS SAMPLES Mud logging services will be specified in the drilling procedure. Mud logging, which is also a part of formation evaluation, has been previously addressed in Section 7 of this manual. Cuttings samples will also be collected, as specified in the drilling program. Typically, several sets of washed and unwashed cuttings samples will be required. These samples will be collected at the intervals specified in the drilling program. Note: Where mud loggers units have hydrogen gas feeding the Flame Ionization Detector (FID), post warning signs indicating the flammable/explosive characteristics of the gas. Inspect the hoses (typically Polyflow) every 2-3 months, and replace if it has been pinched, is brittle, or is discolored from the normal clear or white color (OIMS Manual Element 6). CASING OPERATIONS DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 16 of 16 9.1 CASING OPERATIONS 9.2 Casing Running 1 9.3 Casing Connection Make-up 5 9.4 Casing Checklist 5 _________________________________________________________________________________ _____ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 16 FIRST EDITION MAY, 2003 9.0 CASING & LINER OPERATIONS For all drilling operations, a detailed casing or liner running procedure will be prepared. When the rig is ready to have the casing sent to location, the Operations Supervisor is to call out and arrange delivery from shore base.. Unless otherwise noted in the applicable procedure, the casing operating guidelines in this section will apply. It is the responsibility of the Operations Supervisor to ensure that the casing running or liner running operation is conducted according to the guidelines and requirements in this manual and/or the approved procedure. In cases of conflict between this manual and an approved procedure, the approved procedure shall be followed. • A Job Safety Analysis (JSA) will be completed prior to all casing/liner operations and all personnel involved with the casing/liner running will review the JSA. OIMS REQUIREMENT: Use an Excel spreadsheet to generate the casing tally report. The original should be forwarded to the Drilling Engineer and should be included in the final well report (OIMS Manual Section 4). Additionally, OIMS requires a DRS casing tally report where possible. 9.1 CASING RUNNING Casing Preparation Guidelines 1. Ensure the pipe rack is clean and cleared of debris, tripping hazards, and slick areas. 2. Unload casing using the proper method. Immediately after unloading casing, the number of joints will be counted and compared with the cargo manifest. Any discrepancies will be noted and recorded. 3. The weight and grade of each joint of the casing will be checked to ensure that the proper casing was delivered (check casing ID to ensure correct weight casing was delivered). 4. Ensure the casing is racked properly for pick up and running. 5. Thread protectors will be removed and the threads cleaned if necessary. Most of the time connections will be "field prepped" and doped with the proper thread compound at the yard prior to sending to location. The casing, threads and couplings will be visually inspected for any signs of damage. • Take special precautions to prevent damaging the seal area on connections when removing thread protectors, cleaning etc. Review with the rig crews DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 16 to ensure that all personnel understand what areas of the connections are the sealing areas. 6. Casing will be drifted while on the pipe rack to check for and remove any internal debris. Drift OD is typically API drift but may be a special drift (reference applicable procedure). Recommended drift is a 1' bar (a 3' drift bar is typically used in the pipe yard). 7. All casing will be numbered and strapped. • Strapping buttress threaded casing to the diamond as the threads make up only to the diamond (1-2 inches before the thread run-out on the pin end). This can result in the casing shoe being deeper than anticipated if measurements are made to the thread run-out. Ensure strap is to correct position on the casing. • Use thread run-out template for premium connections and measure from end of pin threads. 8. A casing tally report will be prepared for every casing or liner run, showing the number of joints, casing description including joint type (weight, grade), joint length, joint depth, connection type, and location of major casing string components (float equipment, pup joints, crossovers, RA tags, centralizers, wellhead attachments, etc.). A copy of the report will be kept on the rig for reference during logging, completion, P&A operations, etc. 9. At least two people will check the casing tally. 10. When running production casing, pup joints should be placed above the tops of possible design productive zones in order to facilitate future correlation. RA (Radioactive) Tags may also be useful to ensure accurate tie in when drilling high angle directional wells or when a premium casing thread may be difficult to see with a casing collar locator log (e.g. CRA casing, integral connection). Use of such devices will be specified in the appropriate casing procedure. If RA tags are used, install at least one tag 50m above the top most pay zone. 11. Sufficient rathole should be left below the casing shoe to allow for fill, extra joint, etc. The general guideline on rathole is no more than +/- 50' TVD of the permit depth, deep enough to get all LWD information required below the sand bottom, or deep enough so that the float equipment does not need to be drilled out on production casing. Rathole is more critical for mandrel type hangers where the casing is not planned to be cut off. Cementing Accessory Guidelines DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 16 1. Unless specified otherwise in the applicable casing or liner running procedure, two joints of casing should be run between the float shoe and the float collar as float joints. Typically one joint with the float collar made up on the end and thread locked and one joint with the float shoe made up on the end and thread locked are assembled in the yard and sent to the rig. A back up set of float equipment is also sent to the rig loose. 2. All connections up to and including two joints above the float collar will be threadlocked. 3. Run centralizers, turbolizers, scratchers, cement baskets, etc. as detailed in the applicable procedure. Casing Running Guidelines NOTE: Complete the questions in Section 9.3 prior to beginning cementing operations. 1. A hole opener run is made after TD of all hole sections prior to running casing if it deems necessary. 2. Prior to running casing, a planning meeting will be held with personnel that are directly involved with the casing job to ensure that key personnel understand the job and their particular responsibilities. The casing running procedure will be reviewed and it will be verified that job responsibilities and safety precautions are clear to all personnel. 3. If a mandrel type casing hanger is planned, the landing string complete with cement head should be spaced out if possible, so that the mandrel casing hanger can be run all the way through the stack and landed without having to make a connection while the hanger is in the BOP. 4. The casing hanger and wellhead running tools will be carefully inspected and serviced prior to running. These tools should be made up and stood back in the derrick if possible prior to the wiper trip before running casing. 5. The drill string should be strapped out of the hole after TD of the hole section. If a discrepancy exists, the pipe should be re-strapped in the hole on the hole opener run. 6. Any tight spots are to be reamed, as necessary, on the wiper trip prior to logging. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 16 7. When pulling out of the hole on the last trip before running casing, then change out top set of pipe rams to casing rams and test the bonnet seals when out of hole before running casing.. (The order in which casing rams are installed may be changed at the Opt. Supt. discretion based on current well conditions.) Prior to pulling out of the hole on the wiper trip after logging, the drilling fluid will be conditioned to ensure that it is virtually free of cuttings and is of uniform density, with acceptable properties. Based on hole conditions, a casing running pill may be spotted after conditioning the fluid properties and before pulling out of the hole. 8. The primary well control method is fluid weight. The annular preventer will be used as the secondary means of well control with the casing rams as the third method during casing running operations. Before running casing, reduce the regulator pressure on the annular preventer per manufacturer's specification for the casing size in order to prevent collapse of the casing. 9. The wear bushing must be pulled before running casing. 10. Ensure that the rating of all casing tools (spiders, elevators and links) is sufficient for the casing string weight at total depth plus 200,000 lbs. of overpull. 11. Ensure that the safety valve on the casing-by-drill pipe crossover is a full opening ball valve such as a TIW valve. • Perform a function test of the safety valve on the casing-by-drill pipe crossover and casing swedge before running casing. Record this safety valve function test on the Daily IADC Report and morning report. 12. For heavy liners, the casing load and overpull limitations will be calculated to ensure that the drill pipe has sufficient tensile strength to allow it to be used as a landing string. 13. The inside of float joints will be checked for trash just prior to making up. 14. The float equipment will be checked for proper operation after running the float collar and one joint of casing by filling the casing with fluid and picking up to ensure that the fluid drops out of the casing and stays out after running it back in the hole (if Auto-Fill equipment is not being used). 15. The casing will be filled on a regular basis while picking up the next joint and the fill is to be confirmed at regular intervals. The casing should be filled with the drilling fluid used while drilling the hole. Stop in cased hole and fill the casing entirely prior to running casing/liner into the open hole. Once the casing DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 16 is in the open hole fill the casing as run but do not stop to fill the casing. (Use of fill up tool can aid in casing fill up.) 16. The correct number of sections in slips and clamps will be used for the size casing being run. 17. Safety clamps will be used until there is enough weight to hold the slips down and counteract the buoyant effect of the casing in the mud (buoyant effect can dislodge the casing from the slips and the casing can fall downhole). 18. Returns will be monitored (watch for indications of the well flowing) and running speed adjusted to minimize drilling fluid losses to the hole. Any limitations on casing running speed will be specified in the Drilling Program. 9.2 CASING CONNECTION MAKE-UP 1. Make-up torque will be specified in the Drilling Program based on the connection type, mill coating on the threads, and the thread compound to be used. For all offshore wells using API STC and LTC connections for any string, EMURC Torque-Position values will be used. For API BTC connections, use the EMURC Torque-Position Manual and Torque Position values for casing sizes less than or equal to 7-5/8". For BTC connections in casing sizes greater than 7-5/8" use the EMURC Torque-Position Manual 4-T method. For premium connections, connections will be made up per the manufacturer's recommended procedure. (Reference Operations Technology Bulletin 98-68 revised 11/9/1998.) Modified API connections with seal rings should be run with care and according to the Torque-Position Manual notes. 2. Thread compounds rated for the service temperature and conforming to API specifications will be used. 3. Use tong mounted computer to track each connection make-up. The casing company will ensure that a hard copy of make-up curves for all joints run is sent to the Drilling Engineer. The Drilling Engineer is to make sure that this report is in the well file in case future casing troubles are encountered (e.g. casing leak) and the make-up torques need to be reviewed. 9.3 CASING CHECKLIST Casing 1. Is condition of casing acceptable? 2. Is size and condition of casing drifts adequate? DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 Yes/ No Yes/ 6 of 16 3. Has casing been drifted, strapped, tallied and verified? 4. Is condition of casing threads acceptable? 5. Is enough excess casing on board ? 6. Is numbering of casing joints correct? 7. Is thread compound type and quantity acceptable? No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Operations 1. 2. Are theoretical returns and casing fill up volume calculations correct? Are fill-up and displacement volumes correct? 3. Is the reduction of the hydrostatic pressure due to spacer volume a problem? Yes/ No Yes/ No Yes/ No 4. Is as much rig up completed as possible during HO run, and logging operations? Yes/No 5. Are drill floor and catwalk clear of non-essential equipment? Yes/ No 6. Has a safety meeting been held prior to rigging up equipment? Yes/ No 7. Is hole monitored on trip tank while completing rig up? Yes/ No 8. Does Driller know proper casing running speed? Yes/ No 9. Does the Tong hand know the correct make-up speed and torque? Yes/ No Casing Running Equipment 1. Is all casing running equipment onboard and in acceptable condition? Yes/ No 2. Are casing slips the correct size and in good condition? Yes/ No 3. Are the ratings of spiders/elevators/links acceptable for the casing job? Yes/ No 4. Are tong dies the correct size and in good condition? Yes/ 5. Are clamp-on protectors the correct size and is the quantity on No board acceptable? Yes/ No 6. Is the tensile strength of the landing string sufficient? Yes/ No DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 16 7. Does the casing/drill pipe crossover thread match the casing? 8. Does the circulating swedge thread match the casing? 9. Has the safety valve been actuated, left in the open position, and recorded on the IADC/morning report? 10. Has the stabbing board been inspected and found to be acceptable? Raise permit for use of stabbingi board & review JSA. Yes/ No Yes/ No Yes/ No Yes/ No Cementing Equipment/Accessories 1. 2. Is cementing head the correct size, threads, and in good condition? Are casing subs and swedges the correct size, threads, and in good condition? 3. Is operations supervisor's visual inspection of all other threads complete? 4. Is float equipment the correct size, weight, and threads? 5. Are centralizers the correct size, number, with adequate stop rings? 6. Is there enough Thread-Lok and Threadkote or equivalent for casing job? 7. Is float shoe and float collar clean and free of debris and the cement undamaged? 8. Is the landing joint/cementing head made up? 9. Have the wiper plugs been inspected and installed correctly in cement head? Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No ExxonMobil Drilling Superintendent to verify proper loading of plugs in head. REFERENCE MATERIAL 1. API Bul 5 A2, "API Bulletin on Thread Compounds for Casing, Tubing, and Line Pipe," American Petroleum Institute, Dallas, Texas, Fifth Edition, April 1972. 2. API RP 5C1, "Recommended Practice for Care and Use of Casing and Tubing", American Petroleum Institute, Dallas, Texas, Fifteenth Edition, May 31, 1987. 3. API Spec 5B, "Specification for Threading, Gauging, and Thread Inspection of Casing, Tubing, and Line Pipe," American Petroleum Institute, Dallas, Texas, Thirteenth Edition, May 31, 1988. 4. Day, J. B., Moyer, M. C., and Hirshberg, A. J., "New Makeup Method for API Connections," SPE/IADC 18697, paper presented at the SPE/IADC Drilling Conference, New Orleans, LA, March 1989. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 8 of 16 5. ExxonMobil Upstream Research Company, Torque-Position Manual Third Edition December 1999, Wells and Materials Division. 6. EUSADO, Operations Technical Bulletin 98-68, revised November 9, 1998. CEMENTING 10.1 CEMENTING 10.2 10.3 10.4 10.5 10.6 10.7 General 1 Cementing Guidelines1 Primary Cementing 3 Remedial Cementing 5 Cementing Checklist 6 Reference 7 Appendix G-I ExxonMobil Cement Testing Guidelines DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 9 of 16 _________________________________________________________________________________ _____ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003 10.1 GENERAL This section provides guidelines and procedures for cementing operations. Whenever possible, a cementing recorder chart (pressure, volume, density vs. time) should be used for all operations (i.e. casing cementing, squeeze cementing, pressure testing of lines and equipment, PITs, etc.). The chart should be annotated with all significant events such as pressure testing, pumping spacers, mixing lead and tail slurries, displacement, bumping the plug, etc. For all Drilling Operations, a detailed cementing procedure will be written. For other types of cementing operations a procedure should be written using the guidelines found in this section as a reference (e.g. balanced plugs and KO plugs). 10.2 CEMENTING GUIDELINES Job Planning 1. Prior to the cementing operation, a planning meeting should be held with all personnel that are directly involved with the cement job to ensure that key personnel understand the job and their particular responsibilities. The cementing procedure should be reviewed and it verified that job responsibilities and safety precautions are clear to all personnel. 2. A good communication system between the rig floor and the cement unit is necessary. Rig phones or hand-held radios are acceptable means of communication. 3. Assign one individual (preferably the Operations Supervisor) to coordinate and direct operations between the rig floor and the cementing unit. 4. All lines including the cement manifold should be pressure tested to the pressure specified in the applicable cementing procedure prior to cementing. 5. All cementing equipment, including the densiometer, should be thoroughly checked to ensure it is in good repair and functions properly. 6. Hole calliper information and bottom hole logging temperatures should be sent to the Drilling Engineer as soon as practical during logging operations in order to finalize cement volumes and confirm cement thickening times. Hole calipers may be backed out of same LWD data and some wireline logging tools. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 16 Displacement 1. Cement displacement may be performed with either the cement unit or the rig pumps. Displacement volume, overall job time, desired pump rates, and expected pressures are important to consider when deciding which pump to use for displacement. The following are general guidelines: • For inner-string cementing, the cementing pump should be used for the entire operation. The stinger should be run to about 60 feet above the float shoe/collar. Cement should be displaced to about 20 feet below the stinger. • For full casing string cementing either the cement unit or rig pumps may be used for displacement. As a guideline, use the cement unit for displacements < 200 bbls or where the casing will not be drilled out. Use the rig pumps for displacements > 200 bbls or if the string will be drilled out. Each job should be considered individually based on conditions at the time of the cement job. • For liners, the cementing pump should be used until the top plug is launched, then the rig pump may be used, if desired, to complete the displacement and bump the plug. If high pressures (i.e. > 3000 psi) are anticipated it is probably best to continue displacement with the cementing unit. 2. If cement is to be displaced with the rig pumps, the pumps are to be calibrated using the trip tank prior to starting the cement job. As a contingency displacement mud pit to be observed for fluid loss when pumping with rig pumps. 3. Ensure the cement unit is ready to finish the cement displacement if the rig pumps encounter a problem and vice versa. Have the ability to switch from the rig pumps to the cement pumps as needed. 4. Do not over displace the cement by more than 50% of the volume of the float joints. If the casing is going to be drilled out, do not over displace at all. 5. Two or more independent volume calculations are to be made on displacement. 6. Pressures should be monitored and recorded for the entire cement job. This will require leaving the line open to the cement unit if the cement is displaced with the rig pump. Cement Head/Manifold DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 16 1. All valves on the cement head/manifold, as well as the releasing mechanisms, should be checked to ensure they are in proper working order and that safety devices are in place to prevent premature launching of plugs. 2. Use positive displacement to launch plugs (i.e. do not rely on gravity or falling fluid levels). Plug launching is to be witnessed by Company Supervisor or his delegate. 3. Use bails long enough to latch elevators below the cement head to allow reciprocation of the casing / liner during displacement of the cement. 4. A cement manifold that is designed for a top drive system is to be used, if applicable. 5. If the casing / liner is to be reciprocated or rotated during the cement job, the top drive cement head/manifold rating must be adequate to support the casing and landing string weight plus 100,000 lbs. of overpull. Cementing Well Control 1. Test all cement lines and the cement as specified in the applicable Cementing Procedure. 2. When using an unweighted spacer, ensure that reduction of hydrostatic pressure is not sufficient enough to allow an influx to enter anywhere in the entire wellbore. 3. Ensure circulating swedges (Casing x Drill Pipe and Casing x male half of Chiksan Union) are available on the floor for the appropriate size and threads casing. Function test these valves and document on the morning report and on the IADC. Spacer 1. Spacers will be used on all cement jobs. 2. Water spacers will be used unless specified otherwise in the applicable Cementing Procedure. 3. A pre-flush spacer is used to induce turbulence, to help get good mud displacement, and to help prevent channelling. The postflush spacer is used to help prevent cement contamination. 10.3 PRIMARY CEMENTING Primary Cementing Guidelines 1. Ensure that adequate cement is at the rig along with ample quantities of liquid/dry additives. If practical, there should be 50-100% excess cement and 100% excess liquid/dry additives at the rig site. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 3 of 16 2. Ensure that the transfer facilities from the P-tanks to the cement unit are operating correctly. Ensure P-tanks have been fluffed with clear air prior to transferring. 3. Ensure that air lines contain no water (moisture or water in the supply lines could cause plugging during the cement transfer). 4. At least two people will calculate the total cement job volumes, including the required volume to displace the top plug to the float collar. 5. The volume of mix water pumped will be used to calculate the actual volume of cement pumped. Never rely on P-tank volumes. 6. Circulate and condition the hole prior to cementing. The drilling fluid should be conditioned to ensure that it is virtually free of cuttings, that gas is back down to background levels and that it is of uniform density with acceptable properties. 7. Ensure that the cement head/manifold releasing mechanisms are working properly and that personnel are familiar with their operation. 8. The Operations Supervisor will witness the cementer load the wiper plugs in the cementing head/manifold. It is recommended that the cement job be pumped in the following order: bottom plug, preflush spacer, cement lead, cement tail, top plug, postflush spacer. 9. Monitor returns versus volume pumped throughout the cement job. Any suspected lost returns during cementing operations should be reported on the daily morning report, noting time of loss and pressures. Run ECD calculating software tool on cement jobs where lost returns are possible to fine tune displacement rates. 10. The slurry weight should be kept as consistent as possible to keep from extending or retarding setting times. Liquid additives are more sensitive to weight fluctuations than dry blended. 11. The weight of the cement slurry should be checked frequently using a pressurized mud balance to verify the accuracy of density measurement device on the cement unit. 12. Several samples, spaced throughout the job, of lead and tail slurries should be taken during cementing. A styrofoam/paper coffee cup filled three-fourths full, stored in a protected area is an adequate sampler. 13. After mixing the cement, release the top plug and pump the spacer with the cement unit placing a small volume of cement on top of the wiper plug. If desired, switch to the rig pumps to finish displacement. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 4 of 16 14. Displace the calculated casing volume or until the plug bumps. Do not over displace unless told to do so in the applicable cementing procedure. 15. Bleed casing pressure to zero quickly and check the floats. If floats do not hold, attempt to rock them on seat by repressuring the casing string. If flow back continues, shut in and hold pressure on the casing at least until surface samples setup or no backflow occurs. 10.4 REMEDIAL CEMENTING Remedial cementing is sometimes necessary to rectify poor leak-off below a casing shoe, repair casing or liner top leaks, squeeze off perforations, etc. The primary techniques used for these operations will follow a procedure similar to those described in the core procedures in Section 10. However, it is recognized that each situation will be different and extensive modification to these procedures may be required. When a squeeze procedure is prepared, two cement slurries should be designed and tested. If a low injection rate is all that can be established a low fluid loss cement slurry should be pumped to prevent the cement from being dehydrated as it is squeezed away. If a high injection rate can be established, a cement slurry with higher fluid loss (less expensive) should be pumped. Depending on the type of squeeze required, a low-fluid loss slurry may be followed by a high-fluid loss slurry. Braden Head Squeeze Procedure 1. RIH with open ended drill pipe (or tubing stinger on drill pipe work string) to the desired bottom of cement. 2. Circulate and condition the hole prior to cementing. The drilling fluid should be conditioned to ensure that it is virtually free of cuttings, that gas is back down to background levels, and that it is of uniform density with acceptable properties. 3. Rig up the cementing lines to the drill pipe, with a full opening safety valve installed at the top of the string. Test the cement lines to the pressure specified in the Cementing Procedure. 4. Pump specified preflush spacer (generally water), then spot a balanced cement plug with the top a minimum of 165' above the casing shoe. Attempt to rotate drill string to improve displacement of mud by cement. 5. Pump postflush spacer (generally water) and mud as required for balance. 6. Slowly POOH about 5 stands above the calculated top of cement. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 5 of 16 7. Close the BOP and squeeze the volume of cement specified in the Cementing Procedure by pumping mud down the work string: NOTE: Squeeze pressure must not exceed the casing test pressure. 8. Shut in the well until surface samples have set up or until reaching the desired compressive strength. Do not continue to pump in, or bleed pressure during the shut in period. 9. Release pressure on the work string, check for backflow and open the BOP. 10. Circulate bottoms up and condition the mud until cement contamination in mud returns is acceptable. POOH. 10.5 CEMENTING CHECKLIST Squeeze/Open Hole Plug Work Strings 1. Is there (+/- 700') of stinger (2-7/8" or 3-1/2" tbg, or 3-1/2" DP) at rig? 2. Are there appropriate handling tools for stinger at rig? Cementing Equipment/Accessories 1. Are wiper plugs correct size for casing and free of cuts and/or defects? 2. Witness loading of wiper plugs in cementing head/manifold? Cement Supply 1. Is correct type and amount (50-100% excess if practical) of cement at rig? 2. Are adequate quantities (100 % excess if practical) of additives onboard? 2. Inspection of cement storage and transfer facilities complete? 3. Is there an alternate source(s) of cement if a pneumatic line breaks or plugs? Cementing Personnel 1. Do cementer and key personnel agree on all volumes and rates? 2. Does cementer understand contingency plan/procedures? 3. Are two individuals assigned to record displacement volumes? Cement Pumping 1. In case of cement pump failure, is rig pump ready to take over? DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ 6 of 16 2. Is rig pump efficiency known by pumping into a calibrated tank? Cement Mixing 1. Is cement mixing equipment working properly before cementing? 2. Is calibration of pressurized mud balance complete? 3. Are densiometers operating correctly before cementing (calibrated)? 4. Are adequate blended sample containers available? Mix Water/Displacement Fluid 1. Is quality and supply of cement mix water satisfactory? 2. Is quality and supply of displacement fluid satisfactory? Pressure Testing/Safety 1. Is chiksan line from cement manifold safely chained to hook or bails? 2. Is testing of cement lines to specified working pressure complete? 3. Has cement manifold been pressure tested to specified working pressure? 4. Has safety valve been installed at top of work string. 10.6 1. 2. 3. 4. No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No Yes/ No REFERENCE EPR, Cement Slurry Design Manual EPR, Primary and Remedial Cementing Halliburton, Technical Data Cementing Notebook Halliburton, Cementing Tables Handbook. DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 7 of 16 SQUEEZE PROCEDURE EMDC DRILLING SECTION 10 - APPENDIX I EXXONMOBIL DEVELOPMENT COMPANY DRILLING ORGANIZATION 7-5/8" PROTECTIVE CASING SHOE SQUEEZE PROCEDURE 1. GENERAL INFORMATION Field: FIELDNAME Well: WELLNAME Rig: RIGNAME 1.1 APPROVALS Drilling Engineer: Office: (____) ______-______Home:(_____) ________ DATE________ Supervising Engineer: Office: (____) _____-_______Home:(_____) ________ DATE________ Operations Superintendent: Office: (____) _____-______Home:(_____) ______Pager:1-____-____-______ DATE________ Engineering Directions (This procedure contains extensive hidden text, which provides explanations and suggestions for tailoring the procedure to specific applications . Comments and hidden text can be viewed by choosing View on the menu bar and Comments from the drop down menu. The paragraph symbol (¶) on the standard tool bar also turns the hidden text on and off.) Engineering/Operations Comments RevisionJWB/AMK 1.2 PROCEDURE OBJECTIVE AND KEY ISSUES This procedure provides details for pumping additional cement to ensure pressure integrity at the 7-5/8” protective/production liner top/casing shoe at 7500'. This liner DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 1 of 18 SQUEEZE PROCEDURE EMDC DRILLING top/casing shoe requires a successful pressure test of 2500 psi with 12 ppg mud to drill ahead (18.4 ppg EMW) (per MMS requirements). [NOTE]: Additional comments pertaining to key issues as appropriate. THOROUGHLY READ THIS ENTIRE PROCEDURE AND DISCUSS ANY DETAILS YOU MAY DISAGREE WITH OR WANT CLARIFICATION ON WITH THE ENGINEER AND /OR OPERATIONS SUPERINTENDENT. DISTRIBUTE PROCEDURE TO FIELD PERSONNEL FOR EQUIPMENT AND PROCEDURE VERIFICATION . SIGNIFICANT CHANGES IN OPERATIONS FROM PROCEDURE REQUIRE EVALUATION AND DOCUMENTATION. DISCUSS WITH APPROPRIATE TEAM MEMBERS AND COMPLETE MOC FORM. 1.3 SAFETY Prior to starting each different type of operation, conduct safety meeting with all personnel involved and review job plans. Prepare and review JSA's for all critical operations. Rig Superintendent and Toolpusher should review each JSA prior to beginning work for thoroughness, proper hazard identification, and risk mitigation. 1.4 LIST OF APPLICABLE OP-TECH BULLETINS BULLETI N NUMBER 26 56 98 TITLE Failure to use recommended set screw w/ EZSV cement retainer results in expensive fishing job. Considerations for liner top squeeze cementing in OBM in Directional Hole Stuck "Fasdrill" retainer on recent Pecan Island well. 1.5 SERVICE COMPANY INFORMATION SERVICE Cementing Operations Lab Sales COMPANY BJ Services LOCATION Houma New Orleans New Orleans REPRESENTATIVE Dispatcher John St. Clergy Sparky Barkman PHONE NUMBER (281) (281) (281) Squeeze tool provider Halliburton Houma New Orleans New Orleans Dispatcher Rick Dupont Mark Richard (281) (281) (281) 1.6 TABLE OF CONTENTS 1. GENERAL INFORMATION______________________________________________________1 1.1 APPROVALS________________________________________________________________1 DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 2 of 18 SQUEEZE PROCEDURE EMDC DRILLING 1.2 PROCEDURE OBJECTIVE AND KEY ISSUES__________________________________1 1.3 SAFETY____________________________________________________________________2 1.4 LIST OF APPLICABLE OP-TECH BULLETINS_________________________________2 1.5 SERVICE COMPANY INFORMATION_________________________________________2 1.6 TABLE OF CONTENTS______________________________________________________2 2. DESIGN BASIS________________________________________________________________4 2.1 GENERAL INFORMATION___________________________________________________4 2.2 CURRENT STATUS__________________________________________________________5 2.3 CEMENT DATA SUMMARY__________________________________________________6 3. PROCEDURE__________________________________________________________________6 3.1 TOP OF LINER SQUEEZE - DRILLABLE PACKER______________________________6 3.2 TOP OF LINER SQUEEZE - RETRIEVABLE PACKER___________________________9 3.3 SHOE SQUEEZE - DRILLABLE PACKER_____________________________________11 3.4 SHOE SQUEEZE - RETRIEVABLE PACKER___________________________________14 4. ENGINEERING FOLLOW-UP___________________________________________________16 DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 3 of 18 SQUEEZE PROCEDURE EMDC DRILLING 2. DESIGN BASIS 2.1 TOC @ 8950 ' TOC @ 8950 ' GENERAL INFORMATION Casing Shoe Squeeze Liner Top Squeeze Before Opening After Squeeze Squeeze Tool Squeeze ToolSqueeze Tool @ 9315'@ 8800' Before Opening After Squeeze Squeeze Tool Top of Liner @ 9150' Casing shoe @ 9315' 2.2 CURRENT STATUS Pipe Set MD (ft) - TVD (ft) - 24” Drive Pipe 20” Conductor Casing 16” Surface Casing 9-5/8” Protective Casing 8.500”: Drift diameter of 9-5/8” casing Casing in which squeeze tool will be set in:7-5/8" 39.0# 6.625"ID Casing burst rating w/ (1.375) SF: - psi DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 4 of 18 SQUEEZE PROCEDURE EMDC DRILLING Casing was successfully tested to - psi or - ppg EMW @ casing shoe/liner top Estimated Pore pressure at casing shoe: - psi or - ppg EMW Estimated Frac pressure at casing shoe: - psi or - ppg EMW Desired PIT or Liner Top Test is - psi or - ppg EMW Maximum angle in wellbore above planned squeeze tool depth: 5° Maximum dogleg in wellbore above planned squeeze tool depth:1.5 ° per 100' Mud Weight: Mud Type (WBM / OBM ): - ppg - DEPTHS FROM RKB Description Depth to Top of Liner/Casing Shoe Planned Depth of Squeeze Packer Planned Height of Cement in Casing Estimated TOC in casing MD (ft) 9315 TVD (ft) 9315 8915 8915 150 200 9165 9165 CAPACITIES/DISPLACEMENTS Size 7-5/8" 3-1/2" IF - Weight 39# 13.3# S135 - Nom. ID - Drift ID - Footag e 250' 8915' X X - - - X X Capacity Bpf .054375 = .007220 = - Displaceme nt Bbls 10.70 64.40 0 2.3 CEMENT DATA SUMMARY Cement Company: Dowell @ 512-456-9874 High injection rate/Low injection pressure slurry Cementing Slurry Pilot Test Results ---Sacks Class " "Thickening Time ---------Additivepsi 12 hour compressive strength ------Additivepsi 24 hour compressive strength ------Additivecc/30 min water loss ---ppg slurryml/250ml Free Water ------cf/sk yield ------- DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 5 of 18 ---- SQUEEZE PROCEDURE ------------- EMDC DRILLING gal/sk mix wateroF BHST bbl slurry volumeoF BHCT (sqz schedule) bbl water volume Estimated pump timePilot Test Requested Low injection rate/High injection pressure slurry Pilot Test Results Cementing Slurry ---Sacks Class " "Thickening Time ---------Additivepsi 12 hour compressive strength ------Additivepsi 24 hour compressive strength ---Additivecc/30 min water loss ------Ppg slurryml/250ml Free Water ------cf/sk yield ---Gal/sk mix wateroF BHST ------- Bbl slurry volumeoF BHCT (sqz schedule) ------Bbl water volume ------- Estimated pump timePilot Test Requested 3. PROCEDURE 3.1 TOP OF LINER SQUEEZE - DRILLABLE PACKER 1. Make a casing scraper run if deemed necessary prior to running in with SQZRETAINER. Work casing scraper thoroughly across the interval of pipe at planned SQZRETAINER setting depth. Circulate bottoms up below the SQZRETAINER setting depth. POOH. If it is deemed that a casing scraper run is not necessary, the following are reconcilers for not making the casing scraper run: • • • • The SQZRETAINER will be set above where cement was tagged when RIH. A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full gauge near bit stab, 8-1/2" full gauge stab 15' above the bit, and 8-1/2" full gauge stab 45' above the bit. After determining that a squeeze was necessary, the BHA was tripped and rotated across the bottom section of casing several times to clean the ID of the casing of any remaining cement. The SQZRETAINER will be set in the interval that was cleaned with the stabilizers. The pumps were on while cleaning the casing to remove any cement cuttings. The rig circulated adequate BU before POOH to ensure all cement cuttings have been removed. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 6 of 18 SQUEEZE PROCEDURE EMDC DRILLING 2. Pick up SQZRETAINER for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the liner top). Set SQZRETAINER @ TOOLMD MD (do not set retainer below 10,005’ which is where cement was tagged when running in the hole to clean out). Ensure that the retainer will not be set in a casing collar. Verify setting with 15 - 20 kips weight down on the SQZRETAINER and 500-1000 psi on the DP by casing annulus. • 7.75” is the maximum OD of the SQZRETAINER • Maximum differential pressure for the SQZRETAINER = 5,000 psi • Maximum set down weight for the SQZRETAINER = 50,000 lbs 3. Test cement lines and squeezes manifold to 5,000 psi. (Test against TIW valve) 4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi (Engineer to comment on basis for maximum injection pressure. i.e. To stay within net burst pressure limit (7,927 psi w/ 1.375 SF ) of the 9-5/8” casing assuming 15.7 ppg mud in the wellbore and a 9.0 ppg EMW back-up behind the 9-5/8”). Monitor annulus carefully for pressure response indicative of packer or DP leak. Note that the CGOD CGWT casing was last tested to 3,825 psi with 15.7 ppg mud, the cement lines have been tested to 5,000 psi, and the SQZTOOL is rated for 5,000 psi of differential pressure. Use the PIT plotting technique to record pressure vs volume pumped. Contact the Operations Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the cement design or pump volumes). Do not exceed the liner top test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yet been established at this point. This could indicate a satisfactory liner top test has been obtained. 5. Bleed pressure off of the annulus, PU out of the SQZRETAINER, and establish reversing pressures at 3 - 6 bpm. 6. Mix and displace the following slurries using the cementing unit [EUSADO20]: Note: While displacing cement down the DP while stung out of the retainer, the flowrate may outrun the pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating around DP before stinging into SQZRETAINER. PUMP SCHEDULE BEFORE STINGING INTO THE SQZRETAINER Description Densit Pump y Rate 30 bbls pre-flush spacer (MCS-3) 38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe) DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 7 of 18 SQUEEZE PROCEDURE EMDC DRILLING 38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe) 10 bbls post-flush spacer (MCS-3) 38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZRETAINER) Positions cement ~25 bbls inside the DP above the SQZRETAINER. (1470' inside the DP above the SQZRETAINER) 5” 19.5# S-135 DP capacity = 0.01701 bpf; 9-5/8” 53.5# casing capacity = 0.0708 bpf. 7. Close the choke and then sting into the SQZRETAINER. Set 15 - 20 kips weight down on the retainer and pressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This will leave 2 bbls of cement in the DP above the retainer. Do not overdisplace the cement. PUMP SCHEDULE AFTER STINGING INTO THE SQZRETAINER Description Densit Pump y Rate 119 bbls mud 15.7 5 bbls Fresh Water 8.3 This will leave 2 bbls cement above the SQZRETAINER in the DP. (118' inside the DP above the SQZRETAINER) Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10,000' TVD. 5 bbls of water displacement should provide approximately 200 psi positive pressure. If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drill pipe, perform the following steps: sting out of retainer, POOH 2 stands, reverse circulate out 2 workstring volumes at the maximum rate while keeping the pipe moving (do not exceed the casing test pressure of 3520 psi while reversing). 8. PU out of the retainer and dump the last 2 bbls of cement on top of the SQZRETAINER (TOC @ ~9,922’ MD. This leaves 28' of cement on top of the SQZRETAINER). PU 2 stands and reverse out at the maximum rate possible (do not exceed the casing test pressure of 3520 psi while reversing). Reverse out at least 2 workstring volumes and keep the pipe moving while reversing. 9. POOH and LD retainer setting tool. PU the 8-1/2” clean out assembly and TIH to 9,750’ MD. (180' above expected TOC). 10. Ensure 18 hours has elapsed since cement was pumped and wash down to TOC. Drill cement/SQZRETAINER and continue drilling down to the LNROD liner top @ 10,255’ MD. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 8 of 18 SQUEEZE PROCEDURE EMDC DRILLING Do not rotate excessively on the liner top to avoid damaging the tie-back receptacle. C&C mud to clean wellbore. Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate out 1 cycle. Monitor mud condition/properties and dump all badly cement contaminated mud. Contact the Operations Superintendent to discuss WOC time and forward operations if the cement is not hard. 11. Pressure test the LNROD liner top to 2,300 psi with 15.7 ppg mud. Use the PIT technique at 1/2 bpm and record pressure vs. volume pumped. Hold test pressure for 30 minutes. After test, record volume of mud bled back. POOH. 12. After successful test, proceed with the deeper drilling procedure. 3.2 TOP OF LINER SQUEEZE - RETRIEVABLE PACKER 1. Make a casing scraper run if deemed necessary prior to running in with SQZTOOL. Work casing scraper thoroughly across the interval of pipe at planned SQZTOOL setting depth. Circulate bottoms up below the SQZTOOL setting depth. POOH. If it is deemed that a casing scraper run is not necessary, the following are reconcilers for not making the casing scraper run: • The SQZTOOL will be set above where cement was tagged when RIH. • A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full gauge near bit stab, 8-1/2" full gauge stab 15' above the bit, and 8-1/2" full gauge stab 45' above the bit. • After determining that a squeeze was necessary, the BHA was tripped and rotated across the bottom section of casing several times to clean the ID of the casing of any remaining cement. The SQZTOOL will be set in the interval that was cleaned with the stabilizers. • The pumps were on while cleaning the casing to remove any cement cuttings. The rig circulated adequate BU before POOH to ensure all cement cuttings had been removed. 2. Pick up SQZTOOL for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the liner top). Set SQZTOOL @ TOOLMD MD (do not set squeeze tool below 10,005’ which is where cement was tagged when running in the hole to clean out). Ensure that the squeeze tool will not be set in a casing collar. Verify setting with 15 - 20 kips weight down on the SQZTOOL and 500-1000 psi on the DP by casing annulus. • 7.75” is the maximum OD of the SQZTOOL • Maximum differential pressure for the SQZTOOL = 5,000 psi • Maximum set down weight for the SQZTOOL = 50,000 lbs 3. Test the cement lines and the squeeze manifold to 5000 psi. (Test against TIW valve) DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 9 of 18 SQUEEZE PROCEDURE EMDC DRILLING 4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi (Engineer to comment on basis for maximum injection pressure. i.e. To stay within net burst pressure limit (7,927 psi w/ 1.375 SF ) of the 9-5/8” casing assuming 15.7 ppg mud in the wellbore and a 9.0 ppg EMW back-up behind the 9-5/8”). Monitor annulus carefully for pressure response indicative of packer or DP leak. Note that the CGOD CGWT casing was last tested to 3,825 psi with 15.7 ppg mud, the cement lines have been tested to 5,000 psi, and the SQZTOOL is rated for 5,000 psi of differential pressure. Use the PIT plotting technique to record pressure vs volume pumped. Contact the Operations Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the cement design or pump volumes). Do not exceed the liner top test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yet been established at this point. This could indicate a satisfactory liner top test has been obtained. 5. Bleed pressure off the annulus, open bypass on SQZTOOL. 6. Mix and displace the following slurries using the cementing unit: Note: While displacing cement down the DP with the bypass open, the flowrate may outrun the pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating above the SQZTOOL before the bypass is closed. PUMP SCHEDULE BEFORE CLOSING THE BYPASS ON SQZTOOL Description Densit Pump y Rate 30 bbls pre-flush spacer (MCS-3) 38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe) 38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe) 10 bbls post-flush spacer (MCS-3) 38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZTOOL) Positions cement ~25 bbls inside the DP above the SQZTOOL. (1470' inside the DP above the SQZTOOL) 5” 19.5# S-135 DP capacity = 0.01701 bpf; 9-5/8” 53.5# casing capacity = 0.0708 bpf. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 10 of 18 SQUEEZE PROCEDURE EMDC DRILLING 7. Close the choke and then the bypass on the SQZTOOL and pressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This should leave TOC 250' below the SQZTOOL, and 250' above the liner top. PUMP SCHEDULE AFTER CLOSING THE BYPASS ON SQZTOOL Description Densit Pump y Rate 119 bbls mud 15.7 5 bbls Fresh Water 8.3 This will leave the TOC 250' below the SQZTOOL, and 250' above the liner top. Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10000' TVD. 5 bbls of water displacement should provide approximately 200 psi positive pressure. If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drill pipe, perform the following steps: release the squeeze tool, POOH 5 stands, reverse circulate out 2 workstring volumes at the maximum rate (do not exceed the casing test pressure of 3520 psi while reversing), POOH 1 additional stand, set the packer and put 500-1000 psi on the annulus. 8. Hesitation squeeze Stage up to 5.0 bbls of cement into the formation. Pump in 1.0 bbl at 1/4 bpm every 15 minutes for the first 3.0 bbls. Afterwards, pump in 1.0 bbl at 1/4 bpm every 60 minutes for the last 2 bbls (total squeeze volume = 5.0 bbls). If a pressure break-over is seen prior to finishing each stage, stop pumping immediately and hold whatever pressure is achieved for required stage time before continuing with next stage. Stop pumping at any point if 1675 psi is reached (21.0 ppg EMW). If pressure limit is reached, discontinue staging process and hold final pressure for WOC time. If 1675 psi is not reached after squeezing 5.0 bbls, stop staging process and hold whatever pressure is present. Estimated TOC after the hesitation squeeze is 185' above the liner top. 9. Hold the final squeeze pressure for 12 hours. The drill pipe pressure should increase due to thermal expansion. Allow the drill pipe pressure to rise as high as 4500 psi (21.0 ppg EMW) before bleeding off any pressure. If the pressure builds to 4500 psi, bleed back to 3500 psi before continuing to hold squeeze pressure. If backside pressure increases above 500-1000 psi, it may be indicative of a leak in either the packer or the DP. (Maximum allowed annulus pressure is 1585 psi base on a 21 EMW casing test.) 10. After waiting 12 hours, pressure up to 500 psi over the final squeeze pressure to make sure cement is set. If OK, release pressure, unseat SQZTOOL, and circulate out. POOH. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 11 of 18 SQUEEZE PROCEDURE EMDC DRILLING 11. TIH with 8-1/2" clean out assembly to where the SQZTOOL was set and wash down to TOC. Drill cement down to the LNROD liner top @ 10,255’ MD. Do not rotate excessively on the liner top and avoid damaging the tie-back receptacle. C&C mud to clean wellbore. Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate out 1 cycle. Monitor mud condition/properties and dump all badly cement contaminated mud. Contact the Operations Superintendent to discuss WOC time and forward operations if the cement is not hard. 12. Pressure test the LNROD liner top to 2,300 psi with 15.7 ppg mud (20 ppg EMW at the liner top). Use the PIT technique at 1/2 bpm and record pressure vs volume pumped. Hold test pressure for 30 minutes. After test, record volume of mud bled back. POOH. 13. After successful test, proceed with drilling operations per the deeper drilling procedure. 3.3 SHOE SQUEEZE - DRILLABLE PACKER 1. Make a casing scraper run if deemed necessary prior to running in with SQZRETAINER. Work casing scraper thoroughly across the interval of pipe at planned SQZRETAINER setting depth. Circulate bottoms up below the SQZRETAINER setting depth. POOH. If it is deemed that a casing scraper run is not necessary, the following are reconcilers for not making the casing scraper run: • The SQZRETAINER will be set above where cement was tagged when RIH. • A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full gauge near bit stab, 8-1/2" full gauge stab 15' above the bit, and 8-1/2" full gauge stab 45' above the bit. • • After determining that a squeeze was necessary, the BHA was tripped and rotated across the bottom section of casing several times to clean the ID of the casing of any remaining cement. The SQZRETAINER will be set in the interval that was cleaned with the stabilizers. The pumps were on while cleaning the casing to remove any cement cuttings. The rig circulated adequate BU before TOOH to ensure all cement cuttings had been removed. 2. Pick up SQZRETAINER for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the shoe). Set SQZRETAINER @ TOOLMD MD (do not set retainer below 10,005’ which is where cement was tagged when running in the hole to clean out). Ensure that the retainer will not be set in a casing collar. Verify setting with 15 - 20 kips weight down on the SQZRETAINER and 500-1000 psi on the DP by casing annulus. • 7.75” is the maximum OD of the SQZRETAINER • Maximum differential pressure for the SQZRETAINER = 5,000 psi • Maximum set down weight for the SQZRETAINER = 50,000 lbs 3. Test cement lines and squeeze manifold to 5,000 psi. (Test against TIW valve) DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 12 of 18 SQUEEZE PROCEDURE EMDC DRILLING 4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi (Engineer to comment on basis for maximum injection pressure. i.e. To stay within net burst pressure limit (7,927 psi w/ 1.375 SF ) of the 9-5/8” casing assuming 15.7 ppg mud in the wellbore and a 9.0 ppg EMW back-up behind the 9-5/8”). Monitor annulus carefully for pressure response indicative of packer or DP leak. Note that the CGOD CGWT was last tested to 3,825 psi with 15.7 ppg mud, the cement lines have been tested to 5,000 psi, and the SQZRETAINER is rated for 5,000 psi of differential pressure. Use the PIT plotting technique to record pressure vs volume pumped. Contact the Operations Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the cement design or pump volumes). Do not exceed the PIT test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yet been established at this point. This could indicate a satisfactory PIT has been obtained. 5. Bleed pressure off of the annulus, PU out of the SQZRETAINER, and establish reversing pressures at 3 - 6 bpm. 6. Mix and displace the following slurries using the cementing unit: Note: While displacing cement down the DP while stung out of the retainer, the flowrate may outrun the pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating around DP before stinging into SQZRETAINER. PUMP SCHEDULE BEFORE STINGING INTO THE SQZRETAINER Description Densit y Pump Rate 30 bbls pre-flush spacer (MCS-3) 38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe) 38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe) 10 bbls post-flush spacer (MCS-3) 38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZRETAINER) Positions cement ~25 bbls inside the DP above the SQZRETAINER. (1470' inside the DP above the SQZRETAINER) DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 13 of 18 SQUEEZE PROCEDURE EMDC DRILLING 5” 19.5# S-135 DP capacity = 0.01701 bpf; 9-5/8” 53.5# casing capacity = 0.0708 bpf. 7. Close the choke and then sting into the SQZRETAINER. Set 15 - 20 kips weight down on the retainer and pressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This will leave 2 bbls of cement in the DP above the retainer. Do not overdisplace the cement. PUMP SCHEDULE AFTER STINGING INTO THE SQZRETAINER Description Densit Pump y Rate 119 bbls mud 15.7 5 bbls Fresh Water 8.3 This will leave 2 bbls cement above the SQZRETAINER in the DP. (118' inside the DP above the SQZRETAINER) Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10,000' TVD. 5 bbls of water displacement should provide approximately 200 psi positive pressure. If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drill pipe, perform the following steps: sting out of retainer, POOH 2 stands, reverse circulate out 2 workstring volumes at the maximum rate while keeping the pipe moving (do not exceed the casing test pressure of 3520 psi while reversing). 8. PU out of the retainer and dump the last 2 bbls of cement on top of the SQZRETAINER (TOC @ ~9,922’ MD). PU 2 stands and reverse out at the maximum rate possible (do not exceed the casing test pressure of 3520 psi while reversing). Reverse out at least 2 workstring volumes and keep the pipe moving while reversing. 9. POOH and LD retainer setting tool. PU the 8-1/2” drill out assembly and TIH to 9,750’ MD. (180' above expected TOC) 10. After WOC for 18 hours since the cement was pumped, wash down to TOC. Drill cement/SQZRETAINER and continue drilling out cement. Drill 5'-10' of new hole noting any voids or changes in wellbore conditions. If high gas and or lost returns are encountered just below the shoe, contact the Operations Superintendent immediately. Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate out 1 cycle. Monitor mud condition/properties and dump all badly cement contaminated mud. Contact the Operations Superintendent to discuss WOC time and forward operations if the cement is not hard. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 14 of 18 SQUEEZE PROCEDURE EMDC DRILLING 11. Perform a PIT to 17.0 ppg EMW (2970 psi at the surface with 11.8 ppg mud at 10,317' TVD). Use the PIT technique at 1/2 bpm and record pressure vs. volume pumped. Do not test the shoe to higher than 17.0 ppg EMW. 12. After successful test, proceed with drilling operations per the deeper drilling procedure. 3.4 SHOE SQUEEZE - RETRIEVABLE PACKER 1. Make a casing scraper run if deemed necessary prior to running in with SQZTOOL. Work casing scraper thoroughly across the interval of pipe at planned SQZTOOL setting depth. Circulate bottoms up below the SQZTOOL setting depth. POOH. If it is deemed that a casing scraper run is not necessary, the following are reconcilers for not making the casing scraper run: • The SQZTOOL will be set above where cement was tagged when RIH. • A packed BHA was used during the drillout. Stabilizer placement was as follows: 8-1/2" full gauge near bit stab, 8-1/2" full gauge stab 15' above the bit, and 8-1/2" full gauge stab 45' above the bit. • After determining that a squeeze was necessary, the BHA was tripped and rotated across the bottom section of casing several times to clean the ID of the casing of any remaining cement. The SQZTOOL will be set in the interval that was cleaned with the stabilizers. • The pumps were on while cleaning the casing to remove any cement cuttings. The rig circulated adequate BU before POOH to ensure all cement cuttings had been removed. 2. Pick up SQZTOOL for CGOD CGWT casing and TIH to TOOLMD MD (305’ above the shoe). Set SQZTOOL @ TOOLMD MD (do not set squeeze tool below 10,005’ which is where cement was tagged when running in the hole to clean out). Ensure that the squeeze tool will not be set in a casing collar. Verify setting with 15 - 20 kips weight down on the SQZTOOL and 500-1000 psi on the DP by casing annulus. • 7.75” is the maximum OD of the SQZTOOL • Maximum differential pressure for the SQZTOOL = 5,000 psi • Maximum set down weight for the SQZTOOL = 50,000 lbs 3. Test the cement lines and the squeeze manifold to 5000 psi. (Test against TIW valve) 4. Close annular BOP and pressure up on DP by casing annulus to 500-1000 psi. Establish injection rates at 1/2, 1, 2, 3, and 4 bpm without exceeding injection pressures of 4,500 psi ( Engineer to comment on basis for maximum injection pressure. i.e. To stay within net burst pressure limit (7,927 psi w/ 1.375 SF ) of the 9-5/8” casing assuming 15.7 ppg mud in the wellbore and a 9.0 ppg EMW back-up behind the 9-5/8”). Monitor annulus carefully for pressure response indicative of packer or DP leak. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 15 of 18 SQUEEZE PROCEDURE EMDC DRILLING Note that the CGOD CGWT casing was last tested to 3,825 psi with 15.7 ppg mud, the cement lines have been tested to 5,000 psi, and the SQZTOOL is rated for 5,000 psi of differential pressure. Use the PIT plotting technique to record pressure vs volume pumped. Contact the Operations Superintendent and the Drilling Engineer to discuss results of the injection test (injectivity will dictate if a change is needed in the cement design or pump volumes). Do not exceed the PIT test pressure of 3300 psi with 12.7 ppg mud (15.0 ppg EMW) if injection has not yet been established at this point. This could indicate a satisfactory PIT has been obtained. 5. Bleed pressure off the annulus, open bypass on SQZTOOL. 6. Mix and displace the following slurries using the cementing unit: Note: While displacing cement down the DP with the bypass open, the flowrate may outrun the pump rate due to U-tube pressure. Take returns through the choke, if necessary, so that back pressure can be applied to prevent cement from circulating above the SQZTOOL before the bypass is closed. PUMP SCHEDULE BEFORE CLOSING THE BYPASS ON SQZTOOL Description Densit Pump y Rate 30 bbls pre-flush spacer (MCS-3) 38 bbls (150 sacks) low FL squeeze slurry (See Cement Data for recipe) 38 bbls (200 sacks) high FL (neat) squeeze slurry (See Cement Data for recipe) 10 bbls post-flush spacer (MCS-3) 38 bbls mud (lead spacer position ~15 bbls inside the DP above the SQZTOOL) Positions cement ~25 bbls inside the DP above the SQZTOOL. (1470' inside the DP above the SQZTOOL) 5” 19.5# S-135 DP capacity = 0.01701 bpf; 9-5/8” 53.5# casing capacity = 0.0708 bpf. 7. Close the choke and then the bypass on the SQZTOOL and pressure up 500 - 1,000 psi on the DP by casing annulus. Pump an additional 119 bbls of 15.7 ppg mud at 4 bpm followed by 5 bbls of freshwater down the DP. This should leave TOC 250' below the SQZTOOL, and 250' above the casing shoe. PUMP SCHEDULE AFTER CLOSING THE BYPASS ON SQZTOOL Description Densit y DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 16 of 18 Pump Rate SQUEEZE PROCEDURE EMDC DRILLING 119 bbls mud 15.7 5 bbls Fresh Water 8.3 This will leave the TOC 250' below the SQZTOOL, and 250' above the casing shoe. Note: Displacement volumes assume a 12 ppg FCS in the G-series sand at 10000' TVD. 5 bbls of water displacement should provide approximately 200 psi positive pressure. If the well jugs up or surface pressure rises to 4500 psi during the squeeze operation with cement in the drill pipe, perform the following steps: release the squeeze tool, POOH 3 stands, reverse circulate out 2 workstring volumes at the maximum rate (do not exceed the casing test pressure of 3520 psi while reversing), POOH 1 additional stand, set the packer and put 500-1000 psi on the annulus. 8. Hesitation squeeze. Stage up to 5.0 bbls of cement into the formation. Pump in 1.0 bbl at 1/4 bpm every 15 minutes for the first 3.0 bbls. Afterwards, pump in 1.0 bbl at 1/4 bpm every 60 minutes for the last 2 bbls (total squeeze volume = 5.0 bbls). If a pressure break-over is seen prior to finishing each stage, stop pumping immediately and hold whatever pressure is achieved for required stage time before continuing with next stage. Stop pumping at any point if 1675 psi is reached (21.0 ppg EMW). If pressure limit is reached, discontinue staging process and hold final pressure for WOC time. If 1675 psi is not reached after squeezing 5.0 bbls, stop staging process and hold whatever pressure is present. Estimated TOC after the hesitation squeeze is 185' above the shoe. 9. Hold the final squeeze pressure for 12 hours. The drill pipe pressure should increase due to thermal expansion. Allow the drill pipe pressure to rise as high as 4500 psi (21.0 ppg EMW) before bleeding off any pressure. If the pressure builds to 4500 psi, bleed back to 3500 psi before continuing to hold squeeze pressure. If backside pressure increases above 500-1000 psi, it may be indicative of a leak in either the packer or the DP. (Maximum allowed annulus pressure is 1585 psi base on a 21 EMW casing test.) 10. After waiting 12 hours, pressure up to 500 psi over the final squeeze pressure to make sure cement is set. If OK, release pressure and unseat SQZTOOL and circulate out. POOH. 11. TIH with 8-1/2" drill out assembly to where SQZTOOL was set, and wash down to TOC. Drill out cement and 5-10' of new formation noting any voids or changes in wellbore conditions. If high gas and/or lost returns are encountered just below the shoe, contact the Operations Superintendent immediately. DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 17 of 18 SQUEEZE PROCEDURE EMDC DRILLING Note: If ratty and/or soft cement is encountered as deep as 90' above the expected TOC, PU 3 stands and circulate out 1 cycle. Monitor mud condition/properties and dump all badly cement contaminated mud. Contact the Operations Superintendent to discuss WOC time and forward operations if the cement is not hard. 12. Perform a PIT to 17.0 ppg EMW (2970 psi at the surface with 11.8 ppg mud at 10,317' TVD). Use the PIT technique at 1/2 bpm and record pressure vs volume pumped. Do not test the shoe to higher than 17.0 ppg EMW. 13. After successful test, proceed with drilling operations per the deeper drilling procedure. 5. ENGINEERING FOLLOW-UP Well Name: WELLNAME Superintendents: Drilling Supts Engineer(s): Drilling Engineer Well engineer is responsible for verbal follow-up with rig supervisor. Engineer is to identify and document below sections of the procedure which did not meet the drilling team's needs and describe key learning's to be incorporated into core procedure. Return follow-up to core procedure owner: Recommended Modifications to Procedure: _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 18 of 18 SQUEEZE PROCEDURE EMDC DRILLING _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ _________________________________________________________________________________________ Submitted By: Phone: ( ______________________________________________________________ ) DATE___________ DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFROM/BARGE RIG DRILLING Version 3–April 2003 Page 19 of 18 SECTION 10 - APPENDIX II Well Name Rig Name Previous casing OD= 16 ID= 15.22 PROPOSED CASING Annular Volume DESIGN (bottom to top) MD= 1000 WGHT GRADE/CONN TVD= 10001 0.1128 bpf LENGTH MD IDCAP. (bpf) CAP. (bbls) DISPLACE. 45.5 K-55,BTC 4900 4900 10.05 0.0982 481.0 0.0166 Excess bbls of cement at 2 0.0000 0.0 0.0000 surface if gauge hole 341 3 0.0000 0.0 0.0000 4 0.0000 Req'd height of tail above shoe 500 Assumed hole size Washout = 9.2 12.6 ppg 49% 10.75 Sea Yield: Casing Point 4900 ' MD Float Length= bbls of 8.7 SPACERS ppg seawater spacer. Post-flush with 20 bbls of Annular Volume CEMENT 8.7 ppg 80 20 0.1523 bpf 433.1 bbls displacement 4883 ' TVD 0.0000 feet. Pre-flush with 16.5 " Setting MW Number of bbls 0.0 Lead Slurry: seawater spacer. Class 'H' with liquid additives 6 72.2 72.2 Mixwater: at 13.23 gal/sk MISC. ENGINEERING CALCS. 20 bbls displacement 2 10.0 10.0 2.32 cu.ft/sk Pit gain from casing (bbls): 81.2 630.1 Contingency 60 6 sacks: 1525 Volume: Pit gain from cementing(bbls) 0 754.1 1526 Calculated= Bit Size(in)Tail Slurry: Mixed to: Class 'H' with liquid EMW after displacment (ppg)13.0 13.5Mixwater: Sea Which is Number of sacks: additives U-tube pressure @ floats (psi 930 16.2 425 Volume: at ppg 4.68 gal/sk Yield: 1.11 cu.ft/sk 84.0 bbls 425 Calculated= Tail is estimated at DISPLACEMENT shoe. 4400 ' MD After postflush, displace w/ 453.1 bbls of 9.2 ppg mud. 4400 ' TVD 500 ' above PUMP TIMES Rate Lead Tail casing shoe (assumed hole size). Mix Lead Cement 6 105.0 0.0 If gauge then 1175.3 ' above Mix Tail Cement 6 14.0 14.0 Drop Top Plug Proposed Casing Float Capacity= 7.9 20 bbl postflush bbls 6 5.0 5.0 3.3 3.3 Estimated Job Time 270 165 EJT (hours) 4.49 2.74 EJT with contingency Bottom hole static temperature Bottom hole circulating temperature 5.49 3.74 138 degrees F (est. from log temps) 110 degrees F (from API Spec 10) DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 1 of 2 Well Name Rig Name Previous casing 1610.75 " SHOE SQUEEZE 15.22CASING DESIGN (bottom to top) OD= ID= MD= TVD= 1000WGHT GRADE/CONN 10001 LENGTH MD ID CAP. (bpf) CAP. (bbls) DISPLACE. 45.5 K-55,BTC 4900 4900 10.05 0.0982 481.0 0.0166 2 0 0 0 0 0 0.0000 0.0 0.0000 3 0 0 0 0 0 0.0000 0.0 0.0000 WORKSTRING DESIGN (bottom to top) OD WEIGHT/CONN LENGTH MD ID CAP. (bpf) CAP. (bbls) DISPLACE. 1 5 19.5 #/NC50/X-9544004400 2 0 0 0 4.276 0.017268 76.0 0.000000 0.0 0.0078 0.0000 3 Displacement MW SPACERS 9.2Pre-flush with of 8.7 Follow cement 20 bbls ppg seawater spacer. with 10 bbls of 8.7 ppgseawater spacer. CEMENT Lead Slurry: Class 'H' with liquid additives CasingMixwater: Sea 10.75 " Number of sacks: Desired underdisplacement of pre-flush Calculated= bypass is closed Mixed to: at 257 Volume: 257 when 16 13.23 gal/sk 75.5 bbls Yield: ppg 1.65 cu.ft/sk 5 bbl DISPLACEMENT Close bypass after pumping 71.0 bbls of preflush and cement Squeeze packer setting depth After spacer, displace w/ 80.5 bbls of 9.2 ppg mud. 4400 ' MD TOC desired 250 feet above shoe PUMP TIMES Rate Mix Squeeze Cement 4 Desired squeeze volume 10 bbl spacer 50 bbl Casing Shoe 4900 ' MD 0 bbl other 4 Bit size: 0.0 Length of new hole: 80.5 bbl displacement 10 ' 4883 ' TVD Contingency 9.875 " New hole volume: 0.95 bbl Bottom hole static temperature Bottom hole circulating temperature Squeeze Slurry 18.9 4 2.5 4 20.1 60 Estimated Job Time 102 EJT (hours) 1.69 EJT with contingency 2.69 138 degrees F (est. from log temps) 110 degrees F (from API Spec 10) DRILLING OPERATIONS MANUAL -- JACK-UP/PLATFORM/BARGE RIG DRILLING First Edition - May, 2003 2 of 2 PRESSURE INTEGRITY TESTS 11.0 PRESSURE INTEGRITY TESTS 11.1 11.2 11.3 11.4 11.5 General Casing Test Leak-Off Test Jug Test (Limited PIT) Open Hole Leak-Off Test 1 2 3 4 4 ______________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003 11.1 GENERAL There are three main types of Integrity Tests that are conducted by EMDC drilling. The Casing Test, the Leak Off Test (LOT), and the Jug Test (PIT). A casing test is used to ensure the casing will not fail in a well control situation or completion operation. The LOT and PIT tests are used in open hole just below the shoe to determine the equivalent mud weight that can be held, or that will initiate a fracture and cause leak-off to the formation. One additional type of test that may be performed during drilling operations is an open hole integrity test. If this test is required the applicable drilling procedure will detail that test. Casing tests are to be charted and the chart maintained at the rig and in the office per regulatory agency requirements. The MMS requirement is to pressure test all casing strings except the drive pipe, to hold the test for 30 minutes (generally for non-MMS regulated operations, 15 minute tests are sufficient) with <10% loss in pressure, and to document the test on the IADC report. For all EMDC wells, document the test on the morning report as well. The EMDC Integrity Test Workbook will be completed for either the LOT or PIT and will be performed in accordance with the guidelines specified below (located on the LAN or Global Share). The Excel workbook contains help files with discussion of theory procedures, and test interpretation. Additional information regarding test procedures and analysis is contained in the EPR publication "Pressure Integrity Test - Field Guide". The Operations Supervisor is responsible for completing the PIT form and forwarding it to the Drilling Engineer and Operations Superintendent as soon as practical after completing the test. General Pressure Testing Guidelines 1. Prior to drilling float equipment, a casing test is to be conducted. This test is to be run to the approved test pressure by the MMS or other governing regulatory agency. 2. Integrity Tests are required below each string of casing except the drive pipe and conductor casing. Based on geologic conditions or planned setting depths, a test of the conductor casing shoe may be mandated by the governing regulatory agency. A test is to be conducted after 10' of new hole has been drilled to determine the formation integrity. Per MMS or other governing regulatory agency orders, the test is to be conducted after drilling new formation, but must be performed before drilling 50' of new formation. The test will generally be taken to leak-off, (LOT) but a jug test (PIT) may be requested (see drilling procedure for details). The test surface pressure will not in any case exceed the casing test pressure or the surface line pressure. 3. All pressure tests should be conducted in the same manner. The same gauges and pressure charts should be used on each test. Gauges should be sized for the expected pressure range. 4. Pressure tests will be repeated if any doubt exists as to the validity of the test or if the result is less than anticipated. 5. The cement pump will be used for all pressure tests and, prior to conducting any pressure test, all surface lines will be tested to greater than the anticipated surface pressure as specified in the Drilling Procedure. 6. The following pressure test data will be recorded as accurately as possible: • Pump Rate • Mud Weight • Pump Pressure vs. Cumulative Barrels Pumped • Total Barrels Pumped • Shut-In Pressure vs. Cumulative Time (Minutes) • Total Barrels Bled Back 7. The guidelines in the "Integrity Testing Workbook" should be followed for plot interpretation. 8. After completing Integrity Testing Workbook, fax or email to the Drilling Engineer and Operations Superintendent for review and documentation. 11.2 CASING TEST The Casing Test procedure is as follows: 1. After setting surface casing and all subsequent casing strings, a Casing Test will be conducted using one of the following methods: a. After completing the required BOP test, the blind rams will be closed and the casing will be tested against the blind rams by pumping down the choke/kill line. b. After finding hard cement or prior to drilling the float collar, the BOP will be closed on the drill pipe and the casing will be tested by pumping down the drill pipe. Method "b" is the preferred technique. 2. Pump drilling fluid at 1/4 - 1/2 BPM and record the pressure build up using the cement pump until reaching the casing test pressure specified in the drilling program. Record bbls pumped to reach the test pressure. 3. Stop pumping and record the shut-in pressure for 30 minutes per MMS requirements or other regulatory agency requirements (generally, for non-MMS regulated operations, 15-minute tests may be sufficient). 4. Bleed off the pressure and record the bleed back volume. Record the test data in the Integrity Test Workbook. 5. Open the BOP. 11.3 LEAK-OFF TEST Prior to conducting the Leak-Off Test, the EMDC Integrity Test Workbook is to be prepared for plotting pump pressure and shut-in pressure as a function of cumulative bbls pumped and shut-in time. The drill pipe float valve, either solid or ported, can influence the results; take it into consideration. The accompanying equations may be helpful in calculating pressures and volumes during a leak-off test. Additionally, a spreadsheet to calculate the compressibility of Water or Oil based muds may be found on the LAN or Global Share. The casing test also provides a good indication of the expected pressure response if the mud type and density have not been changed. 1. Perform the casing test as described above, drill out the casing shoe and 10' of new hole. 2. Circulate bottoms up and condition the drilling fluid to ensure that is virtually free of cuttings and is of uniform density. Pull bit up inside the casing. 3. Rig up the cement pump and pump down the drill pipe to ensure all lines are full. Test lines to greater than the expected surface pressure as specified in the Drilling Procedure. The test surface pressure will not in any case exceed the surface line test or casing test pressure. 4. Close the BOP. 5. Pump drilling fluid down the drill pipe or choke/kill line and record the pressure build up versus cumulative barrels pumped. Pump at 1/4 bpm if the wellbore volume is <1000 bbls and 1/2 bpm if greater. 6. Enter the data in 1/4 bbl increments as the test proceeds to determine the leak-off point. 7. Continue pumping until reaching the surface pressure, adjusted for mud weight, specified in the Drilling Procedure, or leak-off plus 3-4 data points, whichever occurs first. • Do not exceed the casing test pressure. 8. Stop pumping and record the instantaneous shut-in pressure 10 seconds after shut in. 9. Read, record and plot the shut-in pressure at 1 minute intervals. Allow at least 10 minutes for pressure to stabilize. If pressure is continuing to fall rapidly maintain shut in until it stabilizes. 10. Bleed off pressure and record the bleed back volume from the annulus shoe so that the op float does not restrict flow. 11. Review the gradial plot in the Integrity Test Workbook and determint the LOT. Repeat the test if the interoperation is not clear. Repeat the PIT test if unacceptable. If it appears that the PIT was unacceptable due to fluid leaking off into a permeable sand, a seepage spill may be spotted prior to repeating the test. Use 20-30 ppb of 5 micron (fine) CaCO 3. Discuss this option with Operations Superintendent prior to pumping the second test. 12. Open the BOP. 13. Attempt to identify the minimum stress (MS) from the shut in data and record it in the results section of the Integrity Test Workbook. If a distinct inflexion is not seen at fracture closure record the MS as "N/A". Complete the workbook, including the comments section, form and fax or email it to the Drilling Engineer and Operations Superintendent as soon as practical. 14. Leak-off is assumed to be at the true vertical depth of the casing shoe which should be used to calculate the PIT. PIT (ppg) = [[ MW (ppg) * 0.052 * TVD of casing shoe (feet) ] + Surface pressure (psi) ] / [ 0.052 * TVD of casing shoe (feet) ]. 11.4 PRESSURE INTEGRITY TEST (JUG TEST) A jug test or PIT of the casing seat is identical to a leak-off test except that it is not taken to leak-off pressure. The test plots are similar in all areas except the top of the pressure build-up curve. In the LOT, the plot bends to the right at the leak-off point. In the jug test, the entire build-up plot should be a straight line because the test is stopped before leakoff pressure is reached. 11.5 OPEN HOLE LEAK-OFF TEST This Integrity Test determines if there is a significant decrease in the open hole fracture pressure in new formations drilled. Normally this test is necessary after penetrating porous/permeable formations that have the potential for lost returns and/or when the mud weight nears the last leak-off value. The same procedure is used as for performing an open hole test after the bit is pulled up inside the casing. A higher pump rate may probably be needed than was used in the PIT at the casing shoe because of the extended open hole section and potential permeability, however the initial attempt should be made at the same rate used for the shoe test. This test may be substituted with for a weight up test when a higher mud weight will be needed to TD the hole section. NOTE: To supplement the compressibility curves the following equations can be used: Equation 1 Barrels Base Fluid Required = (Test Pressure) (Casing Fluid Volume) (Coefficient of Compressibility – C f) Cf Water = 0.000003 Cf Diesel/SBM = 0.000005 Example - Bbls = (1000 psi)(1500 bbls) (0.000003) = 4.5 bbls required Equation 2 – to adjust Eqn. 1 for Mud Weight Adjustment for Mud Solids = (Barrels Base Fluid Required) (1- %Solids) Example – 14.8 ppg Mud Weight Adj = (4.5 bbls) (1-0.24) = 3.4 bbls Adjusted for 24% solids Integrity Test Plot Well Csg Size (in) Rig RKB (AMSL, ft) Water Depth (ft) Field Country Test Example Well 9.625 Example Rig 100 2,000 Example Field International Final Interpretati on Test and interpretation comments... Depth (ft) Type Integ (ppg) Test 1 Test 2 11,000 0 Test 3 0 16.2 LOT MS (ppg) 15.6 Surface Pressure (psi) Volume Prior to ISIP (bbl), Time After ISIP (1 min / minor division) Casing Test Test 1 Test 2 Test 3 FIGURE 11-1 (Intergrity.xls output) PRODUCTION TESTING 12.0 PRODUCTION TESTING 12.1 12.2 12.3 12.4 12.5 12.6 12.7 12.8 12.9 12.10 12.11 12.12 12.13 Production Testing Objectives Well Test Design Test String Surface Equipment Measurement Equipment Safety Personnel Responsibilities Pre-test Planning and Preparation Information Retrieval Well Killing and Zone Abandonment Emergency Procedures Hydrogen Sulfide Hydrates 1 1 3 4 4 5 6 9 10 11 11 11 12 ______________________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003 For Development Jack-up, Platform, & Barge Rig Drilling Operations, a production test is not usually performed. The wells drilled in during development are usually completed and brought on production by the Production group after the drilling rig has moved off location. In the event that a production test is required (e.g. exploratory well), a detailed Well Testing Procedure will be developed by the Well Test Engineer and/or the Drilling Engineer on a well specific basis. This procedure will cover the essential equipment and steps to be utilized during the production test (using industry guidelines and the general information included below). Refer to ExxonMobil Production and Development Company Safety Manuals for safety guidelines concerning drill stem testing, well testing equipment (i.e., steam generators, heater treaters, flowlines, gauge tanks, etc.) and H2S contingency requirements. A Risk Assessment will be conducted prior to initiating Well Production Testing operations. 12.1 PRODUCTION TESTING OBJECTIVES A production test is a formation evaluation technique which may be designed to provide the following reservoir description data: • • • • Types and Properties of Formation Fluids From a Particular Zone Measurements of Reservoir Pressure and Temperature Under Various Flow Conditions Determination of the Well Flow Efficiency Existence of Reservoir Heterogeneities or Boundaries This information will be obtained through either direct physical measurements taken during the production test or through analytical methods using the appropriate reservoir description model, in conjunction with information obtained from the well test. In exploration well testing, the well may be temporarily completed so that reservoir fluids can be flowed to the surface and measurements of pressure and flow rate can be made. Since hydrocarbons surface during the production test, extreme caution is to be taken by all personnel involved with testing operations. It is essential to select equipment and adopt test procedures which will ensure the safety of the drilling rig and its personnel. 12.2 WELL TEST DESIGN A typical production test consists of four distinct time periods: initial flow, initial build-up, final flow, and final buildup. The reservoir's pressure response during each of these time periods is shown schematically in Figure 12-1. The length of each time period is dependent on the reservoir producing capability and the type of fluids produced. Initial Flow Period The purpose of the initial flow period is to clean out the casing perforations and to ensure that a pressure differential exists from the formation into the wellbore. The initial flow period is usually short in duration (anywhere from 2 minutes to 1 hour). For an oil well test or bottom hole shut-in test, it is generally not necessary to flow formation fluids to surface during the initial flow. For a gas well test, all liquids should be completely removed from the wellbore below the first closed valve to prevent a phase hump in wellbore pressure from forming due to gas rising through liquids left in the wellbore. For a surface shut-in gas well test, the initial flow period could last several hours. Initial Build-Up Period Following the initial flow period, the well is shut-in in order to measure the initial reservoir pressure. Ideally, the initial build-up period should last until the bottom hole pressure has completely stabilized; however, this is not always feasible. The initial build-up period will normally be two to four times the length of the initial flow period, with lower productivity reservoirs receiving the higher multiplier. The minimum length for the initial build-up should be 1 hour regardless of the length of the initial flow period. In tests which utilize surface readout bottom hole pressure gauges, it is possible to monitor the bottomhole pressures and plot the data in real-time on a Horner or superposition plot. The shut-in period should, where practical, last until an initial reservoir pressure can be obtained unambiguously from extrapolation of the buildup pressures. Final Flow Period The purpose of the final flow period is to establish stabilized production from the well and to obtain fluid samples for laboratory analysis. The pressure transient introduced into the formation during the final flow period will be used to determine the reservoir permeability-thickness product and identify the existence of reservoir heterogeneities or boundaries. The length of the flow period is typically between 6 to 12 hours, but should be sufficient to obtain definitive flow data. In some cases, flow periods exceeding 12 hours may be required to ensure data quality. If produced liquids are flowed to storage tanks, then the flow rate and flow time will have to be adjusted so as not to exceed the capacity of the tank(s). The fact that stabilized fluid production is necessary for obtaining useful fluid composition data may dictate the actual length of the final flow period. Fluid samples from both the full well stream and the separator should be taken during the final flow period. Final Build-Up Period During the final build-up period, the well will be shut-in so that the reservoir pressure build-up response can be measured and recorded. This information will allow the formation permeability, wellbore damage, and indications of reservoir heterogeneities and boundaries to be determined. The length of the final build-up period should be at least as long as the final flow period. For low productivity reservoirs, the build-up period should be 1-1/2 to 2 times the length of the final flow period. If bottom hole samples are required, they should be taken following the final build-up period. 12.3 TEST STRING Test String The test string contains those components necessary for sealing the tubing annulus, shutting in the tubing downhole (if desired), and suspending pressure and temperature gauges. The shut-in method used will depend on such considerations as types of fluids produced, objectives of the test, and safety considerations. The four basic lower test string assemblies are: Surface Shut-in/Permanent Packer; Surface Shut-In / Retrievable Packer; Bottom Hole Shut-In / Permanent Packer; and Bottom Hole Shut-In / Retrievable Packer. See Figure 12-2 for a typical lower test string assembly with Surface Shut-In / Permanent Packer. Shut-In Methods 1. Surface Shut-In The simplest method for shutting in a well is with a surface shut-in. In this method, primary well control is at the surface test tree. No manipulation of the test string is required while the well is "alive". Unfortunately for reservoir purposes, during surface shut-in the entire wellbore volume is in communication with the formation. This can lead to two detrimental effects, afterflow and phase redistribution in the wellbore. Afterflow is defined as flow from the formation into the wellbore after the well is shut-in at the surface. Formation fluid can flow into the wellbore because of the compressibility of the fluid in the wellbore. Afterflow is usually not a problem in oil or gas wells having moderate to good productivity. In low productivity wells, afterflow can lead to difficulty with analysis of data. Phase redistribution (separation of gas and liquid) may cause problems with analysis of data from high liquid ratio gas wells and high GOR oil wells. If phase redistribution occurs, it can usually be recognized as a hump in the plot of build-up data. If pressure humping lasts throughout the test, the build-up data may be of questionable value for analysis of reservoir properties. 2. Bottom Hole Shut-In The bottom hole shut-in method is the ideal way to shut-in a well for a build-up test, because it eliminates the effects of afterflow and phase redistribution. However, a bottom hole shut-in requires a somewhat complex string of downhole tools, which increases the probability of a mechanical malfunction. With some test strings, pipe motions are required to operate tools while the well is "live" which is considered a disadvantage from the standpoint of safety. A bottom hole shut-in should be considered if: • • Phase redistribution (pressure humping) or afterflow is expected to dominate the data. The surface shut-in pressure of the well is expected to exceed safe conditions. 12.4 SURFACE EQUIPMENT The surface testing equipment is designed to process produced formation fluids from the surface test tree to a point of disposal. Typically, the major components of this system are: data header, choke manifold, flow lines, heater, separator, test/gauge tank, transfer pump, and burner(s). The surface and bottom hole test equipment required for a particular well test will vary depending upon individual well conditions and specific reservoir requirements and will be specified in the Well Testing Procedure. 12.5 MEASUREMENT EQUIPMENT Obtaining accurate measurements of bottom hole and surface pressure and temperature is one of production testing's main objectives. Subsurface pressure and temperature gauges can be either mechanical or electronic downhole recording devices or wireline run electronic gauges which provide a surface readout. Surface pressures are normally obtained with either dial gauges or dead weight testers. Subsurface Measurement Equipment Subsurface gauges are run into the wellbore to record the reservoir pressure and temperature response during flowing and shut-in periods. Subsurface pressure and temperature gauges can either be landed in a nipple located below the perforated joint or run in gauge carriers. There are two basic types of subsurface pressure gauges available, the subsurface recording gauges and the surface readout subsurface gauges. 1. Subsurface Recording Gauges Subsurface recording gauges make a record of pressure and/or temperature versus time. The record can be read at the surface when the gauges are retrieved. These gauges are self-contained recording devices which do not require a physical link to surface equipment. Subsurface recording gauges will either be mechanically or electronically operated. 2. Surface Readout Subsurface Gauges Surface readout subsurface gauges allow real time bottom hole pressure and temperature measurements to be read at the surface. These gauges transmit their data through a monoconductor cable. Because of the electric cable, these gauges cannot be used with a standard bottom hole shutin test assembly. Surface Measurement Equipment Surface pressure and temperature measuring equipment can be connected to the data header located upstream of the choke manifold. Surface pressure can be measured with either dial type gauges, a dead weight tester, and/or electronic gauges. 12.6 SAFETY General Safety Guidelines 1. The drilling supervisor is to hold a safety meeting prior to the initiation of each production test. All personnel are to attend this meeting. 2. Do not subject Oilfield Explosives (perforating guns, tubing cutters, string shots, severing charges, etc.) to pressures higher than the allowable (rated) pressure specified by the manufacturer. This includes pressure testing lubricators that contain electric line conveyed perforating guns, cutters, etc. and also while running explosives into the well (e.g. multiple runs of through tubing perforating guns/ adding perfs on a "live" well). If necessary, substitute an explosive device with a higher pressure rating. 3. Testing of the surface equipment should be addressed in the Risk Assessment. It is also recommended that start-up of the production test be initiated during daylight. Extra lighting may be necessary to insure potential leaks do not go undetected if testing continues after daylight hours. 4. The drilling rig is to be equipped with a warning system, which will be activated any time the well is being tested. During this period, it will be necessary for personnel to follow ExxonMobil Safety Manual guidelines for welding, cutting, electrical work, sand blasting, or other work which could result in a fire or explosion. 5. Cranes will not be operated over "live" test equipment. 6. Personnel not required for duties in conjunction with the test, or for maintenance duties, are to stay clear of production testing equipment. Smoking is permitted only in designated areas. 7. If H2S is anticipated in formation fluids, H2S detection equipment shall be used to determine if any hydrogen sulfide is present in the produced formation fluids. 8. At the conclusion of testing operations, all flowlines are to be thoroughly flushed with water. 9. Cement unit should be tied to the surface test tree for use in well kill operations, if necessary. 10. The surface tree lower master valve should be manual operated, the upper master valve & wing valve should be hydraulic or pneumatic operated with a remote unit located away from the tree. 11. A contractor representative of the tree supplier must be present on the rig floor or near the control unit at all times when the well is "live". 12. If methanol is utilized, ensure that flame and mitigation detection contingencies are in place and reviewed with all personnel. 12.7 PERSONNEL RESPONSIBILITIES The overall responsibility for conducting a safe testing operation rests with the Operations Supervisor. The Operations Supervisor is to work closely with the Drilling/Well Test Engineer, and Service Company Personnel to ensure that all test objectives are achieved. Responsibility guidelines for a typical offshore production test are listed below; refer to Section 2.6 of this manual for additional information. Drilling/Well Test Engineer 1. Develop test procedures and determine equipment needs. 2. Ensure that all test equipment is mechanically sound and compatible with adjacent equipment. Ensure that critical spares are available. 3. Witness pressure and function tests of surface and subsurface test equipment. Coordinate Third Party witnessing of equipment inspections and testing prior to sending equipment to location. 4. Supervise the make-up of the test string and check clearances. Ensure that string spaceout is correct. 5. Ensure that packer, seal assembly, and tail pipe assemblies have the proper OD's, ID's and lengths. 6. Witness perforating operations (if applicable). 7. Ensure that all wireline tools and equipment are available and compatible with durable conditions. 8. Coordinate and gather test data. 9. Evaluate test data on-site for completeness and accuracy. 10. Specify length of flow and build-up periods and size of choke. 11. Supervise surface and bottom hole sampling. 12. Communicate test results to office personnel during and after the test for making tactical decisions. 13. Read and analyze bottom hole pressure charts for evaluation of test results. 14. Follow up on test equipment and service company personnel performance. Wellsite Geologist 1. Determine number of zones to be tested and provide initial information on pressure, temperature, and types of fluids contained in the reservoir. 2. Analyze electric logs to determine perforating interval(s). 3. Witness perforating operations (if applicable). 4. Assist in gathering and analyzing test data. Subsurface Test Tool Personnel 1. Prepare test tools and subs for make-up on drill floor. 2. Function and pressure test tools on pipe rack. 3. Check nitrogen precharge on annulus pressure operated tools. 4. Oversee make-up and running of bottom hole test assembly. 5. Operate down hole test tools, by directing the drill crew, under the direct supervision of the Drilling/Well Test Engineer. Production Testing Service Company Personnel 1. Operate surface and downhole test equipment under immediate supervision of the Drilling \ Well Test Engineer. These responsibilities will include proper functioning of separator, changing orifice and choke sizes, accurate calibration of gas and liquid meters, operating all valves, observing separator pressures, and monitoring gas and liquid flow rates, running gauges, etc. 2. Coordinate separator operation with rig floor for emergency shut-in. 3. Ensure the proper functioning of burner(s) and monitor wind direction. Operate all valving under the direction of the separator operator and help monitor wellhead pressures. Coordinate burner operation with rig floor for emergency shut-in. 4. Take oil, gas, and water samples. Ensure proper labeling. 5. Assist with monitoring wellhead pressures with deadweight tester and record wellhead temperatures. 6. Operate chemical injection of glycol / methanol, as necessary. 7. Coordinate operation of surface test tree and floor choke manifold and be prepared to handle an emergency shut-in. 8. Ensure that the proper wireline tools are available for test string pressure testing. 9. Ensure that the proper testing and maintenance of the surface test tree and floor choke manifold are carried out. 10. Assist in monitoring casing annulus pressure and production test data. 11. Prepare subsurface recording pressure and temperature gauges. Continuously monitor panel for surface reading subsurface pressure and temperature gauges. Mud Logger 1. Take periodic samples of gas at the floor choke manifold during flow periods and analyze samples with the gas chromatograph. 2. Use gas detectors to determine possible presence of gas on the rig floor and in the wellhead/BOP area. Drilling Fluids Engineer 1. Ensure the proper maintenance of the drilling fluid in the pits. 2. Catch samples of condensate and/or water being produced and conduct analysis of filtrate and water properties. Cementer 1. Perform well killing and cementing operations as required. Have pumping equipment in a state of readiness to kill the well and/or cement at short notice. 2. Maintain adequate number of cement retainers and conversion kits to bridge plugs for casing size used in production test. 3. Assist drill crew and subsurface test hole personnel in operation testing of downhole equipment. 4. Assist testing personnel in testing surface test equipment. Rig Toolpusher 1. Ensure that well killing equipment is ready and coordinate the well killing operations. 2. Oversee running of test string and rigging up of surface control equipment. 3. Help coordinate various steps of the production test sequence as pertaining to the rig equipment. 4. Manipulate/operate downhole tools under direction of subsurface test tool personnel. Driller 1. Ensure pressure integrity of rig floor piping. 2. Coordinate the Assistant Driller and/or floormen to provide constant observation of the casing annulus pressure and production test data. 3. Ensure that production test string is properly made up. 12.8 PRE-TEST PLANNING AND PREPARATION Good planning and preparation are essential to conducting a safe and complete production test. Prior to the test, a meeting is to be held with all key personnel to discuss the test procedures, personnel responsibilities, and safety considerations. The BOPs are to be fitted with the proper size rams as necessary to accommodate the test string equipment in the hole. All surface testing equipment is to be pressure and function tested before beginning the test. Meetings and Drills The Operations Supervisor is to hold a pre-test meeting prior to the initiation of each production test. All personnel are to attend this meeting. During the pre-test meeting, the following items are to be reviewed and discussed: • • • • • • • Safety Procedures Spill Prevention Test Objectives Test Equipment and Hook-Up Test Procedures Personnel Responsibilities Data Collection Supervisors must ensure that the responsibilities of all personnel associated with the test are clearly understood. Surface Equipment Preparation At an appropriate time, well before the test string is run in the hole, the separator, heater, transfer pump, gauge tank and burner(s) are to be inspected and prepared for operation. The kill line and flowline connections on the surface test tree are to be checked to ensure that compatible chiksan or other flexible connections are available. The fail-safe closed valve on the surface test tree flowline is to be checked for proper operation. The surface test tree, the flowline chiksans, and the floor choke manifold are to be checked for connection compatibility. The floor choke manifold is to be rigged up with the proper size chokes for the initial flow. The data header is to be checked and the adapters, if required, for the various gauges and transducers are to be made up. Surface Equipment Pressure Testing Make up the surface test tree and rig floor equipment. Ensure that the data header and all instrumentation is functioning properly. Note: Have an OEM (Original Equipment Manufacture) service representative on location during installation and pressure testing of all Christmas tree equipment. Place a permanent warning sign on the valves which have the potential for internally trapped pressure "Warning: This valve has the potential to internally trap pressure". Note: Whenever a back pressure valve (BPV) is to be removed from a tubing hanger, a lubricator shall be installed and anchored. Prior to retrieving the plug, confirmation of pressure equalization should be made if possible. If working on a well with H2S gas, all workers in the area should mask up while retrieving the plug. Pressure test the surface equipment to 200 psi and to the pressures specified in the Production Testing Program, using the cementing unit, as follows. The test pressure is to be held stable for at least 5 minutes on the low pressure test and at least 5 minutes on the high pressure test. 12.9 INFORMATION RETRIEVAL A primary purpose of the production test is to collect sufficient data for making an accurate reservoir description. To accomplish this objective, it is essential that the data gathering activity be given high priority both in planning and during testing operations. This can best be accomplished by ensuring that each individual involved in the test fully understands his responsibilities and the operation of the equipment he is assigned to oversee. Persons responsible for actually gathering data must know what data to gather and which data form is required for transcribing the data. During the pre-test meeting, the Drilling/Well Test Engineer is to assign the appropriate form to each of the individuals involved with data collection. Refer to the EMPC Exploration Well Testing Manual for a listing of suggested data requirements and forms. The rate for data collection will vary according to the test period in progress and the state of the well during the period. In general, data entries should be made more frequently during periods when well conditions are changing rapidly with time (e.g., immediately following shut-in or flow initiation) and less frequently during stable conditions. The primary goal is to ensure that data are smooth and continuous when plotted against time. The actual frequency for collecting data will be specified by the Drilling/Well Test Engineer, but for most test situations, the following guidelines apply: 1. All Flow Periods: Readings should be recorded every 30 minutes during stabilized flow conditions and at an increased frequency during initial flow. 2. Final Shut-In Period: Record wellhead (surface) pressures and temperatures with the chart recorder and pressure recorder as follows- ensure high frequency reading downhole for buildup analysis: • • • • Each minute for the first 10 minutes (or at an increased frequency, if appropriate). Every 5 minutes for the next 20 minutes. Every 15 minutes for the next hour. Every 30 minutes for the duration of the shut-in period. 3. Subsurface Pressure Chart Reading: At the conclusion of the final build-up period, the subsurface pressure gauges are to be recovered and checked for mechanical malfunction and the pressure readings obtained. Sample Gathering Samples of gas, oil/condensate and water are to be collected during each production test for laboratory analysis. Surface and/or bottom hole samples are to be obtained as described in the Well Testing Procedure. A master sample list is to be maintained. This list should identify each sample and provide information necessary to track the sample at a later date. For example, it should identify the sample container by the container serial number and contain all the data specified on the sample label. This will allow the sample to be correctly identified with the sample bottle should the label be destroyed. All pressurized samples are to be packed in the boxes sent out to the drilling rig specifically for this purpose. Bottom hole samples may be required by Reservoir Engineering. When bottom hole samples are required, they will generally be taken directly opposite the perforations, if possible, and with the well flowing through a small choke. 12.10 WELL KILLING AND ZONE ABANDONMENT Well Killing At the conclusion of the final build-up period, the well may be flowed at a high rate to heat up the wellbore for the purpose of avoiding formation of hydrates in the test string. Additional downhole work, such as pulling the pressure gauges, obtaining bottom hole samples, or performing other final actions as specified in the Well Testing Procedure, can then be completed and the well can be killed. The killing operation will vary with the specific well test string being used. However, the significant point is to ensure that a column of mud, with sufficient weight to ensure that an overbalance exists at the formation, is circulated throughout the wellbore. 12.11 EMERGENCY PROCEDURES Refer to specific Emergency Procedures developed for rig operations. 12.12 HYDROGEN SULFIDE Hydrogen sulfide (H2S) is a colorless gas which is both toxic and corrosive. The presence of H2S in the production stream requires special procedures for conducting the well test and testing equipment that has metallurgical properties compatible with the H2S environment. Due to the extreme toxicity of H2S, self-contained breathing apparatus (SCBAs) must be available during the test if H2S is expected. If the potential exists for H2S in the formation fluids, an H2S contingency plan must be developed and implemented prior to initiating well test operations. H2S Safety Procedures The following safety procedures are to be observed on all well tests where H2S is known, expected, or contingent. Also refer to the well's H2S Contingency Plan. 1. Prior to beginning the well test, all personnel are to be briefed on the hazards of hydrogen sulphide and certified (i.e. Fit Tested, and applicable certification). H2S drills are to be performed with all personnel on the rig. 2. All surface and downhole equipment which may be exposed to H2S must be designed for use in H2S environments. 3. Every effort must be made to ventilate the rig floor and separator area before the well is opened. 4. Each individual who will be on the rig floor or working with the hydrocarbon processing equipment (separator, burners, etc.) is to have a self-contained breathing apparatus available in the work area. 5. When the formation fluid surfaces, every effort is to be made to keep the burner(s) operating. 6. When the formation fluid surfaces, and at 15 minute intervals thereafter, the H2S detector will be used to determine if any hydrogen sulfide is present in the produced fluids. 12.13 HYDRATES Hydrate Formation Hydrates are frozen or ice-like chemical compounds formed when certain light hydrocarbons combine with water. Hydrate formation is associated with gas production and is a function of temperature and pressure. Figure 12-3 is a hydrate formation conditions chart. The areas above each curve represent the conditions of temperature and pressure under which hydrates can form if sufficient water is present. At low water concentrations and high flow rates, the formation of hydrates may not be sufficient to cause blockage of the flow stream. However, upon shutting in the well, hydrates may form a blockage and prevent further well flow. Even minor hydrate formation can interfere with wireline/slickline operation for setting plugs or retrieving data. A hydrate mitigation plan should be in place if hydrate conditions are possible. FIGURE 12-1 FIGURE 12-2 Production Tubing Permanent Packer Locator Seal Assembly Landing Nipple Perforated Joint Spacer Tube No-Go Landing Nipple Wireline Entry Guide Perforations Production Casing Lower String Asssembly for Surface Shut-in (Permanent Packer) FIGURE 12-3 PLUG AND ABANDOMENT 13.0 PLUG AND ABANDONMENT 13.1 13.2 13.3 13.4 General Permanent Plug and Abandonment Temporary Plug and Abandonment Site Clearance Verification 1 1 4 4 ______________________________________________________________________________ DRILLING OPERATIONS MANUAL - JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDETION MAY, 2003 13.1 GENERAL Before performing any Permanent or Temporary Plug and Abandonment work, regulatory approval must be obtained from the applicable regulatory agency. The objective of the following general guidelines is to plug and abandon wells in accordance with the governing regulatory agency and ExxonMobil requirements; such that all hydrocarbon zones, abnormally pressured water zones, and freshwater aquifers, are isolated to permanently prevent their contents from escaping into other strata or to the seafloor. Procedures may be adjusted to fit specific hole conditions but should at least meet the minimum objectives described in these guidelines (MMS or local regulatory body and ExxonMobil requirements). During permanent or temporary plug and abandonment operations, the following general guidelines, consistent with local regulations, shall apply: 1. Critical abandonment plugs which isolate hydrocarbon and injection zones from fresh water aquifers should be verified by tagging and/or pressure testing. Coordinate any plugs that must be tagged with the applicable regulatory agency and EMPC. 2. During each phase of the plug and abandonment operation, a means of performing well control is to be maintained. This is valid until casing with a non-sealed outer annulus (generally surface or conductor casing) is to be cut or perforated. 3. When casing is cut, pressure control is to be maintained by closing the annular preventer around the drill pipe. This is valid until casing with a non-sealed outer annulus (generally surface or conductor casing) is to be cut. If communication from an open formation to the surface via the annulus is found, the flow is to be controlled with kill mud and the annulus squeeze cemented through the cut or perforations. The annulus is to be pressure tested after cementing to ensure that it has been properly sealed. 4. When conducting plug and abandonment operations, all mud returns are to be analyzed by the Mud Logging Unit/Mud Engineer in order to detect any formation fluid influx that might occur. 5. Consideration should be made to treat mud left between cement plugs inside the casing with a corrosion inhibitor and/or a bactericide. 6. During each phase of the plug and abandonment operation, the mud left in the hole above a cement and/or a mechanical plug is to have a weight sufficient to withstand, together with the plugs, any pressure which may develop in the well. 13.2 PERMANENT PLUG AND ABANDONMENT The following is a sequence for a permanent plug and abandonment operation in which all casing strings and well bore annulus are permanently sealed. Well specific procedures may vary and will be specified in the Plug and Abandonment Program: 1. Isolation of Zones in Open Hole The following method of isolating open hole intervals is acceptable. • In uncased portions of the hole, cement plug(s) shall be spaced to extend from 100' below the bottom to 100' above the top of the zone(s) to be isolated. Any porous or permeable zone containing hydrocarbons should be isolated. Typically cement volumes in open hole are based on gauge hole plus 10% excess. • Other methods of abandonment may be more practical. The appropriate regulatory agency and the operations superintendent must approve these alternate methods. Note: The placement of a hi-vis pill below cement plugs can be beneficial in preventing the plug from settling prior to setting up. 2. Isolation of Open Hole from Casing Shoe The following methods of isolating open hole below casing are acceptable. • Place a balanced cement plug across (100' above and 100' below) the casing shoe. • Set a cement retainer in the casing, 50' - 100' above the shoe, squeeze 100' of cement below the shoe and place 50' of cement above the retainer. • If lost returns have been experienced place a permanent type bridge plug <150' above the shoe and place 50' of cement above it. • Other methods of abandonment may be more practical. The appropriate regulatory agency and the operations superintendent must approve these alternate methods. 3. Plugging or Isolating Perforated Intervals The following methods of isolating perforated intervals are acceptable. • The perforations may be squeezed. • A balanced cement plug placed opposite all open perforations, extending 100' above to 100' below the bottom of the perforated interval. • Set a cement retainer 50' - 100' above the top of the perforated interval, squeeze cement to 100' below the perforated interval and place 50' of cement above the retainer. • A permanent type bridge-plug may be set <150' above the top of the perforated interval with 50' of cement placed above the bridge-plug. • A cement plug that is at least 200' long may be set with the bottom of the cement plug within the first 100' above the top of the perforated interval. • Other methods of abandonment may be more practical. The appropriate regulatory agency and the operations superintendent must approve these alternate methods. 4. Plugging of Casing Stubs Cut and pull any casing strings required and isolate all annular spaces by placing a balanced cement plug, 100' above and below, the remaining stub or one of the following methods: • A cement retainer or a permanent-type bridge plug is set 50' above the stub and 50' of cement placed on top of it. • A cement plug, which is at least 200' long, is set with the bottom of the plug within 100' of the casing stub. • If the stub is below larger size casing plugging shall be accomplished as required to isolate zones or open hole as described above. 5. Plugging of Annular Space Any annular space that communicates with open hole and extending to the mud line will be plugged with at least 200' of cement. 6. Surface Plug • Set a balanced cement plug at least 150' in length with the top of the plug within 150' below the mud line. The plug will be placed in the smallest string of casing that extends to the mud line. 7. Testing of Plugs The condition and location of certain cement plugs shall be verified by one of the following methods: • By tagging the cement plug, cement retainer, or bridge plug with 15 kips while circulating against the plug. Cement placed above a bridge plug or retainer need not be tested. • By pressure testing the plug with a minimum pump pressure of 1000 psi with no more than a 10% pressure drop in a 15-minute period (MMS). ExxonMobil at least 500 psi in excess of the formation breakdown pressure or within the working limits of the weakest exposed casing string whichever is less. Minimum Verification of Abandonment Plugs • The first plug below the surface plug will be verified by one of the above methods (MMS). 8. Clearance of Location All wellheads, casing, pilings, and other obstructions shall be removed to a depth of 15' below the mud line or to a total depth approved by the applicable regulatory agency. 13.3 TEMPORARY PLUG AND ABANDONMENT A temporary abandonment differs from a permanent abandonment in that all casing strings and wellhead seals remain intact. During temporary plug and abandonment operations, the following general guidelines shall apply: 1. No holes may be punched in the casing except as required for production testing. Perforations are to be properly plugged and isolated. 2. The wellhead seal area is to be protected by installing a corrosion cap or an abandonment tree. For long abandonment periods, the well may be additionally protected by displacing the mud in the seal area with inhibiting fluid. 3. The well is to be equipped with a location marker and identification. 4. Inspection of the wellhead and protective structure is to be carried out at least once per year. 5. A bridge plug or a 100' long cement plug is to be set at the base of the deepest casing string unless the casing has not been drilled out. 6. A retrievable or permanent-type bridge plug or cement plug at least 100' in length, shall be set in the casing within the first 200' below the mudline. 7. Exceptions to these guidelines must be approved by the applicable regulatory agency, the operations superintendent and EMPC. 13.4 SITE CLEARANCE VERIFICATION Final site clearance after abandonment must be approved by the regulatory agency. Typically one of the following methods will be acceptable: 1. Drag a trawl in two directions across the location. 2. Perform a diver search around the wellbore. 3. Scan across the location with a side-scan or on-bottom scanning sonar. WELL CONTROL 14.1 WELL CONTROL 14.2 14.3 14.4 14.5 Well Control – General Hole Monitoring 5 Equipment Testing 8 Equipment Specifications 1 10 14.6 14.7 Well Control Drills 16 Well Control Procedures 19 ______________________________________________________________________________________ DRILLING OPERATIONS MANUAL- JACK-UP/PLATFORM/BARAGE RIG DRILLING FIRST EDITION MAY, 2003 14.1 WELL CONTROL - GENERAL Well Control operations are performed to mitigate well control incidents by minimizing the severity of the influx, properly shutting-in the well as soon as practical, and surfacing the influx in a safe manner or pumping/bullheading the influx back into the formation (when bringing the influx to the surface may be too hazardous, like with H 2S). Uncontrolled flows into the wellbore must always be kept below the blowout preventer stack. Safety of all personnel on the rig is the primary consideration when conducting well control operations. Integrity of the drilling unit and adverse economic impacts are of secondary importance. General step-by-step procedures may vary depending on the BOP configuration on each individual drilling unit. The Drilling Contractor's specific shut-in procedures for each drilling unit are to be reviewed to determine if they are acceptable for EMDC's operations. For all locations, a site specific well control plan is to be in place which includes diverter and well control procedures specific to the drilling unit and BOP stack configuration. General Well Control Guidelines General well control guidelines are as follows: 1. All well control equipment will be maintained in a ready state while conducting drilling operations. 2. Conduct drills in accordance with "Well Control Drills" section of this manual. 3. Test well control equipment (i.e., pressure and function test) as specified in "Well Control Equipment Testing" section of this manual. 4. A current status board of critical drilling parameters will be maintained at the Driller's console in plain view. Information on this board should consist of the following: • • • • Tool joint distance above the rig floor for closing the hang-off rams Most recent BOP test date BOP stack dimensions of the preventer spacing from the wellhead BOP stack dimensions of the preventer spacing below the rotary table (as tool joint space out is typically measured from the rotary table) 5. Laminated copies of rig specific shut-in procedures shall be posted on the rig floor near the Driller's console. Rig specific station bills, listing duties of the crew members, will also be posted on the rig floor and/or bulletin board. 6. Lost Circulation Procedures will be posted on the rig floor. 7. The Driller will be instructed to shut-in the well using his judgment and indicators such as pit gain, flow after stopping the pumps, or improper fill-up on trips. The Driller does not have to secure permission from the Operations Supervisor prior to shutting-in the well. 8. The drill string will always include a float valve above the bit and, after setting sufficient casing to shut in the well, the float valve will be ported, unless a solid float is approved by the Operations Superintendent. Field modification of drill pipe floats is not allowed. 9. At all times, a full opening, ball type, pressure balanced safety valve (TIW or equivalent) for drill pipe and an inside BOP, with crossover subs for drill collars and casing, will be on the rig floor and ready for immediate use (i.e., open). These will be available for all drillstring sizes in use. The safety valve(s) must be function tested and the test must be documented on the IADC report and DMR. The safety valve will always be picked up first. A safety valve will be installed in the string during periods of downtime, such as slipping and cutting drill line, etc. NOTE: API Spec. 7 (November 2001 edition) has divided safety valves into two classes. Class I valves (standard valves) are rated to working pressure from below only and may not seal from either direction if pressure is applied from above. Class I valves are not API pressure rated externally and may leak through the stem. Class II valves are designed for rated working pressure from below and above the ball and externally to 2000 psi minimum. If there is a probability that stripping operations will be required, Class II should be utilized at the rigsite. Section 8 in the "ExxonMobil Drilling Surface Blowout Prevention and Well Control Equipment Manual" provides a listing of manufacturers known to be capable of supplying proven Class II safety valves. 10. Circulate choke and kill lines to ensure lines are clear (frequency will depend on drilling fluid). 11. The choke will be in the open position with the first valve downstream of the choke in the closed position as well. 12. Maintain a "Well Kill Worksheet" for the current wellbore configuration and update the worksheet (or KIK PC program) at least daily while drilling is in progress, or as hole conditions change. 13. Keep the inner choke and kill valves on the BOP in the closed position while drilling. Keep the outer choke and kill valves in the open position. 14. Have the choke manifold lined up to take returns to the poor-boy degasser. 15. Have the PVT and FLO-SHO alarms set to the lowest practical limits. 16. Rig up an annulus fill-up line from the rig pumps for quick fill up of the annulus. 17. Use the annular to initially shut-in the wellbore. The on-site Operations Supervisor will determine if hanging-off the drill string is necessary based on existing operating conditions. 18. If an annular is used to circulate out the influx, the closing pressure may be backed off per the manufacturer's recommendations to reduce wear on the element. Sufficient operating pressure will be maintained to prevent leakage and avoid gas escaping to the rig floor. Closing pressure can be reduced to allow limited pipe movement to avoid sticking the drillstring while circulating out an influx. However, tool joints should not be cycled through the annular element while circulating out an influx. 19. Shut the diverter annular only after opening the diverter line valve(s) to prevent broaching. Assign personnel to monitor for broaching if diverting the well with only shallow casing set. The diverter lines are to be routed overboard and downwind. 20. Utilize mud pumps and/or fire hoses to wet gas exiting from diverter lines. 21. Wind socks should be visible from pertinent areas of the rig. Pressure Recording Guidelines Pressure recording guidelines are as follows: 1. Record the shut-in pressures on the drill pipe and casing every minute until shut-in pressures stabilize. After stabilization, record the shut-in pressure on the drill pipe and casing every 10 minutes until well control operations end. 2. Record the pressure necessary to pump open the float valve as the stabilized drill pipe pressure when using a nonported float valve in the drill pipe. Note: The method to determine when the float valve is opening is the same as determining the break-over limit during a pressure integrity test. 3. Designate specific personnel to record pressures and observations/remarks though out the well control operation. 4. Shut down the pumps and shut-in the well to check pressures if a problem arises while circulating out an influx into the wellbore. 5. Determine a new friction pressure if using a different pump rate when restarting circulation after shutting in to check pressures. 6. Determine the new friction pressure in the same manner as the original friction pressure. Note: The maximum pressure at any point in the wellbore during the killing operation will occur when the top of the influx is at that point or when the influx is on bottom in the case of short open hole intervals or long bottom hole assemblies and the top of the bubble is above the casing shoe. This is especially true in deep wells. Pump Rate Guidelines 1. Ensure that the selection of the circulation rate considers such factors as: a) formation integrity at the casing shoe, b) rig well control equipment, c) capacity of barite additions to the mud system, and d) rig pump oiling limitations at slower rates. 2. Consider the following advantages of a low pump rate. A typical pump rate is in the 1 to 3 BPM range: • Low pump rates allow the choke operator more time to adjust the choke. • Low pump rates minimizes the handling of large gas volumes at the surface • Low pump rates reduces the possibility of lost returns. 3. Understand the limitations of the mud gas separator when 100% gas reaches the surface. Be prepared to bypass the mud gas separator and go directly to the flare if the liquid leg is lost. Well Killing Worksheet A Well Killing Worksheet is critical to a successful well control operation since it helps Operations and Engineering personnel communicate clearly during the operation and perform the necessary calculations. After the BOP stack is installed, a "Well Killing Worksheet" will be prepared. The worksheet will be maintained for the current wellbore configuration and update the worksheet at least daily while drilling is in progress, or as hole conditions change. Note: The KIK PC computer program may be used in lieu of the worksheet. Steps for completion of the "Well Killing Worksheet" are as follows: 1. Calculate the kill mud weight. • Record the original weight of the drilling fluid. • Calculate the necessary increases in drilling fluid weight to balance the formation pressure and to provide an overbalance. • Calculate the kill weight of the drilling fluid. 2. Calculate the maximum allowable surface pressure: • Record the PIT at the last casing shoe. • Calculate the maximum surface pressure which will fracture the formation. • Record the casing burst pressure and safety factor. • Calculate the allowable surface pressure for each weight and grade of casing. • Select the lower of the two calculated values as the maximum allowable surface pressure (to be used for information only). 3. Calculate capacities and total active system volume. 4. Calculate the barite required to weight up the active system and the corresponding volume increase. 5. Calculate the circulation rate and the pressure change schedule: • Enter the circulation rate and initial drill pipe circulating pressure. • Calculate the change in circulating pressure that will occur due to a heavier fluid weight. 6. Select the circulation method and prepare the drilling fluid weight schedule. If practical, consult with the Operations Superintendent as to which of the following methods to use based on well pressures involved, pressure integrity of the casing shoe, rig gas handling capability, mud system capabilities, and mud material on location. • Driller's Method (original mud weight) • Weight and Wait Method (balance mud weight or kill weight mud) 7. Perform influx height and gradient calculations: • 14.2 If the influx gradient is less than 0.2 psi/ft, the influx is probably gas. If the gradient is between 0.2 psi/ft and 0.4 psi/ft, the influx is probably oil. If the gradient is greater than 0.4 psi/ft, the influx is probably salt water. HOLE MONITORING Hole Fill-Up Hole Fill-Up Guidelines: When tripping out of the hole, into the hole, or when the drill string is out of the hole (i.e., logging, BHA change out, slip and cutting drill line, etc.) the hole will be continuously monitored for gains or losses using the trip tank. The following guidelines should be followed to ensure a full column of mud is maintained in the annulus at all times. 1. The hole will be kept full using the trip tank when not pumping down the drill string. The trip tank level will be recorded a minimum of every 15 minutes when pipe is out of the hole. A trip book will be maintained for each well and at least one person is to be assigned to monitor the trip tank on a continuous basis while tripping. The trip book log should compare trips volumes to both the theoretical volume and the previous trip volumes 2. If the rig is equipped with a top drive system, back-reaming and pumping out the first 10 stands of open hole when tripping should be considered. This is especially relevant while drilling directional wells or wells with highly reactive formations. 3. The bit will be returned to bottom and the well circulated bottoms-up if observed fill-up volume is less than calculated or significantly less than fill-up recorded on the previous trip. If the hole does not take the calculated amount of fluid, the Operations Supervisor will be advised immediately. • Pit levels will be monitored carefully when circulating bottoms-up to detect any expansion of gas and/or well flow during the circulating operations. 4. Sufficient mud weight will be used that provides at least 200 psi of overbalance before attempting to pull or pump out of the hole. 5. A trip tank with a minimum capacity of 40 bbls is preferred. The trip tank will be marked in at least 1/2 barrel increments. 6. A grease type packing is to be used on the centrifugal pump that feeds the trip tank. Water injection will not be used. 7. The mud loggers should also closely monitor trip tank volumes while tripping out of the hole and confirm the displacement volumes recorded by the drilling contractor. They should also monitor volumes while tripping in the hole if requested by the Operations Supervisor or if it is specified in the Drilling Program. 8. The maximum amount of drill pipe than can be run in the hole without being filled must be specified in the Drilling Program and will be based on that particular well plan (casing depths, amount of open hole, potential gas sand location, etc.) Section 4 describes a method to calculate the maximum length of pipe that can be run without filling the drillstring. 9. When tripping in the hole displacement volumes from the well must be accurately monitored using the trip tank. The FDM can provide an exception to using the trip tank when tripping in hole. Note: Field modification of drill pipe floats is not allowed. There are no exceptions to this policy. Trip Book Guidelines: Entries in the trip book for trip-to-trip comparison shall be made as follows: 1. The displacement volume for each stand for the first five (5) stands of drill pipe and every five (5) stands of drill pipe thereafter. 2. The displacement volume for every stand of drill collars and HeviWate drill pipe. 3. Entries shall to be made based on the volume accuracy of the trip tank gauge (1/2 bbl or less). Flow Check Guidelines Flow checks and 10-10-10's are to be used as the primary indicators of an under balanced situation. Guidelines for conducting flow checks are as follows: 1. The well will be flow checked before making a connection. 2. The well will be flow checked after an indication of a pit gain. 3. The well will be flow checked after an indication of abnormal pressure. 4. The well will be flow checked after a drilling break over 5' on an exploration well or after a drilling break over 5' on a development well if expecting abnormal pressure or hydrocarbons in the zone. • A drilling break is generally defined as a doubling of the rate of penetration (ROP), but can vary depending upon the area. 5. Flow checks will be planned at intervals less than 100' when drilling with a top drive system in an abnormal pressure zone. 6. It should be stressed to the driller that the Company will support the driller's judgment when making additional flow checks (not included in these guidelines) or when shutting-in the well due to flow. Degasser Guidelines 1. The degasser will be operated whenever there is significant gas in the return flow stream, as indicated by a mud weight cut or chromatograph instruments readings in the logging unit. 2. The drilling fluid weight will be checked downstream of the degasser, as well as at the shaker, in order to determine if the degasser is working properly. 3. Dump the degasser suction and discharge tanks as often as practical to maximize utilization. 14.3 EQUIPMENT TESTING Pressure Tests The BOPs, choke and kill lines, choke manifold, floor safety valves, inside BOPs, and the top drive system/kelly safety valves are to be pressure tested in accordance with the following requirements: BOP Pressure Tests ACTIVITY BOP TESTING REQUIREMENTS 1) Initial BOP acceptance test (when the rig Test with water to 200 psi low and rated comes under contract) working pressure of preventer/equipment 2) Initial Installation on Wellhead if NOT Test with water to 200 psi low and rated fully tested to rated working pressure as WP of preventer/equipment or the per 1) above. wellhead, whichever is less. At least once per well the rams must be tested to their rated WP when the appropriate wellhead is installed. 3) Initial installation on wellhead if fully Test with water to 200 psi low. Test annular to 70% of rated working pressure or rated working tested to rated WP as per 1) above. pressure of wellhead, whichever is less. For 5k psi rams or lower, test rams/equipment to rated working pressure. For 10k psi rams or higher, test rams/equipment to a pressure that exceeds the maximum anticipated surface pressure but not less than 5k psi. At least once per well the rams must be tested to their rated working pressure when the appropriate wellhead is installed. Note: On wells governed by MMS rules, all rams/equipment must be tested to their rated working pressure or rated working pressure of wellhead, whichever is less (unless approved otherwise by District Supervisor). 4) After setting casing string AND prior to Same as 3) above. drilling out casing shoes. 5) Subsequent tests not exceeding every 14 Same as 3) above. On workovers governed by days. MMS rules, then test frequency is every 7 days instead of 14. 6) After disconnection or repair of any Test with water to 200 psi and rated working pressure containing seal but limited to the pressure of preventer/equipment or wellhead, affected component. whichever is less. Notes: 1. Regulatory requirements may require variations from the above and will govern, if more stringent. 2. Pressure tests will be alternated between control stations. After pressure testing from one control station, conduct a complete function test of the BOP at another other station. 3. The test pressures will be in accordance with the above or those specified in the Drilling Program. The pressures will be held stable for at minimum of 5 minutes on both the low pressure test and on the high pressure test or as specified in the Drilling Program. 4. The BOP equipment will be pressure tested when initially installed and at least every 14 days thereafter, as required by OIMS. The high pressure side of the choke manifold is to be pressure tested to the required BOP ram test pressure. The low pressure side of the choke manifold will be tested to its rated WP (OIMS Manual Section 6). The results of all BOP tests and any deficiencies and/or repairs will be recorded on the Daily Drilling Report and IADC Report. Detailed test data will also be recorded by the drilling contractor on a BOP test form designed specifically for the drilling rig. This report should be reviewed by the Operations Supervisor to ensure they are satisfied that sufficient data will be recorded to ensure confidence in the proper operation of the BOP equipment. The completed BOP test form is to be signed by the OIM and the Cementer and will be provided to the Operations Supervisor, along with the pressure recording chart supporting the BOP testing operation. All pressure charts are to be dated and properly labeled as to each component tested. All records pertaining to the BOP tests are to be retained on the drilling rig until completion of the well. The records are then to be forwarded to the Operations Superintendent for inclusion in the well file upon request. Function Tests The diverter system is to be function tested daily and the BOP system is to be function tested weekly. When conducting these tests, all closing and opening times required to function each component are to be recorded for comparison with previous tests. Do not pull out of the hole just to function test the BOPs. Diverter Tests Guidelines for testing diverters are as follows: 1. Response times required to open diverter valves and close the diverter bag around the drill pipe will be recorded and reported on the BOP test form. 2. After initial installation, all diverter lines will be pumped through at the maximum rate possible, to detect leaks, verify correct line up, and inspect for excessive vibration. 14.4 EQUIPMENT Equipment specifications for well control equipment are provided below. Deviations for less than the guidelines shown should be based on a risk assessment and should have both EMDC and Drilling Contractor management approval. Diverter Systems A "Diverter System" will be installed on all casing strings prior to the surface casing. The diverter system should conform to the following specifications: Diverter Design: 1. The diverter system shall consist of: • Annular type diverter packer • Diverter lines (2 lines, 10" ID min, 300 psi WP) • Remote Actuated Ball Valve on each line • Diverter valve 10" ID in the diverter line • Kill line inlet below the diverter (3" nominal) • Valve in the kill line 2. All diverter components (valves, lines, etc.) will be rated for a minimum of 300 psi working pressure. Valve actuators shall be sized to shut in against a minimum of 300 psi. 3. All diverter Valves shall be full opening (ball valves preferred). Diverter Closing System 1. Actuation of the diverter must be available from the rig floor and at least one other remote location away from the rig floor. All diverter functions must be available from these locations. 2. If hydro-pneumatic regulators are used, a nitrogen back-up is required. 3. Diverter Hydraulic Control unit must provide 1.5 times the usable fluid necessary to open the diverter valves and close the diverter annular and be capable of being operated from the main control panel and remotely from the Driller's console. BOP System A BOP stack and closing system shall be installed for all drilling and completion operations with annular and rams capable of shutting in on all drill pipe sizes in use for that hole section in accordance with the following specifications: Note: If Hydrogen Sulfide gas is expected, all BOP components and element seals must be certified for H2S service. BOP Stack 1. The BOP stack should be arranged as specified in the Surface Blowout Prevention and Well Control Equipment Manual. 2. BOP elements shall be compatible with the mud type in use. 3. Two rams are to be sized for the larger drill pipe and one ram for the smaller drill pipe if a two pipe size and/or tapered strings are used. Variable bore rams can be used to meet this criteria. The bottom ram shall be sized for the larger pipe size. VBRs cannot be used for the master ram. See Section 4.0 of the Surface Blowout Prevention and Well Control Equipment Manual for details and additional scenarios. 4. All rams, choke/kill lines, and choke/kill valves shall have a working pressure rating equivalent or greater than the wellhead working pressure rating. Annular shall have working pressure ratings of at least 50 percent of the ram preventers. 5. Ram and Choke/Kill line outlet placement shall provide the capability to: • Close in on the drill string and on casing or liner and allow circulation. • Close and seal on open hole and allow volumetric well control operations. • Strip the drill string using annular preventer. • Bullhead below the blind rams. 6. Choke outlets are to be minimum of 3" ID. 7. Use of clamps would require exception approval from the Field Drilling Manager. 8. Side outlets on ram bodies must be sealed with a blind flange (valves are acceptable only if they are pressure tested at the same frequency as the rams). 9. Rams must have locking capability (if locks are manual, a crank with a wheel must be available on the rig). 10. Rams must be capable of hanging off the maximum anticipated drill string load with the tool joints in use and maintain a seal against wellbore pressure equivalent to the ram body working pressure rating. VBRs are not recommended as the hang-off rams. If VBRs are to be used as the hangoff rams, the manufacturer's specifications will be checked for pipe size and hang-off load rating. Only "hang-off" type ram blocks, with a hardened area around the lip of the ram block, should be used. 11. Drilling spools must have at least the ID clearance and working pressure rating as that of the ram bodies. Choke and Kill Lines The Choke and Kill Lines shall be equipped with and have a working pressure rated at least equivalent to the BOP ram preventer rating. Other specifications as follows: 1. One hydraulic valve (e.g., fail-safe close) on the choke line adjacent to the BOP drilling spool. 2. One manual valve on the choke line between the hydraulic valve and the choke manifold. 3. One hydraulic valve and one manual valve on the kill line between the standpipe or pump manifold and the BOP drilling spool. 4. Choke lines shall have a minimum ID of 3". Kill lines shall have a minimum ID of 2". Wellhead 1. The "A" section shall have double valves on one outlet with working pressure at least equivalent to the "A" section top flange. 2. All wellhead sections shall have a flanged valve with a rated working pressure at least equivalent to the section top flange. 3. A second valve of the same working pressure shall be installed on any wellhead sections where the casing string suspended by the section is not cemented to the surface. Wellhead 4. All sections above the "A" section shall be equipped with a second outlet that has a blind flange installed on the outlet. 5. A pressure gauge shall be installed on all wellhead sections outside of the valves to facilitate monitoring of casing annulus pressure. BOP Control System BOPs shall be controlled by a Control System meeting the criteria listed below and must meet the following objectives: • Provide redundant control system. • Provide emergency back-ups in case of loss of rig air and/or electrical power. • Allow independent adjustable operating pressures to annular and other BOP functions. • Close each Ram Preventer within 30 seconds. • Close each Annular Preventer < 18-3/4" within 30 seconds and within 45 seconds for preventers 18-3/4". Surface Accumulator Bottles 1. A sufficient number of accumulator bottles will be installed, at a minimum, to meet EMDC's technical specifications, API RP 16D (Part I & II), and/or local requirements for accumulator unit sizing. See Section 5.0 of the Surface Blowout Prevention and Well Control Equipment Manual for details on EMDC requirements. NOTE: “API RP 16E as referenced in the BOP manual has since been recalled. The correct API reference for accumulator design is now API Spec 16D”. 2. The precharge pressure for all accumulator bottles will be verified upon mobilization of the drilling unit and approximately every 60 days thereafter. 3. Accumulator bottles shall be divided into at least two or more separate banks of generally the same number of bottles and each bank shall be capable of being separated by isolation valves. Accumulator Control Unit 1. Back-up pumps, driven by a different power source than the primary pumps (air driven when primary are electric drive) will be installed. 2. Each pump is to be capable of being isolated for repairs while the others remain operational. 3. The hydraulic fluid reservoir will be of adequate size to hold twice the required useable fluid capacity of the accumulator bottles. 4. Hydraulic fluid will be strained through 20 mesh or smaller suction strainers. 5. A double needle valve will be installed to bleed off manifold and accumulators into the reserve tank (needed to perform mini-checks). 6. The charging manifold will have a full opening, valved outlet for an external pump. 7. The manifold will be equipped with a pressure reducing regulator (0 to maximum allowable pressure) plus bypass and isolation valves. 8. Pressure relief valves will be installed upstream and downstream of the manifold regulator. 9. The entire system should be in an area which is readily accessible to rig personnel and protected from damage from other rig sources. 10. Check for type of alarm system installed. See required alarms below. Regulators 1. The control system will have surface regulators for manifold pressure. 2. A pneumatic back-up supply, independent of the rig air system, will be available for the surface regulators, unless the regulators are of the worm gear type or equivalent, to avoid losing supply pressure in the event of rig air failure. 3. The annular and manifold regulators will be set to a minimum of 1500 psi for normal shut-in. Refer to the manufacturers operating manual for information on additional closing pressure requirements for high expected shut-in pressures and annular pressures for larger sizes of pipe and casing. BOP Operating Panels 1. Two operating panels will be available, containing all BOP functions, one of which will be located at the accumulator control unit and the other on the drill floor. 2. All functions shall be kept in the power position and not in the block position. • Blind Ram function is to have a safety guard installed at all panels and at the accumulator unit control station to prevent inadvertent operation. The guard at the accumulator unit is not to interfere with remote operating capabilities. 3. If an electrical relay system is used, emergency generator power or a battery back-up system will be available to operate the remote panels for the accumulator unit. 4. If rig air is used, a back-up air supply will be available to operate the remote panels. 5. All functions on all operating panels will be clearly marked as to their purpose and position. 6. Unless a common alarm can be heard in both areas, the drill floor panel and the accumulator control unit will have alarms for: • Low accumulator pressure • Low fluid level in reservoir tanks • Loss of air supply Choke & Kill Manifold The choke and kill lines will be tied into a choke manifold and should conform to the following specifications: 1. The choke manifold will have the capability of taking returns through one of at least two (2) adjustable chokes of which one must be a hydraulic choke. 2. A minimum of two (2) valves will be upstream of each choke and one (1) valve between any other outlets on the manifold such as the standpipe manifold, trip tank bleed line, and the cement unit. 3. Chokes and gauges are to be equipped with and provide the following: • A manual back-up method of some type (e.g., back-up bottle of nitrogen, manual pump, etc.) will be available to power the hydraulic choke in case of rig air failure. • A control panel for the hydraulic choke(s) that has gauges to read the drill pipe pressure and casing pressure immediately upstream from the choke in operation. If the control panel has dual chokes, a casing pressure gauge will be available to monitor pressure upstream of each choke. • A choke panel which contains a gauge indicating choke position, gauges to read pump rate and cumulative pump strokes, and a control to zero the cumulative pump stroke counter. • A selection of calibrated gauges of various ranges that can help determine shut-in drill pipe and casing pressure accurately. 4. Adequate pressure sensors will be installed on the choke manifold and standpipe manifold to monitor the annulus and drill pipe pressure from all choke locations. 5. The pressure rating of all components (flexible hoses, valves, lines, pressure sensors, etc.) between the BOP and the high pressure valve downstream of the choke will have a working pressure rating equivalent to or exceeding the BOP ram preventer rating. 6. All turns in the choke and kill lines from the BOP to the choke manifold, within the choke and kill manifold, and lines downstream of the choke manifold will have targeted tees installed. 7. Manifold outlets will be configured such that well control fluids can be directed from the choke manifold to the following areas: • Mud Gas Separator • Shakers • Trip Tank • Directly overboard or to reserve pit bypassing the Mud Gas Separator Mud Gas Separator A mud gas separator will be installed and should conform to the following specifications: 1. Capable of venting gas to a downwind safe area and salvaging the drilling fluid when circulating through the choke manifold during a well control operation. 2. Provide a sufficient head to force gas out the vent line as well as separate gas from the drilling fluid. • See Surface Blowout Prevention and Well Control Equipment Manual (page 8-19 and 820 for details). 3. Vent line from the mud gas separator will have a minimum diameter of 8" and contain a minimum number of turns to reduce the gas friction pressure. 4. An inspection port will be available on the mud gas separator for visual inspection of the separator. During mobilization and after each use for well control, the separator should be drained, washed and visually inspected. 5. A by-pass valve will be installed which vents gas out a direct vent line and isolates the shale shaker room when the liquid leg is lost at the mud gas separator. The location of the by-pass valve should be upstream of the mud gas separator line to the shakers. 14.5 WELL CONTROL DRILLS General BOP Drill Guidelines Well control drills shall be conducted in accordance with the guidelines in this section to ensure that drilling personnel can detect and shut-in the well in the shortest time possible. Blowout preventer drills will be conducted until the procedure for shutting-in the well both while drilling and tripping is automatic. The drill crew members must detect a simulated well flow and react in the proper manner within the time limit required. A schematic of the BOP will be posted on the drill floor showing distances from RKB to the various BOP components. The Driller must know at all times the position of the drill string tool joint in relation to the BOP stack. The well will initially be closed-in using the Annular Preventer. To allow for a "fast shut-in", the first valve downstream of the hydraulic choke should be in the open position with the choke closed as well. Drills should be announced or unannounced to the drill crew and simulated by changing pit levels, trip tank levels, etc. However, the drilling contractor toolpusher on duty should be made aware of the drill prior to changing pit levels to avoid overreaction by the drill crews he is supervising. Trip Drill The purpose of this drill is to reduce the time required for the Driller to detect and react to an influx while making a trip. After the BOP is installed, this drill must be held with each crew until they are thoroughly familiar with the procedure and thereafter with each crew at a frequency specified by OIMS. While tripping and after the drill string has been pulled into the casing, without prior notice, the apparent trip tank level is to be gradually increased by manually raising the mud pit level float or verbally notifying the Driller from the Trip Tank Hand or the Mud Logging unit (if being used) that an increase in trip tank level has occurred. The Driller, Drill Crew, and Mud Loggers should recognize a 10 bbl trip tank gain within 1 minute and shut in the well within an additional 1 minute by performing the following: 1. Detect the kick and sound the alarm. 2. Record the time to detect the trip tank gain (goal is 1 minute or less). 3. Set the slips with a tool joint at the rotary table. 4. Shut down the trip tank pump and check for flow back into the trip tank. 5. Make up (hand tight) an open safety valve on the drill pipe. Close valve. 6. Check the well for flow. 7. Shut-in the well by opening the HCV valve and closing the anular BOP in one motion, torqueup safety valve. Make sure the choke manifold valve downstream of the power choke is closed. 8. Immediately notify ExxonMobil Drilling Supervisor and Toolpusher. Record the time to shutin the well after flow is detected (goal is 1 minute or less to minimize influx volume). 9. Install and make-up Inside BOP. Close the nside BOP. Open Safety Valve. (For stripping operations). 10. Record casing pressure and gain in trip tank. Check accumulator pressures. Check BOP system components and choke manifold for correct position. Check for leaks and/or flow. 11. Prepare to extinguish sources of ignition. Alert any boat standing by at the drilling rig. 12. Have crane operator standby for possible personnel evacuation. 13. Assess and review proficiency of drill with crew members. Log drill and reaction time on the Daily Drilling Report and IADC Report. Note: A typical drill would stop at Step #10, although the documentation under Step #13 would still be performed. Steps #11 - #12 may be performed for additional training and extended drills. Pit Drill The purpose of this drill is to reduce the time required for the Driller to detect and react to a change in the pit level. After the BOP is installed, this drill will be held with each crew until they are thoroughly familiar with the procedure and thereafter with each crew at a frequency specified by OIMS. While drilling on bottom, without prior notice, the apparent pit level is to be gradually increased by manually raising the mud pit level float or by pumping mud from the trip tank to the active system. The Driller, Drill Crew, and Mud Loggers should recognize a 10 bbl pit gain within 1 minute and shut in the well within an additional 1 minute by performing the following: 1. Detect the kick and sound the alarm. 2. Record the time to detect the pit level gain (goal is 1 minute or less). 3. Pick up the drill string until tool joint clears rotary table. Make sure tool joint is not in BOP. 4. Shut down the mud pump(s) and check the well for flow. (Use trip tank if in doubt about the well flowing). 5. If flowing, shut in the well by opening the BOP choke line valve (HCV) and closing the annular. 6. Report the pit gain and flow check results to the Operations Supervisor and Toolpusher. 7. Record drill pipe and casing pressures. Weigh mud in suction pit. Check accumulator pressures. Check BOP system components and choke manifold for correct position. Check for leaks and/or flow. 8. Complete the Well Killing Worksheet. Determine materials needed to circulate out the kick. 9. Prepare to extinguish sources of ignition. Alert any boat standing by at the drilling unit and/or have security block off the area if on a land rig. 11. Have crane operator standby for possible personnel evacuation if on a jack-up. 12. Assess and review proficiency of drill with crew members. Log drill and reaction time on the Daily Drilling Report and IADC Report. Note: A typical drill would stop at Step #6, although the documentation under Step #12 would still be performed. Steps #7 – #11 may be performed for additional training and extended drills. Power Choke Drill Crews are encouraged to conduct power choke drills prior to drilling-out after setting of each casing string. The drill provides practice for the Drilling Supervisor, Toolpusher, and crew members in operating the power choke. If done from a floating rig, it is an opportune time to measure the choke line and kill line friction pressures at various kill rates. The drill should be performed as follows: 1. Circulate the well clean. 2. Conduct a Pit Drill and close in the well using the Annular BOP. 3. Take slow circulation rates at 20, 30, and 40 spm down the drill pipe and out the choke line with the hydraulic power choke fully open (optional step if already accomplished). 4. Conduct crew training using the power choke. Bring the pump on lie while keeping the casing pressure constant to desired pump speed. The casing pressure can be varied to illustrate the time required for the pressure pulse to travel down the annulus and back up the drill pipe pressure gauge. 5. Assess drill and use of hydraulic choke with crew members. 6. Record the drill, slow pump rates/pressures, and mud weights used on the IADC and Daily Drilling Report. 14.6 WELL CONTROL PROCEDURES Laminated copies of rig specific shut-in procedures shall be posted on the rig floor near the Driller's console. Rig specific station bills, listing duties of the crew members, will also be posted on the drill floor and/or bulletin board. During all well control operations, the following rules will be strictly observed. 1. Smoking will be limited to the quarters area. Violators will be subject to immediate dismissal. 2. Welders will not perform any work without specific instruction and direct supervision by the Senior Drilling Contractor toolpusher and such work must be cleared with the Operations Supervisor in advance. 3. All grinders, needle guns, etc., will be shut down. 4. Off-duty and personnel that are not required will remain in the quarters area or at a designated muster area. 5. If any of the following occur, the rig site is to be immediately abandoned: • Gas surfaces uncontrolled at the rig floor • Well fluids broach around the casing • Well flow is detected with no diverter or no BOP installed. 6. A pre-job safety meeting will be held with all involved personnel prior to attempting a well kill operation. Diverter Installed Successfully diverting a well flow before gas surfaces and without broaching requires that all surface equipment be ready to close the diverter bag immediately yet have a relief path for the well fluids to prevent broaching. While drilling with a Diverter System using a Remote Operated Ball Valve, the valve open function should be plumbed into the diverter close line such that the valve will open prior to the annular closing. Mud should be pumped through the diverter lines every tour to ensure the line and relief path are not plugged. If flow is detected, the following procedure should be followed to divert the flow: 1. Shut down the mud pumps if drilling. 2. Pick up to clear the kelly or tool joint above the diverter bag. 3. Check for flow if uncertain well is flowing. 4. Close the diverter annular. 5. Evacuate personnel to a safe area. 6. Notify the Operations Superintendent. 7. If conditions allow, attempt a dynamic kill by pumping all available mud from the pits followed by water from the water pit if the mud does not kill the well. Pumping will also keep the gas flow wet and reduce the fire hazard. Note: If tripping, running casing, or out of the hole, it may be necessary to strip back to bottom prior to attempting the dynamic kill. 8. Personnel should be posted around the site to detect any signs of broaching. BOP Operations The well control procedures in this section are applicable when drilling below surface casing with a competent shoe and a BOP stack installed. The Operations Supervisor shall make sure the following is in place: • Flowcharts are posted on the rig floor and other appropriate locations for "Shut-In Procedures for Drilling, Tripping, & Running Casing" and the "Station Bill during Well Control Operations" • The Choke Manifold is lined up to take returns through the "Mud Gas Separator" • The valve downstream of the hydraulic choke is in the closed position during drilling operations. Flowcheck Procedure - Drilling 1. The well is to be checked for flow if any of the following occur at anytime during drilling or circulating operations: • Increase in Rate of Penetration. • Increase in Mud Return Flow. • Gain in Pits. • Decrease in Pump Pressure and/or Gain in Pump Strokes. • High Gas Units. • Sudden Increase in Torque. • Increase in mud chlorides. • Decrease in mud chlorides. 2. The following procedure is to be used to check for flow: • Pick up the drill string and position a tool joint at the pre-determined shut-in position. • Shut down the mud pump(s) • Check the well for flow. Use trip tank if in doubt about the well flowing. Shut-In Procedure - Drilling Whenever flow is detected, the Driller is to shut-in the well on his own initiative without any further approval in the following manner: 1. Open the remote choke line valves on the Choke line. 2. Close the annular preventer. 3. Make sure that the Choke Manifold is closed downstream of the power choke. 4. Record the shut-in drill pipe and casing pressures, and pit level gain. 5. Notify Operations Supervisor and Toolpusher as soon as practical. 6. Check accumulator pressures. Check BOP system components and confirm that the choke manifold is lined up properly. Check for leaks and/or flow. 7. Record drill pipe and casing pressure every minute until the pressures stabilize then every 10 minutes thereafter. 8. Complete the 'Well Killing Worksheet'. Select kill method and determine materials needed to circulate out the kick. 9. Adjust regulator pressure on annular preventer. Reciprocate pipe, if possible, to avoid sticking. 10. Prepare to extinguish sources of ignition. Flowcheck Procedure - Tripping 1. The well is to be checked for flow if any of the following occur at anytime during tripping operations: • Hole not taking the correct amount of fluid. • Gain in trip tank. 2. The following procedure is to be used to check for flow: • Set the slips with a tool joint at the rotary table. • Make up an open safety valve on the drill pipe. Close valve. Note: When drilling with a TDS, do not make up the top drive into the drill string. Removing the lower valve in the top drive is time consuming and requires a 65/8 Reg box x 4-1/2" IF box crossover. 3. Observe the well for flow. If there is any question as to whether the well is flowing, it should be shut-in and checked. Shut-In Procedure - Tripping Whenever flow is detected, the Driller is to shut-in the well on his own initiative, without any further approval, in the following manner: 1. Shut down the trip tank pump. 2. Open the remote choke valve in the choke line. 3. Close the annular preventer around the drill pipe or drill collars. 4. Install and make up inside BOP on top of the safety valve. 5. Open the drill pipe safety valve. 6. Notify Operations Supervisor and contractor toolpusher as soon as practical. 7. Record shut-in casing pressure. Record trip tank and/or pit gain. Check accumulator pressures. Check accumulator pressures. Check BOP system components and choke manifold for correct position. Check for leaks and/or flow. 8. Adjust the annular closing pressure and reciprocate drill pipe to prevent pipe from sticking. Note: If the casing has pressure and/or the well will flow through the drill pipe, it will be necessary to strip the drill pipe back to bottom before circulating out the influx. See Stripping Guidelines and Procedure for additional information. Shut-In Procedure (Drill Collars across BOP stack) 1. Install a crossover and make up a safety valve if drill collars are above the rotary table. 2. Initiate shutting-in the well using the same procedures as for drill pipe. 3. Increase annular closing pressure if necessary to obtain a seal around spiral drill collars or spiral HeviWate drill pipe. Shut-In Procedure (Drill String Out Of Hole) 1. Close the blind rams if the well begins to flow while the drill string is out of the hole. 2. Open choke line valves on first outlet below the blind rams. Monitoring will not be possible through the choke line on BOP stack configurations where the blind ram is located below the choke and kill line. This would require monitoring pressure through the annulus valves. 3. Record shut-in casing pressure and gain in trip tank. 4. Notify Operation Supervisor and Contractor toolpusher. 5. Prepare to strip into the hole using the annular. See Stripping Guidelines and Procedures. Flowcheck Procedure - Running Casing 1. Check the well for flow should one of the following occur at anytime during casing running operations: • Annulus flowing. • Gain in pits greater than casing/pipe displacement. 2. Stop casing running operation. 3. Check for flow. Shut-In Procedure - Running Casing 1. Open the remote choke valve in the choke line. 2. Close the annular preventer. • The annular closing pressure should have been adjusted for the larger OD pipe prior to starting to run casing. 3. Install a crossover and make up a safety valve. Note: If the casing float equipment leaks, it may be necessary to open the annular temporarily to relieve flow form the casing while install the safety valve. Well Killing Options - Running Casing There are several possibilities for killing the well, dependent upon the amount of casing run, amount of well flow, condition of the float equipment, and the annulus pressure. The option selected should be based on actual wellbore conditions, after consulting with the Operations Superintendent. Options include the following: 1. Strip casing out of hole. 2. Kill the well at the present casing depth. 3. Strip casing into the hole on drill pipe. Fluid Weight/Circulating Rate Fluid Weight 1. The fluid weight for circulating out influxes and killing wells is to be selected after consulting with the Operation Superintendent, when practical, as to which of the following methods to use based on actual wellbore conditions: • Drillers Method - Circulate out the influx using the original weight fluid, then circulate kill weight fluid around. The major advantages of this method are relative speed and simplicity. However, this method will result in a higher maximum surface pressure. If insufficient barite is on hand to weight up the fluid, this method should generally be used rather than suspending operations until barite becomes available. • Weight and Wait Method - Circulate out the influx in one circulation using a balanced fluid weight. This method generally results in the lowest surface pressure and minimizes the time lost by returning to normal drilling operations as soon as possible if a sufficient volume of heavier fluid is available on the Drilling rig and ready to pump. In some instances, the time necessary to weight up the fluid can be excessive. 2. Mixing rate capabilities of the drilling rig are to be considered. Generally, incremental mud weight increases should be 1.0 ppg or less. 3. The final kill weight fluid is to have a minimum trip margin of about 200 psi depending on the well. Higher trip margins may be necessary for wells with swabbing problems, etc. Circulating Rate Selection: 1. The circulating rates for the well kill operations are to be selected after consulting the Operations Superintendent, when practical. A pump rate in the 1 to 3 BPM range should typically be used for circulating out an influx. The advantages of such a low pump rate are: • Allows More Time for the Choke Operator to Adjust the Choke. • Minimizes the Handling of Large Volumes of Gas at the Surface. • Reduces the Possibility of Lost Returns. 2. Factors such as formation integrity at the casing shoe and rig well control equipment (e.g., limitations of the mud gas separator) are to be considered when selecting a circulating rate. 3. The pump rate should be reduced, if necessary, when gas reaches the surface to prevent loss of the liquid leg in the mud gas separator. 4. When necessary to change circulating rates, the well is to be shut-in and a new friction pressure determined. Constant Bottom Hole Pressure Method Well Kill Procedure The objective of circulating out influxes is to maintain a constant bottom-hole pressure sufficient to prevent further influxes while minimizing lost circulation at the casing shoe. Following are steps to achieve this goal. 1. With hydraulic choke closed, open the valve downstream of the choke to allow returns to be taken from the choke line through the choke manifold and into the Mud Gas Separator. 2. Bring the pump up to speed slowly to the planned circulation rate. Use the hydraulic choke to hold a constant casing pressure on the annulus equal to the original shut-in pressure on the casing plus a 25 to 50 psi safety margin. 3. Read and record drill pipe pressure after the pump reaches the desired constant speed and after casing pressure stabilizes to the desired value. Note: The drill pipe pressure at this point is the pressure necessary to maintain a constant bottom-hole pressure when circulating at that particular pump speed only. The difference between the initial shut-in pressure on the drill pipe and the pumping pressure on the drill pipe is the friction pressure necessary to circulate drilling fluid at that particular pump speed only. 4. Maintain the desired drill pipe pressure at the constant pump rate while circulating out the influx by manipulating the hydraulic choke taking returns from the annulus. • Changes in pressure due to choke manipulation require approximately 2 seconds per 1000' of drill string to register on the stand pipe gauge; however, this lag in response time can be longer if a large gas kick is present. • If original mud weight is used, the drill pipe pressure will be held constant at its reaches the bit. • Be prepared at all times to divert the flow overboard or to the flare as the poor-boy degasser may not be able to safely handle 100% gas. 5. Circulate using the desired fluid weight increments until kill weight mud is circulated around and it is verified that the well is dead. Use caution at all times since additional influxes could enter the wellbore. Stripping Operations This section is applicable after making the decision to strip in the hole in order to perform a kill operation during a well control incident. Stripping Preparation Guidelines: 1. A pre-job meeting is to be conducted with members of the stripping team. 2. Job assignments are to be reviewed and responsibilities designated with each individual on the stripping team. 3. The stripping procedure is to be reviewed and calculations are to be performed for the capacity and displacement of the drill string for the stripping operations. 4. Ensure that an easy-to-read and accurate pressure gauge is installed on the choke manifold. 5. Ensure that a visual communication system between the person operating the choke and the person monitoring the trip tank has been established. 6. Ensure that everything is ready to take returns from the choke manifold through the mud gas separator and into the trip tank. Do not bleed returns into cementing displacement tanks. General Stripping Guidelines: 1. Only strip in the hole if the buoyed weight of the drill string is greater than the upward force from the wellbore when the drill string is across the BOP stack. 2. Utilize lubrication techniques if the buoyed weight of the drill string is less than the upward force from the wellbore. 3. Monitor well bore pressures and control the surface pressures using the bubble migration technique/procedures while rigging up to strip in the hole. 4. Install a non-ported float valve in the bit sub if the drill string is completely out of the hole. 5. Make up additional drill collars, if necessary, for weight to strip in the hole. 6. Install an inside BOP between any drill collars and the drill pipe or above the bit sub if not using drill collars. Note: It is only possible to run wireline tools down to the top of the inside BOP. 7. If out of the hole, trip in the hole and position the bit between the annular BOP and the closed blind rams. 8. Bullhead a higher weight drilling fluid down the choke and kill lines to lower the shut-in casing pressure and reduce the upward force from the wellbore if necessary. 9. Close the annular preventer and pressure up the drill string with the cementing unit to the equivalent casing pressure. 10. Open the blind rams. 11. Bleed off the drill pipe pressure to ensure that the inside BOP is holding. 12. Reciprocate the drill string slowly if in open hole in order to prevent the pipe from sticking while rigging up to strip. 13. Reduce the closing pressure on the annular preventer as necessary in order to minimize wear on the element while reciprocating the drill string. 14. Rig up to the safety valve and obtain the drill pipe pressure prior to stripping if the drill string has a ported float valve. Note: Ensure the drill pipe safety valve is opened prior to stripping in the hole. 15. Always use the safety valve on the rig floor and not the top drive when shutting in the well on a trip. After installation of the safety valve, ensure that a backup valve is on the rig floor before stripping operations begin. Stripping Procedure: 1. Record the shut in casing pressure. 2. Install the inside BOP and open the safety valve. Note: Do not forget to open the safety valve. 3. Fill the drill pipe with a gel pill above the inside BOP to prevent trash in the drill string from plugging the valve. 4. Make up a stand of drill pipe and slowly trip in the hole. 5. Apply pipe dope to each tool joint body to ease passage through the annular preventer. 6. Use minimum closing pressure on the annular preventer during the stripping operation. 7. Monitor the flow line for any leakage from the annular preventer while stripping in the hole. Note: Some leakage from the annular preventer is desirable to increase lubrication between the annular rubber and the drill pipe. 8. Read and record the casing pressure before starting to lower each stand of drill pipe. 9. Slowly bleed returns from the wellbore using the hand adjustable choke in order to maintain the following, whichever occurs first: • A returns volume which is equal to the capacity and displacement of the pipe being stripped into the hole, OR: • A casing pressure which is equal to the pressure recorded prior to stripping the stand in the hole, OR: • Gas is returned at the choke. Note: Fluid is sometimes lost to the formation resulting in reaching a casing pressure that is equal to the recorded pressure at the start of the stand, before a returns volume equal to the capacity and displacement of the pipe can be bleed. Note: Do not bleed off gas. 10. When gas reaches the surface, maintain the casing pressure constant and continue to strip into the hole until the bit is back on bottom. 11. Kill the well using the Constant Bottom Hole Method. Note: It may not be necessary to increase the weight of the drilling fluid to kill the well if the influx to due to swabbing unless the trip margin is insufficient for safe tripping. Well Control for Wireline Operations Procedures and requirements for additional equipment for well control during wireline operations are usually generated by the affiliate drilling team, unless local regulatory specifications are in effect. In many cases the well is completely stable with the mud weight in use at the time logging operations occur and no lubricator system is required. Since the annular preventer may not totally close off the wellbore with wireline in the hole, wirecutters should be available to cut the wire, if required. Each operational team should plan for this possibility, including securing the surface cut section of wire, if possible, to prevent wire run away after the cut. Lubricator systems should be considered where well flows might occur during the logging runs. Areas with open productive zones (particularly high-pressure gas wells), environmentally sensitive areas, and areas with significant H2S concentrations could be considered for the use of lubricators, that can cover the entire logging tool string. The lubricator is usually made up to a pump-in sub and riser assembly that is anchored across a closed element of the annular preventer or flanged to the top of the annular preventer. If the well starts to flow while the logging tool is in the hole, the tool string is pulled into the lubricator and the blind rams are shut to isolate the wellbore. Pressure is then bled off the lubricator and wireline equipment safely rigged down. Barite Plugs In most cases, the goal of using a barite slurry is to kill the well using a hydrostatic pressure greater than the formation pressure. The following three characteristics of barite plugs are the result of an analysis of industry experience and laboratory studies: 1. High density and good pump ability are the most important parameters to consider when designing a heavy kill slurry. 2. The settling of barite from a barite plug is a slow process that is usually of little value in most well control incidents. 3. Lignosulfonate is the best deflocculant to use when designing the slurry for barite to settle. Barite Plug Preparation Guidelines: 1. Plan in advance for use of a barite plug as part of the drilling operation. 2. Ensure that the necessary materials are available during the planning phase to help minimize confusion during the plug setting operation. 3. Ensure that each cementing operator is familiar with the problems of mixing and pumping a barite plug. 4. Design a tentative plan for mixing, pumping, and displacement of the barite slurry. 5. Utilize drilling Contractor personnel's expertise during the planning phase as necessary. 6. Ensure that there is a removable crossover line in place to ship barite from the bulk tanks to the cement unit if plugging occurs. 7. Ensure that a barite deliverability test to the cementing unit is performed prior to attempting to set a barite plug. Barite Plug Mixing Guidelines: 1. Use either the "Settling Recipe" or "Non-Settling Recipe" shown below when mixing a barite plug. SETTLING RECIPE 1 2 bbl Water (fresh or seawater) Lignosulfonate lb. Caustic; pH = 10.5 - 11.5 15 lb. 15 lb. NON-SETTLING RECIPE 1 bbl Water (fresh or seawater) Lignosulfonate 2 lb. Caustic; pH = 10.5 - 11.5 1 lb. XC Polymer As requiredDefoamer These recipes are for one barrel of mix water. 2. Consider using the "Non-Settling Recipe" for large kill operations. 3. Prepare the mix water prior to adding the barite. The mix water requirement is 54 % of the final slurry volume. 4. Prepare a 21 ppg barite slurry by mixing 700 lbs of barite with 0.54 bbl of mix water. Mix the non-settling recipe by recirculating it through the mixing hopper several times if necessary. Barite Plug Pumping Procedure: 1. If possible, the same Drill Crew is to be used during mixing or displacing of a barite plug (do not change the Drill Crew until operations are complete). 2. A chiksan swivel is to be installed on the drill pipe safety valve and sufficient chiksans are to be rigged up to reach the cementing manifold. Do not pump through a kelly or top drive system (TDS) when using the "Settling Recipe" for a barite plug. 3. A bypass line is to be installed in order to discard the initial barite slurry. 4. All connections are to be pressure tested from the mixing pump to the drill pipe safety valve. 5. The manifold valves are to be lined up as necessary in order to use the rig pumps for displacement of the plug in case the cementing pump fails or the line plugs. • It is necessary to keep the barite plug moving at all times while in the drill pipe to prevent plugging. 6. The valves on the cementing unit fill up line are to be tested for leaks and to ensure they function properly. 7. Ensure that a pressurized mud balance is used to weigh the slurry. 8. The safety valve on the drill pipe is to be closed and the bypass line opened in order to discard the barite slurry, until obtaining the correct weight. 9. Begin mixing and pumping the barite slurry to the bypass line. 10. Close the bypass line and open the safety valve after measuring the correct slurry weight at the bypass line. 11. Zero the barrel counter and continue mixing the slurry using the cementing unit and cement displacement tanks. 12. Displace the barite plug without shutting down. Note: Actual displacement volume depends on whether it is possible to pull out of the plug or if the pipe is stuck. 13. Displace the barite slurry at a rate fast enough to get pumping pressure at the stand pipe. The heavier barite in the drill pipe will tend to fall, and it is desirable to keep up with it by pumping at a fast enough rate to produce pump pressure at the stand pipe. 14. Pull the drill pipe out of the barite plug after the barite plug is in place. The chance of successfully pulling out of a barite plug using the "Settling Recipe" is small. Pulling Pipe Procedure - Barite Plug: 1. The Drill Crew is to be in position to immediately pull out of the barite plug as soon as the displacement is complete. 2. Do not take the time to break out the safety valve and swivel before pulling out of the plug. Ensure that another safety valve is available on the rig floor. 3. Pull as fast as possible, consistent with the amount of drag, and rotate the pipe in the slips while standing back each stand. 4. Pull the pipe at least 10 stands above the calculated barite plug top. 5. Circulate bottom up the "long way" after pipe is above the plug at least 10 stands. 6. Wait approximately 8-10 hours before tripping back in the hole and tagging the top of the barite plug in order to be certain that plug is in place. ExxonMobil Development Company Drilling CREW STATION BILL AND RESPONSIBILITIES DURING WELL CONTROL OPERATIONS DRILLER 1) Detect wellbore influx and sound alarm. 2) Pick up drill pipe to proper space out position. 3) Shut down mud pump(s). 4) Check or verify that the well is flowing. 5) Open lower choke valve. Close annular. 6) Notify Operations Supervisor and Toolpusher. 7) Check accumulator pressure. Ensure that the well is properly shutin. ASSISTANT DRILLER (if applicable) 1) Ensure hydraulic choke is closed. 2) Check that the first manual valve downstream of choke is closed. 3) Check remainder of choke manifold for proper alignment. 4) Report to Driller. 5) Begin recording drill pipe and casing pressures. 6) Standby for further instructions from Driller. DERRICK MAN 1) Record pit level and gain. 2) Mark new pit level. 3) Weigh drilling fluid in pits. 4) Check relief valve(s) on mud pump(s) for flow back from the well. 5) Report Drilling fluid weight and active pit gain to Driller. 6) Prepare to weight up mud system. 7) Standby for instructions from Driller. SHAKER HAND 1) Check well for flow at shakers. 2) Report to Driller. 3) Check drilling fluid weight at shakers. 4) Monitor return line from choke manifold and flowline. 5) Standby for instructions from Driller. FLOOR HANDS 1) Standby rotary to mark pipe for proper space out. 2) Standby for further instructions from Driller. 3) Install safety valve (as required) and close same. DRILLING OPERATIONS SUPERVISOR 1) Check to assure well is properly shut-in. 2) Check well pressures and pit gain. 3) Develop well kill plan. 4) Call Drilling Operations Superintendent. TOOLPUSHER 1) Supervise Driller after well is shut-in. 2) Check to assure well is properly shut-in. 3) Monitor drill pipe and casing pressures. 4) Notify Chief Mechanic, Electrician, and Crane Operator. 5) Prepare equipment for well kill operations. CRANE OPERATOR 1) Assemble roustabout crew. 2) Standby to assist in well control operations. 3) Coordinate barite material movement. MUD ENGINEER 1) Check pit volumes, verify mud weight, and report to Derrick Man. 2) Determine barite necessary to increase mud weight. 3) Standby to assist Derrick Man. MECHANIC/ELECTRICIAN 1) Check closing unit. 2) Check accumulator pressure. MUD LOGGERS 1) Monitor pump strokes, gas units, and pit levels. 2) Work up kill sheet. OPERASI STANDAR MANUAL JACK-UP / PLATFORM / TONGKANG RIG DRILLING DAFTAR ISI OPERASI STANDAR MANUAL JACK-UP / PLATFORM / TONGKANG RIG DRILLING DAFTAR ISI OPERASI STANDAR MANUAL JACK-UP / PLATFORM / TONGKANG RIG DRILLING DAFTAR ISI OPERASI STANDAR MANUAL JACK-UP / PLATFORM / TONGKANG RIG DRILLING DAFTAR ISI OPERASI STANDAR MANUAL JACK-UP / PLATFORM / TONGKANG RIG DRILLING DAFTAR ISI OPERASI STANDAR MANUAL MARINE OPERASI JACK-UP / PLATFORM / TONGKANG RIG DRILLING MARINE OPERASI MARINE OPERASI DAFTAR ISI MARINE OPERASI INFORMASI UMUM MARINE OPERASI INFORMASI UMUM BAGIAN 3 â € "LAMPIRAN G III OPERASI UMUM OPERASI UMUM OPERASI UMUM OPERASI UMUM MATRIX RISIKO EMDC OPERASI UMUM OPERASI UMUM MATRIX RISIKO EMDC OPERASI UMUM MATRIX RISIKO EMDC BAGIAN 3 â € "LAMPIRAN G III OPERASI PENGEBORAN OPERASI PENGEBORAN OPERASI PENGEBORAN BIT KLASIFIKASI DAN hidrolika BIT KLASIFIKASI DAN hidrolika DRILLING SISTEM FLUIDA DRILLING SISTEM FLUIDA MARINE OPERASI MARINE OPERASI MARINE OPERASI PEMBENTUKAN EVALUASI PEMBENTUKAN EVALUASI CASING & LINER OPERASI CASING & LINER OPERASI Penyemenan Penyemenan Remas PROSEDUR EMDC DRILLING Remas PROSEDUR EMDC DRILLING TES TEKANAN INTEGRITAS TES TEKANAN INTEGRITAS PENGUJIAN PRODUKSI PENGUJIAN PRODUKSI PLUG DAN DITINGGALKAN PLUG DAN DITINGGALKAN BAIK KONTROL BAIK KONTROL Pengemban gan Pengeboran OPERASI STANDAR MANUAL untuk JACK-UP / PLATFORM / TONGKANG DRILLING Edisi Pertama Mei 2003 UNTUK PERUSAHAAN SAJA Houston, Texas USA a a E n x x o n PO Box 4876 Houston, TX 77210-4876 M o b Pengem ent i l P e n g e m b a n g a n P e r u s a h Mei 2003 E M D C Pe ng eb or an St an da r O pe ra si on al M an ua l un tu k Ja ck U p/ La nd as an / Ba rg e Dr illi ng Untuk: ExxonMobil Drilling Karyawan Manual tertutup adalah Edisi Pertama kami EMDC Drilling Standar Operasi Manual untuk Jack-Up / Landasan / Barge Drilling. Panduan ini menggantikan Transisi Versi 1 pengguna tanggal Oktober 1999. Banyak perubahan dan upgrade telah dilakukan untuk panduan ini didasarkan pada komentar dari Tim Bor dan Pengeboran Grup Dukungan. Pengantar manual menjelaskan bagaimana pengguna akan digunakan dalam operasi kami. Singkatnya, manual: 1. memberikan pedoman untuk melakukan operasi pengeboran menggunakan jack-up, platform yang dan tongkang rig, 2. digunakan dalam hubungannya dengan program-program khusus baik dan prosedur manual lainnya, termasuk OIMS dan SMP, untuk memberikan kerangka dasar dan prinsip-prinsip yang diperlukan untuk perencanaan dan pelaksanaan operasi pengeboran, dan 3. harus ditinjau dan dipahami oleh semua personil dri pengisian. Penting untuk dicatat adalah bahwa perubahan yang signifikan (perubahan yang meningkatkan kesehatan, keselamatan, masyarakat, risiko lingkungan atau keuangan) dari manual memerlukan persetujuan dari Operasi Inspektur dan / atau Bidang Pengeboran Manager. Juga, pedoman dalam manual harus tepat dihubungkan dengan orang-orang yang ditetapkan oleh Kontraktor Pengeboran dan konflik ditangani oleh Operasi Inspektur. Lampiran khusus termasuk dalam setiap bagian dari manual untuk tim bor untuk menyesuaikan manual untuk daerah operasi mereka. Tab untuk lampiran ini diberi label â € œGâ € untuk informasi umum dan bentuk / dokumen yang digunakan perusahaan lebar dan â € Oesa € untuk informasi spesifik dan bentuk / dokumen yang unik untuk tim bor individu. Kami menghargai waktu dan usaha oleh Tim Bor dan Pengeboran Kelompok Dukungan dalam meninjau dan mengomentari draft manual. Lebih dari 150 komentar diterima dengan sekitar 90% diadopsi di manual baru. Komentar yang tersisa disebut permintaan untuk memasukkan praktek-praktek lokal, bagian dalam draft manual yang telah dihapus, komentar umum dengan tidak ada perubahan yang disarankan, item tidak berlaku untuk panduan ini, dan jumlah yang sangat sedikit dari item tidak setuju untuk. Untuk menutup loop, Tim Bor yang menyarankan perubahan tidak setuju akan menerima umpan balik. Panduan ini akan direvisi dan ditingkatkan sesuai dengan proses revisi di OIMS manual. Secara umum, proses ini akan melibatkan penelaahan komentar yang diterima dari Tim Bor, review tahunan MOCS, dan ulasan secara berkala. Silahkan mengambil waktu untuk meninjau panduan ini dan memahami pedoman yang tertuang dalam. Tanda tangan pada berkas tanda tangan pada berkas Tanda tangan pada file____ DR Anglin JW Kiker CW Sandlin Manajer Operasional Manajer Operasional Manajer Operasional Anak Perusahaan ExxonMobil KATA PENGANTAR ExxonMobil Development Company, Operasi Standar Manual untuk Jack-Up / Landasan / Barge Pengeboran telah disiapkan untuk memberikan pedoman untuk melakukan operasi pengeboran menggunakan jack-up, platform yang dan rig tongkang di ranah ExxonMobil Pengeboran ini kegiatan. Ini manual, digunakan bersama dengan Drilling baik-spesifik dan Program Penyelesaian dan manual prosedural lainnya, termasuk Manual Drilling OIMS dan Program Manajemen Keselamatan Manual, akan memberikan kerangka dasar dan prinsipprinsip yang diperlukan untuk Operasi Supervisor dan Pengeboran Insinyur untuk perencanaan dan pelaksanaan operasi pengeboran. Karena variabel yang mungkin banyak dan kondisi yang dapat terjadi, manual ini tidak dapat menggantikan pengetahuan dan penilaian yang baik dari personil pengeboran kunci pada rig pengeboran atau di kantor. Pedoman yang tertuang dalam manual ini adalah urutan logis dari langkah yang diperlukan untuk efisien melakukan operasi pengeboran dengan cara yang aman dan ramah lingkungan pada skala global sementara menyalahi peraturan yang berlaku. Meskipun banyak referensi untuk hukum dan peraturan AS telah dihapus dari versi sebelumnya karena maksud global manual ini, beberapa tetap sebagai contoh dan mungkin berharga untuk operasi internasional. Pedoman yang terkandung harus ditinjau dan dipahami oleh semua personil pengeboran terlibat. Sesuai dengan OIMS "Manajemen Perubahan" elemen, perubahan yang signifikan (perubahan yang meningkatkan kesehatan, keselamatan, masyarakat, lingkungan atau risiko keuangan) dari pedoman ini tidak akan dilakukan tanpa persetujuan tertulis dari Operasi Inspektur dan / atau Bidang pengeboran Manager. Pedoman yang tertuang dalam manual ini juga harus tepat dihubungkan dengan orang-orang yang ditetapkan oleh Kontraktor Pengeboran dan terkandung dalam manual operasi Drilling Kontraktor. Konflik prosedural diidentifikasi harus ditangani oleh Operasi Inspektur dan resolusi apapun yang dihasilkan harus disediakan untuk Operasi Pengawas. tugas dan tidak boleh dibuang hanya untuk mengikuti langkah yang digariskan dalam setiap proses atau prosedur Lampiran khusus termasuk dalam setiap bagian dari manual untuk tim bor untuk menyesuaikan manual untuk daerah operasi mereka. Tab untuk lampiran ini diberi label â € œGâ € untuk informasi umum dan bentuk / dokumen yang digunakan perusahaan lebar dan â € Oesa € untuk informasi spesifik dan bentuk / dokumen yang unik untuk tim bor individu. Pertama Edition - Mei 2003 Pengguna harus dijaga saat ini dengan termasuk direkomendasikan perbaikan / perubahan sesuai dengan proses perubahan yang dijelaskan dalam EMDC Drilling OIMS Manual. Secara umum, proses ini akan melibatkan penelaahan komentar yang diterima dari Tim Bor, review tahunan MOCS, dan ulasan secara berkala. Proses ini sangat penting dalam menjaga Pengeboran mengikuti ide-ide baru, kemajuan teknologi dan perubahan peraturan. Panduan ini disusun dalam upaya untuk menggabungkan praktek-praktek terbaik dari tim bor kami ke dalam satu manual. Meskipun memang mengandung sedikit informasi yang baik dari berbagai sumber, tidak mengandung semua informasi yang dibutuhkan untuk mengebor sumur bor dan lengkap dalam segala situasi. Penilaian yang baik baik harus selalu dilakukan dalam setiap OPERASI PENGEBORAN MANUAL â € "JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 1 CREDO SAFETY Kami, Manajemen dan Karyawan ExxonMobil Development Company: Tanpa henti akan mengejar tujuan akhir kami dari tempat kerja bebas cedera dan penyakit Tidak akan berkompromi fokus kami pada keselamatan untuk mencapai setiap tujuan bisnis lainnya Dan Kami Percaya: Tindakan keamanan kami yang paling efektif ketika kita benarbenar peduli tentang satu sama lain Setiap dari kita memiliki tanggung jawab pribadi untuk keselamatan kita sendiri dan y safet orang lain - baik di dalam dan di luar pekerjaan Semua cedera dan penyakit dapat dihindari ketika kita mempraktekkan perilaku yang aman 1. INFORMASI UMUM 3. Tekanan Pemantauan casing 14 2. Operasi Pengeboran manual 1 4. Kembali Katup Tekanan 14 3. Organisasi 2 5. Rotary Table Insert Bushing Kunci 14 4. Laporan EMDC 3 6. Pohon Natal Peralatan 14 5. Laporan Kontraktor Pengeboran 6 7. Unit Mud Logging 15 6. Layanan Pihak Ketiga Kontraktor Laporan 9 7. OPERASI UMUM 8. Administrasi kontrak 1 9. Prespud Rapat 2 10. Keamanan 3 11. Tanggung Jawab EMDC Drilling Operations Personil 3 12. Personil Kontraktor pengeboran Tanggung Jawab 8 13. Layanan Pihak Ketiga Kontraktor Orang Tanggung Jawab nel 9 14. Operasi Khusus Kewaspadaan 14 1. Operasi helikopter 14 2. Operasi tambat kapal 14 Formulir Penilaian Risiko Lampiran GI EMDCDO Paket Penilaian Risiko Lampiran G-II (contoh) Lampiran G-III EMDC-DO BOPE Form Exception Lampiran G-IV Pengeboran Kinerja Lingkungan Indikator Form Laporan 1. MARINE OPERASI 2. Site Survey / Bawah Sapu / S IMOPs ulasan 1 3. Pindah 2 1. Bergerak Rigs Jack-up 2 2. Bergerak Rigs Landasan 4 3. Bergerak Barge Rigs 5 4. Bergerak Dan Positioning 6 3.7.3 Proses Bor Kelautan 26 5. Pra-Loading (Jack-up Only) 7 3.7.4 Api Drills 27 6. Transfer kargo 8 3.7.5 Api Bor-Contoh 29 1. Kewaspadaan 9 3.7.6 Abaikan Rig latihan 30 2. Batas cuaca 9 3.7.7 Abaikan Rig Bor-Contoh 33 3. Lift berat (Jack-Up Lift di Kelebihan dari 10 MT) 9 3.7.8 Man Overboard Bor 34 3.7.9 Khusus Drills 35 4. Lifting Operasi 10 3.7.10 Aspek Kepala Drills 37 5. Pedoman Rigging 11 3,8 Kapal Collision Avoidance 37 6. Peralatan Pemeliharaan 15 3.6 Transportasi & Personalia Transfer 20 1. Cargo Transport 20 2. Operasi helikopter 21 3. Personil Transportasi-Helicopter 22 4. Personil Transportasi-Pasokan atau Stand-By Boat 24 3,7 Kelautan Pelatihan 24 3.7.1 Umum 24 3.7.2 Pelaporan & Bor Frekuensi 25 3.8.1 Deteksi 38 3.8.2 Radar Perhiasan Prosedur 38 Lampiran GI SIMOPs Checklist Memo Lampiran G-II SIMOPs Deviasi Formulir Lampiran G-III Studi Pile Interaksi dengan Jack-Up Rig Operasi Lampiran G-IV Pra-Startup Inspeksi untuk Baru Armada jackup Rig Pengeboran 4.0 DRILLING OPERATION 4.1 Pendahuluan 1 4.2 Operasi Pedoman Umum 1 4.3 Pra-Spud Operasi 3 4.4 Struktur drive Pipa 4 4.5 Konduktor dan Permukaan Casing Interval 5 4.6 pengalir Operasi 6 4.7 Menengah / pelindung Casing Interval 6 4.8 Produksi Casing / Liner Interval 7 4.9 Slot Pemulihan / Whipstock / Bagian Mill / Cutt & Pull 7 4.10 sumur bor Anti-Collision Pedoman 9 5.9 Bahan Referensi 18 6.0 DRILLING SISTEM FLUIDA 6.1 Umum 1 6.2 Padat Control 1 6.3 Drilling Fluid Perawatan 3 4.10.1 Persyaratan untuk "Risiko Collision" Wells 9 4.10.2 Persyaratan untuk Semua Directional Wells 10 6.4 Drilling Fluid Cek 5 6.5 Suhu Tinggi Drilling 6 4.11 Directional Survei dan Deviasi Kontrol 11 4.12 Bor String Desain 12 4.13 Bawah Lubang Sidang 14 4.14 Hidrogen Sulfida Pertimbangan 17 4.15 Hidrogen Sulfida Contingency Rencana 19 6.6 Pipa Terjebak Pills 6 6,7 Hilang Sirkulasi 7 5.0 BIT KLASIFIKASI DAN hidrolika 5.1 Umum 1 6,8 Non-berair Fluid Operasi 15 6.9 Rig-Site Dielektrik Konstan Pengukuran 33 5.2 Bor Bits 1 6.10 Pengeboran Sistem Fluid Pedoman 5.3 IADC Bit Sistem Klasifikasi 3 5.4 IADC Bit Grading System 6 5.5 Menjalankan Prosedur untuk Cutters Tetap 8 5.6 Hidrolik Program 10 5.7 Pedoman Hidrolik Optimasi 12 5.8 Hidrolik Optimization 17 34 GI Lampiran Fluid Transfer Checklist Lampiran G-II NAF / Minyak Pangkalan Checklist Mud Kesiapan 7.0 DETEKSI TEKANAN NORMAL DI klastik 7.1 Latar Belakang Indikator 1 7.2 Tekanan Sementara Pengeboran 2 7.3 Abnormal Tekanan Deteksi Tim Tanggung Jawab 10 7.4 Mud Logging 11 7.5 Pedoman Operasional 15 8,0 PEMBENTUKAN EVALUASI 8.1 Umum 1 10,6 Referensi 7 Lampiran GI Exxonmobil Pedoman Pengujian Semen 8.2 konvensional Coring 1 8.3 Wireline Logging Program 8 8.4 Dinding samping Coring Operasi 11 8,5 Wireline Radioaktif Sumber 12 8,6 MWD / LWD Logging 12 8,7 Mud Logging dan Stek Sampel 14 9.0 OPERASI CASING 9.1 Casing Menjalankan 1 9.2 Casing Connection Make-Up 5 9.3 Casing Checklist 5 10,0 penyemenan 10.1 Umum 1 10.2 Cementing Pedoman 1 10.3 Primer Cementing 3 10.4 Remedial Cementing 5 10,5 Cementing Checklist 6 11,0 TEKANAN INTEGRITAS UJI 11.1 Umum 1 11.2 Casing Test 2 11.3 Leak-Off Uji 3 11,4 Jug Test (Terbatas PIT) 4 PENGUJIAN 12,0 PRODUKSI 12.1 Pengujian Produksi Tujuan 1 12.2 Nah Uji Desain 1 13.3 Sementara Plug dan Pengabaian 4 13.4 Site Jarak Verificationa 4 14,0 BAIK KONTROL 12.3 Uji String 3 14.1 Nah Pengendalian â € "General 1 12.4 Permukaan Peralatan 4 14.2 Lubang Pemantauan 5 12,5 Peralatan Pengukuran 4 14.3 Peralatan Pengujian 8 12.6 Keselamatan 5 14.4 Peralatan Spesifikasi 10 12,7 Personil Tanggung Jawab 6 14,5 Nah Kontrol latihan 16 Perencanaan 12,8 Pre-test dan Persiapan 14,6 Nah Pengendalian Prosedur 19 9 5 dari 5 12,9 Information Retrieval 10 12.10 Nah Membunuh dan Zona Pengabaian 11 1.0 INFORMASI UMUM 1.1 Drilling Pedoman Operasi 1 12.11 Prosedur Darurat 11 1.2 Organisasi 2 12.12 Hidrogen Sulfida 11 1,3 EMDC Laporan 3 12.13 Hidrasi 12 1.4 Drilling Kontraktor Laporan 6 13,0 PLUG DAN DITINGGALKAN 13.1 Umum 1 13,2 permanen Plug dan Pengabaian 1 1,5 Layanan Pihak Ketiga Kontraktor Laporan 9 2.0 OPERASI UMUM 2.1 Kontrak Administrasi 1 2.2 Prespud Meeting 2 Lampiran G-III EMDC-DO BOPE Form Exception 2.3 Keamanan 3 2,4 EMDC Drilling Operations Personil Tanggung Jawab 3 Lampiran G-IV Pengeboran Kinerja Lingkungan Indikator Form Laporan 3.0 OPERASI MARINE 2,5 Pengeboran Personil Kontraktor Tanggung Jawab 8 2.6 Layanan Pihak Ketiga Personil Kontraktor Tanggung Jawab 9 3.1 Site Survey / Bawah Sapu / SIMOPs ulasan 1 3,2 Bergerak 2 2,7 Operasi Khusus Kewaspadaan 14 3.2.1 Bergerak Jack-up rig 2 2.7.1 Helikopter Operasi 14 3.2.2 Pindah Rigs Landasan 4 2.7.2 Mooring Kapal Operasi 14 3.2.3 Pindah Barge Rigs 5 Tekanan 2.7.3 Casing Pemantauan 14 3.3 Bergerak Dan Positioning 6 2.7.4 Kembali Tekanan Katup 14 3.4 Pra-Loading (Jack-up Only) 7 2.7.5 Rotary Table Insert Bushing Kunci 3,5 Cargo Transfer 8 14 3.5.1 Pencegahan 9 2.7.6 Pohon Natal Peralatan 14 3.5.2 Cuaca Batas 9 2.7.7 Mud Logging Unit 15 Formulir Penilaian Risiko Lampiran GI EMDCDO 3.5.3 Lift Heavy (Jack-Up Lift di Kelebihan dari 10 MT) 9 3.5.4 Lifting Operasi 10 Paket Penilaian Risiko Lampiran G-II (contoh) 3.5.5 Pedoman Rigging 11 3.5.6 Peralatan Pemeliharaan 15 3.8.2 Radar Perhiasan Prosedur 38 3.6 Transportasi & Personalia Transfer 20 Lampiran GI SIMOPs Checklist Memo Lampiran G-II SIMOPs Deviasi Formulir Lampiran G-III Studi Pile Interaksi dengan Jack-Up Rig Operasi Lampiran G-IV Pra-Startup Inspeksi untuk Baru Armada jackup Rig Pengeboran 3.6.1 Cargo Transport 20 3.6.2 Helikopter Operasi 21 3.6.3 Personil Transportasi-Helicopter 22 3.6.4 Personil Transportasi-Pasokan atau Stand-By Boat 24 3,7 Kelautan Pelatihan 24 3.7.1 Umum 24 3.7.2 Pelaporan & Bor Frekuensi 25 3.7.3 Proses Bor Kelautan 26 3.7.4 Api Drills 27 3.7.5 Api Bor-Contoh 29 3.7.6 Abaikan Rig latihan 30 3.7.7 Abaikan Rig Bor-Contoh 33 3.7.8 Man Overboard Bor 34 3.7.9 Khusus Drills 35 3.7.10 Aspek Kepala Drills 37 3,8 Kapal Collision Avoidance 37 3.8.1 Deteksi 38 4.0 DRILLING OPERATION 4.1 Pendahuluan 1 4.2 Operasi Pedoman Umum 1 4.3 Pra-Spud Operasi 3 4.4 Struktur drive Pipa 4 4.5 Konduktor dan Permukaan Casing Interval 5 4.6 pengalir Operasi 6 4.7 Menengah / pelindung Casing Interval 6 4.8 Produksi Casing / Liner Interval 7 4.9 Slot Pemulihan / Whipstock / Bagian Mill / Cutt & Pull 7 4.10 sumur bor Anti-Collision Pedoman 9 4.10.1 Persyaratan untuk "Risiko Collision" Wells 9 4.10.2 Persyaratan untuk Semua Directional Wells 10 4.11 Directional Survei dan Deviasi Kontrol 11 4.12 Bor String Desain 12 4.13 Bawah Lubang Sidang 14 4.14 Hidrogen Sulfida Pertimbangan 17 4.15 Hidrogen Sulfida Contingency Rencana 19 5.0 BIT KLASIFIKASI DAN hidrolika 5.1 Umum 1 5.2 Bor Bits 1 5.3 IADC Bit Sistem Klasifikasi 3 5.4 IADC Bit Grading System 6 5.5 Menjalankan Prosedur untuk Cutters Tetap 8 5.6 Hidrolik Program 10 Lampiran G-II NAF / Minyak Pangkalan Checklist Mud Kesiapan 5.8 Hidrolik Optimization 17 7.0 DETEKSI TEKANAN NORMAL DI klastik 7.1 Latar Belakang Indikator 1 7.2 Tekanan Sementara Pengeboran 2 7.3 Abnormal Tekanan Deteksi Tim Tanggung Jawab 10 7.4 Mud Logging 11 7.5 Pedoman Operasional 15 5.9 Bahan Referensi 18 8,0 PEMBENTUKAN EVALUASI 5.7 Pedoman Hidrolik Optimasi 12 6.0 DRILLING SISTEM FLUIDA 8.1 Umum 1 6.1 Umum 1 8.2 konvensional Coring 1 6.2 Padat Control 1 8.3 Wireline Logging Program 8 6.3 Drilling Fluid Perawatan 3 8.4 Dinding samping Coring Operasi 11 6.4 Drilling Fluid Cek 5 8,5 Wireline Radioaktif Sumber 12 6.5 Suhu Tinggi Drilling 6 8,6 MWD / LWD Logging 12 6.6 Pipa Terjebak Pills 6 8,7 Mud Logging dan Stek Sampel 14 6,7 Hilang Sirkulasi 7 6,8 Non-berair Fluid Operasi 15 6.9 Rig-Site Dielektrik Konstan Pengukuran 33 9.0 OPERASI CASING 9.1 Casing Menjalankan 1 9.2 Casing Connection Make-Up 5 9.3 Casing Checklist 5 6.10 Pengeboran Sistem Fluid Pedoman 10,0 penyemenan 34 GI Lampiran Fluid Transfer Checklist 10.1 Umum 1 10.2 Cementing Pedoman 1 10.3 Primer Cementing 3 10.4 Remedial Cementing 5 10,5 Cementing Checklist 6 10,6 Referensi 7 Lampiran GI Exxonmobil Pedoman Pengujian Semen 11,0 TEKANAN INTEGRITAS UJI 11.1 Umum 1 11.2 Casing Test 2 11.3 Leak-Off Uji 3 11,4 Jug Test (Terbatas PIT) 4 PENGUJIAN 12,0 PRODUKSI 12.1 Pengujian Produksi Tujuan 1 12.2 Nah Uji Desain 1 13.3 Sementara Plug dan Pengabaian 4 13.4 Site Jarak Verificationa 4 14,0 BAIK KONTROL 12.3 Uji String 3 14.1 Nah Pengendalian â € "General 1 12.4 Permukaan Peralatan 4 14.2 Lubang Pemantauan 5 12,5 Peralatan Pengukuran 4 14.3 Peralatan Pengujian 8 12.6 Keselamatan 5 14.4 Peralatan Spesifikasi 10 12,7 Personil Tanggung Jawab 6 14,5 Nah Kontrol latihan 16 Perencanaan 12,8 Pre-test dan Persiapan 14,6 Nah Pengendalian Prosedur 19 9 5 dari 5 12,9 Information Retrieval 10 12.10 Nah Membunuh dan Zona Pengabaian 11 INFORMASI UMUM 1.0 INFORMASI UMUM 12.11 Prosedur Darurat 11 1.1 Drilling Pedoman Operasi 1 12.12 Hidrogen Sulfida 11 1.2 Organisasi 2 12.13 Hidrasi 12 1,3 EMDC Laporan 3 13,0 PLUG DAN DITINGGALKAN 13.1 Umum 1 13,2 permanen Plug dan Pengabaian 1 1.4 Drilling Kontraktor Laporan 6 1,5 Layanan Pihak Ketiga Kontraktor Laporan 9 ______________________________________________ ________________________________ OPERASI PENGEBORAN MANUAL-JACK-UP / PLATFORM / barage RIG DRILLING PERTAMA EDITION-Mei 2003 1.1 DRILLING OPERASI MANUAL The EMDC Jack-Up / Landasan / Barge Rig Pengeboran Operasi Standar Pedoman ini berlaku untuk produksi dan eksplorasi sumur. Pedoman pengeboran, prinsip, dan prosedur yang terdapat dalam panduan ini merupakan praktek pengeboran yang memastikan komitmen tertinggi Perseroan untuk keselamatan, kesehatan, dan lingkungan. Organisasi Pedoman Panduan ini disusun menjadi beberapa bagian yang meliputi aspek penting dari Jack-Up / Landasan / Barge pengeboran Rig. Setiap bagian dibagi menjadi subbagian, yang membahas aspek-aspek yang relevan dari setiap topik bagian. Dalam setiap bagian, satu ayat dikhususkan untuk operasi operasi Bor Tim spesifik. Lampiran yang berlaku untuk operasi pengeboran umum terlepas dari daerah operasi dilambangkan oleh "G" sebelum nomor lampiran. Lampiran yang berkaitan dengan tim bor tertentu dilambangkan oleh "S" awalan sebelum nomor lampiran. Mana yang berlaku, manual ini akan referensi dokumen perusahaan dan industri lainnya yang mengandung informasi tambahan untuk melengkapi pedoman yang terdapat di sini-di. Panduan ini akan menyajikan praktek pengeboran umum untuk berbagai operasi pengeboran, terlepas dari jenis rig. 1.2 ORGANISASI Pengeboran Insinyur Bahan & Drilling Services Pengawas EMDC - Pengeboran Organisasi Pengadaan Jasa Advisor EMDC Drilling bertanggung jawab untuk kegiatan produksi dan pengeboran eksplorasi di seluruh dunia ExxonMobil. Drilling Organisasi bertanggung jawab untuk kontrak layanan dan pemasok bahan, perencanaan dan persiapan pekerjaan teknik pengeboran, dan pengawasan langsung dari operasi pengeboran. Drilling Organisasi harus menyiapkan pedoman dan prosedur, yang diperlukan, sehingga operasi dilakukan dengan cara yang aman dan ramah lingkungan. Tanggung jawab ini akan dipenuhi oleh personil berikut: SHE Manager, Drilling Koordinator lingkungan, Drilling Manager, Drilling Pengeboran Operations Manager Procurement Manager Pengeboran Technology Manager Bidang Drilling Manajer Operasi Inspektur Engineering Manager Operasi Pengawas Mengawasi Insinyur Pengeboran Kontraktor dan Kontraktor Layanan Kritis Pihak Ketiga Lainnya Kontraktor Pengeboran adalah kontraktor independen yang akan menjalankan program pengeboran untuk kepuasan Operasi Pengawas di lokasi. Kontraktor pengeboran juga bertanggung jawab untuk operasi dan pemeliharaan rig pengeboran dalam kondisi kerja yang aman dan sesuai penuh dengan EMDC spesifikasi teknis dan persyaratan peraturan lokal, termasuk persyaratan sebagaimana ditentukan dalam kontrak pengeboran. Kontraktor layanan pihak ketiga penting lainnya adalah kontraktor independen yang akan membantu dalam melaksanakan program pengeboran. Kontraktor ini bertanggung jawab untuk operasi dan pemeliharaan peralatan mereka secara penuh sesuai dengan EMDC spesifikasi teknis dan / atau persyaratan kontrak, dan persyaratan peraturan lokal. Pengeboran kontraktor dan kontraktor layanan pihak ketiga penting lainnya menyediakan layanan di mana kinerja yang tidak memadai bisa mengakibatkan Level 1, 2, atau 3 kejadian (OIMS Element 9). Kontraktor ini harus memenuhi atau melampaui EMDC persyaratan di daerah yang kontrak dikeluarkan. Ini meliputi: Pernyataan Keselamatan, Kesehatan, dan Lingkungan Kebijakan Obat dan Alkohol Kebijakan Program Kontraktor Keselamatan Dokumentasi Peralatan Teknis Sistem Kerja Izin Bahan Berbahaya Penanganan / Penyimpanan Prosedur Prosedur dure ke Control Equipment / Keamanan Kebijakan Perubahan Layanan perusahaan Layanan / Pihak Ketiga Perusahaan layanan / kontraktor layanan pihak ketiga adalah kontraktor independen yang akan membantu dalam melaksanakan program pengeboran untuk kepuasan Operasi Pengawas di rig pengeboran. Kontraktor ini juga bertanggung jawab untuk operasi dan pemeliharaan peralatan mereka secara penuh sesuai dengan EMDC spesifikasi teknis dan persyaratan peraturan lokal, termasuk yang sebagaimana ditentukan dalam berbagai kontrak. 1.3 EMDC- DRILLING LAPORAN Kritis informasi operasi pengeboran dan aspek yang relevan dari kegiatan pengeboran harian akan didokumentasikan dalam laporan standar yang dikembangkan oleh EMDC dan kontraktornya. Panduan ini menjelaskan persiapan dan distribusi laporan-laporan ini. Harian Pengeboran Laporan Operasi Pengawas akan merekam kegiatan pengeboran pada DRS dan mengirimkan, biasanya melalui LAN atau saluran telepon (modem), ke Pusat Informasi Manajemen Drilling (DIMC) setiap pagi. The Daily Drilling Report akan mencakup periode 24 jam dengan aktivitas pengeboran hari saat ini. Meminimalkan biaya pengeboran per kaki dan mencapai peningkatan secara keseluruhan dalam efisiensi operasi pengeboran mengharuskan Manajemen, Operasi Inspektur, dan Teknik menerima, faktual, laporan lengkap akurat dari rig Operasi Pengawas setiap hari. Pengendalian manajemen yang efektif dari operasi pengeboran tidak dapat dilakukan tanpa masukan dari seluruh organisasi pengeboran, dan laporan pengeboran harian adalah dokumen dasar dari yang paling informasi diambil. Pedoman berikut ini pada beberapa aspek dari Laporan Harian Pengeboran: Peristiwa operasi pengeboran harus dipisahkan waktu untuk sesuai dengan EMDC Kode distribusi rig-waktu (tidak IADC). DRS pengguna berisi panduan pada coding operasi. Kedalaman sumur ditentukan oleh pengukuran garis baja string bor. Harus ada kesepakatan yang wajar antara DDR dan laporan IADC. Sebuah laporan yang lebih baik akan terjadi jika masingmasing Operasi Pengawas menulis ringkasan operasi untuk nya / tur nya. Jangan melaporkan pendapat atau dugaan kecuali mereka begitu diidentifikasi. Jika pendapat dilaporkan sebagai fakta, pengawas rig akan tahu ini, tapi staf kantor tidak mungkin. Menggunakan singkatan-satunya standar. Jangan membuat singkatan. Logging listrik: tentukan log menjalankan, selang kedalaman login, suhu lubang bawah, dan kedalaman lubang ketat. Sirkulasi: menentukan mengapa lumpur sedang beredar, dan rotasi tingkat sirkulasi / pipa jika ada. Biaya Laporan Harian Operasi Pengawas harus menyelesaikan Biaya Laporan Harian DRS dan mengirimkan ke DIMC setiap pagi. Biaya Laporan Harian harus menangkap semua biaya pengeboran substansial termasuk layanan dimanfaatkan, sewa peralatan, dan bahan-bahan dikonsumsi. Dimana biaya yang sebenarnya tidak diketahui, perkiraan yang wajar harus dilakukan dan termasuk dalam Biaya Laporan Harian. Beberapa biaya kontraktor tidak akan diketahui persis sampai akhir bulan. Rig tidak harus berusaha untuk memperkirakan apa biaya diskon akan; rig adalah memasukkan muatan tiket pada layar biaya. Drilling Engineer bertanggung jawab untuk memantau potongan bahan dan jasa biaya dan berkomunikasi penyesuaian dengan Operasi Pengawas untuk modifikasi lembar biaya. Ini adalah tanggung jawab Pengeboran Insinyur untuk termasuk biaya semua bahan dan jasa dalam prosedur yang sesuai untuk Operasi Pengawas digunakan dalam menyelesaikan Biaya Laporan Harian. The Pengeboran Insinyur juga memberikan biaya tetap awal untuk Operasi Pengawas dan memeriksa entri untuk kesalahan atau kelalaian. Bom ATF Checklist Ancaman Operasi Pengawas harus siap untuk merespon secara efektif harus mereka menerima ancaman bom melalui telepon. Hal ini sangat penting untuk mengambil pemanggil serius. Meminta orang tersebut untuk mengulangi pesan. Merekam setiap kata yang diucapkan oleh orang tersebut. Lengkapi checklist ancaman bom dan mengirimkan ke Operasi Inspektur. OIMS referensi manual (05/10) untuk informasi lebih lanjut. Casing Tally Laporan The Casing Tally Laporan harus disiapkan untuk setiap casing string yang dijalankan. Salinan laporan akan disimpan di kapal pengeboran untuk referensi selama logging, pengujian produksi, penyelesaian, plug and ditinggalkan operasi, dll Operasi Pengawas bertanggung jawab untuk menyelesaikan laporan penghitungan casing menjalankan dan meneruskan ke Pengeboran Insinyur setelah setiap string casing dijalankan. Meskipun tidak diperlukan untuk mengirimkan penghitungan off-beban dari rig, perlu untuk membuat penghitungan DRS off-beban untuk dapat melengkapi deskripsi casing bagian dari DRS "sebagai run" penghitungan. OIMS membutuhkan laporan casing penghitungan DRS mana mungkin. Laporan kegagalan peralatan akan disiapkan untuk mendokumentasikan kegagalan peralatan yang menghasilkan dampak ekonomi yang signifikan atau kegagalan yang bisa memiliki implikasi keamanan. Laporan kegagalan peralatan harus cukup menggambarkan sifat kegagalan, mengidentifikasi penyebab kegagalan, mendokumentasikan downtime terkait karena kegagalan, dan merekomendasikan cara-cara untuk mencegah kegagalan dari terjadi di masa depan. Indikator Kinerja Lingkungan (EPI) Laporan Operasi Pengawas bertanggung jawab untuk mempersiapkan laporan dan meneruskan ke Operasi Inspektur. Mesin akan meninjau laporan untuk menentukan apakah analisis lebih lanjut atau tindakan yang diperlukan. Pada akhir setiap baik, Engineer Drilling dan EMDC Domestik Regulatory Teknisi akan menyelesaikan Indikator Kinerja Lingkungan (EPI) Laporan untuk dimasukkan di Final Nah Laporan. Formulir ini berisi empat bagian; Nah Informasi, Emisi data, Data Kepatuhan Peraturan Lingkungan, dan Limbah data. Pengeboran Sistem Pelaporan (DRS) Ketika sistem DRS di tempat, laporan DRS berikut akan dipertahankan dan ditularkan dari rig harian atau saat berhubungan, 1) Harian Pengeboran Report, 2) Casing Report, 3) Cementing Report, 4) litologi, 5) Logging Run, 6) Milestones, 7) Mud, 8) Penggunaan Mud Produk, 9) perfs, 10) RFT, 11) drillstring, 12) Cuaca, 13) Nah Test, 14) Stratigrophy. Peralatan Kegagalan Laporan Tangan-Over Catatan Catatan serah akan disiapkan oleh Operasi Pengawas (ketika bekerja pada jadwal rotasi) dan Operasi Pengawas sebelum perubahan kru masingmasing. Tujuan dari catatan ini adalah untuk mendokumentasikan semua situasi dan / atau kegiatan yang akan membutuhkan tindak lanjut oleh personil menghilangkan, serta untuk mengatasi peristiwa operasional yang signifikan yang terjadi selama halangan. Material Transfer / Cargo Manifest Sebuah manifest transfer material / kargo harus siap untuk semua pengiriman bahan ke dan dari rig pengeboran. Memanifestasikan harus disiapkan oleh Basis Manajer / Bahan Koordinator untuk semua untuk-rig pengiriman dan oleh pemilik toko rig pengeboran (jika kontrak) untuk semua dari-rig pengiriman. Kargo manifest harus daftar semua bahan ditransfer, memberikan kuantitas, deskripsi, berat badan, dan jumlah kontainer yang disimpan. Transfer materi dipersiapkan untuk EMDC bahan dan biasanya akan memberikan daftar nomor komoditas. Bahan berbahaya harus diidentifikasi pada manifes. Dalam situasi harus digunakan casing benang pelindung dikirim ke Amerika Serikat dalam sebuah wadah kecuali semua senyawa benang dihapus. Akan ada usaha prosedur bahan tertentu. Setelah selesai, manifest harus ditandatangani oleh originator dan diteruskan ke penerima barang dengan cara yang paling bijaksana (biasanya melalui fax). Salinan manifes harus diberikan kepada kapten kapal mentransfer. Operasi Pengawas harus menandatangani manifest untuk barang diterima di rig. Alat sewa harus dilacak, sebaiknya dalam alat log book sewa atau dalam clipboard dipertahankan di rig. Tekanan Integritas Uji Rekam Tes tekanan Integritas yang dibahas dalam Bagian 11 dari manual ini. Tes integritas tekanan (PIT) bentuk akan siap untuk semua tes yang dilakukan. Informasi tambahan mengenai prosedur PIT dan analisis yang terkandung dalam publikasi EPRCo "Tekanan Integritas Uji - Panduan Lapangan". Operasi Pengawas bertanggung jawab untuk mengisi formulir PIT dan meneruskan ke Operasi Inspektur dan Pengeboran Insinyur secepat praktis setelah menyelesaikan tes. Keselamatan Insiden dan Laporan Spill Mengacu pada Keselamatan Manajemen Program Pengeboran (SMP) dan OIMS Pedoman pedoman pelaporan insiden. Sebuah Insiden Reportable Keselamatan didefinisikan oleh OIMS sebagai sebuah Insiden Lost Time, Dibatasi Kerja Insiden, atau Insiden Pengobatan. Tumpahan minyak adalah setiap rilis hidrokarbon cair lebih besar dari 1 per barel (atau afiliasi / minimum yang diperlukan peraturan) yang jatuh ke air atau ke tanah yang bisa masuk ke air tanah. Salinan laporan akan diberikan kepada Pengawas Operasional untuk meneruskan ke Operasi Inspektur. Keamanan Rapat Rekam Operasi Pengawas harus mencatat isu ditujukan / dibahas pada pertemuan keselamatan umum, serta topik pertemuan keselamatan pre-tour kru bor dan setiap pertemuan keselamatan operasi kritis di meredup dan laporan IADC. Risalah pertemuan keselamatan umum dapat ditulis tangan dan tidak perlu digandakan pada laporan meredup. Salinan maju menit pertemuan keselamatan kontraktor untuk Operasi Inspektur. dirancang khusus untuk rig pengeboran. Laporan ini harus mencakup informasi yang ditentukan dalam Bagian 14 dari manual ini. Nah Membunuh Lembar Kerja Setelah BOP stack diinstal, Lembar Kerja Nah Membunuh akan disiapkan sesuai dengan pedoman yang ditetapkan dalam Bagian 14 dari manual ini. Worksheet akan dipertahankan untuk konfigurasi sumur bor saat ini dan diperbarui setidaknya setiap hari (atau juga kondisi berubah) sementara pengeboran sedang berlangsung atau menjaga data program KIK PC up to date. Operasi Pengawas bertanggung jawab untuk menyelesaikan lembar kerja. Ada beberapa format yang dapat diterima termasuk bentuk tradisional EPRCo, bentuk Randy Smith, bentuk EUSA, dan program PC KIK. Laporan lainnya Persyaratan pelaporan tambahan harus diikuti / diselesaikan sebagaimana tercantum dalam Drilling OIMS Manual dan Program Manajemen Keselamatan. 1,4 DRILLING LAPORAN CONTRACTOR BOP Uji Rekam Hasil semua tes BOP dan setiap kekurangan harus dicatat pada Pengeboran Laporan Harian dan IADC Laporan. Data uji rinci juga akan disimpan oleh Kontraktor Pengeboran pada formulir tes BOP yang Menyelesaikan bentuk tes BOP, ditandatangani oleh operator pompa tes, alat pendorong / OIM, dan Operasi Supervisor, akan diberikan kepada Operation Supervisor. Semua grafik uji tekanan akan tanggal, dan benar diberi label untuk setiap komponen diuji sesuai dengan EMDC berlaku dan persyaratan peraturan. Semua catatan yang berkaitan dengan tes BOP harus dipertahankan pada rig pengeboran sampai selesai dengan baik. Catatan kemudian harus diteruskan ke fasilitas produksi terdekat atau platform host untuk retensi sesuai dengan persyaratan peraturan yang berlaku atau diteruskan ke Operasi Inspektur untuk dimasukkan dalam file baik (operasi pengeboran eksplorasi internasional). Dewan Status saat ini Sebuah papan status harus dipertahankan di stasiun driller ini. Ini harus mencakup ketinggian ram BOP dan informasi bermanfaat lainnya dan posting diamanatkan peraturan atau dokumentasi. Harian Personil Rekam Sebuah daftar dari semua personil pada rig (daftar POB) dan posisi mereka akan hati-hati dipelihara oleh seorang wakil yang ditunjuk dari Kontraktor Pengeboran. Daftar POB akan diperbarui dan didistribusikan setiap hari. Salinan daftar POB akan diberikan kepada Pengawas Operasional pada tengah malam. Daftar ini akan tersedia untuk fax ke Operasi Inspektur bila diperlukan. Salinan daftar POB saat ini akan dipertahankan pada rig pengeboran. Pengeboran Perekam Bagan Kontraktor Pengeboran harus membubuhi keterangan semua kegiatan pengeboran utama (pengeboran, tersandung, beredar, berjalan casing, penyemenan, dll) pada grafik jalur perekaman kontinyu yang merekam kedalaman, waktu, hookload, tekanan pompa, torsi putar, dan berat-onbit , sebagai minimum. Grafik Strip juga harus dijelaskan oleh Kontraktor Pengeboran untuk dicatat kegiatan yang signifikan seperti mengisi lubang, aliran cek, koneksi, lubang ketat, masalah mekanis, pipa terjebak, dll Salinan grafik akan diberikan kepada Pengawas Operasional untuk meneruskan ke Operasi Inspektur ketika diminta. Laporan IADC The IADC Laporan akan disiapkan setiap hari oleh Kontraktor Pengeboran dan ditandatangani oleh kedua perwakilan pengeboran senior pengeboran kontraktor dan Pengawas Operasional. The IADC Laporan akan detail peristiwa kegiatan pengeboran setiap hari, memberikan rincian waktu untuk setiap peristiwa besar. Acara yang tunduk pada tarif biaya rig yang berbeda, seperti yang ditentukan dalam kontrak pengeboran, harus dipisahkan secara jelas. Peristiwa penting seperti insiden keamanan, pertemuan keselamatan, tes BOP, kegagalan peralatan utama, dll akan didokumentasikan pada Laporan IADC. Personil Kontraktor pengeboran harus diidentifikasi oleh nama, posisi dan jam kerja (termasuk lembur ada). Operasi Pengawas akan mengirimkan asli (putih) dan salinan merah muda untuk Operasi Inspektur mingguan. Salinan biru harus disimpan di kantor Operasi Pengawas diatas kapal pengeboran. Hijau dan putih (terakhir) copy akan ditinggalkan untuk Kontraktor Pengeboran. Operasi Inspektur akan meneruskan asli untuk bagian akuntansi dan mempertahankan copy merah muda di file pengeboran kantor. Keselamatan Insiden Laporan Mengacu pada Program Manajemen Pengeboran Keselamatan untuk penjelasan dari laporan yang diperlukan dari kontraktor. Kontraktor Pengeboran akan mempersiapkan laporan insiden insiden semua waktu yang hilang, kematian, insiden kerja dibatasi, insiden perawatan medis, perawatan pertolongan pertama, peristiwa penyakit regional, nyaris celaka, dan merindukan dekat signifikan onboard rig pengeboran. Laporan insiden akan, minimal, menggambarkan sifat kejadian, daftar nama-nama semua orang yang terlibat (baik saksi dan korban), menggambarkan keadaan kontribusi, dan mengidentifikasi langkahlangkah perbaikan dan rekomendasi untuk mencegah kejadian lebih lanjut. Pada opsi Operasi Supervisor, checklist ini dapat digunakan sebagai bantuan dalam membangun rig lantai kru juga mengontrol kompetensi. Checklist ini dalam Bagian 6 dari OIMS Manual dan pedoman dalam Bagian 14 dari manual ini. Keamanan Rapat Laporan 1,5 PIHAK KETIGA LAYANAN KONTRAKTOR LAPORAN Kontraktor Pengeboran akan menyiapkan laporan meringkas diskusi yang diselenggarakan dalam pertemuan keselamatan umum. Laporan pertemuan keselamatan harus, minimal, menjelaskan topik keselamatan dibahas, mengidentifikasi status setiap item keselamatan luar biasa dan memberikan daftar semua peserta rapat. Sebuah laporan yang ditulis tangan dapat diterima. Salinan laporan akan diberikan kepada Pengawas Operasional untuk meneruskan ke Operasi Inspektur. Buku perjalanan Pemantauan utama dari volume lumpur ditambahkan ke lubang untuk menggantikan bor tali perpindahan perjalanan adalah tanggung jawab awak pengeboran. Ketika penuh lumpur layanan logging tersedia, penebang lumpur akan memberikan log book perjalanan cadangan. Tangki perjalanan akan digunakan untuk semua perjalanan kecuali dinyatakan ditangani oleh manajer pengeboran lapangan. Buku perjalanan harus membandingkan volume yang diukur dengan volume yang teoritis maupun volume yang perjalanan sebelumnya. Lihat Bagian 14. Nah Checklist Kesiapan Kontrol Penyemenan Bagan Sebuah grafik perekam penyemenan (tekanan vs waktu) akan disiapkan untuk semua operasi, seperti casing cementing, pengujian tekanan peralatan, PIT, dll grafik akan dijelaskan dengan semua peristiwa yang signifikan seperti spacer memompa, memompa memimpin dan ekor semen, menabrak steker, dll (seperti yang dipersyaratkan oleh afiliasi lokal dan badan pengatur). Grafik akan diberikan kepada Pengawas Operasional untuk meneruskan ke Operasi Inspektur dan Pengeboran Insinyur ketika diminta atau dipertahankan seperti yang dipersyaratkan oleh peraturan daerah. Harian Pengeboran Cairan Laporan The Pengeboran Cairan Insinyur akan menyiapkan Harian Pengeboran Cairan Laporkan sesuai dengan pedoman yang ditetapkan dalam Bagian 6 dari manual ini. Kecuali ditentukan lain oleh Pengawas Operasional, minimal dua lengkap "Di" dan "Out" cek dari cairan pengeboran harus dilakukan setiap hari selama operasi pengeboran. Laporan ini akan diberikan kepada Pengawas Operasional untuk meneruskan ke Drilling Insinyur setiap pagi. Directional data Untuk sumur directional, yang Drillers Directional akan mempersiapkan lubang lembar perakitan bawah dan BHA checklist untuk semua BHA menjalankan dengan baik sesuai dengan pedoman yang ditetapkan dalam Bagian 4 dari manual ini. Directional driller juga akan mempertahankan rekor sumur bor lintasan dan sumur bor plot saat di kantor Operasi Supervisor. The Driller Directional dan Operasi Pengawas harus bekerja sama untuk menyelesaikan dan menandatangani directional drilling pra-pekerjaan lembar data survei (PJSDS) dan maju ke koordinator directional pengebor serta ke Drilling Engineer. Sebuah daftar pra-pekerjaan untuk sumur directional harus digunakan untuk memverifikasi bahwa semua masalah operasional telah ditangani. Kedua item di atas adalah OIMS diperlukan dokumen. Anticollision / baik perhitungan gangguan harus diperbarui pada setiap titik survei dan minimal dua perwakilan kontraktor directional harus onboard ketika masalah gangguan sumur bor yang ada. Teknik perhitungan kelengkungan minimum harus digunakan. Salinan catatan lintasan sumur bor akan diberikan kepada Pengawas Operasional untuk forwarding ke Drilling Insinyur setiap pagi. Laporan lumpur Logger ini The penebang Mud akan menyiapkan Log Lumpur dan Mud Logging Harian Laporan sesuai dengan pedoman deteksi tekanan abnormal ditentukan dalam Bagian 7 dari manual ini. Salinan log / laporan akan diberikan kepada Pengawas Operasional dan wellsite geologi untuk meneruskan ke Operasi Inspektur dan operasi geolog setiap pagi. Pit Volume penghitung Bagan Sebuah Pit Volume penghitung (PVT) grafik benar diberi label dan tanggal harus dipertahankan oleh perusahaan dikontrak untuk menyediakan sama. Keselamatan Radiasi Checklist, Nah Site Penilaian berkala akan dilakukan dari kecukupan program keselamatan kontraktor situs rig yang menggunakan sumber radioaktif. Mengacu pada Keselamatan Program Manajemen Pengeboran dan daftar periksa OIMS. Kapal Harian Log Sebuah harian Log akan selesai semua pasokan / kapal standby pada kontrak dan diteruskan ke Pangkalan Manajer / Koordinator Bahan pada mingguan (atau lainnya tepat waktu) dasar. OPERASI UMUM Formulir Penilaian Risiko Lampiran GI EMDC-DO 2.0 OPERASI UMUM 2.1 Kontrak Administrasi 1 2.2 Prespud Meeting 2 2.3 Keamanan 3 2,4 EMDC Drilling Operations Personil Tanggung Jawab 3 2,5 Pengeboran Personil Kontraktor Tanggung Jawab 8 2.6 Layanan Pihak Ketiga Personil Kontraktor Tanggung Jawab 9 Paket Penilaian Risiko Lampiran G-II (contoh) Lampiran G-III EMDC-DO BOPE Form Exception Lampiran G-IV Pengeboran Kinerja Lingkungan Indikator Form Laporan _____________________________________________________________ _______________________________________________ OPERASI PENGEBORAN MANUAL - jackup / PLATFORM / barage RIG DRILLING PERTAMA EDITION - MAY 2003 2,7 Operasi Khusus Kewaspadaan 14 2.7.1 Helikopter Operasi 14 2.7.2 Mooring Kapal Operasi 14 Tekanan 2.7.3 Casing Pemantauan 14 2.7.4 Kembali Tekanan Katup 14 2.7.5 Rotary Table Insert Bushing Kunci 14 2.7.6 Pohon Natal Peralatan 14 2.7.7 Mud Logging Unit 15 2.1 KONTRAK ADMINISTRASI Setelah pelaksanaan berbagai kontrak antara EMDC-Pengeboran dan kontraktor individu, Operasi Inspektur dan Operasi Pengawas akan mengelola kontrak berdasarkan tanggung jawab sebagai berikut: Operasi Inspektur 1. Mengelola ketentuan kontrak dan ketentuan antara EMDC-Pengeboran dan Kontraktor Pengeboran dan kontraktor layanan pihak ketiga kritis dan non-kritis lainnya. 2. Salinan kontrak yang berlaku dipelihara oleh kelompok pengadaan EMGSC untuk berbagai operasi pengeboran. 1. Ada di tempat program keselamatan dan lingkungan dan membicarakan hal ini dengan EMDC-Drilling Manajemen bila diminta. 3. Alamat pertanyaan dari Operasi Pengawas mengenai ketentuan kontrak atau pengecualian. 2. Mengidentifikasi pembuangan metode / situs yang digunakan untuk limbah kontraktor. Ini adalah persyaratan kontrak dari kontraktor pihak ketiga untuk Pengembangan Operasi Pengeboran Timur AS. Operasi Pengawas 1. Menjadi akrab dengan setiap kontrak yang diperlukan untuk melakukan operasi pengeboran dan mematuhi ketentuan dalam kontrak. 2. Memastikan bahwa semua peralatan pada Rig Pengeboran sesuai dengan ketentuan kontrak. 3. Pastikan bahwa wakil dari masing-masing perusahaan layanan melengkapi tiket pelayanan sesuai dengan ketentuan kontrak. 4. Melakukan safety / operasional ("prespud") pertemuan sebelum start-up dari operasi pengeboran dengan manajemen yang tepat dari Kontraktor Pengeboran dan kontraktor layanan pihak ketiga penting lainnya. Lihat Drilling Program Manajemen Keselamatan untuk pedoman pertemuan 5. Mendokumentasikan pertemuan keamanan di DRS dan menyimpan daftar kehadiran dan materi presentasi dalam file bidang baik. Catatan masalah khusus ditangani dan / atau dibahas dalam pertemuan ini dalam memo kepada Operasi Inspektur. Tanggung Jawab kritis Layanan Kontraktor 3. Menyediakan personil dengan kualifikasi yang memadai sesuai dengan kualifikasi di bagian Tanggung Jawab (Bagian 2.4) dan jika berlaku sesuai dengan 3 rd party kebijakan SSE dan persyaratan. 4. Memiliki program tempat pemeliharaan, program inspeksi, program pengendalian internal, dll, dan meninjau ini dengan EMDC-Drilling Manajemen seperti yang diminta. 5. Hal ini diinginkan untuk memiliki penerimaan inspeksi checklist untuk layanan pihak ketiga berikut: mud logging, pengujian peralatan produksi, pengangkutan sampah, penyimpanan, pembuangan, peralatan pernapasan, penyemenan Unit, wireline logging, perforating, dan LWD dengan sumber radioaktif. 2.2 PRE-SPUD PERTEMUAN Pertemuan pra-kentang akan diadakan sebelum dimulainya operasi pengeboran pada setiap kampanye pengeboran. Personil kunci (Operasi, Teknik, Geologi, Drilling Contractor, Kontraktor Pihak Ketiga, dll) harus menghadiri pertemuan ini. Dalam pertemuan tersebut, hal-hal berikut harus ditangani: 1. Keselamatan, kesehatan, dan kebijakan lingkungan. 2. Harapan dalam bidang berikut: Keselamatan Perencanaan pekerjaan Komunikasi Kepatuhan terhadap peraturan Prosedur darurat dan Rencana Kontinjensi Keamanan data baik 3. Pastikan bahwa kontraktor jelas memahami tanggung jawab mereka untuk transportasi dan pembuangan limbah kontraktor. 4. Memastikan bahwa kedua EMDC-Pengeboran dan kontraktor personil jelas memahami rantai komando dan personil yang bertanggung jawab untuk berbagai keputusan. 5. Diskusikan pengeboran sumur rencana termasuk geologi dan pengeboran relevan bahaya. 6. Mengkomunikasikan hasil penilaian risiko. 7. Salinan Program Pengeboran harus diserahkan kepada Kontraktor Pengeboran dan personil kontraktor pihak ketiga pada pertemuan pra-kentang, seperti yang diperlukan. 8. Operasi Integritas Sistem Manajemen, khususnya Manajemen Perubahan. 9. Pengeboran Program Manajemen Keselamatan 10. Bahan pertemuan pra-kentang proprietary non dapat diedarkan ke semua personil untuk referensi mereka. 3. KEAMANAN Semua personil (EMDC-Pengeboran dan kontraktor) harus mendapatkan, mempertahankan, dan menyimpan data dengan baik, terutama informasi yang berkaitan dengan kedalaman, masalah operasional, dan evaluasi formasi sesuai dengan persyaratan pekerjaan mereka dan melepaskan informasi tersebut kepada orang lain pada ketat "kebutuhan-to- tahu "dasar. Semua personel akan teringat sifat kepemilikan data baik geologi dan kritis. 4. EMDC DRILLING OPERASI PERSONIL TANGGUNG JAWAB Operasi Tanggung Jawab Superintendent 1. Komunikasi: Menyediakan komunikasi, yang diperlukan, antara Operasi Pengawas di Rig Pengeboran dan Manajemen EMDC-Drilling. Jauhkan Bidang Pengeboran Manager dan personil off-situs lain mengenai semua aspek operasi. Penyelesaian, dan Program Pengujian Produksi dan Prosedur. Melakukan audit, inspeksi, dan program keselamatan sesuai dengan OIMS dan Program Manajemen Drilling Keselamatan. Mengkoordinasikan bahan permintaan dan logistik dengan Bahan Group dan / atau Organisasi Produksi untuk memfasilitasi kedatangan tepat waktu persediaan yang dibutuhkan. Menyarankan Bidang Pengeboran Manajer kapan memulai rotasi Operasi Pengawas untuk memastikan lead time yang cukup untuk implementasi penuh OIMS. Menghadiri pertemuan keamanan situs rig dan pertemuan keselamatan pre-tour. Menghadiri rapat koordinasi harian dengan Supervisor Produksi pada platform berawak. Antarmuka setiap hari dengan Manajemen Produksi untuk menjamin kelangsungan operasional. Menghadiri rapat koordinasi harian dengan Supervisor Produksi pada platform berawak 2. Mengawasi Operasi: Pastikan bahwa semua operasi yang sesuai dengan OIMS, Drilling Program Manajemen Keselamatan, Operasi Pengeboran Manual, dan Drilling disetujui, Penyelesaian, dan Program Pengujian Produksi dan Prosedur. Berunding dengan Geological Personil untuk memastikan akuisisi data maksimum pada waktu minimum dan biaya. Berkomunikasi dengan kelompok akuntansi dan kelompok EMDC-DFS untuk memastikan dokumentasi yang tepat dan validitas biaya. Bekerja dengan Mesin staf untuk mengkompilasi manual, program, dan prosedur. Membantu Operasi Supervisor dengan keputusan sehari-hari yang diperlukan untuk membantu Kontraktor Pengeboran melaksanakan Pengeboran disetujui, 3. Koordinasi Lokal manual, Program dan Prosedur: Berkomunikasi permintaan dari Operasi Pengawas untuk membuat pengecualian (s) dengan pedoman atau prosedur tertentu dalam Operasi Pengeboran Manual. Meminta persetujuan lisan dari Lapangan Drilling Manager untuk pengecualian (s) dengan pedoman atau prosedur tertentu sesuai dengan Manajemen Perubahan Proses yang dijelaskan dalam OIMS. Catatan: Menggunakan penilaian yang baik, Operasi Inspektur mungkin mengambil pengecualian untuk pedoman atau prosedur worded dengan "harus" dan "harus" tanpa persetujuan terlebih dahulu. Meminta perubahan (s) ke Operasi Pengeboran Manual dari Operasi Pengawas sesuai dengan proses perubahan yang dijelaskan dalam panduan ini. Dan menyetujui prosedur yang diperlukan untuk melaksanakan Drilling disetujui, Penyelesaian, dan Program Pengujian Produksi dan Prosedur. Pastikan Operasi Pengawas menerima prosedur pengeboran pada waktu yang tepat. Beritahu Bidang Pengeboran Manager, sesegera mungkin, pengecualian (s) dibuat dengan pedoman atau prosedur Program Pengeboran atau Operasi Pengeboran Manual. Dan menyetujui rencana operasi keamanan. 4. Kepatuhan dengan ExxonMobil dan Pemerintah Peraturan: Menjadi akrab dengan hukum dan peraturan yang berlaku, dan memastikan kepatuhan. Pastikan bahwa semua izin peraturan yang berlaku berada di Rig Pengeboran untuk melakukan operasi. Pastikan bahwa laporan yang diperlukan (seperti yang diidentifikasi dalam Drilling disetujui, Penyelesaian, dan Program Pengujian Produksi dan Prosedur) dan / atau izin operasi dikirim ke badan pengawas yang berlaku. Meminta pengecualian peraturan baik dari badan pengawas yang diperlukan atau kontak peraturan yang tepat dalam ExxonMobil. Melaporkan insiden ketidakpatuhan. Menjaga pengetahuan saat ini panduan otoritas. 5. Kontraktor Pengawasan: Catatan: Semua persyaratan worded dengan "akan", "akan", atau "harus", akan disetujui oleh Bidang Pengeboran Manajer sebelum pengecualian. Pastikan bahwa semua manual keselamatan dan operasi yang tersedia di situs rig. Kontraktor Steward dan pemasok untuk memaksimalkan efektivitas biaya dan keamanan. Mengkoordinasikan kontraktor dan pemasok untuk memastikan kedatangan tepat waktu peralatan, perlengkapan dan personel. Memastikan kepatuhan kontraktor dengan semua ketentuan kontrak. Memantau kepatuhan kontraktor dengan kebijakan keselamatan, lingkungan, dan obat dan alkohol dinyatakan dalam kontrak. Drilling disetujui, Penyelesaian, dan Program Pengujian Produksi dan Prosedur. Memastikan kepatuhan Drilling Kontraktor dan Pihak Ketiga kontraktor dengan persyaratan kontrak yang sesuai. Memastikan bahwa semua pihak memahami tanggung jawab mereka per Pedoman ini. Berkomunikasi bahan persyaratan untuk Operasi Inspektur dan menindaklanjuti pengiriman; membantu logistik yang diperlukan. Mengkoordinasikan transportasi peralatan dan personil ke dan dari rig pengeboran yang diperlukan. Pastikan Kontraktor memelihara peralatan yang diperlukan dan melakukan operasi yang efisien dengan cara yang aman dan ramah lingkungan. Operasi Pengawas Tanggung Jawab 1. Mengawasi Operasional Bor Site: Pastikan Program Pengeboran dilakukan oleh karyawan kontrak dengan cara yang aman dan efisien. Bekerja dengan Engineering Staff untuk memastikan tujuan teknis secara operasional layak. Membuat rekomendasi untuk perubahan Drilling, Penyelesaian, dan Produksi Program Pengujian dan Prosedur untuk meningkatkan keselamatan dan / atau efisiensi. Bekerja dengan Kontraktor Pengeboran untuk mengembangkan prosedur dan berencana untuk menerapkan Program Pengeboran. Meninjau rencana harian Kontraktor Pengeboran dan mengkoordinasikan kegiatan Pihak Ketiga Kontrak Personil (yaitu Layanan Perusahaan) untuk melaksanakan 2. Pastikan Kepatuhan OIMS dan Program Manajemen Keselamatan Drilling Berkomunikasi persyaratan ExxonMobil dan harapan mengenai keselamatan dan kinerja untuk semua personil situs rig. Membantu Drilling Kontraktor dengan menerapkan Program Keselamatan sesuai dengan Program Manajemen Drilling Keselamatan. Memastikan bahwa peralatan dan prosedur memenuhi pedoman OIMS. Merekomendasikan perubahan (s) ke OIMS atau Operasi Pengeboran manual yang diperlukan untuk meningkatkan atau operasi tertentu yang benar. Beritahu Operasi Inspektur, pengecualian (s) yang perlu dilakukan untuk pedoman atau prosedur Operasi Pengeboran Pedoman tertentu. Setelah persetujuan yang tepat diberikan, mendokumentasikan pengecualian pada meredup dan mempertahankan catatan dari semua perubahan yang signifikan di rig. Memantau operasi sehari-hari untuk memastikan kepatuhan peraturan. Melaporkan setiap insiden ketidakpatuhan. Memastikan bahwa semua laporan dan catatan yang diperlukan adalah akurat dan lengkap dan mengeluarkan pada waktu yang tepat. Siapkan Pengeboran, Penyelesaian, dan Program Pengujian Produksi dan Tata berdasarkan semua tersedia informasi geologi dan pengeboran dari dekat diimbangi sumur di daerah. Pengeboran ini dan Program Evaluasi harus mencakup teknologi terbaik yang tersedia untuk operasi pengeboran. Jadilah berpengetahuan dari karakteristik operasi dan konstruksi dari semua komponen dalam sistem pengeboran yang akan digunakan dan memiliki pengetahuan tentang sistem dan prosedur yang mungkin dilaksanakan untuk meningkatkan efisiensi operasional alternatif. Pastikan staf operasional memahami dasar-dasar di balik sukses menerapkan teknologi baru. Tanggung Jawab pengeboran Insinyur 1. Memastikan Penerapan Teknologi Terbaik Tersedia dalam Operasi Pengeboran: Siapkan Rencana Pembangunan Situs mempertimbangkan kendala permukaan seperti penduduk lokal, logistik, dampak lingkungan, survei arkeologi, menyapu bawah, dan rig positioning. 2. Siapkan Standar dan Prosedur: Siapkan situs tertentu Tanggap Darurat / SIMOPS (jika berlaku) lampiran untuk Pedoman Operasi Siapkan Bor Nah Paket data untuk memenuhi persyaratan peraturan. Pastikan bahwa semua Standar dan Prosedur yang sesuai dengan OIMS. Siapkan Rencana Keselamatan Operasi sesuai dengan Program Manajemen Keselamatan 3. Mengkoordinasikan Penilaian Risiko untuk semua drillwells: Mengatur pertemuan dengan Operasi Supervisor, Operasi Inspektur, Lapangan Drilling Manager, personil Produksi, Kontraktor Pihak Ketiga, dan lain-lain (yang diperlukan) untuk menilai dan mengurangi bahaya tertentu yang terkait dengan operasi yang direncanakan. Selama proses Penilaian Risiko, yang Pengeboran Insinyur adalah untuk memastikan bahwa Formulir Penilaian Risiko / Action Laporan Status (Bagian 2 â € "GI) selesai dan diarahkan untuk disahkan. EMDC-DO telah menyusun daftar kasus dasar skenario acara kegagalan yang umum untuk sebagian besar kegiatan kami. Daftar ini harus ditinjau selama Risk Assessment dan jika ada skenario risiko tambahan diidentifikasi, ini harus didokumentasikan dengan menggunakan format yang disediakan dan diarahkan untuk disahkan dengan RAF. Sebuah memo penutup digunakan untuk berkomunikasi singkat hasil Penilaian Risiko. Paket Penilaian Risiko contoh telah dimasukkan dalam Bagian 2 â € "Lampiran G-II. Skenario risiko kasus dasar dapat dirujuk di manual OIMS. Persyaratan tambahan adalah penilaian BOPs rig untuk menentukan kepatuhan dengan Surface Pencegahan ledakan Dan Nah Kontrol Peralatan Manual. The ledakan Preventer Peralatan berupa Exception (Bagian 2 â € "Lampiran G-III) akan selesai dan diarahkan dengan RAF. Pengecualian diminta mengenai konfigurasi rig BOP akan disetujui melalui dukungan dari formulir ini. Semua item tindak lanjut akan didokumentasikan dalam paket Risk Assessment. Counsel Operasi Inspektur dan Pengawas Operasional pada kegiatan kritis dan masalah seperti kegagalan peralatan, lumpur dan masalah lubang (termasuk tektonik dan stabilitas lubang sumur), dll Memberikan bantuan teknis situs rig di deteksi tekanan abnormal, berjalan dan penyemenan string kritis casing / liners, operasi pengujian produksi, dan kontrol dengan baik. Memonitor dengan baik biaya dan memastikan bahwa semua biaya yang terus up to date dan akurat (termasuk DRS). Tinjau DRS Laporan dan memastikan bahwa input data yang akurat dan lengkap (coding, dll). Berpartisipasi dalam penyelidikan insiden wellsite, seperti yang dipersyaratkan di SMP. Lakukan persiapan tawaran dan analisis dalam hubungannya dengan Pengadaan Grup EMDC. Jauhkan Engineer Supervisi / Engineering Manager informasi dari semua kegiatan. Siapkan AFES dan Suplemen. 4. Memberikan Dukungan Rekayasa: Memberikan pengawasan pengeboran kemajuan sehari-hari untuk memastikan bahwa program pemboran dan Evaluasi dilakukan untuk menerapkan teknologi terbaik yang tersedia dan mengusulkan modifikasi, yang diperlukan. Mengevaluasi dan merekomendasikan bahan dan peralatan. Menganalisis kinerja pengeboran di kedalaman baik menengah dan bekerja dengan Operasi Inspektur dan Pengawas Operasional untuk menerapkan perubahan dalam prosedur dan peralatan berdasarkan hasil analisis ini. Mengembangkan dan menulis prosedur tambahan untuk semua pengeboran dan penyelesaian operasi besar. Jika penggunaan yang berlaku Standar Prosedur atau inti template ditemukan di Pedoman Operasi ini. Siapkan perkiraan biaya untuk pemilihan alternatif prosedural optimal dan modifikasi peralatan. Lengkapi Final Nah Laporan paket pada akhir setiap sumur. Umumnya, ini akan mencakup: Biaya juga akhir lembar ringkasan Program Keselamatan Bentuk EPI Quality Assurance / Quality Control Program Akhir Nah Laporan bentuk Program Kesiapsiagaan Darurat Produksi Casing dan Tubing penghitungan Program Pemeliharaan pencegahan Program Penilaian Risiko Sistem Kerja Izin Program yang sesuai Afiliasi Simultan Operasi (SIMOPs) untuk operasi pengeboran pengembangan yang berdekatan dengan fasilitas produksi. Program SSE jika berlaku Memperoleh dukungan teknis dari Pengeboran Teknis dan / atau URC yang diperlukan. 2,5 DRILLING PERSONIL KONTRAKTOR TANGGUNG JAWAB sistem berikut di tempat dan berfungsi dengan baik (Drilling OIMS manual Element 8, Bagian E dan Program Manajemen Keselamatan): Kontraktor pengeboran Tanggung Jawab: Mengacu pada Program Manajemen Keselamatan untuk daftar tanggung jawab tambahan 1. Beroperasi sebagai kontraktor independen dan melaksanakan Program Pengeboran untuk kepuasan Operasi Pengawas di Rig Pengeboran. 2. Mengoperasikan dan memelihara Rig Pengeboran dalam kondisi kerja yang aman dan sesuai penuh dengan EMDCDrilling spesifikasi teknis dan persyaratan peraturan lokal, termasuk persyaratan sebagaimana ditentukan dalam kontrak pengeboran. 3. Mengembangkan dan menggunakan prosedur kerja yang aman. Memastikan bahwa program dan / atau 4. Menyediakan teknisi ahli yang efisien dapat mengoperasikan Rig Pengeboran dengan cara yang aman dan ramah lingkungan. Lepas pantai Instalasi Manager (OIM) Perwakilan 1. Mewakili Kontraktor Pengeboran sebagai orang yang bertanggung jawab dan bertanggung jawab atas keseluruhan operasi dan keselamatan Unit dan personil Drilling. 2. Memastikan bahwa operasi rig memenuhi semua persyaratan peraturan yang berlaku. 6. Melakukan latihan, pertemuan keselamatan, dan pelatihan. 3. Melaksanakan Kontraktor Drilling Program Keselamatan 7. Memastikan bahwa operasi pengeboran dokumen personil Kontraktor Pengeboran benar dan bahwa semua laporan lengkap (bentuk tes IADC, BOP, log dek laut, dll) 4. Pastikan bahwa semua peralatan keselamatan dalam kondisi kerja yang tepat. Tanggung Jawab Koordinator Keselamatan 5. Mengamankan pelatihan yang diperlukan bagi personil Kontraktor Pengeboran. 6. Merencanakan dan mengawasi latihan pelatihan. 7. Memastikan kepatuhan / mengawasi Program SSE jika berlaku Tanggung Jawab toolpusher 1. Mengawasi personil Kontraktor Pengeboran yang melakukan operasi pengeboran terkait. 2. Memantau sumur bor untuk masalah lubang dan indikator tekanan abnormal. 3. Menyediakan link komunikasi antara Operasi Pengawas dan Kontraktor Pengeboran. 4. Membuat rekomendasi kepada Pengawas Operasional yang sesuai. 5. Memastikan bahwa perencanaan harian pertemuan diadakan yang berfokus pada melakukan operasi yang diperlukan dengan cara yang aman dan efisien. Lihat Drilling Program Manajemen Keselamatan 2,6 PIHAK KETIGA SERVICE PERSONIL KONTRAKTOR TANGGUNG JAWAB Tanggung Jawab Perusahaan Jasa 1. Mengoperasikan sebagai kontraktor independen yang akan membantu dalam Program Pengeboran mengeksekusi untuk kepuasan Operasi Pengawas onboard Rig Pengeboran. 2. Mengoperasikan dan memelihara peralatan layanan secara penuh sesuai dengan EMDC-Drilling spesifikasi teknis dan persyaratan peraturan lokal, termasuk persyaratan yang ditentukan dalam kontrak. 3. Mengembangkan dan menggunakan praktek kerja yang aman (termasuk JSAs ditulis untuk tugas-tugas penting yang berlaku). 4. Menyediakan teknisi ahli yang efisien dapat melakukan layanan yang diperlukan dengan cara yang aman dan ramah lingkungan. Mematuhi persyaratan personil kontrak dan pendek Layanan Karyawan (SSE) persyaratan program. 5. Setiap perusahaan layanan untuk menunjuk seorang wakil di lokasi, untuk mengkoordinasikan operasi dan layanan diarahkan oleh Perusahaan. 6. Memastikan bahwa semua personil perusahaan jasa menghadiri dan berpartisipasi dalam pertemuan keselamatan, latihan, dan pertemuan keselamatan operasi kritis (termasuk pertemuan keselamatan pretour). Pengeboran Cairan Insinyur Tanggung Jawab 1. Memelihara sistem fluida pengeboran sesuai dengan Program Pengeboran dan Bagian 6 dari manual ini. 2. Melakukan minimal dua (2) lengkap "Di" dan "Out" pemeriksaan cairan pengeboran harian selama operasi pengeboran. 3. Beritahu Operasi Supervisor perubahan signifikan dalam "Dalam" atau "Out" sifat dari sistem fluida pengeboran. 4. Beritahu driller dan toolpusher perubahan berat badan, konten klorida, gas, atau properti lainnya yang dapat menunjukkan perubahan signifikan dalam pembentukan atau masuk ke tekanan normal. Memastikan lumpur dalam kondisi login dengan statis â € "penuaan sampel" di "cairan 24-48 jam sebelum penebangan dan memeriksa properti. Laporan hasil untuk Operasi Pengawas 5. Mengambil "Out" sampel cairan pengeboran beredar sebelum menarik keluar dari lubang (POOH) untuk penebangan dan memberikan kepada Logging Insinyur Wireline bersama dengan, sampel filtrat cairan, dan filter cake terkait. Informasi ini akan disimpan pada log listrik. 6. Menjaga berat fluida pengeboran di pit aktif selama perjalanan dan setiap saat bahwa string bor keluar dari lubang. 7. Memastikan bahwa personel Drilling Kontraktor menimbang cairan pengeboran dan mengukur viskositas saluran cairan pengeboran dengan peralatan dikalibrasi dengan benar. 8. Pastikan bahwa Drilling Kontraktor personel merekam berat cairan pengeboran dan saluran viskositas pada interval 1530 menit yang diukur pada garis aliran dan lubang hisap. 9. Memonitor dan membantu Pengeboran personil Kontraktor ketika terus menerus berat cairan pengeboran di garis aliran dan hilir degasser ketika beredar cairan dipotong gas yang tinggi dari lubang sumur. 10. Menyarankan Operasi Pengawas harian kinerja semua peralatan padatan kontrol. 11. Membantu dalam mengoptimalkan peralatan padatan kontrol (misalnya, merekomendasikan ukuran layar untuk shaker serpih, dll). Menyarankan pengeboran kontraktor tentang persediaan layar. 12. Memperoleh persetujuan dari Operasi Pengawas sebelum menipiskan sistem fluida pengeboran untuk mempertahankan sifat fluida pengeboran ditentukan dalam Program Pengeboran. 13. Berkomunikasi semua perubahan yang direncanakan untuk tingkat pit dalam sistem aktif ke Logger Lumpur dan driller. 14. Memonitor sifat fluida pengeboran setiap hari untuk membantu mengidentifikasi tren atau perubahan tiba-tiba dari pengeboran perawatan cairan. 15. Siapkan Harian Pengeboran Cairan Laporkan sesuai dengan pedoman yang ditetapkan dalam Pasal 6. 3. Pastikan bahwa pengeboran directional praktik sesuai dengan standar anti-tabrakan yang terkandung dalam manual ini. 4. Lengkapi directional drilling survei pra-pekerjaan lembar data, menandatangani, dan hadir untuk supervisor operasi. 5. Mengisi formulir laporan BHA untuk semua BHA berjalan dalam sumur yang meliputi jenis koneksi, BPO, ID, panjang, dan nomor seri untuk setiap komponen. 16. Menjaga inventarisasi semua produk cairan pengeboran onboard Rig Pengeboran. 6. Membantu Pengeboran personil Kontraktor, seperti yang diarahkan oleh Operasi Supervisor, ketika menyesuaikan parameter pengeboran untuk mencapai kinerja BHA yang diinginkan. (Bit berat, RPM, dll) 17. Membantu Operasi Pengawas ketika memesan dalam jumlah yang tepat dari produk cairan pengeboran. 7. Mempertahankan rekor sumur bor lintasan di kantor Operasi Supervisor dengan menghitung azimuth dan kemiringan lubang sumur dari survei. 18. Pastikan bahwa Lembar Data Keselamatan Bahan (MSDS) yang tersedia untuk setiap produk cairan pengeboran di rig pengeboran. 8. Mempertahankan plot sumur bor saat di kantor Pengawas Operasional menggunakan catatan sumur bor lintasan. Tanggung Jawab pembor Directional 9. Memberikan biaya sehari-hari untuk Operasi Pengawas untuk peralatan directional / alat dan layanan yang disediakan oleh Directional Perusahaan. 1. Merekomendasikan Bawah Lubang Sidang (BHA) ke Operasi Pengawas untuk setiap bagian lubang sumur directional sebagaimana ditentukan dalam Program Pengeboran. 2. Mengawasi perakitan semua BHA directional oleh personel Kontraktor Pengeboran. 10. Menjaga inventarisasi peralatan directional / alat di Rig Pengeboran. MWD / LWD Insinyur Tanggung Jawab 1. Mempertahankan MWD Unit / LWD dan peralatan terkait pada lokasi yang ditentukan dalam kontrak. Tanggung Jawab lumpur Logger 2. Pastikan bahwa cukup alat MWD / LWD tersedia di lokasi sebagaimana ditentukan dalam kontrak. 1. Menjaga unit Mud Logging dan peralatan terkait di Rig Pengeboran sebagaimana ditentukan dalam kontrak. 3. Mempertahankan pengawasan 24 jam dari lubang sumur dari unit MWD / LWD selama operasi pengeboran. 2. Mempertahankan pengawasan 24 jam dari lubang sumur dari unit Mud Logging selama semua operasi pengeboran. 4. Mempertahankan catatan semua survei MWD diambil. 3. Beritahu driller dan Operasi Supervisor semua istirahat pengeboran, perubahan yang tidak dilaporkan di tingkat pit, peningkatan aliran, dan unit gas yang tinggi. 5. Membantu driller Directional, seperti yang diarahkan oleh Operasi Supervisor, ketika menghitung azimuth dan kemiringan lubang sumur dari survei MWD. Pastikan bahwa faktor koreksi survei yang underst banjir dan disahkan oleh Drilling Engineer, Operasi Supervisor, dan Directional Driller. 4. Beritahu driller dan Operasi Pengawas dari setiap perubahan stek, seperti kuantitas, ukuran dan bentuk atau parameter yang dapat menunjukkan peningkatan tekanan air pori atau adanya hidrokarbon. 6. Lengkapi directional drilling survei pra-pekerjaan lembar data, menandatangani, dan hadir untuk supervisor operasi. 5. Memonitor tangki perjalanan sementara di perjalanan, penebangan, dan waktu lain bahwa tangki perjalanan digunakan. 7. Menjaga penghitungan pipa yang terpisah dari driller ini pipa penghitungan. 6. Menjaga penghitungan pipa yang terpisah dari driller ini pipa penghitungan. 8. Memberikan Operasi Pengawas salinan MWD yang / LWD log harian dan fax salinan log untuk personil ExxonMobil seperti yang diarahkan oleh Pengawas Operasional / Wellsite Geologist. 7. Menjaga sketsa lubang sumur saat yang mencakup volume dan kapasitas masing-masing bagian lubang di lubang sumur. 9. Melindungi personil dari paparan sumber radioaktif jika sumber seperti yang hadir di lokasi untuk layanan LWD. 8. Mengkalibrasi detektor gas minimal sekali setiap 12 jam dan setelah beredar di luar unit gas dekat saturasi. 9. Memberikan Operasi Pengawas salinan Mud Log dan Mud Logging Laporan harian dan fax salinan ke personil EMDC sebagaimana ditentukan oleh Pengawas Operasional / Wellsite Geologist. 10. Pastikan bahwa Lembar Data Keselamatan Bahan (MSDS) yang tersedia untuk setiap produk mudlogging di rig pengeboran. Catatan: Dimana unit logging lumpur memiliki gas hidrogen makan Flame Ionization Detector (FID), tanda-tanda peringatan posting yang menunjukkan mudah terbakar / karakteristik ledakan gas. Periksa selang (biasanya polyflow) setiap 2-3 bulan, dan mengganti jika sudah terjepit, rapuh, atau berubah warna dari warna yang jelas atau putih normal (OIMS elemen manual 6). Tanggung Jawab Cementer 1. Menjaga unit penyemenan dan peralatan terkait yang ditentukan dalam kontrak. 5. Mengkalibrasi sistem aditif cair (LAS), jika berlaku, sebelum memulai operasi penyemenan. 6. Mengumpulkan semen dan aditif semen sampel dari semen yang diperlukan P-tank dan sistem aditif cair sebelum memulai operasi penyemenan. 7. Mengoperasikan unit penyemenan selama penyemenan operasi seperti yang diarahkan oleh Pengawas Operasional. 8. Menjaga inventarisasi semua aditif semen dan peralatan penyemenan pada Unit Pengeboran. 9. Membantu Operasi Pengawas ketika memesan dalam jumlah yang tepat dari produk semen. 10. Dokumen semua memompa / penyemenan kegiatan sesuai dengan persyaratan peraturan menggunakan peralatan rekaman (chart recorder, densiometers, dll) dan memberikan Operasi Pengawas dengan grafik didokumentasikan dengan baik. 2. Menyarankan Operasi Supervisor setiap kekurangan dalam peralatan semen penyimpanan / transfer. 11. Pastikan bahwa Lembar Data Keselamatan Bahan (MSDS) yang tersedia untuk setiap produk semen di rig pengeboran. 3. Menghitung volume lumpur semen, campuran air, dan perpindahan untuk memperkuat operasi sebagaimana ditetapkan dalam Program Pengeboran. 2,7. PENCEGAHAN OPERASI KHUSUS 4. Memverifikasi perhitungan Volume semen dengan Operation Supervisor sebelum memulai operasi penyemenan. 1. Operasi helikopter Memberikan kargo akurat dan berat memanifestasikan untuk semua transportasi helikopter. Lebih rendah dan mengamankan semua booming derek sebelum pendaratan helikopter / keberangkatan. (Operator crane harus melangkah keluar dari taksi derek sampai pilot telah berhenti rotasi baling-baling.) Membuat pengumuman dari pendaratan helikopter / keberangkatan. Memberikan orientasi keselamatan / membolos petunjuk bagi penumpang. Menetapkan prosedur pelacakan penerbangan. Helideck sistem pemadam kebakaran harus dijaga saat pengisian bahan bakar. Cepat / pengisian bahan bakar panas tidak berwenang. Lihat Keselamatan Manual untuk pengecualian. 2. Operasi tambat kapal Gunakan "jelas Deck of Personnel" kebijakan di perahu bekerja ketika kawat kerja di bawah tekanan. 3. Casing Tekanan Pemantauan Tekanan casing anulus harus dipantau mingguan di semua rig dengan wellheads permukaan. Jika tekanan casing terdeteksi, itu harus dilaporkan pada Daily Drilling Report. Situasi harus ditinjau dengan Operasi Inspektur untuk menentukan apakah tindakan korektif, dijamin, misalnya berdarah off, peningkatan pemantauan, dll 4. Kembali Katup Tekanan Setiap kali katup tekanan kembali (BPV) akan dihapus dari gantungan tabung, pelumas yang harus dipasang dan berlabuh. Sebelum mengambil steker, konfirmasi tekanan pemerataan harus dilakukan, jika memungkinkan. Jika bekerja pada sebuah sumur dengan H 2 gas S, semua pekerja di daerah akan menutupi sampai saat mengambil steker. 5. Rotary Table Insert Bushing Kunci Bushing meja putar insert harus tetap terkunci di semua kali (atau dihapus) kecuali jika prosedur khusus meminta mereka untuk menjadi sementara terkunci. Sebuah cara visual menentukan status terkunci harus disediakan. 6. Pohon Natal Peralatan Punya OEM (Original Equipment Manufacturer) perwakilan layanan pada lokasi selama instalasi dan tekanan pengujian semua peralatan pohon natal. Semua wellhead dan pohon natal peralatan memiliki potensi untuk menjebak tiba-tiba tekanan mematikan antara segel, di gerbang rongga katup, di bawah colokan pipa, sekrup kuncian, fitting gemuk dan di porting kecil yang telah menjadi terpasang. Beberapa model katup gerbang sangat rentan untuk menjebak tekanan di rongga katup gerbang. Tekanan terjebak paling umum terjadi pada perpecahan katup gerbang gaya dan terutama model WKM. Setiap katup yang memiliki alat kelengkapan layanan, yang mengakses tubuh katup, harus memiliki tanda peringatan permanen menyatakan "PERINGATAN: Katup ini memiliki potensi untuk internal tekanan perangkap" 7. Unit Mud Logging Di mana unit logging lumpur memiliki gas hidrogen makan Flame Ionization Detector (FID) tanda-tanda peringatan posting yang menunjukkan mudah terbakar / karakteristik ledakan gas ini. Periksa selang (biasanya Polyflow) setiap 2-3 bulan, dan mengganti jika sudah terjepit, rapuh, atau berubah warna dari warna bening atau putih normal. Tanggung Jawab: Operasi Pengawas Otoritas persetujuan untuk pengecualian: Operasi Inspektur. INFORMASI UMUM BAGIAN 2 - GI LAMPIRAN DRILLING OPERASI manual-JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 1 Pertama Edition - Mei 2003 BAGIAN 2 - LAMPIRAN G-II MEMORANDUM dicatat bahwa keempat skenario dibahas dalam lembar kerja terlampir unik ke lokasi ini dan tidak tercakup oleh ada EMDC Base Case Risk Assessment. The EMDC Basis Kasus Kegagalan Acara Skenario Daftar disertakan untuk referensi Anda. Jika Anda harus memiliki pertanyaan tentang penilaian ini, jangan ragu untuk menghubungi setiap anggota tim untuk klarifikasi. xc: HJ Longwell, III Ensco 99 Drilling Pengawas EMDC DRILLING ORGANISASI TO: Clyde J. Baldwin DARI: Grand Isle 16 OCSG 031 R-22 ST # 1 "Sandberg" Pengeboran Tim DATE: 17 Februari 2000 SUBJ: OIMS Risk Assessment untuk GI 16 OCSG 031 R-22 ST # 1 "Sandberg" Drillwell Konsisten dengan Operasi Integritas Manajemen, tim pengeboran telah menyelesaikan â € œRisk Assessmentâ € untuk GI mendatang 16 OCSG 031 R-22 ST # 1 "Sandberg" drillwell. Terlampir silahkan menemukan lembar kerja skenario untuk empat insiden diidentifikasi sebagai potensi bahaya oleh tim. Harap Elemen 2 Kustodian Penilaian Risiko ELEMEN PENILAIAN RISIKO 2 KEGAGALAN EVENT SKENARIO LIST - DASAR CASE Deskripsi Permukaan meniup-out dengan BOP tumpukan pada drillwell. Tong kang x Ta na h Pero n x x Jack-up ** x Permukaan meniup-out dengan pengalir pada drillwell. x x Permukaan blow-out karena permukaan peralatan (koneksi drillpipe, katup pengaman, kepala kontrol) kegagalan selama perforating underbalance, perforasi bergelombang, atau juga mengangkat / pengaliran operasi. Permukaan meniup-out ketika melakukan operasi selesai dalam cairan jernih dengan perforasi terbuka. Bahan peledak (perforating senjata, tali tembakan, dll) diledakkan di permukaan. x x Cuaca buruk dampak pengeboran operasi. x Pengeboran ketidakpatuhan peraturan atau pelanggaran. x x x x Derrick mengangkat tongkang kecelakaan / kecelakaan. x x Rig pengeboran derek kegagalan / operator kecelakaan. x Rig peralatan mengangkat kegagalan / kecelakaan. x Bor rig dukungan kapal / kendaraan kecelakaan. x Helikopter / pesawat amfibi kecelakaan / kecelakaan. x Berbahaya kecelakaan kimia / kecelakaan. x Bahan bakar, cairan pengeboran berbasis minyak, atau minyak mentransfer tumpahan. x Kritis pasokan atau personil transfer dilarang oleh cuaca. Jack-up rig pukulan-melalui. x Tongkang rig terbalik selama tenggelam operasi / refloating. x Laut tabrakan kapal dengan rig / platform. x x x Insiden pekerja di rig. x Api / ledakan di rig. x Orang ke laut. x x x ** Berlaku untuk R-22 ST # 1 "Sandberg" drillwell x x x x x Sekoci peluncuran kegagalan. Diver insiden. x x x x x x x x x x x x x x x x x x x TAMBAHAN SKENARIO KEGAGALAN EVENT KHUSUS UNTUK ENSCO 99 dan R-22 ST # 1 "Sandberg" DRILL BAIK Deskripsi Tong kang Pengeboran minyak Berdasarkan Cairan Injeksi annular Kecelakaan / Kecelakaan Minyak Berbasis Drilling Fluid Tumpahan Pengeboran Cairan Api minyak Berbasis di Pits Nah Kontrol Insiden Karena mencolok Offset baik. ** Berlaku untuk R-22st # 1 "Sandberg" drillwell Ta na h R-22 ST # 1 "Sandberg" -SPECIFIC OPERASI RISIKO KERJA # 1 EMDC MATRIX RISIKO B SEB UAH C D A k u E H II E A K U A K U A K U F Unexpected ditemukan ketika pengeboran lubang permukaan tanpa konduktor. KONSEKUE NSI: KESEHATAN DAN KEAMANAN Aku P GANGGUAN PUBLIK AKU AKU AKU TANGGAPAN WAKTU: Menit untuk personel rig untuk menanggapi kejadian awal. Alternatif UNTUK OPERASI: Bor dan menetapkan "konduktor 13-3 / 8 pada sekitar 1000 '. IV Hipotetis KEGAGALAN EVENT SKENARIO: Masalah Gas dangkal yang tidak direncanakan selama Konduktorkurang Drilling LOKASI: Jack-up Rig Pengeboran KETERANGA N: gas dangkal TINDAKAN Pencegahan: Semua tindakan pencegahan yang bijaksana akan diambil untuk mencegah kejadian ini. 1. Sebuah tinjauan menyeluruh dari program pengeboran ST54 terbaru dilakukan untuk mengamati unit gas yang diharapkan, bobot lumpur digunakan, dll. B21 ST-1 di 2/98 adalah drillwell terakhir sebelum saat program yang terencana 3 ini. DAMPAK LINGKUNGAN II B-31, "Hesperides," adalah baik 1 dalam program 3 dengan baik saat ini. R-22 ST # 1, "Sandberg," akan menjadi 2 baik dalam program ini. 2. Langkah-langkah pencegahan dicatat dan direncanakan untuk R-22 ST # 1 meliputi (1) pengeboran kontrol untuk mempertahankan lumpur rendah wei GHT "keluar" untuk preventlost kembali dan (2) penyusunan rencana Pengembalian Hilang. 3. Sebuah tinjauan menyeluruh dari sumur log dekat permukaan menunjukkan tidak adanya pasir hidrokarbon-bantalan dangkal. Kedua originalb-1 log, yang lebih baru B-21 dan B-31 log telah dievaluasi. 4. Tekanan casing telah diukur pada semua annuli. Yang baik dengan tekanan terkenal (110 psi) pada casing permukaan adalah bledto nol dan tetap nol setelah pemantauan 24 jam; B-21 akan terus dipantau dan dilaporkan sampai kentang. 5. Evaluasi gangguan baik menunjukkan bahwa (a) paling sumur dari "B" atform -PL dibor secara vertikal dan karena itu inparallel ke kedalaman dekat 5000 ', dan (b) arah driller akan mengebor vertikal untuk ~ 4500' MD, yang di bawah pengaturan kedalaman casing permukaan untuk "Sandberg," dan kemudian menendang-off MITIGASI RENCANA: Sebagai hasil dari pertemuan SIMOPS dengan pengeboran, produksi, dan personil operasi yang hadir, rencana berikut didirikan: 1) PIC adalah EMDCDO Drilling Superintendent. 2) Link penutupan darurat ditetapkan oleh operasi lapangan Nopo. 3) link Komunikasi ditetapkan dengan Nopo bidang mandor dan GI 16 P basis platform, yang merupakan platform G. Pengalir akan nippled dan diuji sementara lubang permukaan pengeboran. Latihan pengalir akan dilakukan dengan semua kru. Pipa drive offset untuk-B 30 juga, Adonis, yang belum dibor, akan blanked off di permukaan untuk mencegah saluran alternatif ke permukaan. RISIKO LEMBAR KERJA # 1 S E B U A B C D E Kecelakaan / Kecelakaan H LOKASI: GI 16 R-Platform dan Ensco 99 A k u KETERANGAN: kesalahan penanganan, hasil kegagalan mekanis dalam eksposur personil untuk Oil Based Drilling Fluid dan aditif potensial. I I A K U A K U KONSEKUENSI: TANGGAPAN WAKTU: Menit untuk menanggapi cedera personil. Potensi respon diperpanjang untuk kebakaran. H P , E , F Hipotetis KEGAGALAN EVENT SKENARIO: Minyak Berbasis Drilling Fluid Injection annular GANGGUAN PUBLIK LINGK AN DAM AKU AKU AKU A K U I V KESEHATAN DAN KEAMANAN Alternatif UNTUK OPERASI: pengeboran berbasis minyak Toko stek cairan dalam kotak dan kapal melalui perahu kembali ke tanah. Ini akan memberlakukan kenaikan biaya yang signifikan pada ini juga. Operasi ini alternatif disertai dengan risiko sendiri itu nya. TINDAKAN Pencegahan: Pelatihan personil (HAZCOM). MSDS tersedia. APD yang tepat. Peralatan inspeksi, dan pemeliharaan. Hydrotesting pengujian / kebocoran dari semua fasilitas baik injeksi. Injeksi air laut sebelum setiap IV IV minyak berdasarkan lumpur / stek. JSA ini. Rig akan diatur untuk "Operasi ZeroDischarge," dengan colokan yang sesuai diatur dalam semua jack-up dek saluran air. Kontrak dengan kontraktor yang kompeten, baik Apollo atau Jasa Injection Nasional. Rok injeksi dipasang di sekitar puncak casing permukaan MITIGASI RENCANA: Medic di tempat untuk lokasi air. Peralatan darurat. APD yang tepat. Api tim pertempuran dan pelatihan. RISIKO LEMBAR KERJA # 2 Hipotetis KEGAGALAN EVENT SKENARIO: Minyak Berbasis Drilling Fluid Tumpahan S E B U A H B C D E A k u I V H LOKASI: GI 16 R Landasan dan Ensco 99 KETERANGAN: tumpahan minyak di air selama setiap operasi transfer minyak karena kegagalan mekanis dan / atau kesalahan manusia. KONSEKUENSI: KESEHATAN DAN KEAMANAN IV E , I I F A K U E , F P a. - Acara potensi kegagalan ini memiliki potensi untuk perhatian media yang merugikan. b. - Ukuran Tumpahan tergantung. A K U TANGGAPAN WAKTU: Jam untuk hari mengandung dan membersihkan tumpahan transfer minyak. A K U Alternatif UNTUK OPERASI: Jangan gunakan minyak lumpur berbasis (potensial diferensial mencuat, torsi yang lebih tinggi, GANGGUAN PUBLIK III (a) LINGK DAM II (b), dan ketidakmampuan utama untuk mencapai tujuan target) TINDAKAN Pencegahan: Kebijakan & Prosedur Transfer Oil. Ensco 99 akan berada di "Nol Discharge Operasi". Berdasarkan personil perusahaan pembuangan cairan pengeboran minyak di papan. Terbaru upgrade selang vibrator. Peralatan untuk diperiksa dan diuji untuk kebocoran sebelum pengiriman pertama OBM. Transfer selang harus memiliki sertifikasi dan pengujian rekaman yang sesuai sebelum pengiriman pertama OBM. Transfer selang harus diperiksa secara berkala dan harus diganti jika ada kekurangan dicatat. Latihan akan dilakukan dengan semua personil mentransfer sebelum pengiriman pertama OBM. Semua personil yang tepat akan selalu berkomunikasi selama transfer OBM, terutama dengan kapten kapal, dan tidak ada aktivitas yang berhubungan dengan gerakan OBM akan tanpa pengawasan. Kondisi cuaca akan menguntungkan untuk transfer dari kapal dan mooring baris harus diperiksa secara berkala. Peralatan proteksi kebakaran akan berlokasi di posisi strategis untuk melindungi personil dalam ruang dan kantor perubahan. JSAs untuk semua kegiatan akan disiapkan dan menyeluruh Ulasan sebelum aktivitas yang berhubungan dengan OBM. APD yang tepat akan digunakan ketika menangani OBM. MITIGASI RENCANA: Tumpahan Minyak Rencana Kontinjensi untuk lokasi air, latihan tanggap darurat. RISIKO KERJA # 3 S E B U A H B C D A k u E H I I H A K U A K U A K U H E , F Alternatif UNTUK OPERASI: Jangan gunakan berdasarkan pengeboran cairan minyak (terlalu merugikan kinerja pengeboran dan biaya). Risiko lainnya yang melekat pada operasi pengeboran. E , I V F , P Hipotetis KEGAGALAN EVENT SKENARIO: Minyak Berbasis Pengeboran Api Cairan di Pits LOKASI: Ensco 99 sementara pengeboran di GI 16 Platform R. KETERANGAN: Fire / Ledakan di rig pengeboran disebabkan oleh pengapian disengaja cairan pengeboran minyak berbasis. Hal ini dapat disebabkan oleh pengelasan, percikan listrik, dll KONSEKUENSI: KESEHATAN DAN KEAMANAN I, II, III (a) - acara Kegagalan ini memiliki potensi untuk perhatian Media merugikan. TANGGAPAN WAKTU: Menit ke jam untuk memadamkan. Potensi respon berlarut-larut untuk insiden besar. TINDAKAN Pencegahan: Pits dan shaker memiliki Skelton Foam Deluge System. Busa Deludge Sistem: Prosedur uji akan ditinjau, tes air lengkap sistem & review busa banjir menutup & prosedur startup. Exxon Keselamatan Manual, JSAs. Ventilasi yang tepat dan membersihkan ruang tertutup. Spesifikasi daerah pengelasan aman dan daerah klasifikasi listrik (lihat API RP 500). Praktik rumah tangga yang baik. Gas dan deteksi kebakaran sistem. Inspeksi listrik independen dari rig. Program pemeliharaan preventif kontraktor. Pelatihan personil tentang bahaya lumpur berbasis minyak. Lumpur minyak memiliki titik nyala yang tinggi. Peralatan kebakaran yang memadai. GANGGUAN RENCANA MITIGASI: PUBLIK medis di lokasi untuk operasi air. Kontraktor api pelatihan pertempuran dan peralatan. Rencana evakuasi darurat. Latihan kebakaran. Escaid 110 invert lumpur minyak emulsi biasanya memiliki titik nyala> 220A ° F RISIKO LEMBAR KERJA # 4 S E B C D E KETERANGAN: Sementara pengeboran, tendangan terjadi sebagai akibat dari mencolok offset dengan baik. Kembali kehilangan berikutnya selama operasi pengendalian juga menyebabkan ledakan dan tumpahan di permukaan. B U A H A k u H I I F KOMENTAR: Hanya satu hidup sumur bor pada platform R, R-21. KONSEKUENSI: A K U A K U KESEHATAN DAN KEAMANAN Aku P E A K U (a) - acara Kegagalan ini memiliki potensi untuk perhatian Media merugikan. TANGGAPAN WAKTU: Menit untuk menanggapi kejadian awal, hari sampai beberapa minggu untuk mengontrol ledakan. Alternatif UNTUK OPERASI: risiko Inherent. Bor berdiri bebas jauh dari lubang bor saat ini. I V KEGAGALAN hipotetis EVENT SKENARIO: Nah Kontrol Insiden Akibat mencolok Offset Nah. LOKASI: Ensco 99 sementara pengeboran di GI 16 Platform R. TINDAKAN Pencegahan: Nah desain jalan dengan penekanan pada menghindari tabrakan. Gunakan dua pengebor arah merencanakan bertabrakan saat dekat untuk mengimbangi lubang bor. Kritis juga akan sementara P & A'd atas kedalaman pendekatan terdekat dan GLG berdarah off dengan baik. Akan menggunakan Op Tek Bulletin # 99-111 sebagai panduan untuk LINGK GANGGUAN PUBLIK IMPACT III (a) III menghindari tabrakan lubang sumur. EMDC praktek pengendalian baik dan kebijakan. Secara teknis dan operasional praktek pengeboran suara. Pedoman pengujian EMDC BOP dan EMDC BOP standar pengujian fungsi. Spesifikasi desain casing, program inspeksi casing, koneksi casing membuat prosedur, tes tekanan casing, kepala sumur QA / QC program. Rig pelatihan kontrol dengan baik atasan, NODO kebutuhan staf tenaga teknis dan operasional. Personil Ensco juga mengontrol pelatihan, latihan kemampuan kru tur pengeboran, rig pengeboran alarm kritis dan instrumentasi. NODO katup kritis Program "soft-kunci". Memadai diimbangi pengeboran sumur dan informasi tekanan formasi. MITIGASI RENCANA: medis di lokasi. Tumpahan minyak rencana tanggap. Operasi kritis dan rencana pembatasan. Gagal-aman permukaan dan bawah permukaan ESD sistem. Peralatan pemadam kebakaran / pelatihan. Pengeboran bersama / produksi latihan evakuasi. INFORMASI UMUM digu nak BAGIAN 2 - LAMPIRAN G-III ExxonMobil Pengembangan Perusahaan â € "Organisasi Pengeboran an kem bali di nonbeb BOPE PENGECUALIAN an bant alan Nah Nama: Risiko Kategori: Insinyur API Bidang / Prospek: Kedalaman: Engr. Supv. County, Jeni s 6B flen Negara ppm H 2 S: Opt. Supt. sa den Rig: 250 ppm HS ROE: Drlg. Engr. Mgr. gan Typ Bidang Drlg. Mgr. eR alur dasa r b. Ren dah baja karb on Typ eR cinc in pen ggu naa n gask et dan bole h data r. (Fla nge baut pen geta tan pem erik saan dipe rluk an, BO P WP â ‰ d. Han ¤ ya 300 satu 0 katu psi). p kelu c. Gas aran ket yan cinc g in dipe baja rluk karb an on pad rend a ah setia dipe p rbol bagi ehk an an kep dala ala m sum gas ur atau (Xm min as yak poh ling on kun WP gan â asa ‰ m ¤ (BO 300 P 0 WP psi). â ‰ e. Pan ¤ el 300 kont 0 rol psi). BO P di aku Emisi data mul ator Galon Konsumsi Bahan Bakar Rig (US) saja. f. Kap asita s Data Kepatuhan peraturan aku mul Pelampauan dilaporkan badan pengatur * ator cuk Nomor ke Tidak udara November ini up jika Tidak untuk waterNo. RQ pelampauan sem ua p reve Tidak untuk LandNo. Denda nter s dap OtherFines Jumlah ($ US) at Total pelampauan DRILLING OPERASI manual-JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 1 Tumpahan minyak *> 1 bbl. No. untuk landVol. mendarat bbls. Tidak untuk waterVol. untuk waterbbls. Pertama Edition - Mei 2003 INFORMASI UMUM BAGIAN 2 - LAMPIRAN G-IV ExxonMobil Pengembangan Perusahaan Pengeboran Lingkungan Indikator Kinerja Laporan Nah: Lokasi: Lepas pantai atau Onshore: Kimia Tumpahan *> 100 kg. No. untuk landVol. untuk landkgs. Tidak untuk waterVol. untuk waterkgs. [Vol. (Gal.) * Khusus Gravity (£ 8,3. / 1 gal) * (1kg / 2.2 lbs.)] = Massa (kg) * Silakan kirim semua tumpahan atau terlampaui laporan ke Drilling Koordinator Lingkungan fax 281-4234337 Data sampah Pengeboran Cairan Jenis: SW, FW, NAF (OBM / SBM / LAINNYA) Stek bor (Hanya lengkap untuk bor pemotongan dengan NAF dibuang ke laut) Termasuk menyelesaikan rekaman dalam Final Nah Laporan dan mengirimkan salinan ke Koordinator EMDC Drilling Lingkungan. DRILLING OPERASI manual-JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 1 NAF Bor Stek dibuang di Vol laut. bbls. % NAF pada Stek Pertama Edition - Mei 2003 MARINE OPERASI Gunakan pengukur volume yang lubang 1. MARINE OPERASI Limbah Berbahaya (diklasifikasikan sebagai limbah berbahaya oleh pihak berwenang) Net Generat ed Ekste rnal Daur Ulan g (lbs.) (lbs.) Berk elanj utan (lbs.) 2. Site Survey / Bawah Sapu / SIMOPs ulasan 1 3. Pindah 2 1. Bergerak Jack-up rig 3 2. Bergerak Landasan Rigs 4 3. Bergerak Barge Rigs 5 3. Bergerak dan Positioning 6 Perio dik (lbs.) 4. Pra-Loading (Jack-up Only) 7 Insinyur: Eng. Manajer: 5. Kargo Transfer 8 1. Kewaspadaan 9 2. Batas cuaca 9 3. Lift berat (Jack-Up Lift di Kelebihan dari 10 MT) 9 7. Meninggalkan Rig Bor-Contoh 33 4. Lifting Operasi 10 9. Khusus Drills 35 5. Pedoman Rigging 11 10. Aspek utama dari latihan 37 6. Peralatan Pemeliharaan 15 3.6 Transportasi & Personalia Transfer 20 1. Cargo Transport 20 2. Operasi helikopter 21 3. Personil TransportasiHelicopter 22 4. Personil TransportasiPasokan atau Stand-By Boat 24 3,7 Kelautan Pelatihan 24 1. Umum 24 2. Pelaporan & Bor Frekuensi 25 3. Proses Bor laut 26 8. Man Overboard Bor 34 3,8 Kapal Collision Avoidance 37 1. Deteksi 38 2. Radar Perhiasan Prosedur 38 Lampiran GI SIMOPs Checklist Memo Form Deviasi Lampiran G-II SIMOPs Lampiran G-III Studi Pile Interaksi dengan Jack-Up Rig Operasi Lampiran G-IV Pra-Startup Inspeksi untuk Baru Armada jackup Rig Pengeboran ______________________________________ _____________________________________ ___ OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING 4. Api Drills 27 PERTAMA EDITION - MAY 2003 5. Api Bor-Contoh 29 6. Abaikan Rig latihan 30 3.1 SITUS SURVEY / BOTTOM SWEEP / SIMOPS REVIEW Untuk operasi laut yang berlaku, situs studi pengoperasian tertentu dapat dilakukan oleh EMDC Technology Group atau Marine Engineering kontraktor disetujui. Up-to-date gambar platform produksi dan fasilitas untuk menilai potensi gangguan dan mengidentifikasi persyaratan SIMOPs terkait dengan melakukan Jack-Up Operasi Pengeboran atas platform produksi. Diagram dukungan platform Produksi menumpuk posisi dan didorong kedalaman untuk menilai JUR spud kaleng dan platform tumpukan potensi gangguan (pastikan untuk memperhitungkan untuk platform produksi kaki adonan). Bagian 3 -Appendix G-IV ("Amoco / McClelland Studi" Jack-Up Rig Gangguan Tanah ") adalah subyek dari sebuah memo yang ditulis oleh EJ Henkhaus. The Drilling Engineer untuk mendamaikan semua Miru berencana dengan memo ini (dan Teknologi Sipil ExxonMobil kelompok, jika diperlukan). Kegempaan Regional (yaitu, jumlah dan intensitas gempa bumi) di daerah rawan gempa. Adanya rembesan alami. Sastra (perusahaan dan masyarakat). Sebelum rig baru ditambahkan ke armada, serangkaian pemeriksaan harus dilakukan pada rig baru. Bagian 3 -Appendix GV adalah panduan untuk inspeksi khusus yang harus dilakukan. Inspeksi tambahan dapat diselesaikan seperti yang dipersyaratkan oleh rig atau program pengeboran persyaratan tertentu. Sebelum bergerak rig ke lokasi baru atau yang sudah ada sebelumnya, penilaian bahaya dangkal situs (OIMS Elemen 3) harus dilakukan. Penilaian tersebut akan membantu dalam lokasi kabel laut, jaringan pipa, pelampung, batu, gas dangkal, dll harus hambatan seperti ada di sekitar lokasi yang diusulkan. Penilaian harus mencakup tinjauan dari informasi yang ada untuk bukti bahaya dangkal. Sumber mungkin termasuk yang berikut: Offset baik / data tanah, menyapu bawah sebelumnya, survei lokasi, data geologi dan geofisika yang tepat, dan offset tekanan baik casing. Up-to-date peta jaringan pipa (termasuk platform yang vent / garis flare) dan data mengenai posisi dan karakteristik rig sebelumnya yang bekerja di daerah. Berdasarkan hasil penilaian bahaya dangkal, survei situs dapat dilakukan. Survei situs mungkin termasuk: Profil batimetri melalui Echo Sounder â € ¢ profiler Sub-bottom 2-D seismik resolusi tinggi multifold Side scan sonar Magnetometer Meninjau potensi JUR kaki menjalankan atau pukulan melalui selama operasi pra-beban. Pengalaman preload sebelumnya di daerah dan / atau tanah membosankan analisis akan menjadi prediktor yang baik dari ini. Sebuah menyapu bawah area di mana JUR akan diposisikan berdekatan dengan platform produksi dilakukan untuk setiap program pengeboran JUR / Produksi. Perusahaan yang menyediakan menyapu bawah akan memberikan diagram daerah menyapu bawah mengidentifikasi pipa ditandai dan setiap penghalang bawah air atau kentang sebelumnya dapat lubang diidentifikasi. Ini harus dimasukkan dalam Prosedur MIRV. Jika ada penundaan yang signifikan antara saat menyapu dilakukan dan ketika rig benarbenar akan pindah ke lokasi (misalnya lebih dari 30 hari) atau jika ada aktivitas yang signifikan di dekat platform (misalnya konstruksi), meninjau dengan Produksi dan kontraktor rig untuk menentukan apakah menyapu bawah lain harus dilakukan. Boring tanah (100 '-150') Untuk rig JU, kecukupan JUR panjang kaki harus dipertimbangkan. Ini akan mencakup kentang dapat penetrasi berdasarkan penetrasi sebelumnya maksimum atau tanah membosankan analisis perkiraan (jika yang pertama kali di lokasi) ketinggian, kedalaman air, diperlukan JUR lambung celah udara, produksi platform deck, dan peralatan. EMDC yang tepat dan manajemen EMPC dan badan pengatur. Daerah menyapu harus mencakup semua wilayah di mana rig Jack-Up bisa mengatur kakinya ke dasar laut (umumnya, ini adalah dalam 500 'dari platform). Semua pipa dalam 490 'dari kaleng JUR kentang harus ditandai dengan reflektor sonar dan pelampung permukaan, area masuk / keluar yang aman ditutup dengan spidol, atau keringanan yang tepat akan diperoleh-dari Sebuah Memo SIMOPs Checklist (Bagian 3 Lampiran GI) dan review antara EMDC sesuai Drilling Op. Supt. dan EMPC Op Supt harus diselesaikan sebelum mobilisasi JUR untuk setiap program pengeboran JUR / Produksi. â € ¢ Jika keputusan dibuat untuk membuat penyimpangan dari pedoman yang ditetapkan dalam manual SIMOPs, ini dapat dicapai dengan routing deviasi SIMOPs untuk disetujui oleh Production. Sebuah formulir kosong dilampirkan sebagai Bagian 3 -Appendix G-II. Pertemuan survei platform yang akan diadakan untuk membahas isu-isu spesifik platform yang (misalnya, bergerak tangga, bergerak crane, perlindungan peralatan proses dekat kantilever, dll). Pertemuan ini harus mencakup perwakilan dari EMDC Drilling, EMPC, dan kontraktor rig. 3.2 MOVING 3.2.1 BERGERAK â € "RIGS JACK-UP Sebelum dimulainya setiap operasi gerakan laut sangat penting bahwa review peraturan daerah untuk pemberitahuan dilakukan untuk memastikan izin yang diperlukan telah diperoleh. Informasi ini kemudian dapat digunakan untuk mengevaluasi potensi dampak eksplorasi dan operasi mengidentifikasi opsi mitigasi. Debit dan pengeboran izin yang sah, dari negara dan atau badan-badan federal, harus dipasang di rig sebelum Miru rig di lokasi. Izin lainnya DOCD, APD, MMS, dan Negara O & G Boardsâ € ™ â € œPlans untuk Exploitationâ € juga harus tersedia. Juklak umum berikut berlaku untuk Jack-Up tongkang selama persiapan untuk dan pelaksanaan operasi transit. 1. Prosedur kelautan harus didokumentasikan sesuai dengan pengeboran contractorâ € ™ s Operasi Kelautan Manual. Peraturan Pemerintah Persyaratan asuransi Contractorâ € ™ s Arus diharapkan dan cuaca Jarak dari tow Persyaratan posisi di lokasi mobilisasi dan lokasi pengeboran akhir. 4. Sebelum memulai langkah itu, pemeriksaan semua kapal penarik meliputi: Penarik kawat dan aksesoris Tow winch Tow rigging seperti mata towing, dll Peralatan komunikasi (harus menyertakan dua sistem yang terpisah) Kondisi umum pembuluh tow 5. Semua peralatan onboard, harus benar diamankan sebelum rig bergerak. Perhatian khusus akan diberikan kepada tumpukan BOP dan barang tubular. 6. Jack-Up perhitungan stabilitas kapal setelah pemuatan Perusahaan dan peralatan pihak ketiga. 2. Pengaturan penarik akan dilakukan baik di muka. 7. Fungsi menguji peralatan jacking. 3. Ukuran dan jumlah kapal derek diperlukan mengingat: 8. Deskripsi dan atau peta rute belakangnya. 9. Sebuah prosedur darurat akan diberlakukan untuk cuaca berat termasuk: Ditentukan lokasi penampungan yang aman atau lokasi di sepanjang rute. Mengurangi prosedur penarik seperti memperlambat dan berubah menjadi cuaca berat. 10. Di daerah di mana rig bergerak berlaku, harus mempertimbangkan â € œlump-Suma biaya € mobilisasi kutipan yang akan diperoleh dari kontraktor pengeboran dan analisis ekonomi harus dilakukan untuk menentukan apakah EMDC Pengeboran akan menerima proposal lump sum atau memilih untuk memobilisasi JUR yang pada dayrate. 3.2.2 BERGERAK â € "RIGS PLATFORM Sebelum dimulainya setiap operasi gerakan laut sangat penting bahwa review peraturan daerah untuk pemberitahuan dilakukan untuk memastikan izin yang diperlukan telah diperoleh. Informasi ini kemudian dapat digunakan untuk mengevaluasi potensi dampak operasi pengeboran dan mengidentifikasi opsi mitigasi. Debit dan pengeboran izin yang sah, dari lembaga negara dan atau federal, harus dipasang di rig sebelum memulai pemboran. Izin lainnya DOCD, APD, MMS, dan Negara O & G Boardsâ € ™ â € œPlans untuk Exploitationâ €. Juklak umum berikut berlaku untuk platform selama persiapan untuk dan pelaksanaan operasi transit. 1. Prosedur kelautan harus didokumentasikan sesuai dengan pengeboran contractorâ € ™ s Operasi Kelautan Manual. 2. Seseorang yang ditunjuk oleh tim proyek melakukan pemeriksaan onsite untuk menentukan penempatan disukai semua paket rig dalam hubungan dengan jaringan pipa, peralatan proses fasilitas, sistem pembuangan, garis ventilasi blowdown, dan peralatan lain yang mungkin akan terpengaruh. 3. Pengaturan penarik akan dilakukan baik di muka. 4. Pengaturan tongkang derek akan dibuat baik di muka. 5. Periksa platform yang memuat yang berkaitan dengan peralatan paket rig dan mengamankan Struktural engineeringã € ™ s persetujuan dengan rencana mobilisasi rig. 6. Meninjau lokasi yang diusulkan dari tempat tinggal, jalan keluar, tangki penyimpanan diesel, dll dan menentukan apa proteksi kebakaran yang diperlukan. Urutan down load harus direncanakan & didokumentasikan untuk menentukan urutan di mana komponen rig harus dimuat ke platform berdasarkan prioritas. 7. Cari semua stasiun peralatan perlindungan kebakaran di dek utama, dan menilai kebutuhan untuk pindah. 8. Survei sistem minuman keras yang Platforma € ™ s untuk menentukan di mana tie-in dapat dibuat untuk memasok air ke rig api utama, dan bahwa desain tekanan pipa kompatibel. Pastikan bahwa Platforma € ™ s pompa minuman keras memenuhi persyaratan GPM untuk fasilitas itu. 9. Periksa semua deck saluran utama untuk memastikan mereka bebas dari halangan apapun, dan menentukan apakah ada saluran air harus diisolasi / dimodifikasi karena posisi dari paket rig. 10. Sebuah gambar yang menggambarkan skala Platform / rig tata letak peralatan harus dikembangkan menyoroti daerah yang ditunjuk aman pengelasan, serta daerah di mana Kerja Hot dilarang. 11. Cari semua anak tangga pipa masuk dan keluar, dan menentukan apa perlindungan ini memerlukan selama Miru dan fase pengeboran. 12. Pastikan bahwa link komunikasi didirikan antara tongkang dan platform, terutama antara operator tongkang derek dan orang-orang bercak peralatan di dek utama dari platform. 13. Pastikan bahwa crane kontraktor memenuhi persyaratan pemeriksaan API RP2D. Dokumentasi pemeriksaan ini diperlukan. 14. Meninjau proses kritis (yaitu, garis NGL / injeksi tekanan tinggi) dan menilai perlunya pertimbangan khusus dalam hal situasi darurat. 15. Meninjau semua klasifikasi listrik yang berlaku untuk lokasi yang direncanakan dari tempat tinggal dan komponen rig. 16. Periksa tangki penyimpanan diesel Platforma € ™ s, penyimpanan air minum, dan berbagai pompa transfer untuk menentukan apakah mereka memenuhi kebutuhan rig. Jika platform memiliki sistem pengisian bahan bakar helikopter, memeriksa pipa dan menentukan apakah pompa dapat digunakan jika stasiun pengisian bahan bakar instalasi pada heliport rig diperlukan. 17. Periksa semua dek kisi, plating, dan pegangan tangan dan mengatur untuk perbaikan atau penggantian diperlukan. Memeriksa kondisi setiap downcomers yang dapat diinstal untuk rig platform yang dimobilisasi sebelumnya, dan menilai apakah mereka dapat digunakan kembali. 18. Ukuran dan jumlah kapal derek diperlukan mengingat: Peraturan Pemerintah Persyaratan asuransi Contractorâ € ™ s Arus diharapkan dan cuaca Jarak dari tow Persyaratan posisi di lokasi mobilisasi dan lokasi pengeboran akhir. 19. Deskripsi dan atau peta rute belakangnya. 20. Sebuah prosedur darurat akan diberlakukan untuk cuaca berat termasuk: Ditentukan lokasi penampungan yang aman atau lokasi di sepanjang rute. Mengurangi prosedur penarik seperti memperlambat dan berubah menjadi cuaca berat. 3.2.3 BERGERAK â € "RIGS TONGKANG Sebelum dimulainya setiap operasi gerakan laut sangat penting bahwa review peraturan daerah untuk pemberitahuan dilakukan untuk memastikan izin yang diperlukan telah diperoleh. Informasi ini kemudian dapat digunakan untuk mengevaluasi potensi dampak operasi pengeboran dan mengidentifikasi opsi mitigasi. Debit dan pengeboran izin yang sah, dari lembaga negara dan atau federal, harus dipasang di rig sebelum memulai pemboran. Izin lainnya DOCD, APD, MMS, dan Negara O & G Boardsâ € ™ â € œPlans untuk Exploitationâ €. Juklak umum berikut berlaku untuk tongkang selama persiapan untuk dan pelaksanaan operasi transit. 1. Prosedur kelautan harus didokumentasikan sesuai dengan pengeboran contractorâ € ™ s Operasi Kelautan Manual. 2. Jika data historis tidak ada, sampel bore tanah dapat dianalisis untuk memfasilitasi desain / bangunan dari rockpad a. 3. Survei dan pengerukan pengaturan akan dilakukan baik di muka. 4. Pengaturan penarik akan dilakukan baik di muka. 5. Ukuran dan jumlah kapal derek diperlukan mengingat: Peraturan Pemerintah Persyaratan asuransi Contractorâ € ™ s Cuaca diharapkan Jarak dari tow Persyaratan posisi di lokasi mobilisasi dan lokasi pengeboran akhir. 6. Semua peralatan onboard, harus benar diamankan sebelum rig bergerak. Perhatian khusus akan diberikan kepada tumpukan BOP dan barang tubular. 7. Deskripsi dan atau peta tow rute dan lokasi penyeberangan pipa dan fasilitas lainnya yang dapat mempengaruhi rig bergerak. 8. Sebuah prosedur darurat akan diberlakukan untuk cuaca berat termasuk: â € ¢ Pra-ditentukan lokasi penampungan yang aman atau lokasi di sepanjang rute. 9. Untuk tongkang rig bergerak rincian pembayaran harus ditentukan dalam kontrak pengeboran (yaitu, dayrate atau lump sum). 3.3 MOVING DAN POSITIONING Prosedur untuk bergerak dan posisi di lokasi pengeboran meliputi: Towing 1. Sebuah memimpin kapal dan derek master akan didirikan jelas. 2. Mendapatkan cuaca dari layanan cuaca dan / atau sekitarnya rig / kapal sepanjang jalan belakangnya yang diusulkan. Catatan: derek ini tidak akan dilakukan jika angin dan laut diperkirakan akan melebihi 25 knot dan / atau 5 kaki di lokasi mobilisasi, rute tow, lokasi akhir, atau selama jack-up dan pre-loading operasi akhir. Persyaratan asuransi Rig Kontraktor harus dipertimbangkan. 3. Hadir kapal derek yang harus terpasang dengan penarik kabel ke Jack-Up sebelum jackdown akhir. Operasi ini harus dilakukan dalam cuaca yang baik dan di siang bila memungkinkan. GOM produksi JUR malam bergerak-in dan positioning memerlukan persetujuan EMDC yang tepat dan manajemen EMPC melalui SIMOPs checklist / proses review dan tepat keringanan / persetujuan dari MMS (jika semua pipa yang tidak ditandai memadai). 4. Rancangan yang sebenarnya, setelah semua kaki bebas dari dasar laut, akan dibandingkan dengan jumlah dihitung untuk memastikan perhitungan stabilitas yang benar. 5. Para kru harus memastikan bahwa cek terus menerus dipertahankan pada rancangan lambung selama tow. 6. Semua lampu navigasi di rig akan beroperasi. 7. Kabut tanduk akan diuji untuk memastikan bahwa itu adalah operasional. 8. Sebuah arloji 24 jam akan dipertahankan, selama seluruh belakangnya, untuk lalu lintas pelayaran dan hambatan (pelampung, platform, dll). Catatan: individu tertentu yang akan ditugaskan tugas jaga dan tugas tersebut tidak akan lebih dari 2 jam terus menerus tanpa istirahat. Positioning Sebuah positioning system permukaan akan dimanfaatkan untuk memantau posisi rig pengeboran itu seperti yang berlayar ke lokasi yang diusulkan. Prosedur navigasi tertentu akan tergantung pada lokasi dengan baik dan akan ditentukan dalam Move-In Prosedur Rig-Up. Posisi akhir dari rig pengeboran harus diverifikasi setelah kaki telah disematkan. Lokasi yang sebenarnya pengeboran rig, ditentukan setelah jumlah yang memadai satelit lewat, adalah untuk berada dalam toleransi dinyatakan sebagai ditentukan dalam prosedur Miru. Untuk rig kantilever melalui platform yang ada, posisi akan dianggap diterima jika persyaratan hookload dapat dipenuhi setelah posisi paket bor selama slot yang sesuai (s). Judul pengeboran rig akan ditentukan dalam MoveDalam program pengeboran Prosedur Rig-Up atau prosedur tambahan tersebut. Ini umumnya akan ditentukan oleh kantilever / rotary aksesibilitas tabel slot juga konduktor yang diinginkan pada platform produksi dan arah angin menonjol dan kekuatan gelombang untuk lokasi yang diusulkan dan waktu tahun. Insinyur akan menentukan beban kantilever maksimum yang akan tersedia dalam posisi skiddeddi Rig-Up Prosedur Move-in dan mengkonfirmasi bahwa ini akan memenuhi beban desain juga maksimal baik sebelum dan sesudah posisi JUR akhir. Dalam program pengeboran multi-baik, hookloads untuk semua sumur dan posisi harus diterima. Faktor-faktor seperti posisi crane, workboat logistik, dll juga dapat mempengaruhi pos diprogram rig. Catatan: Jangkar tidak akan digunakan untuk menahan Jack-Up tongkang di lokasi sebelum menjepit kaki. Setiap penggunaan jangkar akan memerlukan penggunaan prosedur rinci dan akan memerlukan pengecualian untuk standar (persetujuan Bidang Pengeboran Manager). 3.4 PRE-LOADING (JACK-UP ONLY) Sebelum penetrasi kaki dari dasar laut (menjepit), pemeriksaan dasar laut dapat dilakukan untuk memastikan bahwa jaringan pipa, bangkai kapal, persenjataan menghabiskan, dan sampah lainnya tidak hadir. Pemeriksaan ini dapat dimasukkan dalam survei situs jika ada yang dilakukan. Sebelum jacking-sampai ketinggian pekerjaan yang telah ditentukan, pra-beban harus diterapkan. Secara umum, preloading harus dilakukan konsisten dengan kontraktor rig dan prosedur operasi standar rig produsen. Namun, panduan umum berikut berlaku sebagai pos pemeriksaan. 1. Pra-beban untuk siklus pertama diterapkan dengan bagian bawah lambung sekitar 3-5 kaki di atas garis aksi gelombang. Setelah lambung tongkang menyentuh garis aksi gelombang selama pra-loading, semua air ballast dibuang dan Jack-Up tongkang kemudian dapat mendongkrak ke 5 kaki celah udara di atas garis aksi gelombang. Lanjutkan pra-loading sampai Jack-Up berdiri kokoh tanpa penurunan. Final pra-beban akan diselenggarakan selama minimal 3 jam tanpa penurunan lebih lanjut. 2. Persyaratan preload yang harus sesuai dengan Drilling Kontraktor Standard Operating Procedure, biasanya di atau dekat pembebanan maksimum. Catatan: bobot Preload adalah untuk dimasukkan dalam Core Jack-Up Move-In RigUp Prosedur. 3. Penetrasi kaki yang sebenarnya harus dibandingkan dengan nilai-nilai dihitung dan sebelumnya Jack- Up posisi rig di platform produksi yang sama, dan, jika berbeda nyata, tambahan core tidur laut harus dipertimbangkan untuk menentukan alasan untuk perbedaan dan dasar laut yang sebenarnya integritas. 4. Selama operasi jacking, air laut menara keharusan operasional setiap saat, dengan pasokan normal air laut yang tersedia dalam situasi darurat. 3,5 TRANSFER CARGO Kargo transfer Sertif ikasi / Pedo man Kom Transfer kargo antara pasokan kapal dan offshore rig / platform merupakan salah satu usaha yang lebih berbahaya di lingkungan lepas pantai. Sebuah Buoy Kembali-Down ketika melayani rig Jack-Up dianjurkan, terutama selama arus kondisi / angin kencang. Ketika menetapkan Buoy Kembali-Down, pastikan bahwa itu tidak diatur pada pipa bawah laut atau bahaya lainnya. Jangan menggunakan platform produksi untuk menyimpan peralatan pengeboran tanpa melibatkan EMPC untuk memastikan struktur dapat menangani beban yang direncanakan dengan faktor keamanan yang dapat diterima. unika Pedoman dalam bagian ini mencakup beberapa operasi mentransfer utama. Sementara tidak ada pengganti untuk akal sehat yang baik, Kelautan dan Jack-Up personil rig yang menggunakan panduan ini dan penilaian yang baik untuk melakukan operasi mentransfer dengan cara yang aman. Sebuah JSA (Job Safety Analysis) diperlukan sebelum semua operasi mengangkat. Sebuah JSA adalah wajib bagi semua lift buta dan lift personil. iki Definisi: angkat berat didefinisikan sebagai setiap mengangkat lebih dari 10 (sepuluh) MT. 3.5.1 PENCEGAHAN si JackUp Kontr aktor adala h memil dan memb erikan : 1. Sertifikasi Pihak Ketiga untuk semua crane Jack-Up sesuai dengan API RP 2D. 2. Dokumen sertifikasi untuk semua Jack-Up operator crane. 3. Semua sling yang telah bersertifikat dan ditandai untuk peringkat mereka termasuk pemutusan akhir dan harus kembali bersertifikat-setiap 6 bulan. 4. Derek kait dilengkapi dengan kait yang berfungsi keselamatan, yang berada dalam kondisi yang bisa diterapkan baik. 5. Operator crane yang terlatih dan bersertifikat untuk Jack-Up kerja. 6. Komunikasi yang baik selama semua operasi kargomentransfer (yaitu, headset radio, talkie talkie, dll). 3.5.2 BATAS CUACA Kargo transfer Pedoman Cuaca 1. Sebuah kekosongan transfer kargo umum dalam kondisi cuaca yang berat, terutama lift berat. 2. Pertimbangkan menangguhkan operasi pengeboran sampai kondisi cuaca membaik sebelum mentransfer kargo berat dalam cuaca berat. 3. Hanya mentransfer kecil buah peralatan, diperlukan untuk menghindari penghentian operasi, dari kapal pasokan dalam kondisi cuaca berat dan hanya jika kapten kapal, DIM, dan Pengawas Operasional adalah semua dalam perjanjian itu adalah aman untuk melakukannya. Catatan: "Snatch Lift" yang akan dilakukan hanya dengan lift pra-tersampir di mana sling melekat kargo dapat dilampirkan ke crane kait. Memborgol sling untuk kargo ketika sling melekat derek tidak diizinkan untuk Lift merebut. 3.5.3 LIFTS BERAT (JACK-UP Cabut MELEBIHI 10 MT) Berikut ini berlaku untuk Lift berat: 1. Lift di lebih dari 10 MT yang akan diawasi oleh Pengawas Operasional dan OIM Kontraktor atau menunjuk nya. 2. Lift berat harus direncanakan untuk siang hari bila memungkinkan. 3. Lift berat harus memiliki pra-tersampir, sling mengangkat bersertifikat dan belenggu. 4. Mengadakan pertemuan koordinasi untuk Lift berat (yaitu, lebih dari 10 MT) dengan Crane Operator, Toolpusher, dan Operasi Pengawas hadir dan membahas: Jenis kecurangan yang diperlukan. Inspeksi visual tali-temali. Signaling metode. Keseluruhan rencana off pemuatan dan penempatan angkat. Catatan: di atas berlaku untuk mengangkat setiap berarti, yaitu, crane, BOP troli, atau perangkat mengangkat lainnya. 3.5.4 OPERASI LIFTING lain dan komunikasi melalui radio (walkietalkie). Crane Operator Tanggung Jawab 1. Mengoperasikan crane dengan cara yang aman dan masuk akal. 2. Lengkap inspeksi derek harian dan sekarang laporan inspeksi lengkap untuk supervisor. 3. Lakukan perawatan harian pada crane dan peralatan rigging. 3. Memecah lift berat ke lift yang lebih kecil jika di semua praktis. 4. Mengadakan pertemuan koordinasi untuk Lift berat (yaitu, lebih dari 10), dengan operator crane, toolpusher, dan Operasi Pengawas hadir dan membahas: Jenis kecurangan yang diperlukan. 4. Menjaga rumah yang baik menjaga di daerah kargo. Inspeksi visual tali-temali. 5. Gunakan pengaturan melempar memadai dan aman. Signaling metode. 6. Partisipasi dalam derek inspeksi oleh Perusahaan Personil. Keseluruhan rencana untuk off-loading dan penempatan angkat. 7. Memastikan komunikasi yang baik digunakan antara signaler dan dirinya sendiri. 8. Mendapatkan Izin Kerja untuk Lift berat atau angkat lebih fasilitas Platform (jika ada). 5. Memperoleh persetujuan dari Operasi Inspektur dan OIM sebelum melakukan lift ganda (yaitu, penggunaan dua atau lebih crane untuk mengangkat tunggal). Pedoman Lifting 6. Jelas menandai semua lift di atas 1 MT di dermaga sebelum memuat ke workboat tersebut. 1. Menangani kargo sehingga tetap terlihat dengan Crane Operator bila memungkinkan. 7. Jauhkan beban vertikal di bawah hook booming untuk menghindari berayun sebanyak praktis. 2. Gunakan personil estafet dalam situasi di mana kargo tidak terlihat Crane Operator (JSA Wajib). 8. Pastikan derek hook vertikal berpusat di lift sebelum mengangkat off dari kapal pasokan mengambil dari deck rig. Catatan: Crane Operator dan personil estafet yang memiliki kontak visual dengan satu sama 9. Gunakan garis tag pada semua lift. 10. Melampirkan sling longgar untuk setiap beban, yang tidak pra-tersampir di kapal pasokan sebelum menghubungkan beban ke crane kait. Catatan: derek ini tidak mendukung gendongan saat menyambung sling untuk beban. Catatan: Satu-satunya pengecualian adalah penggunaan bar pallet untuk off-loading palet dan kait casing untuk off-loading casing. yang memadai, bar pallet diproduksi dan kait casing, dll). Off-Loading Kebijakan Pipa bundel tidak akan off diambil dari sebuah kapal pasokan dalam keadaan apapun jika salah satu kondisi berikut: Pipa bundel memiliki sling yang hanya membungkus tunggal sekitar bundel pipa, 11. Gunakan minimal dua (2) deck tangan saat menangani kargo dan melampirkan sling pada supply vessel. Pipa bundel memiliki sling pendek, yang mengakibatkan sudut derek kail lebih dari 30 derajat. 12. Pastikan bahwa semua personel mengenakan Hidup Rompi / Jaket sementara di dek kapal saat mentransfer kargo dari kapal pasokan. Pipa bundel memiliki sling sekitar bundel pipa, yang lebih dari 25% dari panjang pipa dari ujung bundel pipa. 13. Mengambil tindakan pencegahan untuk menghindari tamparan pengikat kembali saat melepas pengikat rantai di kargo dari kapal pasokan. Catatan: kapal Pasokan akan menggunakan pengikat rantai untuk mengamankan kargo dan menjaga dari pergeseran selama kondisi laut kasar. 3.5.5 PEDOMAN RIGGING Lifting Equipment Kebijakan Peralatan yang tepat yang akan digunakan untuk off-beban kargo (yaitu, sling dan belenggu ukuran Kebijakan Rigging Sling Sling yang memiliki penutup plastik yang tidak digunakan dalam kondisi apapun. Menutupi memungkinkan korosi terjadi yang dapat terdeteksi. Pedoman Tubular Off-Loading Tergantung pada ukuran tabung, memanfaatkan pengaturan sling berikut: 30 "Gunakan hanya kain yang melekat pada belenggu, 1 bersama per angkat maksimum 20 "Gunakan hanya kait casing, 1 bersama per angkat maksimum 13-3 / 8 "" Gunakan hanya casing kait, 2 sendi per angkat maksimum 9-5 / 87 "Gunakan hanya casing kait, 2 sendi per angkat maksimum 5 "Gunakan baik kait casing atau sling, 4 sendi per angkat maksimum Gunakan pratersampir, jumlah yang wajar dari sendi (atau lebih kecil) Catatan: bundel Pra-tersampir yang memiliki dua sling, masing-masing memiliki dua membungkus di sekitar pipa dengan minimal lima sambungan pipa per bundel untuk ukuran sampai dengan 5 ". Catatan: bundel Pra-tersampir untuk casing yang lebih besar dari 5 "sampai 7" casing adalah memiliki minimal empat sendi per bundel. Catatan: Jangan pra-sling casing 7 "dan lebih besar. 2. Angkat maksimal dua palet pada satu waktu dan tidak melebihi 6 ft tinggi (yaitu, total untuk dua palet). 3. Gunakan sling dengan jumlah yang sama dari kaki sebagai jumlah tali pada tas untuk mengangkat tas besar. Menghubungkan semua tali tas individual ke kaki sling. Catatan: Jangan membelenggu bersama tali tas di kaki selempang yang sama dan tidak mengangkat tas kecuali menggunakan semua tali di tas untuk berbagi beban antara tali. 4. Off-load hanya satu tas per angkat. 5. Meninggalkan tas yang telah merusak tali pada kapal pasokan. 6. Gunakan pengaturan sling empat kaki untuk mengangkat kontainer kargo dan keranjang. 7. Membelenggu setiap kaki sling ke padeyes mengangkat ditunjuk pada kontainer kargo dan keranjang. Pedoman Umum Rigging 8. Gunakan kain, rantai, dan link yang memadai untuk mengangkat tertentu. 1. Gunakan bar pallet diproduksi untuk mengangkat palet (yaitu, tidak gaya dibuat di lokasi rig.). 9. Gunakan Tabel pada akhir bagian ini untuk informasi tambahan dan spesifikasi. Tabel No I - Wire Rope Sling Banyak Kerja Aman Tabel No.2 - Rantai Sling Aman Kerja Banyak Tabel No.3 - Banyak Guru link Aman Kerja Tabel No.4 -Installation Wire Rope Klip Cargo Transportation Pedoman 1. Pastikan kargo kontainer adalah metode utama untuk mengangkut drum. Drum harus ditempatkan pada dan diamankan ke palet dalam kontainer kargo untuk kemampuan forklift. Catatan: Menghapus drum dari keranjang sulit dan berbahaya. Catatan: Dalam situasi kritis atau darurat dan jika kontainer kargo tidak tersedia, selempang hanya satu drum yang pada waktu per angkat menggunakan drum yang kait yang tepat. 2. Botol gas transportasi (yaitu, oksigen, acetylene, nitrogen, dll) menggunakan botol rak yang tepat yang memiliki titik angkat padeye tunggal. Catatan: Jangan mengangkut botol gas longgar. 3. Hanya mengangkut bahan radioaktif dan bahan peledak dalam wadah yang tepat yang dibuat khusus untuk bahan tersebut. Sling Rigging Pedoman 1. Menghitung beban kerja yang aman dari sling dengan membagi katalog melanggar kekuatan gigi pengangkat oleh faktor keamanan. 2. Gunakan berikut untuk menentukan berlaku faktor keamanan. Fakt or Operasi kese lama tan Sling Wire Rope 5.0 Rantai dan tali-temali mengatasi 3,5 Personil keranjang 10,0 3. Menghitung beban per kaki selempang dengan membagi total beban vertikal dengan jumlah sling kemudian membagi lagi dengan cosinus dari sudut angkat (yaitu, sudut antara sling di derek kait). 4. Pastikan bahwa kain yang cukup panjang sehingga sudut maksimum antara sling di crane hook 60 derajat untuk kontainer, dll dan maksimum 30 derajat untuk pipa dibundel (yaitu, 50 ft panjang selempang untuk 40 ft pipa bundel dan 40 ft panjang sling selama 30 ft pipa bundel). Catatan: Jika panjang kaki sling sama atau melebihi jarak horizontal antara titik lampiran beban (yaitu, padeyes), sudut angkat adalah 60 derajat atau kurang. 5. Cari setiap kaki sling jarak yang sama dengan 15 persen dari panjang pipa dibundel saat mengangkat bundel pipa (yaitu, 6 ft. Dari akhir untuk 40 ft sambungan pipa). 6. Menggunakan kawat sling tali. Catatan: sling tali kawat istirahat satu untai pada suatu waktu sedangkan sling rantai istirahat dengan sedikit atau tanpa peringatan. Juga, rantai kurang tahan terhadap shock loading. 7. Gunakan tali kawat galvanis bila memungkinkan. 14 Gunakan belenggu yang baik tipe sekrup atau jenis pin-baut-mur. Catatan: Banyak yang memiliki secara permanen belenggu berdedikasi, yang memiliki pasak luar mur belenggu. 15. Gunakan casing kait yang diri pengetatan dengan kunci tekanan dan rilis manual. Catatan: Jika tipe terbuka kait yang diperlukan, gunakan tarikan garis interkoneksi longitudinal antara kait. 3.5.6 EQUIPMENT MAINTENANCE 8. Pastikan bahwa rantai galvanis tidak digunakan dalam lingkungan lepas pantai sebagai kekuatan Definisi: pemeliharaan yang baik adalah sering memburuk untuk beberapa nilai yang tidak diketahui inspeksi, pembersihan, dan dari waktu ke waktu. pelumasan peralatan rigging. 9. Menggunakan kawat Hitches tali kalung yang memanfaatkan slip melalui atau bidal mata reeve. 10. Hanya menggunakan geser kait choker yang dari desain kait keselamatan. 11. Jangan menggunakan belenggu keselamatan melalui mata lembut-line untuk membuat sambungan halangan. Panduan Perawatan peralatan 1. Mempertahankan rantai, tali kawat, belenggu, kait dan semua peralatan rigging lain secara periodik. 2. Periksa semua peralatan rigging pada operasi startup dan setiap 3 bulan setelahnya. Sling harus disertifikasi ulang setiap 6 bulan. 12. Pastikan bahwa sling kait serta derek kait memiliki aman kait kait gagal. 3. Menghancurkan peralatan rigging yang memiliki korosi, keausan berlebihan, kabel terdampar, atau dalam kondisi sebaliknya tersangka. 13. Pastikan beban terlibat sepenuhnya tentang tenggorokan kail dan titik pemuatan tidak terjadi untuk sling pada crane kait. 4. Melumasi semua peralatan rigging selama setiap pemeriksaan. 5. Pastikan peralatan rigging bersih dan kering sebelum aplikasi pelumas. 6. Terapkan pelumas yang tepat benar untuk peralatan rigging. 7. Sikat minyak ringan langsung di tali-temali peralatan dari wadah minyak. 8. Menengah panas untuk minyak berat sebelum menerapkan peralatan rigging. 9. Gunakan pelumas yang tidak mengandung logam (yaitu, tidak menggunakan minyak crankcase). 10. Gunakan pelumas yang anti air dan memiliki kemampuan penetrasi yang baik. 11. Pertimbangkan pelumas untuk sling, belenggu, rantai, dll dari daftar berikut: Rocal Rd 105 Sea King Sk 620 Canggih Pelumas Svcs. Esso Surett Fluin 4k Rocal Rd 05 Aerosal Esso Rustban 395 Esso Petroleum il 795 Mobil Oil Mobiltac 81 British Tali Britlube IOB / 69b Pedoman Wire Rope 1. Melumasi tali kawat lebih sering daripada hanya selama inspeksi. Catatan: tali kawat ini perlu pelumas ketika karakteristik berikut dicatat: Berderit suara sementara tali yang spooling. Melanggar kabel di lembah tali tanpa indikasi seragam untai nicking. Catatan: Berikut ini adalah contoh dari pengurangan kekuatan dalam "karatterikat" tali kawat dengan asumsi diameter tali kawat tetap konstan (yaitu, tidak ada pengurangan karena korosi). Baru 7/8 ", 6 x 36, IWRC tali kawat dengan aslinya pelumasan Minimum kekuatan putus adalah 34 ton dengan 4,51 persen peregangan. Tali kawat yang sama dalam kondisi yang tidak terpakai tetapi dengan korosi ringan akan istirahat sekitar 22 ton dengan hanya 1,63 persen peregangan. TABLE NO. 1 KAWAT TALI SLING BEBAN KERJA AMAN Galvanis, BS 6166: 1981 Cara Uniform Load / penambahan Imp. Membajak Baja (180 kgf / mm2) 38 (1-1 / 2 ") 18,5 MT 19,4 MT 25,9 MT 38,8 MT 51 (2 ") 34,8 MT 36,5 MT 48,7 MT 73.1 MT TABLE NO. 2 Maksimum Angkat Angle = 60 Deg. - (Semua kawat tali 6x36 IWRC) CHAIN SLING BEBAN KERJA AMAN Max. Lds aman Kerja (Metrik Ton) (faktor keamanan = 5) - Max Aman Ld Kerja (Mt) Panas Ditangani Alloy Steel (800N / mm2) -Bs 6166: 1981 Metode beban Uniform Tali Dia. SingleLeg Dua Kaki Max. Angkat Angle = 60 Deg Dua Kaki Ganda Choker Max. Banyak Kerja Aman (Metrik Ton) - (faktor Halanga = 4) keamanan n mm (in) Halanga n 9 (3/8 ") 1.0 MT 1.1 MT Rantai Dia 1.4 MT 13 (1/2 ") 2.1 MT 2.2 MT 2,9 MT mm (in) 16 (5/8 ") 3.3 MT 3.4 MT 4.6 MT 6 (1/4 ") 6.4 MT 8 (5/16 ") 8,7 MT 10 (3/8 ") 12,0 MT 13 (1/2 ") 14,0 MT 16 (5/8 ") 18.3 MT 19 (3/4 ") 4.6 MT 4.8 MT 22 (7/8 ") 6.2 MT 6.5 MT 26 (1 ") 8.6 MT 9.0 MT 28 (1-1 / 8 ") 32 (1-1 / 4 ") 10,0 MT 13,1 MT 10,5 MT 13,7 MT Single-Leg Halanga n Dua Kaki Ganda Choker Dua Kaki Halang an EmpatLeg Halang an 1,5 MT 1.6 MT 2.1 MT 3.1 MT 2.0 MT 2.1 MT 2.8 MT 4.2 MT 3.2 MT 3.3 MT 4.4 MT 6.7 MT 5.4 MT 5.6 MT 7.5 MT 11,3 MT 8.0 MT 8.4 MT 11.2 MT 16,8 MT 19 (3/4 ") 12,5 MT 13,1 MT 17,5 MT32 mm (1-1 / 4 ") 13,3 MT 15.2 MT 22 (7/8 ") 16,0 MT 16,8 MT 22,4 MT38 mm (1-1 / 2 ") 18.1 MT 24,0 MT 26 (1 ") 20,0 MT 21.0 MT 28,0 MT45 mm (1-3 / 4 ") 23,6 MT 34,5 MT 32 (1-1 / 4 ") 32,0 MT 33,6 MT 44,8 MT 51 mm (2 ") 36,9 MT 47,2 MT 57 mm (2-1 / 4 ") 45.1 MT - 64 mm (2-1 / 2 ") 55,7 MT - 70 mm (2-3 / 4 ") 67,4 MT - TABLE NO. 3 BEBAN MASTER LINK AMAN KERJA TABLE NO. 4 PEMAS ANGAN KAWAT TALI KLIP Tunggal Guru Tautan Saham Diameter (satu atau dua kaki selempang) Faktor keselamatan = 6: 1 Wire Rope Minimum Nomor Klip Tali Hidupkan kembali Momen 13 mm (1/2 ") 1,8 MT Diameter Dari Thimble 16 mm (5/8 ") 2,5 MT 6 mm (1/4 ") 2 121 mm 2 kgm (15 ft-lb) 19 mm (3/4 ") 3.9 MT 9 mm (3/8 ") 2 165 mm 6 kgm (45 ft-lb) 26 mm (1 ") 9.2 MT 13 mm (1/2 ") 3 292 mm 9 kgm (65 ft-lb) 16 mm (5/8 ") 3 305 mm 19 mm (3/4 ") 4 457 mm 22 mm (7/8 ") 4 483 mm 25 mm (1 ") 5 660 mm 29 mm (1-1 / 8 ") 6 864 mm 32 mm (1-1 / 4 ") 6 940 mm 38 mm (1-1 / 2 ") 7 1219 mm 51 mm (2 ") 8 1803 mm 3.6 TRANSPORTASI & PERSONIL TRANSFER Transportasi & Personalia transfer Kata Pengantar Bagian ini berisi pedoman untuk mengangkut kargo dan personil ke dan dari situs lepas pantai. Untuk panduan yang lebih rinci ketika mentransfer tenaga dari fasilitas lepas pantai, lihat EMPC Keselamatan Manual. 2. Beritahu Bahan Pengawas jenis kargo dan waktu kedatangan yang diharapkan untuk memastikan penanganan yang efisien dari peralatan dan alat-alat di Base. 3. Semua materi kembali harus ditunjukkan pada Material Transfer Cargo Manifest (MTCM) dan dikirim pada kapal pasokan dengan bahan yang menunjukkan informasi berikut: Deskripsi Barang Keselamatan personil adalah tujuan utama ketika bergerak personel dan kargo lepas pantai. Ketika ada keraguan tentang segala aspek keselamatan personil, transfer tidak harus terjadi sampai bahaya (s) menyebabkan keraguan dieliminasi atau dikelola secara efektif. Kondisi Barang (1 -New, 2 -Digunakan, 3 -Needs Perbaikan, 4 - Sampah) Pemilik Barang (Affiliate atau Kontraktor Nama) Untuk kebanyakan operasi, helikopter akan menjadi pilihan sarana transportasi personil antara Shore Base dan rig. Pasokan kapal mungkin menjadi sarana utama pada beberapa operasi dan dapat digunakan pada operasi lain jika kondisi cuaca melarang penerbangan helikopter. Transfer hanya harus dilakukan pada saat kondisi laut tenang (yaitu, 5 kaki atau kurang). Disposisi Barang (kembali ke saham, kembali ke Kontraktor, perbaikan) 3.6.1 CARGO TRANSPORT Kapal pasokan 1. Mengkoordinasikan bongkar muat kapal pasokan di dasar melalui Bahan Pengawas. Catatan: Setiap kargo berbahaya adalah untuk secara jelas ditandai seperti pada kedua MTCM dan wadah item. Catatan: MTCMs terpisah harus digunakan untuk pemilik bahan yang berbeda, yaitu, alat sewa dikembalikan ke Kontraktor berbeda harus ditampilkan pada memanifestasikan terpisah. 4. Semua kargo di geladak kapal pasokan berangkat dasar harus diamankan. 5. Cuaca memungkinkan, semua kargo pada pasokan deck kapal berangkat dari lepas pantai harus diamankan. 6. Pembuluh akan memiliki gerbang di batang mereka setiap saat, kecuali ketika menangani jangkar atau menetapkan pelampung. 7. Tidak ada individu akan diizinkan di dek kapal pasokan sementara kapal sedang berlangsung atau berdiri dengan ketika ada kargo di dek. 8. Tubulars 5 "dan lebih kecil harus pra-tersandang dalam jumlah yang tepat per bundel kedua outbound dan inbound. Helikopter 1. Transportasi kargo melalui helikopter terbatas pada barang-barang kecil ringan kecuali penting untuk operasi. Persetujuan yang tepat harus di tempat sebelum mengangkut setiap kargo selain item kecil ringan. Biasanya, prosedur / peralatan yang digunakan untuk airlift berat, non item standar akan memerlukan konsultasi dengan Departemen Penerbangan kontak dan Lapangan Drilling Manager. 2. Bahan yang berpotensi berbahaya seperti baterai, cat, bahan kimia asam atau korosif, dll tidak akan diangkut melalui helikopter. 3. Sebuah kargo akurat dan berat nyata untuk semua transportasi helikopter, termasuk penumpang, harus selesai sebelum naik (OIMS manual Element 6). 3.6.2 OPERASI HELICOPTER Helideck 1. Pilot untuk mengunci rem saat helideck jika helikopter memiliki roda. 2. Helideck adalah memiliki tali tikar atau permukaan non-selip. Catatan: Rope tikar harus dari ukuran yang tepat untuk menghindari belitan helikopter meluncur / roda. 3. Tali tikar harus aman terikat. 4. Helideck harus ditandai dengan jelas dengan lingkaran arahan dan memiliki nama lokasi jelas terlihat dari udara. Landing & Takeoff 1. Hanya Jack-Up helideck harus digunakan untuk operasi helikopter. Setiap pengecualian untuk menggunakan helideck platform harus dibersihkan dengan Operasi Inspektur & Produksi. 2. Semua crane harus ditutup 10 menit sebelum landing / lepas landas (OIMS manual Element 6). 3. Pasokan kapal / perahu siaga harus off anchor dan siap untuk merespon selama mendarat dan berangkat. 4. Pemadam kebakaran harus dijaga dengan tim api terlatih siap untuk menanggapi setiap kali helikopter mendarat, pengisian bahan bakar, atau berangkat, dan selama mesin startup / shutdown. (OIMS manual Element 6). 5. Helideck harus dibersihkan dari semua tiba / berangkat penumpang dan / atau kargo sebelum pindah penumpang dan / atau kargo ke helideck untuk boarding. 6. Beritahu Shore Base kedatangan helikopter dan keberangkatan. (OIMS manual Element 6). Catatan: Shore Base adalah bertanggung jawab atas "Flight Tracking System". (OIMS manual Element 6). Mengawasi operasi pengisian bahan bakar. Bahan bakar tes untuk air dan sedimen segera sebelum pengisian bahan bakar. Helikopter tanah dengan kawat tanah disetujui selama operasi pengisian bahan bakar. 4. Semua peralatan pengisian bahan bakar harus dipertahankan dalam kondisi sangat baik. 5. Helideck sistem pemadam kebakaran akan diawaki saat pengisian bahan bakar operasi (OIMS manual Element 6). 7. Personil terlatih akan ditunjuk untuk awalnya mendekati helikopter setelah mendarat untuk membuka dan menutup pintu helikopter dan kemudian hanya setelah menerima izin dari pilot. Penjadwalan & Terwujud (OIMS manual Element 6) 8. Pengumuman akan dilakukan dari semua pendaratan helikopter / keberangkatan pada sistem komunikasi publik rig (OIMS Pedoman Element 6). 1. Faks akan dikirim ke Shore Basis Dispatcher hari sebelum penerbangan, kecuali dalam keadaan darurat, daftar; 3.6.3 PERSONIL TRANSPORT-HELICOPTER Pengisian bahan bakar Darurat Situasi Hanya Nama penumpang 1. Matikan helikopter, menghapus helideck semua personil non-esensial dan manusia peralatan pemadam kebakaran helideck selama operasi pengisian bahan bakar. (OIMS manual Element 6). Perusahaan Afiliasi .Weight Penumpang dan Bagasi 2. Hanya menggunakan peralatan pengisian bahan bakar disetujui. 3. Pilot untuk pribadi: 2. Lepas pantai daftar faks terikat akan dikirim dari Shore Base dan pantai terikat daftar faks akan dikirim dari situs lepas pantai. 3. Terwujud akan menemani semua penerbangan daftar penumpang dan Perusahaan mereka; (OIMS Pengguna Element 6) a. Penerbangan Outbound: Manifest akan disiapkan oleh Shore Basis Dispatcher dan salinan diberikan kepada situs lepas pantai operator saat kedatangan helikopter. b. Penerbangan Inbound: Manifest akan disiapkan oleh Lepas Pantai Situs operator dan diberikan kepada helikopter sebelum keberangkatan dari lepas pantai. 4. Helikopter tidak akan dijadwalkan pada malam hari kecuali keadaan darurat medis ada (beberapa penerbangan malam geografis mungkin diperlukan karena siang hari tertentu). Tanggung Jawab Helikopter Penumpang 1. Pendekatan helikopter dari 3 atau 09:00 posisi setelah diarahkan oleh pilot. 2. Tunggu pengawalan di rig / shorebase sebelum memulai / mendarat. 5. Kenakan PFD atau kehidupan inflatable jaket saat helikopter saat terbang di atas air. 6. Kencangkan sabuk pengaman sebelum lepas landas dan menjaga sabuk pengaman sampai helikopter tiba di tempat tujuan. 7. Tidak pernah bergerak kabin ketika helikopter tersebut dalam penerbangan. 8. Pastikan bahwa pendaratan helikopter selesai sebelum membuka kancing sabuk pengaman. 9. Jangan tidak merokok saja saat di atau dekat helikopter. Helikopter Percontohan 1. Semua penumpang akan diberikan orientasi keselamatan / membolos petunjuk sebelum naik helikopter di lokasi dasar pantai. (OIMS manual Element 6) 2. Instruksikan penumpang untuk tetap di papan sampai pisau rotor adalah di halte lengkap jika mematikan helikopter. 3. Beban dan membongkar penumpang dengan pisau rotor bergerak hanya setelah mengumumkan kepada penumpang bahwa helikopter tidak akan menutup dan untuk melanjutkan dengan hati-hati. 3. Berjalan sebagai dekat dengan hidung helikopter mungkin saat melintasi di depan helikopter memperhatikan tabung poros yang mungkin panas. Lepas pantai Instalasi Manajer 4. Tidak pernah berjalan di bawah bagian ekor atau sekitar bagian belakang helikopter. 1. Pastikan penumpang masuk dan berat catatan badan dan bagasi. 2. Pastikan manifest selesai. (OIMS manual Element 6) 3. Pastikan personil pertemuan helikopter personel (yaitu, tim kebakaran dan dispatcher) dilatih, terorganisir dengan baik, dan dalam posisi sebelum helikopter kedatangan / keberangkatan. 4. Memastikan bahwa pengumuman publik dibuat sebelum semua pendaratan helikopter / keberangkatan. (OIMS manual Element 6). 3.6.4 PERSONIL TRANSPORT -suplai OR STAND-BY BOAT Secara umum, metode yang disukai transportasi, bahkan dalam keadaan darurat, adalah melalui helikopter. Namun, ketika kapal yang digunakan, JSA yang harus disiapkan dan ditinjau dengan semua personil sebelum asrama. 3.7 PELATIHAN MARINE 3.7.1 UMUM Laut Bor Tujuan Tujuan dari latihan laut pada unit pengeboran lepas pantai mobile untuk melatih semua pengeboran papan kontraktor personil on (yaitu, siang dan malam kru) untuk merespon dengan tepat ketika menghadapi situasi darurat. Tujuan sama pentingnya adalah untuk melatih dan memastikan bahwa semua personil lainnya on-board (biasanya sementara atau sementara untuk rig) bagaimana mengidentifikasi sinyal darurat, bagaimana menanggapi, dan cara aman mengungsi. General Kelautan Pedoman Pelatihan 1. Memastikan bahwa setiap bor menunjukkan kemampuan kru untuk menanggapi keadaan darurat dan benar mengoperasikan peralatan keselamatan yang diperlukan. 2. Jadwal latihan untuk memungkinkan partisipasi penuh dari kru dan meminimalkan gangguan operasi pengeboran. 3. Latihan rencana, yang mensimulasikan keadaan darurat realistis dan menunjukkan langkah-langkah yang diperlukan untuk mengurangi darurat nyata. 4. Memastikan bahwa setiap anggota awak bor memahami tugas mereka darurat yang ditunjuk untuk skenario bor (yaitu, mengamankan dengan baik). 5. Berjalan melalui latihan dan personil kunci pelatih yang diperlukan untuk memastikan awak akrab dengan tugas mereka yang ditunjuk dan bahwa semua orang lain tahu sinyal, mengumpulkan poin, dan prosedur evakuasi. 6. Memanfaatkan pengumuman atas sistem alamat publik yang diperlukan. 7. Mengadakan sesi diskusi setelah menyelesaikan area pengeboran dan kritik untuk perbaikan. 8. Setiap bor, termasuk diskusi kelompok dan kritik, harus mengambil sekitar satu jam. 3.7.2 PELAPORAN & DRILL FREKUENSI Pelaporan 1. Merekam semua latihan di Harian Drilling Report. 2. Merekam semua latihan di Harian IADC Laporan. 3. Meneruskan Bor Kelautan Darurat Formulir Laporan untuk Operasi Inspektur. Catatan: Lihat "Form Kosong" dalam manual ini (Bagian 3 -Appendix G-III) untuk Kelautan Darurat Bor Formulir Laporan. Laut Bor Frekuensi 1. "Api Drills" latihan -Initial yang diperlukan untuk merencanakan dan mengatur Api Melawan ing Skuad dan mingguan setelahnya. Catatan: Perilaku latihan kebakaran selama jam kegelapan dan / atau memegang bor tanpa prior pemberitahuan kepada awak sekali setiap bulan. 2. "Abaikan Latihan Rig" -Frequently sampai semua personil tahu stasiun dan prosedur ditinggalkan dan mengumpulkan cek yang memuaskan (yaitu, semua personil melaporkan mengumpulkan poin). Melakukan latihan mingguan setelahnya. Catatan: Melakukan "Abaikan Latihan Rig" selama jam kegelapan dan / atau memegang bor tanpa pemberitahuan sebelumnya kepada awak sekali setiap bulan. 3. "Man Overboard Drills" -Initially yang diperlukan untuk merencanakan dan mengatur Response Tim dan setiap dua minggu sesudahnya. Catatan: Perilaku manusia ke laut bor selama jam kegelapan dan / atau memegang bor tanpa pemberitahuan sebelumnya kepada awak sekali setiap bulan. 4. "Khusus Drills" -Seperti diperlukan untuk melatih tim respon yang ditunjuk untuk memastikan anggota tim yang mahir di tugas mereka ditugaskan. Jenis pelatihan tidak dengan sendirinya memenuhi persyaratan untuk latihan mingguan karena hanya bagian dari kru berpartisipasi. Namun demikian, yang berharga dalam mengembangkan awak terlatih. Catatan: Tahan Api Bor dan Abaikan Rig Bor bersamaan sebagai bor mingguan ketika praktis. Catatan: Melakukan pelatihan dalam penggunaan peralatan penyelamatan dan tugas tugas sebagai pengganti manusia ke laut latihan pada hari-hari cuaca buruk. 3.7.3 MARINE DRILL PROSES Proses Bor laut Rencana Bor: Hati-hati merencanakan latihan untuk fokus pada pelatihan untuk kebutuhan tertentu. Melakukan Bor: latihan Realistis mensimulasikan kondisi aktual dan membutuhkan kru untuk melakukan seolah-olah situasi darurat yang sebenarnya ada. Bor kritik: Diskusi: sesi akan mengidentifikasi masalah dan membantu mengidentifikasi area untuk perbaikan. Pedoman Perencanaan Bor laut 1. Desain setiap bor untuk menekankan satu aspek merespon situasi darurat. Ini harus meningkatkan kemungkinan aspek ini ditarik dalam keadaan darurat. 2. Menekankan aspek-aspek pokok yang tercantum dalam Bagian 3.7.1 selama latihan. 3. Pilih lokasi yang sesuai untuk menekankan aspek tertentu selama latihan. 4. Tuliskan skenario untuk bor dan mendistribusikan ke berbagai pemimpin tim. 5. Menindaklanjuti dengan bor direncanakan berusaha untuk tidak mengubah kondisi bor 6. Bervariasi hari dan waktu latihan untuk memastikan bahwa semua anggota awak siap untuk bereaksi secara efisien untuk darurat nyata. 7. Ketika praktis, pertemuan keselamatan rencana untuk mengikuti bor untuk mendorong diskusi bor. Laut Drills Pedoman 1. Hindari mengekspos awak atau Jack-Up kondisi yang dapat menempatkan mereka dalam bahaya. Misalnya, tidak menggunakan gas beracun ketika pelatihan awak dalam penggunaan alat bantu pernapasan selfcontained atau mulai kebakaran untuk menguji sistem pemadam kebakaran. 2. Sebuah kekosongan menempatkan kru dalam situasi berisiko tinggi; Namun, menghindari semua risiko tidak harus menjadi dasar untuk gagal untuk menguji beberapa peralatan keselamatan. Misalnya, meluncurkan sekoci di laut ringan dapat memerlukan beberapa risiko; Namun, risiko ini dapat diterima karena operasi peralatan ini meningkatkan kemungkinan penyebaran sukses dalam darurat nyata. Mengkritisi Pedoman Pastikan bahwa kunci kritik personel pengawas bor dan memimpin diskusi, yang berfokus pada aspek pokok bor segera mengikuti semua latihan. Semua personil Jack-Up harus didorong untuk berpartisipasi dalam sesi diskusi berikut bor. Kritik dan diskusi sesi harus: Tinjau penekanan bor. Diskusikan masalah, yang terjadi selama latihan. Menilai apakah bor berfokus pada aspek tertentu seperti yang direncanakan. Menentukan apakah bor dilakukan dengan cara yang realistis. Diskusikan situasi yang bisa dikembangkan jika ini telah situasi darurat nyata. Membangun disepakati daerah untuk perbaikan yang perlu latihan selama latihan masa depan. 3.7.4 latihan kebakaran Tujuan dari Api Bor Siapkan Tim Tanggap (yaitu, Fire Fighting Skuad) untuk mengurangi api dan menyelamatkan personil terluka dan / atau terperangkap. Juga, menunjukkan bahwa anggota Fighting Skuad Api memahami tugas mereka yang ditunjuk dan melakukan mereka dengan cara yang dapat diterima. Fire Fighting Anggota Squad Satu (I) Pemadam Kebakaran pemimpin Squad Empat (4) Fire Fighters Pedoman api Bor 1. Lima orang Pemadam Kebakaran Squad harus diselenggarakan untuk setiap shift 12-jam. 2. Setiap anggota dari Fire Fighting Skuad harus memiliki on the job training. 3. The Fire Fighting Leader Squad harus telah menyelesaikan kursus pelatihan pemadam kebakaran. 4. Menetapkan petugas medis on-board untuk Fire Fighting Squad praktis. 5. Salah satu anggota di setiap Fire Fighting Squad adalah untuk diangkat pemimpin Squad asisten. 6. Off-tugas personil harus berpartisipasi dalam latihan ini jika memungkinkan. 7. Melakukan latihan kebakaran tanpa pemberitahuan dan / atau malam bor sekali setiap bulan 8. Latihan harus mencakup cedera mengejek dan / atau situasi penyelamatan. 9. Sesekali menunjuk pemimpin Squad sebagai orang yang terluka selama situasi penyelamatan sehingga asisten bahwa pemimpin Squad memimpin Fire Fighting Squad. baik dalam posisi dan dekat BOP kecuali ketika di lubang terbuka). 7. Memobilisasi stand-dengan perahu atau kapal pasokan, jika tersedia, ke posisi standby. 8. Berkomunikasi laporan selama setiap fase bor untuk ditunjuk "pusat komando" 10. Lokasi kebakaran harus bervariasi. Prosedur api Bor Langkah-langkah berikut merupakan suatu latihan kebakaran yang efektif: 1. Pengamat api harus membunyikan alarm dan menyarankan fasilitas lokasi kebakaran. 9. Semua personil tidak terlibat dalam memerangi api atau dalam operasi rig kritis untuk mengumpulkan di stasiun kerahkan mereka yang ditunjuk. 10. Sebuah kerahkan harus diambil untuk memastikan bahwa semua personil dicatat dan hasilnya dilaporkan kepada Orang Dalam Mengisi (PIC). 2. Person In Charge (PIC) atau utusannya harus segera pergi ke pusat komando pra-ditunjuk (misalnya, ruang radio, jembatan, ruang kontrol, dll). 11. The Pemadam Kebakaran Squad respon untuk menyertakan simulasi tindakan yang diperlukan untuk mengurangi api jika keadaan darurat yang sebenarnya sedang berlangsung. 3. Peralatan komunikasi rig dan prosedur yang akan diuji oleh menyiagakan ditunjuk pantai dasar bahwa "latihan kebakaran" sedang berlangsung. 12. Pemimpin pasukan adalah untuk berkomunikasi situasi bahan berbahaya untuk Orang Dalam Mengisi (PIC) atau utusannya. 4. The Skuad Pemadam Kebakaran yang mengumpulkan di lokasi kebakaran. 13. Personil yang ditunjuk harus siaga untuk tindakan yang diperlukan untuk mendukung Fire Fighting Squad. Ini akan mencakup tugas seperti pembawa tandu, dll 5. Person In Charge (PIC) atau utusannya akan memberitahu kru bor untuk mengamankan sumur dan mengaktifkan sistem Shut Down (ESD) / Bah Darurat. 6. Bor awak mengamankan dengan baik (yaitu, ketika pengeboran / tersandung, posisi pipa untuk menutup- 14. Memasukkan menonton kebakaran setelah api keluar untuk menjaga terhadap pengapian. 15. Orang Dalam Mengisi (PIC) bertanggung jawab untuk de-penyiraman operasi dan pemantauan kapal siaga seluruh operasi pemadaman kebakaran. 16. Pemimpin pasukan adalah untuk mempersiapkan kritik setelah latihan kebakaran dan mengadakan sesi diskusi. 17. Lengkapi Bor Laporan dan maju ke Operasi Inspektur. MERAKIT 3.7.5 KEBAKARAN DRILL -example SKENARIO TANGGAL WAKTU: 4-25-84 / 0030 LEVEL: Serius MENGUSU T LOKASI: Penyemenan Room KEBAKARAN: TERLUKA: No.2 LOKASI: Terjebak dalam ruang dekat api PENEKANA N: Pencari yang efektif untuk hilang awak. KEBAKARA N SKENARIO: Periksa Komunikasi. Sebut pantai dasar & kapal. Kru yang belum ditetapkan untuk mengumpulkan di daerah ditugaskan. Gulung memanggil Jack-Up stasiun ditinggalkan. Beritahu Orang Dalam Mengisi (PIC) dari siapa pun hilang dar roll. Api kru untuk merakit dekat daerah api. - Ditugaskan anggota tim pemadam kebakaran untuk memeriksa area kebakaran. Tim api singkat pada kondisi kebakaran. Panggilan untuk pesta penyelamatan medis -Masukkan. Bocor saluran bahan bakar diesel semprotan pada berjenis MEMBATA - Api Kru mengandung api untuk menyebabkan kebakaran untuk menelan SI mesin. Dua operator memungkinkan penyelamatan dari cedera. berlindung di kantor yang keluar hanya terbakar. PERILAKU ALARM SUARA Alarm suara Mengumumkan Bor lokasi -Fire. Penyelamatan awak untuk bergerak terluka ke daerah yang aman. Medic untuk menghadiri personil yang terluka. RESCUE Minimum Life Boat Pelengkap: PEMADAM Menyebarkan tim kebakaran untuk memadamkan api. Memadamkan Api. Kritik Satu (I) Boat Komandan Bersertifikat sebagai Komandan Satu (I) Mekanisme Rilis Operator Bersertifikat Life Boatman (Coxswain) Merakit semua pengawas dan tim pemadam Dua (2) anggota awak lainnya bersertifikat sebagai kebakaran. Hidup Boatman (Coxswain) Diskusikan tujuan drill - apakah itu dicapai? Satu (I) Electrician atau Mechanic -Operate winch perahu kehidupan Diskusikan prosedur atau peralatan masalah. DISKUSI - Lengkap Bor Laporan dan mengirimkan salinan ke kantor. LAPORAN Dokumen bor di IADC dan Harian Pengeboran Laporan Maju Laporan Bor untuk Operasi Inspektur. 3.7.6 ABANDON latihan RIG Tujuan dari Abaikan Rig Bor Memastikan bahwa personil rig dapat melakukan tugas mereka ditugaskan dan menunjukkan operasi sekoci dan peralatan terkait dan bahwa semua personel on-board (terutama non-Rig kontraktor personil) tahu bagaimana / kapan harus aman mengumpulkan dan mengevakuasi. Untuk membantu rekoneksi sekoci menurunkan garis setelah bor selesai dan untuk membantu dalam mengoreksi masalah mekanis yang tak terduga, ini adalah pelengkap minimum yang diperlukan untuk launching bor. Abaikan Pedoman Rig Bor 1. Pastikan bahwa frekuensi radio rig, lokasi rig, dan judul untuk perlindungan yang aman yang diposting di setiap sekoci. 2. Kadang-kadang memegang bor tanpa pemberitahuan sebelumnya kepada kru. 3. Sebagian rendah (yaitu, 10-15 kaki) semua sekoci minggu sekali setiap, cuaca memungkinkan. 4. Sekoci peluncuran, navigasi di perairan terbuka, dan mengambil bulanan jika mungkin tapi setidaknya sekali per kuartal. 5. Hanya meluncurkan sekoci selama kondisi cuaca / laut yang wajar dan ketika pasokan kapal / standby siap untuk menyelamatkan jika diperlukan. 6. Melakukan mendadak meninggalkan rig pengeboran dan / atau malam bor sekali setiap bulan, dan setidaknya sekali per bulan, bor harus mencakup cedera tiruan atau situasi penyelamatan. 7. Personil tidak diperlukan di dalam sekoci sementara sebagian menurunkan dan menaikkan. 8. Mesin uji dan sistem sprinkler di sekoci mingguan saat air dapat diberikan. 9. Jangan menurunkan sekoci ke dalam air sampai mesin (s) sedang berjalan. 2. Suara alarm yang ditunjuk untuk meninggalkan rig. Jenis alarm tagihan stasiun rig di berbagai lokasi. Mengumumkan bahwa ini adalah latihan atas sistem alamat publik. 3. Peralatan komunikasi rig dan prosedur diuji oleh memperingatkan ditunjuk pantai dasar bahwa "Sekoci Launching Bor" sedang berlangsung. 4. Semua personil untuk melaporkan segera ke mereka tugas tagihan stasiun dan mengumpulkan kartu ditinggalkan mereka dari pemegang kartu kecuali dimaafkan untuk melanjutkan operasi. Alasan membutuhkan persetujuan terlebih dahulu dari Operasi Pengawas dan oleh pengecualian saja. 10. Pastikan minimal empat (4) orang berada di sekoci ketika diluncurkan. 5. Semua personil untuk memakai pakaian yang tepat dan membawa peralatan survival untuk mengebor (yaitu, baik jaket pelampung atau kelangsungan hidup sesuai tergantung pada lingkungan). 11. Man sekoci derek dengan individu yang memenuhi syarat (misalnya, rig listrik atau mekanik) selama peluncuran dan pemulihan dari sekoci. 6. Hidup Boatmen mempersiapkan kehidupan Boat untuk naik (yaitu, pasang grip dan liontin keselamatan), 12. Mensimulasikan mengamankan sumur dan mengaktifkan sistem rig ESD / Deluge. 7. Personil masukkan Life Boat petunjuk berikut dengan Boat Commander dan kencangkan sabuk pengaman mereka segera. Langkah-langkah berikut merupakan suatu efisien Abaikan Rig pengeboran: 1. Memastikan bahwa / kapal pasokan stand-by dipindahkan ke sekitar daerah pendaratan sekoci sebelum menurunkan sekoci jika peluncuran yang sebenarnya harus dilakukan. 8. Orang yang kartu tetap dalam pemegang kartu di ditinggalkannya stasiun berada. 9. Kontak radio dibuat sebelum meluncurkan dan dijaga setiap waktu pada frekuensi yang jelas telah ditentukan antara Boat Commander dan Orang In Charge (PIC) atau utusannya yang memiliki muatan keseluruhan bor. 10. Mesin (s) dimulai dan dioperasikan selama beberapa menit. 11. Perahu Komandan adalah untuk menjelaskan prosedur operasi dan menurunkan. 12. Jika TIDAK LAUNCHING Kehidupan Boat, semua personil kapal Life Boat adalah untuk keluar secara teratur dan kerahkan untuk diskusi bor. 13. Jika LAUNCHING Kehidupan Boat, semua personil kapal Life Boat kecuali "Minimum Life Boat Pelengkap" yang keluar secara teratur dan kerahkan untuk diskusi bor. 14. Komandan perahu untuk memastikan daerah pendaratan yang jelas di bawah sekoci sebelum menurunkan. 15. Setelah sekoci meninggalkan davits, tidak ada orang selain Boat Commander akan melakukan apa pun untuk mempengaruhi menurunkan sekoci. 16. Perintah untuk melepaskan sekoci dari menurunkan garis tidak akan diberikan oleh pihak lain selain perahu Komandan dan tidak akan diberikan olehnya sampai ia memastikan dengan cara visual yang sekoci adalah ditularkan melalui air. 17. Boat Commander akan merilis dan manuver sekoci jauh dari rig ke titik kumpul yang ditunjuk pra. Praktis, mengoperasikan semua peralatan untuk memastikan berfungsinya. 18. Perahu Komandan adalah untuk manuver sekoci sepanjang sisi rig, melampirkan menurunkan kait line untuk sekoci. 19. Angkat sekoci kembali ke davits dan aman sebelum keluar personil sekoci. 20. Perahu Komandan adalah untuk melakukan kritik verbal dengan krunya setelah menyelesaikan bor. Diskusi harus fokus pada daerah untuk perbaikan dan prosedur ditinggalkan alternatif. 21. Orang yang bertanggung jawab adalah untuk mengkritik bor dengan Komandan Kapal. 3.7.7 ABANDON RIG DRILL -example SKENARIO TANGGAL WAKTU: 4-25-84 / 0030 LEVEL: MAJOR LOKASI: Sekoci Memanjang KEBAKARAN: Tidak ada TERLUKA: Nomor 0 LOKASI: KERUSAK AN: Maju sekoci dioperasi PENEKANA N: Ditinggalkan tertib dengan satu sekoci yang rusak. SITUASI: PERILAKU Badai telah merusak maju sekoci dan kapal adalah daftar. Pengabaian harus memanfaatkan sekoci belakang dan dua rakit. CRITIOUE ALARM SUARA MERAKIT PERAHU LAUNCH (Simulasikan) PERAHU LAUNCH (Aktual) Suara Alarm. Mengumumkan maju perahu tidak beroperasi. DISKUSI Periksa Komunikasi. Sebut dasar pantai / perahu. Merakit semua pengawas dan komandan sekoci. Membahas tujuan bor -adalah itu dicapai? Diskusikan prosedur atau peralatan masalah. Muster di perahu belakang daerah. LAPORAN Dewan Life Boat pergeseran fwd awak ke rakit. Gulung menelepon. - Dokumen bor di IADC dan Harian Drilling Report. Mencari orang hilang dari roll. 3.7.8 Man Overboard DRILL - Instruksikan pada Launching Boats. - Lengkap Bor Laporan dan mengirim salinan kantor. Tujuan dari Man Overboard Bor Memastikan bahwa personil rig dapat melakukan tugas mereka ditugaskan ketika seseorang masuk ke Mengoperasikan Semua Peralatan. dalam air. Mulai mesin. Instruksikan pada Pengabaian Alternatif. Anggota Tim penyelamat: Satu (I) pemimpin tim penyelamat Satu (I) Penyelamatan Boat - Turun semua personil kecuali awak perahu kehidupan (4). Commander - Stasiun Electrician di winch. - Peluncuran sekoci. Satu (I) Penyelamatan Kapal Rilis Mekanisme Operator (Coxswain) Dua (2) anggota awak lainnya yang Coxswains berkualitas Satu (I) Electrician atau Mechanic untuk mengoperasikan penyelamatan kapal winch Pedoman Bor Man Overboard 1. Menyelenggarakan (6 orang) Tim Penyelamat untuk setiap kru. 2. Praktis, menetapkan medis rig ke salah satu Tim Penyelamat. 3. Latihan rencana untuk menekankan titik kunci (s) atau daerah untuk perbaikan. 3. Memasukkan pandangan-keluar (s) pada titik terbaik dengan teropong yang tanggung jawab adalah untuk menjaga melihat orang laut, selama mungkin, dan terus-menerus menunjuk ke arahnya. 4. Peralatan rig komunikasi dan prosedur diuji oleh memperingatkan ditunjuk pantai dasar bahwa "manusia kapal bor" sedang berlangsung. 5. Melemparkan cincin kehidupan di sekitar manusia ke laut (yaitu, boneka apung) sesegera mungkin. Berkala, menggunakan lampu dan flare asap menambah realisme untuk mengebor. 4. Hanya memulai penyelamatan kapal selama kondisi cuaca dan laut yang wajar ketika pasokan kapal / standby siap untuk menyelamatkan jika diperlukan. 6. Orang yang bertanggung jawab adalah untuk mengumpulkan Rescue Team di rescue boat. Rig medis adalah untuk memberikan pertolongan pertama kepada manusia ke laut. 5. Melakukan man laut bor tanpa pemberitahuan dan / atau malam bor sekali setiap bulan, dan setidaknya sekali per bulan, bor harus mencakup cedera tiruan atau situasi penyelamatan. 7. Jika pasokan atau kapal stand-by tersedia, memberitahukan kapal bantuan. Kapal yang menggunakan jaring untuk berebut secepat praktis. Prosedur Overboard Man Langkah-langkah berikut merupakan suatu Man Overboard bor efisien: 1. Untuk mensimulasikan seorang pria ke laut, melempar boneka apung ke dalam air yang ukuran perkiraan, bentuk dan berat seorang pria. 2. Lulus kata-kata "Man Overboard" pada melempar boneka ke laut. 8. Jika pengambilan dimungkinkan dengan crane, operator crane adalah menurunkan keranjang personel dengan dua anggota kru, mengenakan lifejackets, untuk mengambil orang itu ke laut. 9. Ketika cuaca memungkinkan, peluncuran penyelamatan kapal dan mengambil Man Overboard. Pastikan bahwa Electrician atau Mechanic operasi penyelamatan kapal winch di rig. Dalam skenario ini, menganggap individu (s) tidak dapat membantu diri mereka sendiri dan menentukan kesesuaian alat pengambilan dan teknik untuk memulihkan individu terluka atau tidak sadar setelah pergi ke laut. Menilai kesesuaian teknik jika kondisi cuaca secara signifikan lebih buruk. 10. Jika penyelamatan perahu tidak diluncurkan, mengambil Man Overboard dummy dengan pasokan kapal / standby. 11. Kerahkan seluruh kru ke lokasi pra-ditunjuk. Lakukan apel untuk menentukan jumlah dan namanama anggota yang hilang awak (s). Laporan hasil untuk orang yang bertanggung jawab. 12. Setelah menyelesaikan bor, membuat entri log yang sesuai termasuk waktu yang dibutuhkan untuk memulihkan pria laut. 13. Rescue Team Leader adalah untuk mempersiapkan kritik dan tahan sesi diskusi dengan Tim penyelamat dan Personalia rig. 3.7.9 latihan KHUSUS Tujuan dari Bor Khusus Melibatkan tim respon dan / atau kelompokkelompok kecil dari kru dalam pelatihan khusus sehingga pelatihan yang dapat fokus pada keterampilan khusus dalam bidang yang perlu perbaikan dan mengembangkan tim respon yang efektif. Beberapa contoh jenis keterampilan cocok untuk pelatihan ini adalah: Kehidupan perahu LaunchingKecil jumlah peluncuran kru dan mengoperasikan kapal. Penyelamatan Operasi -Rescue Tim berlatih mankapal bor atau penyelamatan atau korban kebakaran. Kebakaran helikopter -Fire Berjuang Squad tes sistem busa untuk api helikopter. Pemberat Kontrol -React peralatan gagal. Kebakaran khusus -Fire Berjuang praktek Squad mengurangi kebakaran di ruang tertutup dengan menggunakan peralatan pernapasan. 3.7.10 ASPEK UTAMA latihan Skenario bor harus berempati keterampilan yang tercantum di bawah ini. Api Dr penyakit: Komunikasi koordinasi Koordinasi Penanggulangan Kebakaran Skuad Koordinasi Penyelamatan Tim Penanganan Situasi Api Complex: Ruang tertutup Akses terbatas Kombinasi di atas Berjuang jenis api yang berbeda Personil terluka Penggunaan Peralatan seperti: Bernapas Peralatan Usungan Api selang Radio 3,8 KAPAL menghindari tabrakan Kapal Tabrakan Penghindaran Kata Pengantar Unit pengeboran tidak boleh berlokasi dekat jalur pelayaranRig: maupun antara jalur pelayaran batas jika Abaikan Latihan memungkinkan. Jika perlu, sumur directional dapat dibor untuk menghindari daerah-daerah. Jika Unit Komunikasi koordinasi Pengeboran harus ditempatkan di daerah tersebut, Meninggalkan sekoci -satuuntuk dinonaktifkan penilaian risiko operasi harus mencakup kedekatan Unit Pengeboran untuk kapal daerah lalu Meninggalkan rute -escape diblokir lintas. Operasi sekoci di lokasi jalur laut Semua Satuan Pengeboran diusulkan harus diteliti untuk pengiriman jalur kedekatan dan lalu Muster & personil lintas di akuntabilitas daerah dan tepat "Deteksi Prosedur" penilaian disiapkan dan risiko selesai. Satu-satunya cara untuk menghindari tabrakan Man Overboard Latihan: adalah untuk melihat kapal bandel awal dan mengeluarkan peringatan. Prosedur dan pedoman Tanggapanyang awaldijelaskan bagi manusia ke lautharus diikuti. di bawah Menggunakan kehidupan dan 3.8.1perahu DETEKSI penyelamatan kapal Umum Deteksi Pedoman -Untuk MODU di atau Pemberiandekat pertolongan pertama jalur pelayaran Koordinator Komunikasi Semua personil on-board Unit Pengeboran bertanggung jawab untuk kewaspadaan dalam Koordinasi kerajinan lain di daerah mendeteksi kapal yang bersalah mendekati situs. Namun, tingkat pelaksanaan program deteksi resmi Posting dan menjaga lookout akan tergantung pada kedekatan Unit Pengeboran untuk pengiriman jalur dan / atau lalu lintas kapal berat. Ada banyak "tidak resmi" jalur pelayaran yang digunakan oleh kapal sesingkat-luka dan beberapa program deteksi selalu diperlukan. 1. Pastikan semua sistem radar reflektor beacon fungsional setiap saat. 2. Selama kondisi berkabut, memasukkan menonton radar di Unit Pengeboran. Di daerah-daerah berisiko tinggi, yaitu, dekat jalur pelayaran atau berat bepergian rute, prosedur radar dijelaskan di bawah harus dilaksanakan pada unit pengeboran. Operasi Radar 3. Terus menerus 24 jam radar jam tangan dan / atau pembuluh standby harus digunakan ketika di sekitar kapal yang tinggi lalu lintas dan pengiriman jalur. 4. Radar menonton dan / atau kapal prosedur menonton siaga bila beroperasi di dekat kapal lalu lintas harus diselesaikan dan disetujui oleh Manajer Bidang Pengeboran untuk memasukkan; Rencana aksi untuk berbagai pendekatan radar dan tentu saja kapal judul. Rencana pemberitahuan kapal Pengabaian prosedur 5. Memastikan bahwa semua alat bantu navigasi (pencahayaan dan peluit kabut) yang operasional. 6. Menyarankan semua personel Satuan Pengeboran selama Pertemuan Keselamatan untuk waspada untuk mendekati kapal. 7. Segera memberitahukan Offshore Installation Manager setelah bercak kapal dipertanyakan atau kapal mendekati 8. Sebuah pinger sonar akan dipasang dan beroperasi setiap saat setelah rig diposisikan. 3.8.2 RADAR PROSEDUR PERHATIKAN 1. Instalasi radar Drilling Unit harus berada: Di daerah menyediakan kontak visual dengan laut luar sekitarnya, yaitu, jembatan, dll Jauh dari daerah berat bepergian dan berisik, yaitu, tidak berada di ruang radio. Dekat radio VHF Marine. 2. Operator radar berkualitas dan terlatih untuk lakilaki stasiun radar 24 jam per hari dan akan hilang dengan personil kelautan yang memenuhi syarat setidaknya setiap 3 jam untuk istirahat. 3. Pengaturan satuan radar harus dipelihara sebagai berikut: Scanning utama diatur ke 12 nm. Audio alarm ditetapkan untuk 5 nm. Batin Penjaga Cincin ditetapkan untuk 2 nm. 4. Tugas Radar Perhiasan Operator harus mencakup: Terus manusia stasiun radar kecuali bila lega untuk istirahat. Mempertahankan pengaturan satuan radar dijelaskan di atas. Melacak semua kapal dalam 12 nautical mil dan menentukan berbagai pos saja mereka. Kapal kontak mencapai 5 mil laut berbagai posisi dan permintaan kapal Drilling Unit mempertahankan 2 pemisahan mil laut. Radio Kontak Tidak Didirikan Radar Perhiasan Operator akan memberitahukan Offshore Installation Manager (OIM). OIM akan mengirimkan pasokan kapal / standby untuk menarik perhatian kapal (misalnya, selang kebakaran, kapal tanduk, radio). Menjaga buku catatan dari semua kontak dengan kapal. Prosedur peringatan 1. Kapal dalam rentang radar 12 mil laut utama akan ditandai dengan "EBL" oleh Penyelenggara Radar yang akan melacak pos kapal dan menentukan judul saja. 2. Kapal mencapai kisaran 5 NM akan dihubungi oleh Penyelenggara Radar: Meminta kapal mempertahankan 2 mil laut dari pemisahan Unit Pengeboran. 3. Kapal mencapai kisaran 4 NM dan tentu saja: Radar Perhiasan Operator Beritahu OIM. Lepas pantai Instalasi Manajer Hubungi kapal untuk mengalihkan jalurnya dan / atau menentukan apakah kapal mengalami kesulitan mekanik. Radio Hubungi Didirikan Verifikasi awak kapal menyadari posisi instalasi Drilling Unit. Beritahu Operasi Pengawas bertugas yang tabrakan adalah mungkin. Mengkonfirmasi bahwa kapal tersebut tidak dalam kesulitan mekanik. Beritahu pasokan kapal / standby untuk mencegat kapal. 4. Kapal mencapai kisaran 4 NM dan pada jalur tabrakan yang tidak bisa dihubungi dan / atau memiliki kesulitan mekanik (mesin / kegagalan kemudi): Beritahu pasokan kapal / standby untuk membantu rig ditinggalkan. Lepas pantai Instalasi Manajer Abaikan rig. Beritahu pasokan kapal / standby untuk kembali ke rig jika kapal tidak dapat disadap. Beritahu Operasi Pengawas bertugas. Terdengar alarm dan mengumpulkan personil rig di stasiun ditinggalkan mereka. Operasi Pengawas Beritahu Bor kru untuk mengamankan sumur. Beritahu Shore Basis yang tabrakan adalah mungkin dan dekat. 5. Kapal mencapai 2 NM radar penjaga cincin pada bertabrakan: Lepas pantai Instalasi Manajer Menentukan kebutuhan untuk ditinggalkan. Membunyikan alarm ditinggalkan untuk Unit Pengeboran. Disiarkan peringatan navigasi terus menerus. BAGIAN 3 - GI LAMPIRAN MEMORANDUM ExxonMobil Development Co Pengeboran DATE: UNTUK: PRODUKSI DAN DRILLING OPT. SUPTS DARI: KANTOR TEKNIK TEAM SUBJECT: "" Landasan Drilling Program SIMOPS Rapat / Miru LATAR BELAKANG The jack-up rig pengeboran dijadwalkan mulai beroperasi pada "" Platform tentang . Pada , Pertemuan SIMOPS diadakan untuk mengevaluasi risiko yang terlibat dengan simultan pengeboran dan produksi operasi di platform. Berikut ini adalah ringkasan dari tinjauan dari SIMOPS Pindah-In / Rig-Up Checklist untuk Jack-Up Rig Pengeboran. SIMOPS Miru DAFTAR REVIEW 1. Sebuah survei mudline dengan penyelam dan / atau sisi scan sonar mungkin diperlukan untuk memeriksa setiap rintangan atau puing-puing yang mungkin di daerah mana rig tersebut akan diposisikan. Menentukan apakah pipa daerah perlu didukung untuk pendekatan direncanakan rig. Pada saat-platform di mana rig jack-up telah beroperasi sebelumnya, jejak dari rig yang akan dipelajari untuk menentukan apakah dapat digunakan kembali. (Catatan: Sisi scan sonar biasanya dilakukan jika rig jack-up belum di lokasi withi n 12 bulan, atau jika ada konstruksi atau workover kerja yang cukup besar telah dilakukan dalam tahun lalu). Catatan, jika ada pipa berada dalam 490 ft dari rig, MMS membutuhkan pelampung, kecuali pengabaian diperoleh. Global positioning biasanya cukup untuk mendapatkan pengabaian kecuali kaleng kentang sangat dekat (~ 50 kaki) ke pipa. • 2. Mengevaluasi potensi pukulan-melalui kaki rig. • 3. Mengevaluasi adonan leg platform yang dan posisi lumba-lumba gangguan potensial dengan kaki rig. Rekayasa pengeboran / Bawah Permukaan akan memberikan gambar skala rig, kaleng kentang, dll • 4. Meninjau lokasi semua pipa, garis flare bawah air, peralatan rocess p jalur ventilasi, penambah pipa, dll dan menentukan apakah ada relokasi atau perlindungan kerja yang diperlukan. Pipa aktif yang diharapkan akan terletak di bawah tongkang jack- up akan tekanannya selama MOB / DEMOB. Bagi mereka baris untuk diaktifkan kembali setelah Miru, keputusan bersama oleh Pengeboran dan Operasi Produksi Manajemen dibuat mengenai tindakan pencegahan khusus diperlukan untuk memastikan bahwa tingkat yang sesuai keselamatan tetap terjaga. • 5. D etermine jika produksi dek proce utama peralatan ssing terletak di bawah kantilever membutuhkan perlindungan atau relokasi. (Catatan: Ada tidak ada kapal yang tidak dilindungi bertekanan proses, seperti separator, menara kontak glikol, dll, terletak di bawah kantilever, maupun gas ventilasi di t daerahnya). • 6. Peralatan proses yang tidak dilindungi terletak 10 ft. Kantilever harus memiliki monitor api, dioperasikan dari rig, diarahkan di atasnya. • 7. Cari semua stasiun peralatan perlindungan kebakaran di dek utama, dan menentukan apakah mereka memerlukan relokasi. • 8. Jika platform memiliki sistem minuman keras, memastikan bahwa itu adalah beroperasi dan memenuhi deliverabilityrequirements untuk fasilitas itu. • 9. Pastikan bahwa lokasi yang ditunjuk daerah aman pengelasan rig memenuhi semua MMS dan peraturan ExxonMobil (mempertimbangkan distan ces dari bahan yang mudah terbakar atau peralatan proses yang mengandung hidrokarbon yang ada). • 10. Sebuah gambar yang menggambarkan skala Platform / rig tata letak peralatan harus dikembangkan menyoroti daerah yang ditunjuk aman pengelasan, serta daerah di mana Kerja Hot adalah proh ibited. • 11. Periksa semua platform yang dek kisi-kisi, plating, papan, dan pegangan tangan, dan mengatur perbaikan atau penggantian yang diperlukan. • 12. Memastikan bahwa semua bantuan ke menu beroperasi dengan benar. • 13. Merekam semua tekanan casing pada kedua memproduksi dan non-penghasil wel ls. Informasi ini ditransmisikan ke Drilling atau Workover Engineer. â € ¢ tekanan Casing pada SEMUA adalah sebagai berikut: Nama baik Di dalam drive Pipa Konduktor dalam Permukaan dalam Catatan: NA berarti bahwa tidak ada tekanan segel & Gauge di annulus. 14. Tinjau dengan Lapangan Inspektur jadwal bergerak rig untuk mengkoordinasikan Operasi Produksi sementara rig sedang dimobilisasi / didemobilisasi dan kantilever ke posisi atas platform. • Bidang Supts: atau & , x- 18. Jika rig terletak pada platform dengan tempat produksi, sistem alarm darurat rig terhubung ke sistem alarm produksi dan alarm ini akan kompatibel. • 19. Pastikan bahwa pencahayaan darurat yang cukup tersedia di semua pintu keluar kuartal hidup, sepanjang rute pelarian, dan pada kapsul melarikan diri untuk memberikan transit yang aman ke daerah kerahkan. • EMDC Pengeboran Supts: at ( ) ORANG YANG BERTUGAS (PIC) 15. Sebuah gambar skala yang menunjukkan posisi rig dan kantilever dalam kaitannya dengan peralatan proses Platform, peralatan perlindungan kebakaran, pencahayaan, melarikan diri rute, dll dikembangkan dan didistribusikan. • 16. Pastikan crane kontraktor memenuhi persyaratan pemeriksaan API RP2D. Dokumentasi pemeriksaan ini diperlukan. • 17. Rencana Evakuasi Darurat (EEP) lembar data selesai dan diajukan untuk persetujuan kepada Pejabat lokal di Charge Kelautan Inspeksi Amerika Serikat Coast Guard sebelum s pud. Bidang Inspektur harus mengumpulkan data untuk EEP dan meneruskannya ke Regulatory Affairs Engineer. • The akan PIC. Drilling dan Lapangan Pengawas akan bekerja sama untuk mengkoordinasikan mengikat rig dan platform ESD sistem bersama-sama, memanfaatkan I & E Teknisi, per SIMOP itu Manual. PIC dan Lapangan Inspektur harus berkomunikasi setiap hari sebelum pertemuan keselamatan Produksi 06:00 mengenai isu-isu keamanan dan status pekerjaan. PERSETUJUAN Ops pengeboran. Supt. Ops produksi. Supt. SIMOPS Rapat Peserta: MARINE OPERASI BAGIAN 3 - LAMPIRAN G-II AS-TIMUR SIMULTAN OPERATIONS DEVIASI REQUEST DATE: LOKASI: Originator: FIELD PIC: JENIS OPERASI: KEGIATAN JENIS: PERSYARATAN NO: IDENTIFIKASI JENIS KEBUTUHAN: MMS HARUS harus MASA DEVIASI: DARI ATAS URAIAN DEVIASI: PENCEGAHAN KHUSUS DIAMBIL: PERSETUJUAN DIBUTUHKAN: FIELD SUPERINTE NDENT: originator OA ID: DRILLING OPERASI manual-JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 1 Pertama Edition - Mei 2003 MARINE OPERASI BAGIAN 3 â € "LAMPIRAN GIV PEMERIKSAAN PRA-STARTUP UNTUK BARU UNTUK ARMADA jackup DRILLING RIGS 3. Pedoman Exxon untuk Menyiapkan dan Melakukan Efektif latihan pada MOU. Sebuah perusahaan pihak ketiga (ModuSpec) dengan surveyor terlatih dalam pedoman ini telah dikontrak untuk melakukan inspeksi dan melaporkan temuan. 1.2 Integritas Struktural 1.0 Tujuan 1.2.1 Penilaian Untuk mendokumentasikan praktek saat kepatuhan dengan Bagian Satuan Keamanan di Laut Mobile Offshore dari ExxonMobil Hulu Desain Bimbingan manual Untuk MOU atau desain yang telah memiliki penilaian integritas struktural di masa lalu. Penilaian terdiri dari: 1.1 Pemeriksaan Kritis Kelautan dan Peralatan Darurat / Survey Marine Safety Inspeksi tersebut memastikan bahwa peralatan MOU sesuai dengan Hulu Desain Bimbingan Manual, dipertahankan, dan operasional. Selain itu akan membahas kompetensi personel dan kinerja personil dalam fungsi kelautan kritis dan tanggap darurat. Pemeriksaan dilakukan sesuai dengan pedoman berikut: 1. Hulu Desain Bimbingan Pedoman Mobile Offshore Satuan Marina Keselamatan 2. Lepas pantai melarikan diri Instalasi, Evakuasi, dan Analisis Pedoman Penilaian Rescue, EPR.61PR.96 1. Sebuah tinjauan lambung dan kaki inspeksi sebelumnya termasuk Klasifikasi Masyarakat (ABS, D & V, Lloyd) Periodik Survey khusus. Bantuan teknis dalam mengkaji dokumen-dokumen ini tersedia dari Stan Christman di Drilling Technology Group. 2. Sebuah tinjauan sejarah operasi sebelumnya 3. Sebuah tinjauan dari kondisi lingkungan situs tertentu. Untuk MOU baru desain analisis struktural dan kelelahan diperlukan dan harus diselesaikan dengan bantuan teknis dari Hulu Penelitian Perusahaan. 4.4 Struktur drive Pipa 4 OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 2 Pertama Edition - Mei 2003 4,5 Konduktor dan Permukaan Casing Interval 5 MARINE OPERASI 4,6 pengalir Operasi 6 1.2.2 Inspeksi Pemeriksaan jika diperlukan terdiri dari visual dan NDT dari bidang-bidang berikut: kantilever, crane tiang, helideck, sistem jacking, struktur jackhouse, kaleng kentang, dan kaki. Rencana pemeriksaan untuk pemeriksaan rutin dapat dikembangkan oleh Bennett & Associates atau ModuSpec. URC harus dihubungi untuk rencana pemeriksaan untuk aplikasi jackup tidak biasa seperti es laut, seismicicty tinggi, kondisi tanah yang tidak biasa, dll 4,7 Menengah / pelindung Casing Interval 6 4.8 Produksi Casing / Liner Interval 7 4,9 Slot Pemulihan / Whipstock / Bagian Mill / Cut & Pull 7 4.10 lubang sumur Anti-Collision Pedoman 9 4.10.1 Persyaratan untuk "Risiko Collision" Wells 9 4.10.2 Persyaratan untuk Semua Directional Wells 10 OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 2 dari 2 4.11 Survei Directional dan Deviasi Kontrol 11 Pertama Edition - Mei 2003 4.12 Bor String Desain 12 4.0 DRILLING OPERATION 4.13 Bawah Lubang Sidang 14 4.1 Pendahuluan 1 4.14 Hidrogen Sulfida Pertimbangan 17 4.2 Umum Operasi Pedoman 1 4.3 Pra-Spud Operasi 3 4.15 Hidrogen Sulfida Contingency Rencana 19 __________________________________________ ____________________________________ DRILLING OPERATIOS MANUAL - JACK-UP / PLATFORM barage RIG DRILLING PERTAMA EDITION - MAY 2003 4.1 PENDAHULUAN Bagian ini memberikan pedoman untuk melakukan operasi pengeboran yang aman, efisien, dan ramah lingkungan. Pedoman ini dapat dimodifikasi berdasarkan kondisi baik sebenarnya setelah persetujuan sebagaimana ditentukan dalam OIMS. Persyaratan khusus untuk masing-masing juga akan dibahas dalam prosedur pengeboran inti yang ditunjuk oleh masing-masing tim bor untuk operasi pengeboran khusus mereka. Untuk rincian tentang pemasangan berbagai komponen kepala sumur, lihat manual wellhead produsen operasi. Menerapkan teknologi pengeboran terbukti operasi rig efisien adalah penting untuk meminimalkan biaya pengeboran. Karena setiap lubang bor berbeda, pengawas pengeboran harus tetap fleksibel dan melakukan penilaian yang baik dalam meminta izin untuk melakukan perubahan prosedur yang telah disetujui. Perencanaan dan desain kriteria luas telah pergi ke dalam susunan sebuah disetujui pengeboran prosedur. Jika upgrade diperlukan karena atau pengetahuan langsung onsite pembelajaran ini, Menhub (Manajemen Perubahan) proses harus digunakan (lihat Bagian 4 â € "Lampiran VII untuk Form MOC disarankan). Proses ini memastikan bahwa semua anggota tim bor memiliki kesempatan untuk input dan menyadari semua perubahan. Ada sejumlah faktor yang berkontribusi untuk berpuasa, masalah pengeboran bebas: 1) secara konsisten mengikuti praktek yang baik, 2) tes penerimaan rig lengkap dan pelatihan keselamatan kru sebelum spudding, 3) mengatur komunikasi dan sistem sebelum spudding pelaporan, 4) memiliki semua bahan dan peralatan yang diperlukan untuk pekerjaan di lokasi dan diperiksa, 5) memiliki sistem perlindungan lingkungan terpasang dan berfungsi sebelum spudding, 6) pilih bit yang tepat, 7) benar merancang majelis lubang bawah, 8) menjalankan padatan rendah pengeboran cairan, 9) hidrolika optimal, anggota tim 10) bor mempertahankan kesadaran kondisi lubang, 11) menerapkan dan mengikuti praktik pencegahan pipa terjebak, dan 12) mengakui juga mengontrol tandatanda peringatan dini segera. Tujuan dari panduan ini bukan untuk memberikan rekomendasi spesifik untuk setiap situasi tetapi untuk memberikan pedoman. Personil pengeboran juga harus mengandalkan pengalaman dan pelatihan mereka untuk melengkapi manual ini. 4.2 UMUM OPERASI PEDOMAN 1. Semua pengukuran kedalaman harus dibuat dari titik acuan yang konsisten, bagian atas drive bushing kelly. "RKB" ketika ditentukan pada rig dengan sistem penggerak atas berarti permukaan meja putar. Setelah nippling up kepala casing, catatan atas laporan pengeboran harian elevasi spool flange relatif terhadap RKB. 2. Slip menangani harus diikat untuk mencegah menjatuhkan disengaja pipa selama kondisi berikut: Setiap kali BHA dekat atau di atas kepala sumur. Waktu lain ada kemungkinan lift memukul pipa di slip. 3. Selama pengeboran rutin di zona tekanan normal, WOB dan RPM harus bervariasi sebagai diperlukan untuk mempertahankan performa maksimal. Ketika pengeboran di dekat diantisipasi zona tekanan abnormal, parameter pengeboran harus dijaga konstan untuk memungkinkan deteksi tekanan yang lebih akurat. 4. Di bawah setiap string dari casing, kecuali konduktor, tes integritas tekanan harus dilakukan setelah 10 'lubang baru telah dibor untuk menentukan integritas formasi. The PIT biasanya akan dibawa ke bocor-off atau kendi diuji untuk tekanan ditentukan dalam prosedur, tetapi tidak akan melebihi tekanan tes casing (lihat Bagian 11 dari manual ini). 5. Perjalanan, domba-domba jantan buta akan ditutup ketika string bor dihapus dari sumur bor. Perhatian akan digunakan ketika domba buta dibuka, karena potensi tekanan terperangkap. Setiap rig harus memiliki prosedur di tempat untuk memonitor tekanan di bawah ekor domba jantan buta ketika mereka ditutup. 6. Ketika pipa keluar dari lubang, penutup rotary akan dipasang. 7. Mekanisme penguncian untuk mengunci bushing guru dalam rotary dan mangkuk di bushing induk harus bebas dan fungsional untuk rotary dipertimbangkan operasional. The kelly bushing akan terkunci sepanjang waktu (atau dihapus) kecuali jika prosedur khusus meminta mereka untuk menjadi sementara terkunci. 8. Sementara tersandung dalam lubang, mengisi string bor sering. Frekuensi akan ditentukan oleh pengawas pengeboran berdasarkan berat saat lumpur, kondisi lubang, dan kedalaman. Tangki perjalanan akan digunakan sementara berjalan di lubang kecuali dinyatakan ditangani oleh Bidang Pengeboran Manager. Jika digunakan, pompa lumpur tangki perjalanan di shaker serpih ketika mengosongkan. Adalah lebih baik untuk menggunakan drop tingkat lumpur maksimum yang dapat diterima dalam anulus bukan jumlah tegakan dijalankan sebagai string bor mengisi pedoman sementara tersandung lubang. Sebagai contoh, asumsikan lima inci 19 1/2 pipa bor PPF sedang berjalan di sebuah lubang dan mengambang pipa bor memungkinkan ada lumpur untuk memasukkan string bor. Setelah menjalankan 1.860 kaki, float pipa bor gagal memungkinkan lumpur ke Utabung dan keseimbangan dalam pipa bor dan anulus. Tergantung pada ukuran lubang, tingkat lumpur akan turun sebagai berikut: Lubang Ukuran, inci tingkat Mud drop, kaki 8 ½ 520 12 ¼ 238 17 ½ 114 19 ¼ 94 Persamaan khusus untuk 5 inci 19 1/2 pipa bor PPF untuk menghitung penurunan kadar cairan untuk skenario di atas adalah: d = L x [18,32 / ((D x D) 6.68)] di mana: d adalah penurunan lumpur di annulus, di kaki L adalah panjang 5 inci pipa bor berjalan tanpa mengisi, di kaki D adalah diameter lubang, dalam inci Sebuah persamaan umum untuk menghitung penurunan lumpur untuk ukuran string yang berbeda yang dijalankan di dalam lubang adalah: d = (C x L) / (A + C) di mana: d a d a l a h p e n u r u n a n l u m p u r d i a n n u l u s d i k a k i C a d a l a h k a p a s i t a s d r i l l s t r i n g d a l a m b b l / k a k i L adalah panjang drill string yang berjalan tanpa mengisi kaki A adalah kapasitas anulus di bbl / kaki Insinyur pengeboran dapat dengan mudah menghasilkan serangkaian tabel untuk sumur tertentu dan mengisi jadwal optimal berdasarkan pada penurunan tekanan downhole diterima yang akan didasarkan pada perkiraan tekanan pori sementara pengeboran. 9. Penyelesaian atau plug and Program ditinggalkan harus dikembangkan sementara hasil pengeboran. Hal ini memungkinkan peralatan yang akan dibeli secara tepat waktu dan selesai atau P & A pertimbangan, seperti casing sendi anjing berjalan untuk membantu mengendalikan kedalaman perforasi, yang akan dilaksanakan selama fase pengeboran. 10. Sebuah float non-porting akan dijalankan ketika pengeboran melalui casing ditetapkan pada cukup mendalam untuk memungkinkan sumur untuk menutup di. Setelah casing yang cukup diatur untuk memungkinkan baik yang akan ditutup, pelampung porting akan dijalankan. Modifikasi float pipa bor, termasuk port, tidak harus dilakukan di rig. Bidang modifikasi pipa bor mengapung tidak diperbolehkan. Entah Model "F" (plunger) atau Model "G" (flapper) dapat digunakan sebagai mengambang padat. Hanya Model "G" dapat digunakan dengan port mengeras di flapper. Ukuran umum dari katup mengambang adalah: Bit Ukuran 6 inci 8 1/2 inci 12 1/4 inci Alat bersama 3 1/2 Reguler 4 1/2 Reguler 6 5/8 Reguler ukuran katup mengambang 2F-3R 4R 5F-6R Sebuah katup pengaman (bola terbuka) dan di dalam BOP (plunger dikunci) akan berada di lantai rig. Sebuah katup pengaman dan dalam BOP akan tersedia, di lantai rig, untuk setiap ukuran pipa bor yang saat ini digunakan. Sebelum menjalankan atau menarik setiap kapal casing atau tubing, cross-over kembali ke katup pengaman dan katup pengaman harus berada di lantai rig. Katup pengaman harus fungsi diuji dan tes harus didokumentasikan pada laporan IADC dan DMR. 11. The Crown-O-Matic akan diperiksa setiap hari dan setelah tergelincir garis pengeboran. Hasil pemeriksaan ini harus dicatat setiap hari sesuai dengan Peraturan MMS. 12. Mengalir periksa semua koneksi. 13. Cepat (keras) menutup-dalam metode menggunakan pencegah annular untuk menutup-dalam sumur akan digunakan. 14. Jangan menguji pelumas dengan perforating senjata dalam untuk tekanan lebih tinggi dari senjata perforasi yang dinilai. 15. Tekanan annulus casing harus dipantau setiap hari pada semua rig dengan wellheads permukaan. Jika tekanan casing terdeteksi, itu harus dilaporkan pada Daily Drilling Report. Situasi harus ditinjau dengan Operasi Inspektur untuk menentukan apakah tindakan perbaikan yang diperlukan, misalnya berdarah off, peningkatan pemantauan, dll (OIMS manual Element 6). 16. Pipa tegak atau pompa lumpur hisap layar yang lebih baik untuk mengebor pipa layar. Hanya menjalankan layar downhole bila tidak ada alat sumber nuklir di BHA. Selalu membahas penggunaan DP atau layar downhole dengan Operasi Inspektur. 4.3 PRE-SPUD OPERATIONS 1. Mengembangkan rencana pembuangan limbah yang membahas berikut: Plastik dan styrofoam Logam (tidak digunakan benang casing pelindung yang akan dikirim ke Amerika Serikat) Sampah (termasuk sisa makanan tanah) sesuai dengan USCG MARPOL undang-undang Kertas dan kardus Mesin yang digunakan minyak Kontraktor Tanggung Jawab Mud - Per berlaku NPDES manual Padatan bor (di mana peraturan mengharuskan) -NPDES manual Limbah dan limbah - Per Program Kepatuhan Manual atau Discharge NPDES (memastikan bahwa pabrik pengolahan unit pengeboran adalah operasional) Nah Penyelesaian / Workover / Pengobatan Cairan - per NPDES manual 2. Mengadakan pertemuan pra-kentang. 3. Lengkap penerimaan rig sebelum mengambil rig dan lagi pada frekuensi yang ditentukan oleh Operasi Inspektur. Tes minimum akan yang dibutuhkan dalam kontrak pengeboran. Minimal semua rig memasuki armada ExxonMobil akan diperiksa oleh Inspektur Operasi atau yang ditunjuk sebelum penerimaan. 4. Pastikan bahwa daftar kerahkan telah selesai dan semua personil dicatat. 5. Melakukan pertemuan keselamatan umum, meninjau semua yang bersangkutan Keselamatan Alarm. 6. Pastikan bahwa lumpur kentang telah dicampur sesuai program pengeboran. 4. STRUKTUR DRIVE yang PIPA Waktu yang paling efektif metode pengaturan perjalanan pipa adalah untuk mengarahkan ke penolakan (biasanya kurang dari 225 pukulan per kaki) dengan diesel / hidrolik palu. Plain-end atau pipa koneksi cepat digunakan dan dilas / dibuat-buat sebagai sendi ditambahkan ke string. Untuk perkiraan tinggi, gunakan 45 kaki untuk diesel / hidrolik palu dan sling dan 42 kaki untuk bersama drive pipa. Meskipun tidak penting, penggunaan mesin pipa bevel dan dua mesin las akan sangat mempercepat proses mengemudi untuk pipa yang harus dilas. Adalah penting bahwa mengemudi tidak berhenti setelah dimulai (misalnya semalam ditutup) sebagai pipa mungkin tidak akan mulai bergerak lagi. Mengemudi pipa dengan diesel / hidrolik palu memerlukan lebih tinggi dari risiko yang normal. Pipa akan dicabut oleh padeyes yang mungkin tidak akan memiliki las diperiksa. Saat mengemudi, pipa berkendara bisa masuk zona lembut dan drop cepat. Sebuah jenis koneksi koneksi cepat memungkinkan penggunaan meja putar palsu dan lift, dan mempercepat waktu mengemudi sementara menghilangkan bidang pengelasan. Hal ini kadang-kadang diperlukan untuk mencuciout drivepipe selama operasi mengemudi jika pukulan drive yang palu per kaki mencapai maksimum yang disarankan sebelum mencapai direncanakan / memadai mendorong penetrasi pipa. Cuci-out drive pipa selama operasi mengemudi membutuhkan penilaian risiko termasuk pertimbangan bahaya dangkal, persetujuan MMS sebelumnya, dan EMDC tepat dan persetujuan manajemen EMPC. 5. KONDUKTOR DAN PERMUKAAN CASING INTERVAL D & E prosedur memberikan rincian untuk operasi berikut: lubang konduktor pengeboran; konduktor casing berjalan, penyemenan & hang-off; prosedur pengalir; pengeboran lubang permukaan; permukaan casing berjalan, penyemenan, hang-off, dan pemasangan wellhead. 1. Tujuan dari casing konduktor adalah untuk memberikan yang memadai Nah Kontrol integritas untuk memungkinkan pengeboran ke titik casing permukaan. Casing konduktor biasanya diperlukan bila: Sebuah program pengeboran yang aktif belum dilakukan pada platform tertentu dalam 12 bulan sebelumnya. Ada gas dangkal yang signifikan dan / atau pengembalian hilang potensial hadir. Offset baik casing tekanan dan potensi kebocoran casing menyajikan kemungkinan menghadapi formasi dibebankan dangkal dari kedalaman casing permukaan. 2. Tujuan dari casing permukaan adalah untuk memberikan yang memadai Nah Kontrol integritas untuk memungkinkan pengeboran ke titik pengaturan casing depan (pelindung atau casing produksi mendalam). Casing Permukaan adalah pertama casing string pada yang penuh 5 pencegah BOP stack nippled-up. Casing permukaan mendukung berat semua string berikutnya casing, tabung dan permukaan peralatan (yaitu preventers ledakan atau kepala sumur dan pohon). Pengaturan mendalam akan berkisar dari 2000 kaki ke beberapa ribu kaki. Casing permukaan disemen ke permukaan baik selama pekerjaan semen primer atau setelah pekerjaan utama dengan pekerjaan nat. Kecuali ditentukan lain dalam program pengeboran, konduktor dan permukaan lubang akan dibor dari bawah sepatu berkendara pipa ke ~ 20 'di bawah kedalaman sepatu direncanakan untuk casing masing. Pastikan untuk berhenti pengeboran sebelum melebihi maksimum kedalaman diizinkan untuk interval lubang. Rathole kurang kritis dengan kepala sumur las-on seperti itu mungkin diinginkan untuk mengatur konduktor atau permukaan pipa di bagian bawah. Konduktor dan permukaan lubang umumnya akan dibor dengan sistem SW-gelCLS lumpur ke kedalaman total. Mana risiko gas dangkal yang signifikan diidentifikasi, konduktor atau permukaan lubang dapat dibor memanfaatkan lubang percontohan untuk memfasilitasi operasi kontrol dengan baik. Cara utama kontrol baik selama lubang percontohan pengeboran adalah membunuh dinamis. The annular clearance antara kerah bor dan sumur bor memberikan penurunan tekanan gesekan, untuk membantu meningkatkan BHP efektif pada tingkat yang beredar tinggi dalam hal masalah kontrol dengan baik. Jika tendangan dengan baik, beredar lumpur pengeboran di tingkat maksimum. Bit harus berada dalam jarak 200 kaki dari bawah. Spot satu ppg berat lumpur atau barit steker jika aliran juga tidak dapat dibunuh dengan lumpur biasa. Beredar lumpur berat sekitar dapat menyebabkan sirkulasi hilang. Pedoman umum berikut ini untuk operasi pengeboran lubang percontohan: 1. Sebuah volume satu ppg lebih berat dari berat badan pengeboran membunuh lumpur dapat dicampur dan dipelihara dalam cadangan sampai lubang percontohan telah dibor. Minimum volume lumpur menjadi dicampur akan ditentukan dalam program pengeboran dan umumnya akan menjadi jumlah volume anulus antara string bor dan lubang pilot dari TD ke flowline ditambah volume yang dibutuhkan untuk menghentikan aliran waduk sebagaimana ditentukan oleh dinamis membunuh simulasi untuk lubang geometri dan waduk ketentuan yang berlaku. Di daerah di mana potensi keberadaan gas dangkal rendah, simulasi membunuh dinamis tidak akan diperlukan. Jika perhitungan membunuh dinamis dibuat, volume dipompa terhadap tingkat pompa rencana akan diproduksi yang memiliki No Membunuh Daerah dan Bunuh Region. 2. Selama operasi kritis (pengeboran, tersandung, dll) yang dilakukan sementara pengeboran lubang percontohan, baik supervisor operasi atau alat pendorong harus pada atau dekat lantai rig. 3. Jika rig dilengkapi dengan drive atas, berputar sambil menarik keluar dari lubang akan mengurangi efek swabbing dan mengurangi kemungkinan masuknya. Memompa keluar dari lubang juga merupakan pilihan. 4. Meminimalkan lubang washout, menghindari rembesan lumpur yang berlebihan, mengendalikan berat badan lumpur kembali, dan directional control / sumur bor menghindari lebih penting daripada tingkat tinggi penetrasi untuk konduktor dan permukaan bagian lubang. 4.6 OPERASI pengalir Sebuah perakitan pengalir terdiri dari gulungan spacer, pengeboran lintas, dan annular akan nippled up selama semua konduktor dan permukaan lubang pengeboran. Sebuah garis kill akan terhubung ke salah satu outlet spool dan garis pengalir akan terhubung ke dua 10 "outlet samping. Pertimbangan utama adalah untuk memiliki garis pengalir lurus dengan katup non-restriktif (bola atau katup gerbang). Garis pengalir harus melampaui kantilever rig dan tidak harus diarahkan ke platform atau menuju rig pengeboran dan harus memperhitungkan arah angin umum. Kontrol harus diurutkan untuk mencegah menutup annular sebelum turun pengalir angin katup kalimat pembuka. Jangkar akhir garis pengalir. Pertimbangkan perlu untuk menginstal garis flare terpencil ignitor. 4,7 INTERMEDIATE / PELINDUNG CASING INTERVAL Pengeboran Menengah Lubang Tekanan formasi di lubang bawah casing permukaan menentukan jenis baik yang dibor - normal atau abnormal tekanan. Di daerah di mana formasi tekanan abnormal ditemui atau kondisi lubang mandat pembentukan isolasi, casing menengah atau pelindung mungkin diperlukan sebelum mencapai kedalaman total. Casing kursi atau TD Hunts mungkin diperlukan. Gradien fraktur formasi yang dihadapi harus diperkirakan berdasarkan drillwells offset. Jika tidak ada yang berlaku offset yang sumur, perkiraan dari data empiris seperti kurva Eaton dapat digunakan. Berjalan dan Cementing Menengah Casing Sebuah string penuh casing akan dijalankan dan tergantung dari di kepala sumur. Casing string yang akan mencakup sepatu mengambang, mengambang kerah, dan mungkin casing sendi anjing. The penyemenan perakitan akan mencakup atas dan colokan wiper bawah, dan semen kepala / bermacam-macam. The Casing dan Cementing Bagian manual ini harus dirujuk ke ketika merencanakan pekerjaan ini. Setelah penandaan semen dengan bit dan sebelum pengeboran dari sepatu, lakukan latihan kontrol dengan baik. Ulasan ditutup dalam prosedur dengan kedua kru. Menutup dengan baik dan mengedarkan baik melalui manifold choke. Membiarkan anggota kru pengeboran bekerja tersedak. (Bergantian ini dapat dilakukan setelah menggusur lubang dengan lumpur untuk menentukan penurunan tekanan garis choke untuk perhitungan tendangan.) Sebuah tes casing biasanya akan dimandatkan oleh badan pengawas yang mengatur sebelum pengeboran dan setelah mendarat BOP stack. Menjalankan tes integritas tekanan setelah pengeboran bawah casing string yang menengah. Perbarui lembar tendangan harian sementara pengeboran. 4,8 CASING PRODUKSI / LINER INTERVAL Pengeboran lubang Produksi Pedoman yang sama diberikan dalam Drilling bagian Menengah Lubang berlaku ketika pengeboran bagian lubang ini. Jika menggunakan drive atas, mengambil pipa bor yang cukup untuk mengebor total kedalaman. Sebuah bor porting pipa mengapung akan digunakan di bawah permukaan casing sekali baik dapat menutup di atas tendangan. Setelah penandaan semen dengan bit dan sebelum pengeboran dari sepatu, lakukan latihan kontrol dengan baik. Ulasan ditutup dalam prosedur dengan kedua kru. Menutup dengan baik dan mengedarkan baik melalui manifold choke. Biarkan pengeboran kru bekerja tersedak. (Bergantian ini dapat dilakukan setelah menggusur lubang dengan lumpur untuk menentukan penurunan tekanan garis choke untuk perhitungan tendangan.) Casing / kapal akan tekanan diuji sesuai dengan persyaratan peraturan yang berlaku. Perbarui lembar tendangan harian sementara pengeboran. 4,9 SLOT RECOVERY / WHIPSTOCK / BAGIAN MILL / CUT & PULL Penawaran diskusi berikut dengan metode pengeboran sumur baru atau bagian lubang dari dalam atau sekitar sumur yang ada. Pemulihan Slot memungkinkan untuk sumur baru dari permukaan sementara whipstocks dan casing cut & menarik menggunakan kembali casing yang ada untuk mencapai tujuan baru. Secara umum, whipstocks mendalam akan lebih murah daripada memotong & menarik (C & P), yang umumnya lebih murah daripada pemulihan Slot dan sumur bor baru. Ketika memutuskan apakah atau tidak untuk menggunakan kembali sumur bor, faktor untuk menyertakan adalah: arah yang ada baik dibandingkan dengan tujuan yang diinginkan (s), ada program yang casing vs ukuran lubang dan penyelesaian diperlukan, kehidupan masa depan penyelesaian yang ada, kemampuan untuk mencapai (dan lain-lain pada program multiwell) dan telah diperlukan hookload, dan lain-lain. Jika sumur yang ada adalah untuk memiliki bagian dari itu digunakan kembali, upaya maksimal harus dilakukan untuk mengkonfirmasi kesesuaian dengan baik sebelum bergerak rig ke lokasi. Ini termasuk meneliti menyeluruh sejarah sumur (misalnya, pengeboran pakai, tes tekanan mencatat, catatan semen), pemeriksaan kepala sumur oleh teknisi servis yang memenuhi syarat, tekanan pengujian casing mungkin, dan melakukan semua yang mungkin P & A bekerja. Jika pekerjaan semen untuk string casing dipertanyakan, kadang-kadang disarankan untuk menjalankan alat pencitraan berkualitas tinggi (misalnya, Schlumberger usit log) untuk menentukan kualitas semen dan TOC balik casing; ini dapat membantu dalam penempatan Whipstock dan membantu memutuskan apakah C & P adalah mungkin. Banyak kali, berbagai prosedur yang dijelaskan akan dijalankan bersama-sama (misalnya casing produksi C & P untuk memungkinkan Whipstock dari casing permukaan). Ini akan menjadi penting untuk memverifikasi sesuai dengan pedoman peraturan yang tepat dan mendapatkan persetujuan untuk operasi. Slot Pemulihan Slot Pemulihan adalah metode membuka ruang pada platform untuk drillwell baru yang telah memiliki semua slot konduktor yang digunakan oleh sumur sebelumnya. Hal ini membantu menghindari modifikasi platform yang mahal yang sebenarnya dapat diperlukan. Diver Alihkan and Drive Pipa Whipstock adalah dua jenis pemulihan slot yang tersedia untuk digunakan setelah subjek juga telah sepenuhnya P & A'd (lihat Bagian 13 untuk rincian tentang operasi P & A). Untuk pemulihan Slot Diver Alihkan, semua string dari casing (termasuk berkendara pipa) dipotong dan pulih dari ~ 5 kaki di atas garis lumpur. Pipa drive baru diturunkan melalui panduan konduktor platform untuk di bawah garis air di mana penyelam kemudian memandu pipa drive baru ke sisi bertopik casing yang ada. Pipa drive baru kemudian didorong ke kedalaman yang diinginkan dan juga operasi dilanjutkan seperti biasa. Hal ini sering diinginkan untuk memiliki drive sepatu menyimpang di bagian bawah pipa berkendara untuk membantu memastikan pemisahan dari sumur tua secepat mungkin. Untuk pemulihan Slot drive Pipa Whipstock, semua string dari casing (termasuk berkendara pipa) dipotong dan pulih  ± 60 â € "80 kaki di bawah garis lumpur. Sebuah whipstock melekat ke bagian bawah pipa drive baru dan diturunkan melalui panduan platform konduktor ke bertopik casing yang ada. Whipstocks tersedia dengan baik tombak atau overshot dan dapat berorientasi ke arah yang diinginkan. Setelah whipstock tersebut dikawinkan dengan konduktor ditinggalkan, pipa drive baru yang terpotong dari whipstock dan pipa drive didorong ke kedalaman yang diinginkan. Sekali lagi, operasi sekarang dapat melanjutkan seperti biasa. Whipstocks pipa drive umumnya pilihan yang lebih disukai karena tidak ada persyaratan bagi para penyelam untuk berada di air. Kedua pilihan memerlukan evaluasi khusus dari diantisipasi berkendara pipa defleksi untuk menentukan apakah satu atau lebih platform yang panduan konduktor harus dihapus. Whipstocks Casing Whipstocks adalah perangkat mekanik mengatur dalam casing yang ada dan digunakan untuk keluar dari sebelumnya dibor sumur. The Whipstocks dapat berupa satu kali perjalanan atau beberapa perjalanan. Perbedaan harga antara satu kali perjalanan dan multiple-perjalanan harus dievaluasi untuk setiap situasi (umumnya, sistem satu kali perjalanan akan lebih ekonomis pada keluar lebih dalam sementara beberapa perjalanan yang baik untuk keluar dangkal di mana perjalanan yang cepat). Rencana umum operasi adalah bahwa Whipstock dijalankan di dalam lubang, berorientasi, dan mengatur (baik secara mekanis atau hidrolik). The Whipstock harus berorientasi ke arah yang diinginkan untuk sidetrack (umumnya ~ 30 ° â € "45 ° dari highside). Kemudian, pabrik casing yang digunakan untuk keluar casing dan membuat lubang baru yang cukup untuk melakukan PIT a. Setelah ini selesai, operasi pengeboran baru dapat melanjutkan. Hal ini penting untuk tidak pernah memutar apapun di muka whipstock tersebut; ini akan membantu mencegah whipstock dari berputar dan menyebabkan lubang baru yang akan hilang. Sistem fluida harus cukup kental dan memiliki magnet parit di tempat untuk membantu menghilangkan serutan logam dari sistem. Bagian Penggilingan Bagian penggilingan mirip dengan whipstocking dalam sumur bor yang ada keluar oleh penggilingan lubang di casing. Perbedaan utama adalah bahwa cara keluar casing bukan merupakan alat mekanis. Bagian Mill, underreaming-jenis pabrik casing dijalankan ke dalam casing string yang ada dan lubang digiling dalam casing (biasanya, ~ 100 '). Sebuah plug semen kemudian ditempatkan di interval giling dan juga teralihkan dari plug semen ini. Metode ini lebih disukai daripada operasi Whipstock ketika bagian lubang baru akan lama, terarah kompleks, atau menyebabkan keausan berlebihan dan air mata pada whipstock yang dapat menyebabkan kegagalan (dan dengan demikian kehilangan lubang baru). Casing Cut & Pull Manfaat dari casing Cut & Menarik untuk sidetracking lubang baru adalah peningkatan ukuran lubang yang tersedia dengan menghapus satu atau lebih string casing. Rencana dasar untuk C & P adalah untuk menurunkan pemotong casing (umumnya hidrolik) ke dalam lubang dengan kedalaman pemotongan yang diinginkan, memotong casing, kemudian berusaha untuk menarik casing lama dari lubang. Berdasarkan kedalaman dipotong, penghapusan casing bisa baik mengekspos pembentukan atau casing string yang sebelumnya. 4.10 lubang sumur PEDOMAN ANTICOLLISION Pedoman anticollision sumur bor di bagian ini adalah minimum yang disarankan standar untuk semua operasi. Pedoman ini harus ditinjau baik oleh basis baik. Setiap pengecualian untuk standar ini memerlukan persetujuan Operasi Inspektur. 1. Bagian paling penting dari informasi di arena antitabrakan adalah kualitas data. Semua survei Platform dan RKB harus ditinjau oleh individu yang memenuhi syarat untuk memastikan data yang benar, wajar dan bebas dari kesalahan. Bayar perhatian khusus pada azimuth tinggi round-off error dan RKB datum (ini telah salah di masa lalu). 2. Setelah jalan baik telah dihasilkan, memiliki kontraktor directional menjalankan laporan antitabrakan. Meninjau laporan dan mengidentifikasi sumur yang akan perlu ditangani secara individual. Mendapatkan sketsa sumur bor terbaru untuk setiap baik pada platform dan untuk semua sumur yang lulus dekat diusulkan juga (sumur mungkin berasal dari sebuah platform yang berdekatan atau lokasi perairan terbuka). Perhatikan sumur tubingless, sumur produksi, gas mengangkat sumur, dan terpasang sumur. 3. Dalam pertemuan SIMOPS diadakan antara EMDC dan EMPC, membahas status sumur diidentifikasi sebelumnya. Rencana untuk menutup di, berdarah off dan atau set colokan di sumur dekat dengan jalan baik yang diusulkan. 4. Selama pengeboran operasi dekat masalah gangguan, survei setiap berdiri dan menggunakan teknologi saat ini untuk memberikan informasi yang terbaik (yaitu, permukaan pembacaan gyro). Memiliki pasokan kontraktor directional driller sebuah directional tambahan untuk menjalankan proyeksi dan laporan anticollision saja. Gunakan perakitan pengaliran untuk mengarahkan dekat gangguan. Meminimalkan Bor tali rotasi (JANGAN GUNAKAN MOTOR) sementara di dekat yang lain juga. Pantau terus untuk torsi, LR, stek besi, semen, atau parameter lain yang bisa menunjukkan gangguan. 4.10.1 PERSYARATAN â € œCOLLISION Riska € WELLS 1. Perencanaan menghindari tabrakan dan kebutuhan operasi (Item 1-7) akan berlaku untuk â € œCollision Risiko wellsa €. Wells Risiko tabrakan didefinisikan sebagai: 2. Apa yang dibor dari pad multi-baik atau struktur (termasuk ditinggalkan sumur). 3. Operasi tunggal-baik, jika lintasan yang direncanakan diharapkan untuk lulus dalam 100 m (330 kaki) dari yang dari offset juga. 4. Jika SIMOPS atau persyaratan lokal menghindari tabrakan peraturan yang lebih ketat dari persyaratan EMDC, persyaratan yang lebih konservatif akan diikuti. 5. Entah Wolff & DeWardt atau ISCWSA model dapat digunakan untuk mengembangkan menghindari tabrakan dan perhitungan EOU. Vendor bertanggung jawab untuk pemilihan faktor kesalahan alat dan kinerja perangkat lunak berpemilik mereka. 6. Metode paling jarak akan digunakan untuk menghitung pemisahan antara elips. 7. Ellipse perhitungan ketidakpastian akan didasarkan pada 2 standar deviasi (2 ïƒ). 8. Offset pemantauan dan menutup-in persyaratan untuk Wells Risiko Tabrakan ditentukan oleh â € œSeparation Distanceâ € atau â € œSeparation Factorâ € persyaratan, mana yang lebih besar. Persetujuan FDM diperlukan untuk mengoperasikan dengan EOU Pemisahan Jarak <10 kaki, atau Pemisahan Factor <1,5. FDM dapat menyetujui pengecualian untuk menutup persyaratan jika risiko dapat dikurangi ke tingkat yang dapat diterima melalui praktik operasional. PEMISAHAN DISTANCE Jika EOU Pemisahan Jarak diproyeksikan ke titik survei berikutnya adalah <10 ft, memantau berlaku diimbangi anulus terus menerus. Jika EOU Pemisahan Jarak diproyeksikan ke titik survei berikutnya adalah <5 kaki, menutup di offset dan mengatur plug bawah kedalaman mencegat diperkirakan (atau SSSV dekat jika ita € ™ s di bawah titik mencegat). Memonitor anulus terus menerus. PEMISAHAN FACTOR Jika EOU Pemisahan Factor diproyeksikan ke titik survei berikutnya adalah <1,5, memantau berlaku diimbangi anulus terus menerus. Jika EOU Pemisahan Factor diproyeksikan ke titik survei berikutnya adalah <1,2, menutup di offset dan mengatur plug bawah kedalaman mencegat diperkirakan (atau SSSV dekat jika ita € ™ s di bawah titik mencegat). Memonitor anulus terus menerus. Sebagai cek perencanaan akhir, directional driller penukaran adalah untuk menjalankan profil menghindari tabrakan independen untuk Collision Risiko Wells sebelum memulai pekerjaan. Plot anti-tabrakan akan dipertahankan untuk Collision Risiko Wells di lokasi rig. Pembaruan yang diperlukan berikut setiap survei sampai titik mencegat potensi dilewatkan. 4.10.2 PERSYARATAN UNTUK SEMUA WELLS Directional 1. Ditulis rencana directional dan kedekatan pemantauan akan dimasukkan dalam program. Insinyur, pengawas teknik baris pertama, dan operasi pengawas harus mendukung rencana sebelum pelaksanaan lapangan. 2. Persetujuan FDM dari MOC diperlukan untuk perubahan lintasan setelah persetujuan rencana akhir yang menciptakan 1) â € œCollision Risiko Wella €, atau 2) perubahan dalam menutup dalam persyaratan offset juga (per Pemisahan Factor atau Pemisahan Jarak aturan). 3. Program pemboran akan menentukan jenis alat survey dan frekuensi minimal survei di setiap interval. 4. Data perencanaan pra-bor kritis akan diringkas dan ditransmisikan ke survei kontraktor anddirectional secara tertulis. Data akan mencakup, tetapi tidak terbatas pada: Magnetik Deklinasi Deskripsi target dan kendala garis keras Jenis alat survey dan frekuensi, dengan selang 1 Semua data survei akan dikomunikasikan antara pihak di lokasi rig dalam format standar. Baik kontraktor atau ExxonMobil dapat mengembangkan format (elektronik atau tertulis). 2 Insinyur pengeboran akan meninjau informasi dalam survei juga akhir untuk akurasi dan awal itu sebelum didistribusikan. 3 Persyaratan menargetkan Geologi akan diperoleh dari organisasi klien secara tertulis. 4 Rencana survei dan lintasan akan memastikan bahwa wellboreâ € ™ s dua-sigma elips ofuncertainty cocok sepenuhnya dalam target geologi yang ditentukan pada baris direncanakan pendekatan. Jika hal ini tidak dapat dicapai, persetujuan manajemen klien diperlukan untuk mengebor lintasan dengan probabilitas mengurangi mendarat dalam area target. Nama baik Awal Referensi Elevation Slot / Yah Permukaan Koordinat Perpindahan dari Slot ke Platform Tie Titik 4.11 SURVEYING Directional DAN PENGENDALIAN DEVIASI Azimuth Referensi Koreksi (True North, Grid Utara) Tujuan dari pedoman dalam bagian ini adalah untuk mempertahankan kontrol arah pada semua sumur (vertikal dan directional) sebagai pengeboran berlangsung. Kontrol arah memastikan lokasi lubang bawah dikenal dan lintasan dengan baik untuk menghindari tabrakan / kerusakan untuk mengimbangi sumur bor dan efisien untuk tujuan geologi (s) dan sasaran bantuan baik jika perlu. Untuk tujuan relief well, penting untuk mengetahui posisi baik untuk dalam 50 kaki, yang merupakan jarak efektif log kebisingan dan alat MagRange. Untuk tujuan penerapan persyaratan survei umum berikut, baik vertikal didefinisikan sebagai baik yang memiliki kurang dari tiga derajat kemiringan dari permukaan ke kedalaman total. Tabel berikut merangkum persyaratan survei minimum: Jenis Nah Kebutuhan Vertikal Well (kurang dari 3  °) Kecenderungan Survey setiap 1000 'Directional Nah selama Kecenderungan normal dan Azimuth setiap 500' pengeboran Directional Nah selama direncanakan inklinasi dan Azimuth setiap 100 'perubahan sudut Sebelum pengaturan permukaan dan inklinasi lebih dalam dan Azimuth 500 'dari sepatu CSG casing di kedua arah dan sumur vertikal Total Kedalaman pada kedua Kecenderungan arah dan Azimuth 500 'dari TD dan vertikal sumur Sebuah survei komposit baik dari pipa drive atau konduktor sepatu untuk TD harus disediakan sesuai kebutuhan MMS. Survei Pedoman 1. Jika survei juga diperlukan di luar minimum yang dirangkum di atas, mereka akan ditentukan dalam program pengeboran. 2. Untuk menentukan survei kebutuhan, definisi casing berikut akan digunakan: Drive, atau Struktural, - pipa yang digerakkan untuk mendukung deposito unconsolidated dan memberikan lubang stabilitas untuk operasi awal (biasanya 20-30 inci). Konduktor - Mengatur bawah berkendara pipa dan sebelum pipa permukaan untuk mengurangi beberapa bahaya pengeboran dangkal. Permukaan - pencegah tumpukan ledakan yang nippled-up di atas string ini dan tes integritas tekanan dijalankan setelah sepatu casing yang dibor. Casing permukaan tidak dapat digunakan sebagai casing produksi, tanpa pengecualian tertulis dari manajer pengeboran lapangan. 3. Sebuah survei penyimpangan gyro akan diambil pada total kedalaman lubang berkendara pipa atau sepatu. Biasanya lang harus dijalankan karena pipa didorong di tempat. 4. Survei diambil dengan alat MWD yang definitif, dan tidak perlu untuk mengkonfirmasi survei MWD dengan survei tembakan. Pipa tegak atau pompa lumpur hisap layar yang lebih baik untuk mengebor pipa layar. Hanya menjalankan layar downhole bila tidak ada alat logging sumber nuklir di BHA. Selalu membahas penggunaan layar pipa bor dengan Operasi Inspektur. 5. Dalam kasus di mana bawah lokasi lubang sangat penting, multi-shot elektronik atau survei gyroscopic dapat dijalankan. EPRCo ini Wellpath program atau vendor perangkat lunak dapat digunakan untuk memperkirakan jumlah kesalahan yang dihasilkan dari menggunakan berbagai alat survey dan bantuan dalam keputusan untuk menjalankan multi-shot atau survei gyro. 6. Pengeboran pengawas harus memberikan data directional secara terus menerus. Untuk sumur directional, yang driller directional dan pengeboran insinyur yang mempertahankan rekor sumur bor lintasan dan lubang sumur plot saat. Semua plot directional harus diperbarui, dan setiap penyimpangan yang signifikan dari program terarah direncanakan akan disampaikan kepada pengawas operasi segera. Teknik perhitungan kelengkungan minimum harus digunakan. 7. Hasil survei harus dilaporkan pada layar survei laporan pengeboran harian dan IADC Laporan. Semua informasi directional harus dikonversi ke pengukuran GRID ketika melaporkan dan diplot. 4.12 DRILL STRING DESIGN Bor String Pedoman 1. Semua koneksi drill string yang harus torqued untuk API nilai dianjurkan kecuali sebagaimana tercantum dalam prosedur yang tepat. Jet-Lube ini Kopr-Kote dapat digunakan untuk setiap koneksi dari bit ke kelly / top drive. KoprKote tidak mengandung seng atau timbal. Sebelum penerapan Kopr-Kote, alat benang bersama harus dibersihkan telanjang logam. Untuk mencegah menyakitkan dari komponen non-magnetik saat menggunakan Kopr-Kote, koneksi harus dibersihkan, diperiksa, dan diberi MAG-COAT. Tanpa MAG-COAT, koneksi bukan magnetik akan memiliki insiden yang lebih tinggi dari menyakitkan menggunakan Kopr-Kote. 2. Mengubah pipa bor berdiri istirahat pada setiap perjalanan. 3. Menjaga tali akurat dari pipa bor di lantai rig. Sumur kedalaman ditentukan oleh STM yang driller ini. 4. Gunakan jar pengeboran yang memiliki ID besar sehingga dimungkinkan untuk menggunakan string tembakan wireline atau biaya pemutusan jika diperlukan. 5. Komponen bor tali harus memiliki OD sambungan dasar yang sama kecuali crossover bottlenecked digunakan untuk menyediakan transisi. Semua komponen drillstring koneksi OD ini harus eksternal fishable untuk ukuran lubang mereka digunakan dalam. Pengecualian harus disetujui oleh Operasi Inspektur. BAIK SERVICE 6. Jika memungkinkan, string bor harus dirancang untuk menahan minimal £ 100,000. dari overpull di lubang lurus dan £ 150.000. dari overpull di lubang terarah. KATEGORI Layanan kritis 7. Bor string harus dirancang untuk menahan diprediksi gabungan torsi dan ketegangan beban menggunakan program FORCAL (lihat Directional Drilling BHA) untuk sumur directional sulit dan / atau sumur kritis. Standar Pelayanan 8. Membatasi torsi putar selama operasi pengeboran yang normal untuk mengebor pipa koneksi torsi makeup untuk mencegah over-torquing koneksi pipa bor. Periksa torsi makeup yang sebenarnya digunakan oleh Kontraktor Pengeboran. 9. Jika pipa bor baru atau diperbaharui, memeriksa sendi alat untuk banding keras abrasif yang dapat merusak casing. Drill Collar / BHA Komponen Pipa bor 6 "dan lebih kecil 6-1 / 4 "dan lebih besar 1500 150 200 2500 250 300 Interval di atas harus disesuaikan berdasarkan pengalaman dan pengalaman kegagalan. Metode pemeriksaan yang direkomendasikan untuk bor komponen tali harus sesuai dengan Standar DS1, Bor Stem Desain dan Inspeksi, Edisi Kedua, oleh TH Hill dan Associates, Maret 1998 panduan. Kategori inspeksi layanan, kriteria penerimaan / penolakan, dan pengecualian untuk DS-1 diberikan dalam ECIDO Drilling OIMS Manual. Bor String Inspeksi Ada beberapa klasifikasi kategori baik dan OIMS mengharuskan drill string yang pemeriksaan frekuensi serta desain casing didasarkan pada kategori baik. Komponen bor string yang akan memerlukan pemeriksaan berkala berdasarkan jam dan jenis layanan pengeboran (yaitu kritis atau standar) berputar. Berikut frekuensi pemeriksaan dianjurkan: The OIMS pengguna menunjuk kategori layanan serta standar atau penting dalam Elemen 3 dan daftar tiga kondisi yang memenuhi syarat serta kritis. 10. Lakukan break-in prosedur yang tepat untuk koneksi pipa bor yang baru dipotong. Berputar Jam Antara Pemeriksaan Atas drive harus memiliki pemeriksaan partikel magnetik dari permukaan terkena pada semua komponen bantalan beban setiap tahun untuk menentukan adanya indikasi kelelahan retak. Harus benar melumasi bahu dan benang Harus menggunakan torsi yang tepat - Harus diukur 4.13 rakitan LUBANG BOTTOM Harus segera memperbaiki kerusakan kecil Umum Pedoman dalam bagian ini membahas desain, perawatan, dan cermin majelis lubang bawah untuk pengeboran operasi untuk memenuhi tujuan-tujuan berikut: Kontrol atau Menginduksi Perubahan Lubang Deviasi Meningkatkan Kinerja Bit Memberikan Berat pada Bit Memastikan Gauge Lubang Penuh Mengurangi Kerentanan untuk Diferensial Perekat dan / atau Seating Key Mengurangi Downhole Getaran Mencegah / Mengurangi Masalah BHA Seperti Wash-out dan Twist-off Pedoman Operasional BHA 1. Tiga keharusan untuk kinerja bor yang baik kerah adalah: 2. Tidak pernah membuat kerah bor atau komponen BHA dengan membalik meja putar. Kencangkan setiap koneksi secara terpisah. Jangan ganda untuk menghemat waktu. 3. Ketika pecah kerah bor, memutar perlahan dengan tarik ke atas sedikit di blok. Jangan biarkan benang untuk melompat setelah kerah didukung keluar. 4. Untuk menghindari menyakitkan, praktik rig yang baik adalah untuk "berjalan keluar" sendi bor kerah menggunakan penjepit rantai. 5. Mengubah istirahat berdiri pada kerah BHA / bor pada setiap perjalanan. 6. Mengoptimalkan penempatan jar dengan menjalankan guci dekat kemungkinan besar titik macet. 7. Menjaga gambar yang akurat dari semua komponen BHA termasuk dimensi masing-masing komponen (OD ini, ID, panjang, nomor seri, dll). Dimensi harus diukur dengan cara seperti untuk berkontribusi terhadap sukses memancing. Dimensi diameter luar harus diambil dengan caliper yang hanya akan tergelincir seluruh tubuh berat sendiri. 8. Mengukur bit setelah makeup akan memastikan bahwa itu tidak terjepit oleh bit breaker. Lihat Bagian 5 (Klasifikasi Bit dan Hidrolik) untuk mengukur bimbingan. 9. Menjaga blade stabilizer OD, sesuai dengan desain BHA diprogram, dengan mengukur mereka setiap perjalanan dan mengganti yang diperlukan. Adalah lebih baik untuk tidak mengubah lebih dari satu stabilizer per perjalanan. Ikuti panduan pengukuran diberikan dalam bagian bit. 10. Pin angkat sub harus dibersihkan, diperiksa, dan dilumasi pada setiap perjalanan. Jika pin ini telah rusak dan tidak diketahui, mereka akhirnya akan merusak semua kotak bor kerah. BHA Desain Lubang perakitan bawah yang akan digunakan dalam setiap bagian lubang akan ditentukan dalam prosedur pengeboran yang bersangkutan. Pertimbangan berikut harus dimasukkan saat melakukan desain BHA: 1. HeviWate pipa bor yang dikelola antara kerah bor dan pipa bor menyediakan zona transisi serta tersedia tambahan string yang berat. Di sumur yang lebih dalam dengan meningkatnya sudut, meminimalkan HWDP untuk membantu dalam mengoptimalkan pengeboran hidrolik adalah praktek umum. 2. Pastikan bahwa crossover dari besar kerah diameter bor untuk kerah bor kecil atau pipa bor tidak melebihi "pengurangan ukuran 2, atau bahwa rasio kekakuan tidak melebihi 5,5 untuk sumur noncritical atau 3,5 untuk kritis baik. 3. Bor kerah diterima dan alat BHA lentur rasio kekuatan adalah 2,25-3,20. 4. Ini rasio kekuatan lentur tidak mungkin dengan ukuran bor kecil kerah seperti kerah 4 3/4 inci bor dengan 3 1/2 IF (NC 38) koneksi. Pengalaman menunjukkan bahwa bahu rotary kegagalan koneksi jarang terjadi menggunakan 4 3/4 inci kerah bor bahkan dengan BSR bawah 2,0. 5. Pilih komponen dari BHA mengingat hilang sirkulasi kebutuhan bahan dan potensi drill string yang menempel dan operasi penangkapan ikan berikutnya (nozel, motor, MWDs, dll mungkin pasang ketika memompa LCM). 6. Pastikan bahwa semua koneksi BHA memiliki koneksi kotak menghilangkan stres boreback dan alur menghilangkan stres pada pin. 7. Kerah bor spiral lebih disukai untuk meminimalkan potensi mencuat diferensial. 8. Lurus stabilisator pisau dilas meminimalkan swabbing di bagian gumbo. Stabilisator dengan bidang kontak peningkatan dinding area support lagi di formasi lembut. Stabilisator dengan bidang kontak yang lebih pendek lebih disukai dalam formasi keras. Pertimbangkan penggunaan spiral, stabilizer pisau terpisahkan dengan luas yang memadai untuk memotong sudut tinggi, directional membersihkan lubang sumur. BHA Pengeboran directional Pedoman ini tidak dimaksudkan untuk menjadi standar fleksibel kebijakan atau tetapi harus menjadi landasan yang menjadi dasar keputusan untuk desain baik yang spesifik. Dari sekitar 1950-1980, pipa bor dan HeviWate pipa bor tidak pernah dijalankan di kompresi karena takut kegagalan kelelahan akibat tekuk. Namun, kecenderungan sumur bor jarang diperhitungkan dalam menghitung diperlukan berat bor kerah. Akibatnya sebagian besar operator tidak menambahkan kerah sebagai lubang sudut meningkat yang tidak diragukan lagi menyebabkan pipa bor yang akan dijalankan di kompresi. Kegagalan kelelahan diharapkan untuk pipa bor dijalankan di kompresi tidak terjadi. Industri telah menetapkan bahwa pipa bor dapat membawa beban tekan tinggi di sumur sudut tinggi tanpa tekuk dan kegagalan kelelahan. Tekuk tidak menyebabkan kerusakan dipercepat kelelahan dan alat sendi keausan yang dapat ditoleransi untuk jangka waktu yang singkat terutama jika itu akan menghemat perjalanan atau mengurangi kemungkinan bor string yang berbeda-beda terjebak. Dasar kesimpulan ini adalah bahwa string bor meletakkan di sisi rendah dari lubang cenderung sangat tahan terhadap tekuk sejak mendukung lubang dan membatasi pipa sepanjang panjangnya. Manfaat penting dari menjalankan pipa bor di kompresi adalah bahwa panjang HeviWate dan kerah bor dapat dikurangi dan hidrolika, lubang pembersihan, dan ROP dapat ditingkatkan. Izin FORCAL desain drill string berdasarkan diijinkan pipa bor kompresi untuk lubang bor yang menyimpang atau lurus. ROB memprediksi tingkat membangun atau drop untuk rotary majelis lubang bawah. Penempatan stabilizer di bagian bawah dari BHA untuk kontrol arah dapat dianalisis serta bagaimana kerah bor akan menekuk antara stabilisator. Perusahaan jasa directional dapat menyediakan perangkat lunak desain pipa bor yang sama. Pastikan untuk mencatat keterbatasan perangkat lunak tertentu yang digunakan dan periksa ini terhadap situasi yang dianalisis (misalnya kebutuhan FORCAL dimodifikasi masukan ketika model casing berjalan karena didasarkan pada teori string). Metode desain baru BHA yang mengambil keuntungan dari berkurangnya BHA tekuk kecenderungan di sumur directional telah digunakan sejak awal 1980-an dengan hasil yang luar biasa. Bor pendek panjang kerah diperlukan (sering hanya MWD peralatan / LWD untuk operasi GOM) mengakibatkan penurunan torsi dan drag dan mengurangi frekuensi berbeda-beda terjebak BHA. Jumlah pipa bor, HeviWate pipa bor, dan kerah bor berjalan dalam kompresi baik spesifik dan tergantung pada ukuran lubang, berat lumpur, baik sudut, WOB diinginkan, dan torsi dan tarik kendala. Semua operasi pengeboran harus mengambil keuntungan dari metode desain yang dapat meminimalkan masalah dengan torsi dan drag dan terjebak BHA. Ketika tekanan diferensial melebihi sekitar 1.500 psi, berhati-hati untuk menghindari berbeda-beda mencuat string bor. Menerapkan prosedur khusus seperti membuat koneksi berputar, mengendalikan lumpur kehilangan cairan dan lumpur kualitas kue, memastikan pembersihan lubang yang efektif (yaitu, membatasi stek dune tinggi, dll), dan memompa keluar dari lubang di rig dengan sistem penggerak atas. Untuk tekanan lebihan diferensial lebih besar dari 2.500 psi mempertimbangkan penggunaan lebihan tinggi, "Seal-Sementara-Pengeboran" teknik. Untuk sumur antara 15-35 derajat dari sudut, menerapkan pedoman BHA umum berikut. Untuk sumur dengan> 45 derajat dari sudut praktek pengeboran khusus mungkin diperlukan. 1. Meminimalkan jumlah kerah bor dan menjalankan jumlah maksimum pipa bor dan HeviWate pipa bor di kompresi seperti yang ditunjukkan oleh program FORCAL. Dalam kebanyakan kasus hanya non-mag kerah diperlukan selain kerah MWD / LWD berdasarkan sudut baik, ukuran lubang, berat badan yang diinginkan pada bit, baik sudut, berat lumpur, dan torsi dan tarik kendala. 2. Jangan menjalankan lebih dari satu yang tidak didukung drill collar di atas stabilizer atas sumur directional. Ini juga dapat dihilangkan jika non-mag spacer tidak diperlukan, atau jika non-mag HWDP tersedia untuk dijalankan di tempat kerah non-mag. Pada sudut tinggi, tambahan DC membuat stres lentur yang sangat tinggi dalam koneksi stabilizer atas. Mereka juga menciptakan potensi untuk pipa terjebak jika mereka melorot menghubungi dinding. 3. Program komputer ROB dalam hubungannya dengan arah perusahaan jasa perangkat lunak / pengalaman harus digunakan untuk merancang penempatan stabilizer untuk BHA. Dalam kebanyakan daerah, terutama di daerah di mana diferensial mencuat adalah kekhawatiran, stabilisator harus ditempatkan setiap 60 kaki. 4. Kontraktor pengeboran directional harus memberikan direkomendasikan BHA untuk evaluasi oleh Drilling Engineer. 5. Bersaing dengan tekanan diferensial antara berat lumpur dan tekanan pori. Mengambil tindakan pencegahan khusus untuk mencegah string bor macet kapan diferensial tekanan melebihi sekitar 1.500 psi terlepas dari pembentukan jenis dibor. 6. Dalam formasi keras, reamers rol kadang-kadang digunakan sebagai pengganti stabilisator. Roller reamers sering digunakan ketika jumlah signifikan reaming diantisipasi atau pengurangan torsi putar yang diinginkan. Non-berputar bor pelindung pipa atau lengan harus dipertimbangkan ketika pengurangan torsi yang diinginkan. 7. Untuk dapat dikendalikan rakitan pengeboran PDM, mengoptimalkan lumpur bermotor dan alat konfigurasi LWD untuk diantisipasi dengan baik kondisi termasuk: pengeboran jenis cairan, debit, suhu downhole, diantisipasi waktu antara perjalanan, jenis bit, dan pengeboran WOB dan persyaratan torsi. Untuk GOM Directional sumur menggunakan kinerja tinggi, diperpanjang kekuasaan bagian Methods bila memungkinkan. Software V.5.02 FORCAL memperkirakan torsi dan tarik pada tubular diberikan geometri sumur bor, konfigurasi tubular, arah gerakan, dan koefisien gesekan. Gerakan ini dapat aksial, rotasi, atau gabungan. Dua koefisien gesekan dapat digunakan, satu untuk bagian casing dari sumur dan yang lainnya untuk bagian lubang yang terbuka. Tersandung tubulars masuk dan keluar dari lubang sumur dapat dimodelkan. Mengingat torsi diukur atau hookload, FORCAL dapat menghitung koefisien gesekan. Software ROB V.5.01 memprediksi kinerja membangun / drop dan berjalan dari rotary dan motor BHA perakitan. Pengguna dapat melakukan analisis sensitivitas untuk memprediksi efek dari berbagai parameter pada kinerja BHA. Efek geologi seperti perlapisan juga dapat dimasukkan dan modul kalibrasi memungkinkan pengguna untuk mengambil keuntungan dari pengalaman lokal. ROB melakukan pengeboran ke depan dan juga memperpanjang perhitungan bersama dengan 2-D dan 3-D juga berencana. V.3.8 powerplan juga dimanfaatkan dan memiliki kemampuan prediksi kedua torsi / drag dan membangun / drop dan berjalan berbeda BHA ini. Torsi dan tarik pengawasan harus dipantau untuk semua lubang pelindung dan produksi lebih dari 40  ° dengan lebih dari 1500 'MD dari openhole. Contoh termasuk dalam Bagian 4 â € "Lampiran VIII. 4.14 HIDROGEN PERTIMBANGAN sulfida (OIMS manual Element 10) Hidrogen sulfida adalah gas yang sangat beracun. Dalam pengeboran operasi, berbagai konsentrasi hidrogen sulfida dapat ditemukan. Efek dari konsentrasi ini juga berkisar luas - dari bau yang tidak menyenangkan atau gangguan mata pada konsentrasi rendah untuk penyakit serius atau bahkan kematian pada konsentrasi yang lebih tinggi. Semua karyawan yang bekerja di daerah di mana mereka dapat terkena hidrogen sulfida harus dilatih untuk mengenali dan memahami bahaya dan untuk melindungi diri dari efek berbahaya (kontraktor dan layanan personil perusahaan harus H2S disertifikasi sebelum datang ke rig). Personil harus dilatih untuk menyelamatkan korban dan mengelola pertolongan pertama bagi mereka yang mengatasi, tanpa membahayakan diri mereka sendiri. Semua personel di rig harus memiliki akses ke paket melarikan diri. Hidrogen sulfida adalah (1,18 berat jenis) gas sangat beracun, tidak berwarna, lebih berat dari udara. Luka bakar dengan api biru dan menghasilkan sulfur dioksida gas yang sedikit kurang beracun dari hidrogen sulfida, namun dapat menyebabkan mata dan paru-paru iritasi dan cedera serius. Dalam konsentrasi rendah, hidrogen sulfida memiliki bau telur busuk. Membentuk campuran meledak dengan udara pada konsentrasi antara 4,3% dan 46% volume. Hal ini larut dalam air dan minyak tetapi menjadi kurang larut dengan naiknya suhu cairan. Sensor - lokasi, kalibrasi, visual dan sinyal terdengar, tetap dan tangan memegang Prosedur darurat Latihan dan pertemuan keselamatan periodik Pedoman operasi Ketika ada potensi untuk menghadapi hidrogen sulfida, berikut ini harus dipertimbangkan dan ditangani: Kaus kaki angin dan daerah perakitan aman Transportasi dan evakuasi Pemantauan Bagian dari proses Penilaian Risiko Penggunaan alat bantu pernapasan MMS atau lainnya Badan Pengatur H 2 S Contingency Rencana Pembangunan & Persetujuan Posisi alat bantu pernapasan Pelatihan peralatan Lokasi berbahaya Pemilihan bahan - BOP dan peralatan kontrol baik H2S dipangkas Contoh pedoman pada rambut dan korektif lensa wajah sebagai berkaitan dengan peralatan pernapasan bisa: Peraturan Pertolongan pertama Dicukur bersih di daerah-wajah-piece penyegelan dan tidak harus memiliki rambut wajah yang dapat mengganggu fungsi masker. Kode tanduk udara atau bel alarm Respon pada berbagai tingkat konsentrasi hidrogen sulfida Sebelum mengenakan respirator dengan sepotong penuh wajah, setiap kepala meliputi, gelas dan barang-barang asing di mulut harus dihapus API RP 55 dapat memberikan bimbingan pada operasi yang melibatkan hidrogen sulfida dan berisi meja pada efek fisiologis berbagai konsentrasi. Memakai lensa kontak dengan respirator tidak diizinkan. Pemakai kacamata resep yang ditugaskan ke daerahdaerah di mana respirator wajah penuh mungkin diperlukan harus disediakan dengan cara melampirkan lensa resep untuk masker wajah. Unit Jalan keluar berkerudung memungkinkan untuk penggunaan kacamata resep selama evakuasi darurat. Pedoman Untuk Pengeboran Untuk semua operasi di mana H2S yang diproduksi pada platform atau di mana H2S mungkin ditemui saat pengeboran, rencana kontingensi akan dikembangkan dan disetujui oleh badan pengawas yang berlaku seperti yang diperlukan. Sulfida hidrogen pemantauan harus terus menerus sementara pengeboran mana saja yang dicakup oleh rencana kontingensi. Pemantauan harus dilakukan dengan sensor jarak jauh yang terletak di minimal dekat puting bel, di lantai rig, dan di atas shaker shale. Gas perangkap gas dan daerah rawan juga dapat dipantau. Rencana kontinjensi disetujui akan memiliki rincian tentang di mana sensor harus ditempatkan. Pemeliharaan dan kalibrasi login penting. Pada indikasi pertama H2S, konfirmasi harus dilakukan dengan meteran tangan. Jika pengeboran di daerah H2S, Garrett Gas Kereta sulfida bacaan pada filtrat lumpur juga akan diminta. Dianjurkan untuk memulai lima hari pengeboran sebelum memasuki diprediksi zona hidrogen sulfida untuk membangun konsentrasi latar belakang. Draeger baru-baru ini berubah skala pada tabung mereka, dan faktor tabung yang diberikan dalam API RP 13B-1 harus hati-hati diperiksa untuk memastikan faktor tabung sesuai dengan tabung yang digunakan. 4.15 HIDROGEN RENCANA KONTINGENSI SULFIDE Sebuah rencana hidrogen sulfida khas kontingensi memiliki tiga fase: Jika kadar H2S yang diukur adalah sepuluh ppm atau kurang, tetapi lebih besar dari nol kemudian, Lanjutkan pengeboran yang normal Peka kru dengan latihan dan pertemuan keselamatan Pastikan pemulung H2S (seng karbonat dasar) adalah pada lokasi dan mendiskusikan Selain untuk sistem lumpur Menjaga pH lumpur sebesar 9,5 atau lebih tinggi Mempertimbangkan untuk meningkatkan jumlah kemasan udara pada lokasi Periksa kalibrasi sensor Batasi pengunjung dan personil yang tidak perlu pada lokasi Periksa penyala pada gasbuster garis flare Driller dan lumpur penebang untuk tetap komunikasi Jika diukur H 2 tingkat S adalah dua puluh ppm atau kurang, tetapi lebih besar dari sepuluh ppm kemudian, Menghentikan operasi pengeboran dan melakukan upaya untuk menekan H2S sebelum melanjutkan dengan pengeboran. H suara 2 S alarm dan menerangi lampu berkedip Rig kru segera don alat bantu pernapasan dan sirkulasi berhenti untuk mengontrol sumber hidrogen sulfida. Driller adalah untuk mengetahui apakah sumur harus ditutup di. Beritahu toolpusher dan ECI pengeboran pengawas Semua personil non-esensial melanjutkan ke melawan angin daerah perakitan. Tidak ada personil non-esensial akan diizinkan berada di area dengan kemungkinan H 2 S paparan. Melakukan pertemuan keselamatan dan review berencana untuk kembali ke pengeboran. Respon rencana dalam hal konsentrasi hidrogen sulfida melebihi dua puluh ppm. Ulangi pertemuan keselamatan sebelum kru datang pada tur. Semua personil memeriksa peralatan keselamatan mereka untuk operasi yang tepat dan lokasi. Orang tanpa peralatan pernapasan ditugaskan tidak bisa bekerja di daerah berbahaya. Perlakukan lumpur dengan pemulung yang diperlukan Beritahu pengawas operasi sebelum kembali ke pengeboran Gunakan 'Buddy Sistem' â € "tidak ada individu akan diizinkan untuk bekerja di daerah yang terkena sendiri Jika H diukur 2 tingkat S lebih besar dari dua puluh ppm kemudian, H suara 2 S alarm Don Rig awak bernapas alat dan menutup di dalam sumur Semua personil melanjutkan ke melawan angin daerah perakitan aman Menangguhkan operasi pengeboran dan menilai kembali rencana kontingensi dengan inspektur Pedoman Untuk Pengendalian Nah Dalam situasi tendangan, di mana H 2 S sebelumnya telah terdeteksi dalam filtrat cairan pengeboran atau dengan analisis gas lumpur logging, semua personel yang terlibat langsung dengan operasi yang memiliki tersedia diri individu terkandung bernapas aparat (SCBA). Semua personil lainnya harus waspada dan dibuat sadar daerah yang ditunjuk aman pengarahan (s) yang akan digunakan selama operasi juga membunuh. Selama sirkulasi tendangan, personil di atas adalah untuk mengenakan SCBA mereka, sebagai minimum, 30 menit sebelum waktu kedatangan dihitung dari cairan tendangan dan tetap sampai 30 menit setelah cairan tendangan vented bawah garis suar SCBA ini. Mencoba untuk membakar gas tendangan jika kondisi memungkinkan, dan Persetujuan Peraturan yang tepat telah diperoleh. Selama seluruh sirkulasi tendangan, anggota yang ditunjuk dari kru bor adalah untuk memeriksa (dengan SCBA di) daerah pengocok untuk konsentrasi H2S. Juga, cairan pengeboran kembali harus dipantau untuk H 2 S di seluruh operasi juga membunuh. Jika pada setiap saat selama sirkulasi tendangan, H 2 konsentrasi S melebihi 20 ppm atau lebih dalam suasana kerja (udara), baik itu harus ditutup dan personil non-esensial untuk dipindahkan ke daerah pengarahan aman (s) atau dievakuasi (tergantung pada konsentrasi H 2 S). Dalam hal terjadi situasi kontrol dengan baik di mana terjadinya H 2 S kemungkinan, pertimbangan harus dibuat untuk bullheading cairan formasi kembali ke dalam formasi, daripada beredar tendangan keluar dan melepaskan H 2 S di permukaan. Pedoman Untuk Coring Dan Produksi Pengujian Lihat Bagian 8 dan 12 manual ini untuk informasi / pedoman mengenai H2S di coring dan pengujian produksi operasi. Jika bekerja pada sebuah sumur dengan gas hidrogen sulfida, semua pekerja di daerah harus menutupi sementara mengambil katup tekanan kembali. BIT CLASSFICATION DAN hidrolika 5.0 BIT KLASIFIKASI DAN hidrolika 5.1 Umum 1 5.2 Bor Bits 1 5.3 IADC Bit Sistem Klasifikasi 3 5.4 IADC Bit Grading System 6 5.5 Menjalankan Prosedur untuk Cutters Tetap 8 5.6 Hidrolik Program 10 5.7 Pedoman Hidrolik Optimasi 12 5,8 Hidrolik Optimization 17 Referensi ________________________________________ ________________________________________ ______ OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING FIRST EDITION - MAY, 2003 5.1 UMUM Drilling Program harus menentukan pilihan bit dan hidrolika program yang direkomendasikan berdasarkan diimbangi dengan baik data dan kondisi pengeboran (atau) diantisipasi. Program bit dan hidrolika ditentukan dalam Program Pengeboran harus dilihat sebagai pedoman saja dan penyesuaian harus dibuat yang diperlukan di lapangan untuk memperhitungkan kondisi pengeboran yang sebenarnya. 5.2 BITS DRILL Pedoman Operasional bit 1. Menetapkan parameter bit optimal di awal bit run. Tes bor-Off harus digunakan untuk menentukan titik di mana ROP mulai menurun dengan meningkatnya WOB. Titik menggelepar di bor-off tes adalah WOB di mana bit yang mulai bola. Dimungkinkan untuk meningkatkan WOB dan ROP jika sedikit pembersihan ditingkatkan. Pilihan untuk meningkatkan sedikit pembersihan meningkat hidrolik, mengurangi pisau pada PDCs, aditif lumpur (ROP penambah) jika MW <10 ppg, dan lumpur inhibitive. Bervariasi berat pada bit (WOB) dan kecepatan putar (RPM) yang diperlukan untuk mempertahankan performa maksimal, dengan persyaratan deteksi pertimbangan tekanan abnormal, gas bor tinggi, dan daya dukung lumpur (kemampuan untuk menghapus potongan efisien). 2. Ketika pengeboran di dekat diantisipasi zona tekanan abnormal, parameter pengeboran harus dijaga konstan untuk memungkinkan deteksi tekanan yang lebih akurat. 3. Monitor tren bit ROP untuk menentukan kapan break even point, berdasarkan pada peningkatan biaya per kaki, telah tercapai. Biaya Per Foot (CPF) = Bit biaya + Rig biaya (Perjalanan Waktu + Pengeboran Time) Footage dibor 4. Gunakan Driller otomatis, jika tersedia, ketika pengeboran bawah casing permukaan. 5. Kelas masing-masing bit untuk memakai dan kerusakan menurut IADC Sistem Grading Bit Kusam disajikan pada akhir bagian ini. 3. Di bagian lubang yang lebih dalam, di mana beberapa bit berjalan diperlukan, pemilihan bit adalah harus didasarkan pada optimalisasi kinerja sedikit, kecuali operasi mendatang potensial (coring, log menengah, casing kursi berburu, dll) mendikte sebaliknya. BIT SELEKSI BAGAN FORMASI IADC BIT KLASIFIKASI 1 st KARAKTER KARAKTERIST IK TYPE ROCK Pemotong TETAP BITS Bit Seleksi GIGI INSE RT Pemilihan bit disediakan untuk Rig Pengeboran harus cukup untuk menutupi berbagai kondisi pengeboran. Panduan berikut diberikan untuk seleksi bit: 1. Temukan bit umumnya akan memanggil untuk bit paling agresif yang akan berdiri dengan litologi diantisipasi. Lembut bit gigi pabrik pembentukan umumnya akan menjadi sedikit pilihan untuk lubang permukaan pengeboran. 2. Disegel bantalan (bearing dan mungkin jurnal) bit gigi umumnya akan direkomendasikan untuk pengeboran lubang sedimen permukaan yang lembut dalam upaya untuk mengebor bagian ini dalam satu bit run. 1 st & 2 nd KARAKTER PD C M (S) 1 M Liat, Marl, Gumbo, Red LEMBUT: Sticky, kuat tekan rendah dan drilabilitas tinggi. Tempat tidur, tidak dikonsolidasi Pasir & Shales, Halite (S) 2 1 4 M (S) 3 S (M) 4 DIAMO ND LEMBUT UNTUK MEDIUM: Kekuatan tekan rendah interbeded dengan lapisan keras. Dolomit, Rijang Pasir, Shale, Anhydrite, Sandstone lembut dan lembut lapisan abrasif. 1 Kapur, shaley Kuarsa, batu pasir Batu kapur SANGAT KERAS: Sangat keras dan kasar. Shale, Chalk, Pasir, MEDIUM: Sulit dengan kuat tekan moderat. Anhidrit, shaley 2 Kapur, batu kapur lembut dengan keras Gurat. Shale, batulanau, pasir, MEDIUM UNTUK KERAS: Padat dengan meningkatnya kuat tekan tetapi non atau semi-abrasif. KERAS: Keras dan padat dengan kuat tekan yang tinggi, beberapa Kapur, Anhydrite, Dolomit, Calcareous Sandstone, Sandstone dengan Rijang & Pyrite Gurat Pasir, batulanau, Kuarsit, granit, Konglomerat, Abrasive Sandstone & Limestone. 2 3 Konglomerat, Volkanik seperti Basalt, Gabbo, Rholite, Granit. Tabel di atas berkorelasi karakteristik pembentukan terhadap jenis bit berdasarkan sistem klasifikasi bit IADC. Meskipun ini adalah cukup lurus ke depan untuk bit rock, itu lebih samar-samar untuk bit cutter tetap (khususnya, berbagai PDC). Penggunaan PDC hanya datang dengan sendirinya dalam beberapa tahun terakhir; dibandingkan dengan bit batu teknologi ini masih dalam "tahap balita". Akibatnya, baik, tekan, jelas sistem klasifikasi belum dikembangkan. Untuk mengklasifikasikan pemotong tetap, Dunia Oilâ € ™ s 1995 Klasifikasi Bor Bit Tabel Ulasan untuk menentukan bit jenis yang direkomendasikan oleh manufaktur untuk formasi tertentu. Karakter berani menunjukkan Sedikit klasifikasi yang muncul paling sering di bawah formasi tertentu. Ukuran relatif indikasi sekunder seberapa sering jenis bit tertentu dianjurkan. Sebuah diskusi yang komprehensif dari sistem klasifikasi IADC berikut. 5.3 IADC SISTEM KLASIFIKASI BIT M7 8 M8 IADC Klasifikasi Bit 5. - Soft ke Medium The IADC Bit Sistem Klasifikasi mengidentifikasi bit menggunakan sistem penomoran. Untuk rol kerucut bit, angka-angka ini mengidentifikasi jenis formasi / gigi, tingkat kekerasan dalam dasar pembentukan dan bantalan jenis. Untuk bit cutter tetap, karakter mengidentifikasi bahan tubuh, kepadatan cutter PDC atau ukuran Diamond, ukuran PDC atau jenis Diamond, dan profil bit. The IADC Klasifikasi Bit Sistem dijelaskan di bawah ini. 6. - Medium ke Hard, Semi-Abrasi Roller Cone Bits Misalnya, IADC klasifikasi khas untuk sedikit rol kerucut adalah 1-1-1. Karakter pertama:. Pemotongan Struktur Series (1-8) Mengacu pada karakteristik formasi. Dalam kelompok gigi baja dan insert, formasi menjadi lebih keras dan lebih abrasif sebagai nomor seri meningkat. Bits Mill Tooth (1-3) 1. - Soft 2. - Medium ke Medium Keras 3. - Hard, Semi-Abrasive / Abrasive Insert Bits (08/04) 4. - Soft 7. - Hard, Semi-Abrasive / Abrasive 8. - Sangat keras, Abrasive Kedua Karakter:. Pemotongan Jenis Struktur (1-4) Mengacu pada tingkat kekerasan dalam jenis formasi. 1 - formasi Paling lembut => 4 - formasi Hardest Karakter ketiga: Jenis Bantalan / Gage Perlindungan (1-9). 1. = Standard Roller Bearing 2. = Roller Bearing, Air Cooled 3. = Roller Bearing, Gage Dilindungi 4. = Sealed Roller Bearing 5. = Sealed Roller Bearing, Gage Dilindungi 6. = Sealed Gesekan Bantalan 7. = Sealed Gesekan Bearing, Gauge Dilindungi 8. = Directional 9. = Lainnya, Reserved Untuk Masa Depan Gunakan Keempat Karakter:. Fitur Khusus (karakter Alpha) Mendefinisikan fitur tambahan roller cone bit berkaitan dengan struktur pemotongan, bantalan, segel, hidrolik, dan aplikasi khusus. N = InsertsZ Terutama kerucut = Sisipan Bentuk Lain Tetap Cutter Bits: Baru (sekarang) IADC Klasifikasi: A. = Air Application (Journal bearing dengan nozzles) Misalnya, IADC klasifikasi khas untuk cutter bit tetap adalah M-1-2-1. B. = Bantalan khusus Seal Karakter pertama:. Body Bahan (Alpha Character) Mengacu pada jenis konstruksi tubuh. M = Matrix atau S = Baja (hanya dua sebutan) C. = Pusat Jet D. = Deviasi Kontrol E. = Diperpanjang Jets (panjang penuh) A = Ekstra Gage / Perlindungan Tubuh B = Horizontal / Pengarah Aplikasi J = Jet Lendutan L. = Lug Pads M. = Motor Aplikasi L = Standar Baja Tooth Model M = Dua Cone L = Peningkatan Struktur Cutting M = Sisipan Tooth Terutama pahat Karakter kedua:. Cutter Density Untuk bit PDC ini mengacu pada jumlah total cutter, termasuk pemotong pengukur standar. Untuk Diamond bit ini mengacu pada ukuran berlian. Seperti bit rock, semakin besar jumlah yang lebih cocok untuk aplikasi yang lebih abrasif sulit. PDC Bits (1- 4) Penunjukan 1 merupakan cahaya diatur sementara 4 merupakan set yang berat. Count Cutter didasarkan pada 1/2 "ukuran cutter, cutter (besar / kecil) ukuran yang diproyeksikan sebagai 1/2" kepadatan cutter. 1. = 30 atau lebih sedikit 1/2 "pemotong 2. = 30 sampai 40, 1/2 "pemotong 3. = 40 sampai 50, 1/2 "pemotong d i a m e t e r 4. = 50 atau lebih besar 1/2 "pemotong Diamond Bits (6-8) Sebuah penunjukan 6 merupakan berlian yang lebih besar sementara 8 merupakan berlian yang lebih kecil 6. = <3 batu per karat 7. = 3-7 batu per karat 8. => 7 batu per karat Catatan: (0, 5, & 9) adalah undesignated dan disediakan untuk penggunaan masa depan. Desain khusus menggunakan pemotong tambahan pengukur, seperti sidetrack bit, atau bit untuk pengeboran horisontal, tidak dianggap untuk tujuan klasifikasi. Karakter ketiga:. Ukuran atau Jenis Cutter Untuk bit PDC, karakter ketiga mengacu ukuran cutter sementara untuk Diamond bit, mengacu pada jenis berlian. PDC Bits (1- 4) Ukuran 1. => 2 4 m m 2. = 1 4 m m k e 2 4 m m d i d i a m e t e r 3 4 = Diresapi Berlian Bit (Berlaku hanya Bits kepadatan tertinggi) = Karakter keempat Profil atau Body. Memberikan gambaran tentang penampilan dasar bit, berdasarkan panjang keseluruhan pemotongan wajah bit. 9 m m k e PDC Bits (1- 4) 1. = Fishtail 1 3 m m 2. = Datar Wajah 3. = Profil bit Panjang d i a m e t e r 4. = Profil bit Semakin lama Diamond Bits (1- 4) 1. = Datar Wajah TSP dan Alam Berlian 2. = Panjang 3 = Lagi 4 = <8mm diameter Diamond Bits (1- 4) Ketik 1. = Diamonds Alam 2. = TSP (termal Stabil Polycrystalline) Diamonds Cutters 3 = Kombinasi (seperti berlian alami dan TSP) 4 = S e m a k i n S = Baja Tubuh PDC T = termal Stabil Polycrystalline L a g i O = Lainnya (TSP) Nomor pertama: Profil Bit (Gauge Point ke Cone) O l d 1 = Panjang Taper, Deep Cone 2 = Panjang Taper, Medium Cone I A D C 3 = Panjang Taper, Dangkal Cone 4 = Medium Taper, Deep Cone 5 = Medium Taper, Medium Cone 6 = Medium Taper, Cone Dangkal K l a s i f i k a s i : 7 = pendek lancip, Deep Cone 8 = Pendek Taper, Medium Cone 9 = pendek lancip, Cone Dangkal Nomor kedua: Desain hidrolik Ketik Tubuh diganti Jets Pelabuhan Tetap Terbuka Tenggorokan Berbilah 1 2 3 Misalnya, IADC klasifikasi khas untuk cutter bit tetap adalah D-2-1-2. Surat: Cutter Jenis dan Bahan Tubuh D = Alam Berlian M = Matrix Tubuh PDC Bergaris 4 5 6 Terbuka Menghadapi 7 8 9 Sebutan alternatif: R = Radial Flow, X = Cross Flow, O = Lainnya Jumlah ketiga: Cutter Ukuran dan Densitas Cutter Ukuran Cahaya Density Med. Kepadatan Berat Density IADC BIT MEMBOSANKAN KODE GRADING Besar 1 2 3 CUTTING STRUKTUR Sedang 4 5 6 ROW Kecil 7 8 9 INNER Diresapi 0 0 0 Catatan Definisi Distribusi Ukuran 1 OUTE R ROW 2 B CHAR LOKA kusam. SI 3 4 (1) CUTTING STRUKTUR INNER Kecil Lebih dari 7 batu / karat untuk Diamond alami. BEARING SEALS G GAUG E 1/16 " 5 KETERANG CHAR LAIN. 6 7 (2) CUTTING STRUKTUR - OUTER Batin 2/3 bit. Outer 1/3 dari bit. BITS Kurang dari 3/8 "diameter tinggi yang dapat INSERT - D Ukuran digunakan untuk PDC bit. d linear B hilang, l usang dan / Medium 3-7 batu / karat untuk berlian alami. atau rusak u sisipan. (0- 3/8 "untuk 5/8" diameter tinggi yang dapat digunakan untuk PDC bit. d tidak ada BITS GIGI STEEL - Ukuran linear struktur pemotongan hilang akibat abrasi atau kerusakan. (0 - tidak ada kerugian dari pemotongan struktur s kerugian, akibat abrasi atau kerusakan, 8 - kerugian total pemotongan struktur akibat abrasi atau kerusakan. ( dikenakan k dan / atau Besar Kurang dari 3 batu / karat untuk berlian alami. d sisipan p rusak, 8- s semua p sisipan r usang dan / dapat digunakan untuk PDC bit. 5.4 IADC SISTEM BIT GRADING d hilang, Lebih besar dari 5/8 "diameter tinggi yang atau rusak.) (3) UTAMA KARAKTERISTIK kusam ( (5) 4 BEARIN ) G/ C O N E * SM - Patah Cone N - Hidung Row C M - Row Tengah - 1 S e b 2 G - Gage Baris a C h o A - Semua Rows n e u 3 k E m j s e F m j s g X m j e (Kode-kode ini juga digunakan untuk Kolom 7) ROLLER CONE N - h T i e d t u a p p a H n i d u n g T u d t i t p e e r r B k i i t r - C a k T a a n p e b r a n G a - d a G a k u e g h e i d u A p a - S e m u n y a n g a d A r e a i g u n a k a n , 8semua kehidup an digunak an, yaitu, tidak BU - mengepalkan Bit * CC - Cracked Cone BT - Patah Gigi / Cutters * CD - Cone Menyeret CI - Cone Interferensi CR - Cored FC - Wear Crested datar CT - Chipped Gigi / Cutters ER - Erosi HC - Panas Pemeriksaan LN - Hilang Nozzle LT - Hilang Gigi / Cutters JD - Sampah Kerusakan * LC - Hilang Cone OC - Off-Pusat Wear PB - Terjepit Bit PN - Terpasang Pipa / Arus Ayat RG - Dibulatkan Gauge RO - Dikelilingi Out SD - Kerusakan bagian bawah kemeja TR - Pelacakan WO - Dicuci Out SS - Self Sharpening Wear WT - Gigi Worn / Cutters NO - Tidak ada Mayor / Karakteristik Kusam Lainnya * - Ditampilkan cone # atau # â € ™ s di bawah lokasi 5.5 PROSEDUR RUNNING UNTUK TETAP pemotong Berikut ini adalah panduan umum untuk digunakan ketika menjalankan cutter tetap (PDC dan Diamond) bit. MEMPERSIAPKAN HOLE: Gunakan PDC peralatan mengambang dibor. Periksa bit sebelumnya untuk kerusakan sampah dan pengukur keausan. Membuat perjalanan cleanout jika perlu dengan sampah keranjang. Cari bit dan pemutus di meja putar dan membuat hingga torsi direkomendasikan. Tripping DI LUBANG: Hapus bit breaker dan sedikit hati-hati yang lebih rendah melalui meja putar. Perjalanan hati-hati melalui BOPs, sepatu casing, dan kapal gantungan. Hati-hati menghapus bit dari kotak. Jangan mengatur sedikit langsung di decking baja. Menggunakan kayu atau karet tikar. Perjalanan perlahan-lahan melalui tepian, kaki anjing, dan tempat-tempat yang ketat. Cuci tiga sendi terakhir ke bawah dengan aliran penuh pada 50 - 60 RPM. Periksa bit untuk kerusakan. Sedikit catatan nomor seri. Pendekatan bottom mengamati indikator berat badan dan torsi putar. Tag bawah dengan lembut dan mengambil 6-12 inci dari bagian bawah. Edarkan 5 - 10 menit dengan aliran penuh pada 50 - 60 RPM. PASTIKAN LUBANG IS BERSIH. MEMPERSIAPKAN BIT THE: Transportasi bit dalam kotak ke lantai rig untuk menghindari kerusakan cutter. Periksa O-cincin, nozel, dan sedikit pengukur (tidak berlaku untuk bit berlian). Periksa dalam bit untuk penghalang atau benda asing. PEMBUATAN UP THE BIT: Reaming: Reaming UNDERGAGE LUBANG TIDAK DIANJURKAN. Fit bit breaker untuk bit dan terlibat latch. Bersih dan minyak pin. Rim tempat ketat dengan aliran penuh untuk menjaga pemotong keren. Drill string yang lebih rendah ke atas pin dan terlibat benang. Gunakan 2.000 - 4.000 £ WOB dan 50 - 60 RPM. Rim perlahan - menghindari TORQUE TINGGI. BIT BREAK IN: Lebih rendah sedikit ke bawah dengan aliran penuh pada 60-80 RPM. Penggunaan motor akan menghasilkan kecepatan rotasi yang lebih tinggi. Bandingkan diharapkan vs hidrolik yang sebenarnya. biasanya akan menghasilkan nilai torsi yang lebih tinggi. Jika torsi atau RPM bersepeda parah, mengontrol dengan WOB ringan atau meningkat RPM. MEMBUAT SAMBUNGAN: Setelah membuat sambungan, lebih rendah ke bawah perlahan-lahan dengan aliran penuh dan 50 - 60 RPM. Rekam tekanan stand-pipa dan stroke pompa. Bor pola lubang bawah dengan 2.000 - 4.000 £ WOB. Memeriksa tekanan pipa tegak dan pompa stroke dan mematikan bawah. BREAK BIT DI perlahan - JANGAN TERBURU-BURU. Meningkatkan RPM ke tingkat sebelumnya dan menambah berat perlahan. Setelah tiga kaki, menambah bobot 2.000 pound bertahap dan meningkatkan putar untuk RPM optimal. JANGAN JAM BIT THE BACK ON BOTTOM. DRILLING DEPAN: Menentukan parameter pengeboran yang optimal dengan mengubah WOB dan RPM dalam pedoman yang direkomendasikan. Melakukan drill-off tes untuk memaksimalkan ROP. Menarik diri dari HOLE: Memperlambat melalui bintik-bintik ketat, sepatu casing, kapal gantungan, dan BOPs. Melampirkan bit breaker dan keluar sedikit di meja putar. Hindari kerusakan cutter ketika menghapus bit. Jangan letakkan sedikit langsung di atas meja putar. Jangan ragu untuk menyesuaikan parameter pengeboran. Rotary torsi harus perkiraan bahwa dari bit batu di sama ROP dan WOB. ROP lebih cepat Kembali sedikit ke kotak setelah evaluasi kusam. 5.6 PROGRAM hidrolika Program hidrolik yang direkomendasikan untuk setiap bagian lubang akan ditentukan dalam Program Pengeboran berdasarkan parameter pengeboran diprediksi seperti berat lumpur, konfigurasi BHA, kemampuan pompa, kerugian tekanan, dll Bit hidrolik yang akan dihitung ulang onboard Kapal Pengeboran berdasarkan parameter aktual . Desain ini memiliki tiga wilayah aliran berdasarkan laju alir kritis Q Crit, laju aliran di mana total tenaga kuda yang tersedia digunakan pada tekanan permukaan maksimum yang diijinkan, P Surf. KASUS I: tekanan permukaan terbatas (kondisi tidak dibatasi oleh kendala tekanan permukaan). Tingkat aliran tinggi dan tekanan permukaan rendah. Di wilayah ini dampak hidrolik dimaksimalkan ketika 74% dari tekanan yang tersedia dikeluarkan pada bit dengan laju alir di atas Q Crit. Kondisi ini biasanya terjadi pada kedalaman dangkal di konduktor dan permukaan casing bagian dari lubang di mana total kerugian tekanan dalam sistem rendah. Liners sering lebih besar dan / atau perubahan yang tidak dibenarkan untuk lubang atas cepat, menghalangi hidrolik optimal sampai pengeboran bawah lubang permukaan. Tingkat aliran tinggi adalah parameter untuk kunci pada. â † P Bit = 0,74 P Surf Alir> Q Crit KASUS II: Menengah antara Kasus I & II Case. Laju aliran tetap konstan sementara beredar tekanan meningkat dengan kedalaman. Di wilayah ini tingkat sirkulasi tetap konstan pada Q Crit sementara tekanan permukaan meningkat hingga 48% dari tekanan maksimum yang diijinkan dikeluarkan di bit. Kondisi ini biasanya terjadi di bagian casing menengah / pelindung lubang. â † P Bit = (0,48-0,74) P Surf Alir = Q Crit KASUS III: Terbatas tekanan permukaan (kondisi dibatasi oleh tekanan permukaan maksimum yang diijinkan, Pmax). Tekanan permukaan tetap konstan sementara tingkat yang beredar berkurang. Di wilayah ini dampak hidrolik dimaksimalkan ketika 48% dari tekanan maksimum yang diijinkan dikeluarkan di bit. Kondisi ini biasanya terjadi di bagian yang lebih dalam dari lubang bawah permukaan atau casing pelindung. Seringkali perubahan dalam ukuran kapal diperlukan di bawah casing pelindung. â † P Bit = 0,48 P Surf Alir <Q Crit Dalam ExxonMobil masa lalu umumnya menggunakan Reed Log-Log Metode Grafis untuk menghitung optimal rig hidrolik seperti dijelaskan di atas. Sebuah diskusi rinci dari metode ini dapat ditemukan di EUSA Drilling Sekolah Teknik Manual dan tua Operasi EUSA Pengeboran Manual (Buku Merah). Saat ini program komputer Reed hidrolik digunakan. Persamaan hidrolik HHP = (HP) (Em) (Ev) HHP = (P) (Q) 1714 HP = Masukan daya kuda dari tabel kinerja pompa lumpur (hp) Q Crit = 1714 (HHP) V N = 0,32 (Q) P Surf A 2 â † P N = (MW) (Q) 2 Daya HHP = Mud keluaran pompa hidrolik kuda (hp) MW = Mud berat (ppg) F B = (MW) (V N) (Q) 12.042 (Cd) 2 A 2 1932 Sebuah V = 24,5 (Q) P. = Tekanan Beredar, tekanan pipa tegak (psi) â † P N = â † P Bit, penurunan tekanan di nozel bit (psi) P Surf = P Max, tekanan sirkulasi maksimum yang diijinkan (psi) (DH) 2 - (DP) 2 Dimana: A = TFA, total luas aliran nosel (di 2) Sebuah V = Velocity annular (fpm) Cd = koefisien Nozzle = 1.03 DH = Diameter lubang (di) DP = Diameter pipa di lubang (di) Em = efisiensi Teknik pompa lumpur (%) Ev = efisiensi volumetrik pompa lumpur (%) FB = hidrolik dampak berlaku pada bit (lbs) Q. = Beredar tingkat (gpm) Q Crit tingkat = Sirkulasi di yang total tersedia tenaga kuda digunakan pada tekanan permukaan maksimum yang diijinkan, P Surf (gpm) V N = kecepatan Nozzle (fps) 5.7 PEDOMAN hidrolika OPTIMALISASI Berikut pedoman, rekomendasi, dan aturan-ofthumb dimaksudkan untuk menyediakan sarana untuk memantau kondisi di rig dan untuk mendapatkan merasakan seberapa baik hal tersebut terjadi. Mereka tidak "jawabannya" tapi bendera saja, menunjukkan apakah pemeriksaan lebih lanjut diperlukan atau sebagai titik awal untuk perencanaan program hidrolik Lubang Pembersihan Gejala utama dari pembersihan lubang miskin tergantung pada lubang sudut. Pada sudut yang rendah (<20) stek cenderung jatuh downhole segera setelah pompa dihentikan. Tanda terbaik pembersihan miskin adalah mengisi di bagian bawah, baik pada koneksi atau setelah tersandung. Dalam kasus ekstrim mungkin sulit untuk menarik dari bawah dengan pompa off. Pada sudut tinggi (> 50) stek jatuh ke sisi rendah dari lubang membentuk stek tidur stasioner. Ada biasanya tidak ada mengisi pada koneksi bawah dan tidak ada kesulitan membuat. Bukti utama membersihkan lubang miskin terlihat pada perjalanan. String mungkin menarik ketat atau terjebak off bawah ketika mencoba untuk menarik melalui stek kamar. Pada menengah sudut (40 60) stek jatuh ke sisi rendah dari lubang membentuk tempat tidur stek. Tempat tidur ini tidak stasioner; akibatnya, ketika sirkulasi dihentikan tidur stek mungkin mulai geser (avalanche) downhole. Gejala membersihkan lubang miskin untuk kasus sudut menengah, akan berkisar antara yang terlihat untuk sudut rendah dan sudut tinggi sumur. Dalam hal apapun, jika drag mendapat tinggi, Rih 2-3 berdiri, menempatkan drive atas dan mengedarkan dan memutar pada tingkat maksimum sampai lubang dibersihkan; jangan mencoba untuk menarik melalui tempat yang ketat. Mungkin perlu untuk memompa keluar atau kembali rim keluar dari lubang di sudut yang lebih tinggi sumur. Backreaming keluar dari lubang memerlukan persetujuan Operasi Inspektur. Memanfaatkan sedikit dengan luas penampang rendah kemungkinan, atau area terbuka setinggi mungkin, akan memberikan manfaat ketika tersandung melalui menengah dan tinggi sudut lubang stek tidur. Daya Dukung Index (CCI) Untuk sudut rendah dan lubang menengah hingga 35, CCI masih muncul untuk menjadi indikator terbaik dari lubang pembersihan. Tidak ada derivasi matematika untuk CCI; observasi lapangan menunjukkan bahwa produk numerik dari K, kecepatan annular, dan berat lumpur harus sama atau melebihi 400.000 untuk membersihkan lubang yang baik. Daya dukung lumpur tergantung pada perbedaan kepadatan antara stek dan cairan pengeboran, kecepatan annular, dan viskositas fluida di annulus. Sebagai salah satu dari angka-angka ini meningkat, daya dukung meningkat lumpur. CATATAN: The CCI hanya berarti ketika beredar. Sebuah kapasitas suspensi cairan pengeboran juga dibutuhkan untuk membuat ramuan dan melumpuhkan stek di washouts selama perjalanan. Kekuatan gel yang memadai diperlukan untuk perjalanan. CCI = (MW) (K) (AV) Baik lubang pembersihan terjadi ketika CCI> 1 400.000 K = (511) 1-n (PV + YP) Dimana: MW = Mud Berat (ppg) AV = annular Velocity (fpm) n = 3,322 log PV + YP 2PV + YP PV = Plastik Viskositas (cp) YP = Yield Titik (lb / 100 ft2) K adalah indeks konsistensi yang sesuai dengan viskositas lumpur pada laju geser dari satu detik timbal balik, dan n adalah ukuran dari perilaku aliran nonNewtonian dalam model rheologi kuasa hukum, SS = K (SR) n. Grafik berikut memberikan solusi grafis untuk PV nilai K memanfaatkan dan YP dari lumpur. lubang pembersih berdasarkan desain drill string yang (desain bit, ukuran lubang, kerah, pipa bor), pipa bor berputar kecepatan, pengeboran reologi cairan, laju aliran, dan baik profil. EMURC saat ini sedang mengembangkan sebuah program PC untuk pengawasan di lapangan. HCR = H / H crit. Baik lubang pembersihan terjadi ketika HCR> 1.1 Dimana: H = ketinggian keseimbangan wilayah bebas atas tempat tidur stek dan merupakan fungsi dari variabel yang tercantum dalam gambar 1. di bawah ini. Solusi grafis untuk Low Shear Tingkat Viskositas - K Rasio lubang Cleaning (HCR) Untuk menengah dan tinggi lubang sudut yang mengembangkan stek tidur, EMURC telah mengembangkan parameter yang disebut Rasio Lubang Cleaning (HCR) yang sangat korelatif dengan masalah lubang pembersih. Karena banyak variabel pengeboran dan sistem fisik yang rumit yang terlibat, sederhana "Direkomendasikan annular Velocity" meja yang muncul dalam literatur EPR masa lalu tidak lagi didukung. Sebagai gantinya, EMDRC telah mengembangkan alat baru dari teori mekanika fluida, data laboratorium yang diterbitkan, data eksperimen baru, dan data lapangan yang menyediakan kombinasi yang optimal dari variabel pengeboran untuk membersihkan lubang efisien. Telah digunakan untuk perencanaan atau desain dengan baik untuk memprediksi kemungkinan menghadapi masalah H crit = ketinggian kritis adalah terutama fungsi dari bit geometri. Rasio lubang Cleaning (HCR) (lanjutan) Lubang Pembersihan Operasi (Menengah dan Tinggi Angle Lubang) Berdasarkan pekerjaan ini, memompa keluar prosedur berikut direkomendasikan untuk bagian menyimpang dari sumur bor di mana masalah karena stek tidur dicurigai. Memonitor torsi dan tarik menggunakan Torque & Drag Surveillance spreadsheet. Mengedarkan dan memutar drillpipe di aliran yang diijinkan / direkomendasikan tarif maksimum sebelum memulai perjalanan. Pengalaman menunjukkan bahwa 2 sampai 3 bottoms up volume mungkin diperlukan untuk membersihkan lubang yang cukup untuk tersandung. Jika sidetracking mungkin, bergerak sedikit perlahan-lahan selama interval pendek Putar akan membantu membangkitkan dan menghapus potongan tidur terutama jika banyak sliding dilakukan. Lihat EMDC Technology Group untuk pedoman rinci. Pada bagian menyimpang, POH perlahan seperti yang dijelaskan dalam prosedur pengeboran (~ 21 / 2 sampai 3-1 / 2 menit per berdiri). Jika kelebihan tarik diindikasikan, berhenti menarik, mengendur 1 bersama, kemudian beredar dan memutar setidaknya satu dasar di laju aliran maksimum yang diijinkan. Berputar bantu signifikan untuk lubang pembersihan di lubang sudut tinggi (praktek normal adalah 100120 rpm). Kemudian, jika drive atas tersedia, memompa keluar dari lubang di / laju aliran direkomendasikan maksimum sementara menarik di 2-1 / 2-3-1 / 2 menit per berdiri atau lebih, terus sampai lubang membebaskan-up. Setelah di bagian sudut bawah lubang sumur (sebaiknya di dalam casing), beredar setidaknya dua pantat di laju aliran maksimum sampai stek kembali menurun. Setelah lubang bersih, finish POH tanpa pemompaan. Untuk pengeboran operasi dengan bagian lubang diperpanjang di atas 45, backreaming mungkin diperlukan. Rincian operasional akan diberikan dalam prosedur pengeboran yang berlaku. Memastikan bahwa bahaya backreaming di lubang yang tinggi-sudut secara menyeluruh dibahas sebelum memulai dengan baik sehingga setiap orang jelas pada strategi yang akan digunakan. Aturan-of-Thumb 1. Laju alir: laju aliran pengeboran lepas pantai Biasanya jatuh antara 50 hingga 70 GPM per inci diameter bit. Namun, laju aliran lebih besar dari 70 GPM per inci diameter bit tidak pernah terdengar di sumur sudut tinggi. Jangan mengorbankan laju aliran untuk mendapatkan lebih banyak tenaga kuda, kecepatan jet, atau penurunan tekanan sedikit. Terlalu rendah laju aliran kehendak bola sedikit dan mengurangi pembersihan lubang yang efektif. Laju aliran anulus terlalu rendah untuk menyebabkan erosi. Namun, kecepatan nozzle yang biasanya 200-400 ft / sec dapat menyebabkan pembesaran di batu kekuatan rendah (<1.500 psi). Batasi nozzle kecepatan untuk <400 fps di soft rock. Pengeboran cepat dengan bobot lumpur rendah membutuhkan minimal 50 GPM per inci diameter bit untuk lubang <20; lubang sudut yang lebih tinggi mungkin memerlukan lebih banyak. 3. Bit Pressure Drop: Ketika beroperasi di bawah Q Crit, desain hidrolik untuk penurunan tekanan 48% menjadi 65% di seluruh bit yang; ini biasanya terjadi di bawah permukaan casing. Optimal Hidrolik Dampak terjadi ketika 48% dari hilangnya tekanan sistem di bit sementara optimal hidrolik Horsepower terjadi dengan 65% dari kerugian pada bit. Jika total drill string dan kehilangan tekanan annulus lebih besar dari 52% dari tekanan pompa yang tersedia, nozel kecil diperlukan. Namun, tidak beroperasi di bawah 30 GPM per inci diameter bit. Pertimbangkan untuk menggunakan pipa bor yang lebih besar. Saat menjalankan sebuah PDM, dianjurkan bahwa tekanan diferensial di seluruh bit yang tidak melebihi 1.000 psi untuk mencegah keausan dipercepat dari perakitan rotor / stator. 2. Horsepower hidrolik: Menjaga 2-7 horsepower hidrolik per inci persegi luas lubang bor (HHP / di 2). PDC bit dengan OBM membutuhkan lebih sedikit HHP / di 2 dibandingkan dengan WBM. Total laju aliran lebih penting ketika pengeboran dengan bit PDC dan OBM dari HHP / di 2. Pengeboran cepat umumnya memerlukan HHP tinggi / di 2; Namun, beberapa bit PDC di OBM dapat bertahan dengan sesedikit 2 HHP / di 2. Bit yang lebih besar membutuhkan lebih HHP. Namun, berkali-kali di lubang yang lebih besar ukuran tinggi HHP tidak mungkin. Dalam kasus ini, memompa volume maksimal. Maksimum HHP / di 2 harus dipertimbangkan hanya jika kelebihan pompa tenaga kuda tersedia. 4. Jet Velocity: kecepatan jet Baik biasanya antara 350 dan 450 kaki per detik (menggunakan kurang dari 400 fps di batu sangat lembut untuk menghindari washout). â € ¢ kecepatan Jet akan mempengaruhi chip yang terus turun dan ROP. 5,8 Hidrolik Optimization (GOM Pengeboran untuk referensi) Kecuali di batu sangat lembut, hidrolika don t harfiah bor. Namun, mereka membersihkan sedikit sehingga stek membangun tidak mulai untuk membawa WOB yang harus di gigi (balling). Hidrolik memperpanjang titik flounder, yang merupakan titik di mana bit mulai bola. 1. Dalam ROP tinggi, directional, kriteria desain hidrolik utama adalah lubang pembersihan. Tenaga kuda hidrolik optimum pada bit dapat dimanfaatkan untuk memberikan pembersihan yang efektif dari bit. 2. Optimasi hidrolik harus ditentukan oleh kinerja peralatan rig dan hasil sebelumnya bit run (s). 3. Nozel bit harus setidaknya 12/32 "untuk menghindari plugging untuk operasi pengeboran normal dan â ‰ ¥ 14/32" jika kembali kehilangan diantisipasi. Peralatan MWD dan motor juga mungkin perlu dirancang khusus jika kembali kehilangan diantisipasi untuk mencegah mencolokkan drillstring dengan LCM. Layar downhole telah digunakan jika tidak ada alat sumber nuklir yang dijalankan. Penggunaan bor layar pipa downhole atau permukaan harus disetujui oleh Operasi Inspektur. 4. Dalam lembut, formasi yang tidak terkonsolidasi, membatasi kecepatan jet untuk meminimalkan lubang wash-out (<400 fps) 5. Dalam pengeboran cepat dan lubang sudut tinggi, memaksimalkan laju alir untuk membersihkan lubang yang lebih baik. 6. Hati-hati menganalisis ECDs dan gradien frac untuk menentukan tarif sirkulasi yang tepat. 7. Sering dalam operasi pengeboran GOM, bit PDC mampu ROPs lebih dari kemampuan kita untuk membersihkan lubang. Untuk situasi ini, sangat penting untuk mengoptimalkan RPM dan hidrolika untuk secara efektif membersihkan lubang, belum tentu memaksimalkan ROP. Memanfaatkan software HOLECLEAN untuk mencapai desain hidrolik dengan HCR> 1.1. 5.9 REFERENSI BAHAN: Klasifikasi bit 1. Dunia Oilâ € ™ s 1995 Bor Bit Classifier. 2. Trinidadâ € ™ s Operasi Pengeboran Manual, Operasi Pengeboran Bagian, Halaman 27.â € ž 3. Teluk Mexicoâ € ™ s Operasi Pengeboran Manual. 4. Hughes Tool Company, Bit Kusam Grading Kode grafik. 5. IADC Drilling Manual, Kesebelas Penambahan, Bab A, Bagian 2, Page 2 & 3; Bagian 3, Page 1; Bagian 4, Page 3 & 4. 6. EPR Pengeboran Mekanika, Bagian 4-Roller Cone Bits, Halaman 34. 5. Praktek pengeboran Manual, Preston L. Moore, Bab 10Hidrolik di Rotary pengeboran. 6. Randy Smith Pengeboran Sekolah Handbook, BENAR-Yah Rencana Sec., Hidrolik Perencanaan. 7. Reed Tool Company Program Hidrolik Manual. 7. Hycalogâ € ™ s Tetap Cutter Handbook. 8. Reed Tool Company Hidrolik Slide-Peraturan dan Pompa Kinerja Charts. 8. Geologi, A Golden Gratis, Frank HT Rhodes, Klasifikasi beku Rocks 9. IADC Drilling Manual, Kesebelas Penambahan, Bab R, Bagian 13, Page 1. 1. Pedoman EUSA Pengeboran Sekolah Teknik, Bagian Hidrolik. 10. Trinidadâ € ™ s Operasi Pengeboran Manual, Operasi Pengeboran Bagian, Halaman 2-7. (tersedia dari Rivers RE (EMDC) Hidrolika 2. EUSA Operasi Pengeboran Manual (Buku Merah) Rig Hidrolik Bagian. 3. EPR Directional Drilling Workshop ECI, Surveillance dan Tindak Lanjut Bagian. 4. IADC / SPE Kertas 27.464 Lubang Cleaning di besar, tinggiAngle lubang bor, Marco Rasi, EPR 11. Dr Leon Robinsonâ € ™ s Dibor Padat Manajemen Seminar. DRILLING SISTEM FLUIDA 1. DRILLING SISTEM FLUIDA OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING PERTAMA EDITION MAY 2003 1. UMUM 2. Umum 1 3. Padatan Kontrol 1 4. Pengeboran Perawatan Fluid 3 5. Pengeboran Cairan Cek 5 6. Suhu tinggi Pengeboran 6 7. Terjebak Pipa Pills 6 8. Kehilangan Sirkulasi 7 9. Non-berair Fluid Operasi 15 10. Rig-Site Dielektrik Konstan Pengukuran 33 11. Pengeboran Sistem Fluid Pedoman 34 GI Lampiran Fluid Transfer Checklist Lampiran G-II NAF / Minyak Pangkalan Checklist Mud Kesiapan ____________________________________________ __________________________________ Sistem fluida pengeboran yang paling efisien tergantung pada keseimbangan biaya isu-isu lingkungan (material dan waktu rig), stabilitas lubang sumur perlu, karakteristik pembentukan dan. Sebuah sistem fluida pengeboran efektif meminimalkan jumlah komponen kimia yang berbeda diperlukan untuk mencapai sifat fluida pengeboran ditentukan dalam Program Pengeboran. Memeriksa persyaratan lokal untuk bahan untuk menjaga di tangan. Pengembangan program pengeboran akan menggabungkan pemahaman kontinjensi berdasarkan hasil analisis risiko dalam jenis bahan dan persyaratan melalui berbagai tahapan dengan baik. 2. PADATAN KONTROL Mempertahankan kontrol yang rendah padatan gravitasi konten di cairan pengeboran akan memaksimalkan kinerja sistem fluida pengeboran. Dua cara umum untuk mempertahankan padatan kontrol: (1) peralatan padatan kontrol dan (2) dilusi. Keseimbangan antara kedua metode ini diperlukan untuk menjaga sistem cairan pengeboran dengan biaya yang efektif. Kecuali jika cairan pengeboran tertimbang, metode yang paling ekonomis padatan kontrol adalah dengan menggunakan padatan peralatan kontrol. Hal ini memerlukan pemeliharaan peralatan padatan kontrol dalam kondisi optimal sehingga melakukan sesuai dengan spesifikasi pabrik. Namun, peralatan padatan kontrol tidak 100% efisien dan beberapa padatan kontrol dengan pengenceran selalu diperlukan. Shaker serpih adalah cara yang paling efisien untuk menghilangkan padatan. Mereka melihat cairan pengeboran segera karena keluar dari lubang sebelum stek berkurang dalam ukuran dengan peralatan pengolahan permukaan. Penggunaan shaker berkualitas tinggi, dengan layar baik dipertahankan per rekomendasi pabrik, adalah biaya yang paling efektif metode menghilangkan padatan. Sebuah centrifuge biasanya ekonomis dalam lumpur yang tinggi berat (> 14 ppg) atau dalam lumpur berat badan rendah jika fase cair mahal (beberapa lumpur polimer atau lumpur non-berair). Pengenceran adalah metode yang paling mahal dari padatan kendali ketika menggunakan pengeboran cairan tertimbang (> 11,0 ppg). Pedoman pengenceran 1. Mempertahankan padatan gravitasi rendah sebagaimana ditentukan dalam Program Pengeboran terutama oleh penggunaan peralatan padatan kontrol dan hanya encer bila diperlukan. Beberapa pengenceran diperlukan pada kebanyakan lumpur. 2. Jika penambahan langsung air pengenceran yang dibuat untuk sistem aktif, harus menyadari bahwa aditif lumpur juga akan diperlukan untuk menjaga sifat lumpur konstan. 3. Encerkan sistem aktif untuk kandungan padatan yang diinginkan dalam satu sirkulasi oleh perpindahan parsial (membuang sebagian dari sistem lumpur aktif sebelum menipiskan dengan seluruh lumpur). Perhatikan bahwa pembuangan lumpur biasanya diatur oleh badan pemerintah lokal. Jangan melebihi tingkat lumpur debit per jam maksimal dan selalu memastikan bahwa kondisi debit yang tepat terpenuhi sebelum dibuang. 4. Encerkan sistem aktif sebelum pembobotan atas cairan pengeboran untuk menghindari dilusi biaya cairan pengeboran yang lebih tinggi. 5. Pemantauan ukuran partikel lumpur di lumpur cahaya atau tertimbang dapat mendorong keputusan untuk mencairkan lebih agresif. Pengenceran - Premixed Drilling Fluid Keuntungan menggunakan cairan pengeboran premixed (seluruh lumpur) ketika menipiskan sistem aktif adalah sebagai berikut: Mudah bagi Pengeboran Cairan Insinyur untuk menjaga dengan konsentrasi produk. Menyediakan lebih bahkan konsentrasi bahan kimia dalam sistem fluida pengeboran. Mengurangi kebutuhan untuk menambahkan bahan massal (garam, barit) ke sistem aktif saat beredar. meningkatkan kapasitas pengolahan. Hindari menggunakan layar bergelombang pada panel akhir atau pada panel yang tidak sebagian besar terendam. Kerugian meliputi: Pedoman Hidrosiklon Menambahkan produk yang tidak diperlukan Mencegah praktek membiarkan lumpur tren properti berkendara yang bahan yang digunakan Mengikat ruang mud pit terus menerus. 1. Gunakan Hidrosiklon terus ketika beredar cairan pengeboran tertimbang dalam kebanyakan situasi. 2. Periksa kerucut setiap tur untuk memasukkan. Shale Shaker Pedoman 3. Pastikan kerucut beroperasi di debit semprotan sebanyak mungkin. 1. Gunakan shaker serpih sebagai primer berarti untuk mengontrol kandungan padatan dari sistem fluida pengeboran. 4. Pastikan bahwa hilangnya cairan pengeboran dari bagian bawah kerucut bukan karena inlet memasukkan. 2. Berinvestasi di sejumlah dermawan dari shaker teknologi terbaru yang tersedia. 5. Harga pakan ke hidrosiklon harus sekitar 125% dari tingkat pompa downhole. 3. Gunakan ukuran layar yang memungkinkan shaker serpih untuk memproses aliran aliran fluida pengeboran seluruh dengan aliran arus sekitar dua pertiga untuk mengakhiri layar. 6. Pastikan kerucut inlet berjenis memiliki kepala gauge dan beroperasi pada 75 ft. Kepala. Pedoman lumpur Cleaner 4. Mengoptimalkan penghapusan padatan dengan mengevaluasi ukuran layar pengocok terus menerus dan menggunakan layar terkecil yang mungkin mempertimbangkan tingkat pompa yang diperlukan dan tingkat penetrasi. 1. Gunakan pembersih lumpur untuk tertimbang atau mahal cairan pengeboran tertimbang (garam tinggi, PHPA polimer, dll) hanya jika padatan gravitasi tinggi rasio padatan gravitasi rendah, ppb, kurang dari 2 di debit layar (yaitu HGS, ppb <150 = 1,5). 5. Jauhkan shaker serpih dalam kondisi operasi yang baik. Menjaga ketegangan layar yang tepat dan segera menggantikan layar robek. Bergelombang ("Piramida") layar gaya telah terbukti efektif untuk LGS 100 2. Periksa kerucut setiap tur untuk memasukkan. 3. Pastikan kerucut beroperasi di debit semprotan sebanyak mungkin. 4. Pastikan bahwa hilangnya cairan pengeboran dari bagian bawah kerucut bukan karena inlet memasukkan. 5. Tunggu satu atau dua sirkulasi sebelum mengoperasikan lumpur bersih saat menambahkan jumlah besar barit ke sistem. 6. Menjalankan lumpur bersih ketika menggunakan layar yang lebih halus dari 180 jala dapat mengakibatkan kelebihan debit barit. Biasanya, lumpur cleaner adalah tidak ekonomis bila menggunakan layar lebih dari 180 mesh lumpur berat yang tinggi (> 14 ppg). Pedoman Centrifuge 1. Feed centrifuge dengan cairan pengeboran dari sistem aktif saja. 2. Jalankan centrifuge hanya sebanyak yang diperlukan untuk memelihara atau memulihkan reologi lumpur dan filtrasi sifat diterima. 3. Tidak melebihi laju umpan maksimum yang ditentukan oleh produsen. 4. Bilas dan flush centrifuge setelah digunakan untuk mencegah kerusakan dari barit menetap. 5. Sementara pengeboran depan, centrifuge tidak akan mengurangi LGS tetapi akan membantu mempertahankan status quo. CATATAN: Referensi URC MANUAL - Pedoman untuk pemilihan, penggunaan, dan evaluasi Padat Kontrol Metode. 6.3 DRILLING FLUID PERAWATAN Pengeboran Pedoman Pengobatan Fluid 1. Melakukan minimal dua (2) lengkap "Di" dan "Out" pemeriksaan cairan pengeboran harian selama operasi pengeboran. 2. Memproses cairan pengeboran kembali dari lubang sumur sehingga sifat fluida cairan pengeboran akan kembali ke dalam lubang yang dalam kisaran yang ditentukan dalam Program Pengeboran. 3. Uji coba perubahan yang signifikan direncanakan untuk sistem fluida pengeboran sebelum membuat perubahan. 4. Mengukur dan mencatat berat fluida pengeboran dan saluran viskositas pada 15 menit interval dari garis aliran dan lubang hisap. 5. Jangan menambahkan minyak atau aditif apapun untuk sistem fluida pemboran yang tidak disetujui untuk debit selama debit cairan yang diinginkan. 6. Beritahu Driller dan Mud Logger perubahan direncanakan untuk volume sistem aktif. 7. Prehydrate semua bentonit di air tawar sebelum menambahkannya ke sistem aktif dalam lumpur air asin. 8. Jika tersedia, gunakan perangkat geser untuk memaksimalkan hasil gel dan polimer saat prehydrating. 9. Campur semua penambahan kaustik dalam tong tertutup sebelum menambahkan ke sistem aktif (bukan dari hopper a). 10. Presolubilizing semua polimer di air tawar sebelum menambahkan ke sistem lumpur garam yang tinggi lebih disukai. 11. Memaksimalkan pemanfaatan semua bahan kimia oleh pra-hydrating mereka di air tawar sebelum menambahkan ke sistem aktif. 12. Pastikan bahwa gerbong yang mematikan jika tidak digunakan untuk pencampuran. 13. Bahan lumpur (terutama bahan massal) harus diuji secara berkala untuk memastikan bahwa kualitas dari bahan memenuhi standar API, atau standar yang ditentukan oleh kontrak dengan pemasok. (yaitu, tes berat jenis barit) Pengeboran Cairan Peralatan Pengujian 3. HTHP filter press jika sesuai untuk jenis lumpur dan lingkungan downhole. 4. PH meter digital dan elektroda dan kalibrasi buffer pH = 7 dan 10. 5. Pilot test kit lengkap dengan kecepatan tinggi Waring mixer (Hamilton Beach, Waring Blender atau setara). 6. Portabel rol oven dan 2-3 sel panas-usia. 7. Methylene blue test kit. 8. Keseimbangan lumpur bertekanan lengkap dengan kalibrasi kit. 9. Kit Garrett Gas Kereta untuk mengukur karbonat dan hidrogen sulfida untuk baik lumpur air atau nonaquious cairan (NAF) jika sesuai. Cairan Pengeboran Laporan Pedoman The Drilling Fluids Engineer untuk memberikan Harian Pengeboran Cairan Laporan kepada Pengawas Operasional yang meliputi: Drilling Fluids Engineering Company adalah untuk menjaga peralatan pengujian berikut di rig: Harian dan kumulatif Penggunaan Drilling Fluid Produk 1. Satu lengkap pengujian lumpur kit dengan bahan kimia pengujian dan API pers. Biaya harian dan kumulatif Drilling Fluid Produk Digunakan 2. Enam-kecepatan Fann viscometer lengkap dengan secangkir panas. Harian dan kumulatif Volume Dilusi Harian dan kumulatif Pengeboran Volume Cairan yang Hilang (Perkiraan) Lebih Padat Kontrol peralatan, Sirkulasi Hilang, Atau Tidak Dicatat Untuk di The Volume Pengenceran Rekam kumulatif Semua Pengeboran Cek Cairan Benar Dicap sebagai Time dan Kedalaman Bit 6.4 DRILLING FLUID CEK The Drilling Fluids Engineer adalah untuk membuat pengukuran berikut untuk setiap cek lumpur pada cairan pengeboran waterbase. Pengeboran Berat Fluid Corong Viskositas PV (Plastik Viskositas) @ 120º F YP (Yield Point) @ 120º F Rheometer Bacaan Untuk 600, 300, 200, 100, 6, dan 3 Bacaan rpm Dial di 120º F Gel Kekuatan @ 120º F (10 detik., 10 min., Dan 30 menit.) API Rugi air pada 100 psi dan Suhu Kamar HTHP Rugi Cairan pada 500 psi Differential dan Suhu Berdasarkan Program lumpur ExxonMobil. Metilen biru Test (MBT) pH Pengukuran Menggunakan Digital pH meter Pf, Mf, dan Pm dititrasi dengan pH meter Konten klorida penambahan Bor Air / Air Rig ini (Barel) Konten chloride untuk lumpur make-up air Klorida dan Total Hardness lumpur filtrat Air, minyak dan Padat Isi (cekatan) Low Gravity Padat Isi / Pasir Konten KCl (wt%) dan Potasium (mg / L) jika menggunakan Sistem Fluid KCl Drilling PHPA (PPB) jika menggunakan Sistem Fluid PHPA Drilling H 2 S jika Ditentukan di Drilling Program (Garrett Gas Kereta Pengukuran Sulfida.) (Mg / L) Karbonat menggunakan Garrett Gas kereta api (mg / L) Lime Konten 5. SUHU TINGGI DRILLING Hot Roll dan Static Age Sampel Lumpur pengeboran berpotensi dapat memiliki masalah gelasi signifikan ketika terkena suhu tinggi untuk waktu yang lama. Masalah-masalah ini dapat sangat akut di lumpur berat tertimbang yang dibutuhkan untuk mengebor formasi normal tertekan. Insinyur lumpur atau asistennya adalah untuk gulungan panas dan statis sampel lumpur usia diantisipasi suhu lubang bawah secara sering (minimal 1 / minggu) setiap saat suhu lubang bawah statis melebihi 250 derajat Fahrenheit. Kecuali ditentukan lain dalam Program Pengeboran, sampel harus canai panas selama 12 jam dan statis berusia selama 24 jam baik di Diperkirakan suhu lubang bawah. Reologi, Gel kekuatan, pH, dan HTHP pembacaan kehilangan cairan dari usia / sampel canai panas harus dibandingkan dengan bacaan prausia untuk mengevaluasi stabilitas lumpur dan untuk membantu menentukan apakah pengobatan tambahan diperlukan. 6. PIL PIPA STUCK Terjebak Pedoman Pill Pipa 1. Untuk pipa berbeda-beda terjebak, Campur pil dengan volume yang cukup besar untuk menutupi BHA, termasuk kelebihan 50% untuk lubang washout, ditambah sekitar 25-50 bbls. Volume ini cukup cairan untuk memompa 0,5-1,0 per barel setiap 30 menit selama 24 jam. 2. Mencampur pil pipa terjebak yang dapat diterima lingkungan ketika praktis. 3. Pastikan bahwa tekanan hidrostatik tidak berkurang di bawah tekanan pori formasi saat menggusur pil. 4. Campur pil di slugging pit atau cadangan pit. 5. Spot pil seluruh BHA sesegera mungkin menggunakan pompa semen. 6. Pompa barel bercak cairan setiap 30 menit selama 24 jam sementara menggelegar. 7. Jika pil pipa terjebak harus dicampur, memastikan bahwa itu digulung secara teratur untuk membantu mencegah pengendapan. Hal ini terutama penting dalam berat lumpur yang tinggi dan dalam kondisi cuaca dingin. 8. Untuk tambahan dan tidak boleh dilakukan pada bercak cairan, meninjau "ExxonMobil Pipa Terjebak Bercak Pedoman Fluid" â € "tersedia dari Drilling Operations Technical Support. 6,7 HILANG SIRKULASI Prioritas pertama ketika menghadapi kehilangan sirkulasi adalah untuk mengisi lubang secepat mungkin dengan air atau cairan ringan lainnya untuk menjaga lubang penuh. Ini adalah tanggung jawab driller, penebang lumpur, dan insinyur lumpur untuk waspada untuk kehilangan sirkulasi. Tanda-tanda peringatan adalah sebagai berikut: 1. Rugi di Pit Tingkat 2. Rugi lengkap Pengembalian 3. Kehilangan Pompa Tekanan Sebuah data pihak ketiga dengan sistem akuisisi data yang pengarsipan dan alarm harus dipertimbangkan jika pemantauan pengembalian hilang sangat penting. Membangun Integritas Hilang kembali terjadi ketika tekanan di lubang sumur melebihi stres menolak di batu. Integritas ditentukan oleh stres penutupan (psi) di fraktur yang dibuat. Stres Penutupan dibangun dengan menerapkan tekanan untuk meningkatkan lebar fraktur, yang menekan batu sehingga mendorong kembali dengan kekuatan yang lebih besar. Semakin besar lebar dicapai, semakin besar peningkatan integritas. Namun, dalam rangka untuk menerapkan tekanan yang dibutuhkan untuk kompres batu, pertama-tama perlu untuk mengisolasi ujung fraktur yang dinyatakan akan terus tumbuh pada tekanan yang sangat rendah. LCM konvensional isolat ujung dengan menjadi massa unpumpable karena kehilangan cairan carrier karena perjalanan menyusuri fraktur wajah permeabel. LCM juga berfungsi untuk berkemas fraktur terbuka sehingga stres penutupan lebih tinggi dipertahankan. Bahkan relatif partikel-partikel kecil yang efektif dan akan menjadi massa unpumpable jika leakoff yang tinggi. Leakoff tinggi dan konsentrasi padatan tinggi adalah fitur kunci dalam desain pil. Pertumbuhan fraktur tidak dihentikan dengan memblokir dengan partikel besar, dihentikan oleh hilangnya cairan pembawa dan pengembangan massa unpumpable. Pil mungkin memiliki kerugian lonjakan intrinsik tinggi dan belum menjadi tidak efektif jika permeabilitas yang rendah. Ragu-ragu meremas sangat penting dalam permeabilitas yang rendah (<500 + md) karena memungkinkan waktu untuk cairan pembawa bocor off. Beberapa lapisan LCM yang akhirnya dibangun di dekat kawasan lubang sumur yang mencapai lebar rekahan yang cukup dan stres penutupan untuk memungkinkan pengeboran untuk melanjutkan. Integritas tidak dapat dibangun kecuali patah tulang dibuat dan lebarnya meningkat. Jika peningkatan yang diperlukan dalam stres penutupan sangat rendah, padatan lumpur saja dapat mencapai lebar diperlukan ketika mikro-patah tulang hanya memulai dan tidak ada kerugian yang diamati. Jika kenaikan sedikit lebih lebar diperlukan, maka baik mungkin â € œtake sebuah € drinka dan kemudian pengeboran dapat terus. Ketika kerugian lengkap terjadi pendekatan yang paling efektif yang tersedia harus digunakan pada upaya pertama. Hal ini dibenarkan oleh tingginya biaya waktu rig untuk beberapa upaya untuk membangun integritas. Campur tinggi pil kehilangan cairan, menggunakan konsentrasi tertinggi LCM mungkin, dan berencana untuk raguragu meremas. Ini mungkin bukan yang terbaik â € œfirstâ respon € dalam kasus di mana zona loss isna € ™ ta pasir selama sekitar 100md atau underbalance oleh lebih dari 1000psi. Mengisi Lubang Jika kembali kehilangan terjadi dan tingkat cairan anulus tetes adalah penting untuk mengisinya segera. Ketika kehilangan diamati: 1. Segera mengambil dari bawah minimal 15 ft (jelas kelly bushing jika menggunakan kelly). 2. Matikan pompa lumpur. 3. Mengamati tingkat cairan dalam anulus, (bell puting) jika terlihat. 4. Jika tidak berdiri penuh, mengisi awalnya dengan 020 bbls lumpur berat bor untuk melihat apakah kerugian tersebut menurun. 5. Jika kerugian tidak jadi € ™ t penurunan, isi dengan air atau minyak dasar melalui tangki perjalanan sampai kerugian berhenti. Anulus akan stabil ketika kepala Total sama dengan stres penutupan fraktur di zona loss. Mengukur dan mencatat volume cairan cahaya yang diperlukan untuk mengisi annulus. 6. Hitung stres penutupan fraktur (integritas) di zona kerugian berdasarkan jumlah mengisi dan melaporkan volume mengisi dan FCS pada laporan harian. FCS ppg = [(Light Isi Tinggi) (Light Isi Density) + (Mud Tinggi) (MW)] (Perkiraan Kedalaman Rugi) 7. Amati anulus. Jika mengisi cahaya upaya untuk mengalir kembali kemungkinan bahwa aliran bawah tanah terjadi. Diam di segera untuk mencegah flowback dan memonitor tekanan. Segera hubungi Operasi Inspektur. 8. Setelah anulus stabil, mungkin terus menurun perlahan-lahan karena rembesan. Mulailah mengisi dengan seluruh lumpur daripada mengisi cahaya untuk menghindari underbalancing zona dangkal dengan cahaya mengisi. Mencoba untuk Membangun Sirkulasi 1. Dalam kebanyakan kasus, hal ini diinginkan untuk menarik pipa ke dalam sepatu casing sebelumnya. 2. Setelah menarik ke sepatu, memungkinkan 2-4 jam sebelum mencoba untuk memastikan sirkulasi cairan dalam fraktur telah bocor off, memungkinkan untuk menutup. Memonitor pada tangki perjalanan. 3. Bekerja string bor perlahan dan menggunakan choke pipa tegak jika diperlukan ketika memulai sirkulasi setelah menunggu penutupan fraktur. 4. Beredar pantat naik dari sepatu casing sebelum tersandung kembali ke dalam lubang terbuka. 5. Perjalanan di lubang terbuka perlahan-lahan dan sirkulasi istirahat sering. Pengobatan Seleksi 1. Memanfaatkan Gambar 6-1 untuk memilih pengobatan yang tepat untuk acara kehilangan berat. Prosedur rinci untuk setiap jenis pengobatan yang terkandung dalam EMDC Generic Hilang Mengembalikan Prosedur diposting di Dunia Share. Diposting dokumen ini terus diperbarui dengan pembelajaran dalam praktek operasional dan formulasi pil. Gambar 6-1 Hilang Mengembalikan Pengobatan Panduan Pemilihan (Lihat EMDC Generic Hilang Mengembalikan Prosedur untuk rincian) LCM Pengobatan konvensional untuk Kerugian Parah 1. Jika sumur tidak akan beredar, posisi bit dalam sepatu casing sebelumnya dan mempersiapkan diri untuk operasi bullhead. Jika sumur dapat diedarkan tempat sedikit di bawah zona loss dan mengedarkan LCM seluruhnya dari bit untuk posisi itu di anulus. Tarik sedikit ke dalam sepatu sebelumnya untuk melakukan meremas. 2. Jika pil tersebut akan beredar di luar, mencampur LCM sedikit lebih berat dari lumpur sehingga jatuh kembali untuk mengisi perpindahan pipa ketika menarik DP. Gunakan pelampung yang solid untuk mencegah aliran balik ke dalam BHA. Isi anulus dengan seluruh lumpur. String akan menarik basah. 3. Campur pil dengan menambahkan air, 15ppb Attapulgite, dan LCM. Jika Attapulgite tidak tersedia, gunakan karet 0,5 ppb Xanthan sebagai viscosifier. Setelah pencampuran LCM, menambahkan barit untuk mencapai kepadatan yang diperlukan. 4. Gunakan konsentrasi tertinggi LCM yang dapat dipompa melalui komponen drill string yang. 5. Jangan gunakan bahan yang mengurangi hilangnya dorongan (misalnya kalsium karbonat baik, microfiber, pati dan bentonit). 6. Jangan biarkan cairan untuk kembali dari anulus sambil meremas LCM. Diam di sebelum memulai pemindahan dan memonitor dan merekam tekanan. Setiap perubahan dalam tekanan anulus adalah ukuran langsung dari perubahan stres penutupan fraktur (integritas). 7. Ragu-ragu meremas memaksimalkan stres penutupan fraktur. Menempatkan sekitar ¼ dari LCM ke fraktur dan menutup. Melakukan setidaknya dua meremas dengan keragu-raguan antara masing-masing untuk memungkinkan cairan pembawa LCM bocor off. Ragu untuk 1-4 jam antara setiap pemerasan. Tinggalkan 1020 bbls dari LCM di atas zona kerugian setelah meremas akhir 8. Tahan tekanan antara meremas. Jika arus balik diperbolehkan sebelum cairan pembawa bocor off, lebar fraktur dan stres akan menurun. 9. Memberikan tekanan dan volume data ke insinyur pengeboran untuk merencanakan dan pengarsipan dalam catatan baik. 10. Setelah memegang tekanan pemerasan akhir untuk minimal 4 jam, pendarahan tekanan dan tahap pompa perlahan-lahan. Tahap string bor ke bawah, melanggar sirkulasi pada setiap titik dan pemantauan kembali untuk keuntungan atau kerugian tambahan. Formulasi pil Formulasi pil terus meningkatkan. Pembelajaran yang terus-menerus diperbarui dan dipublikasikan dalam EMDC Generic Hilang Mengembalikan Prosedur, yang diposting di Dunia Share. Hubungi Drilling Operations Technical Support untuk bantuan tambahan dalam desain pil. Pil harus menjadi desain yang paling ekonomis yang berhasil akan membangun integritas. Kemudahan yang integritas dibangun tergantung pada leakoff (permeabilitas) dan peningkatan yang diperlukan dalam fraktur stres (lebar). Jika permeabilitas tinggi atau peningkatan yang diperlukan kecil, konsentrasi yang relatif rendah menengah LCM mungkin efektif (20-40 ppb). Permeabilitas yang sangat rendah dan sangat ditarik pasir konsentrasi lebih dari 100 ppb telah menjadi praktek standar. Konsentrasi LCM yang dapat dipompa terbatas oleh ukuran partikel dan pembatasan dalam drill string yang. Serat media telah dipompa melalui MWD pada 80 ppb. Lebih kecil 400 mikron LCM (misalnya, Steel Seal, SweepWate) telah dipompa melalui MWD pada konsentrasi lebih dari 300 ppb. Konsentrasi yang lebih tinggi dari partikel yang lebih kecil lebih efektif daripada konsentrasi rendah bahan menengah, tetapi juga lebih mahal. Pengalaman lapangan diperlukan untuk menentukan pendekatan yang lebih efektif biaya. Karena tingkat penyebaran untuk rig pengeboran tinggi, preferensi umumnya harus diberikan kepada pendekatan yang lebih mungkin untuk bekerja pada upaya pertama (konsentrasi tinggi dari 400 mikron). Terlepas dari ukuran partikel atau jenis, cara di mana sebuah LCM digunakan lebih penting daripada apa yang digunakan. Kombinasi tinggi desain kehilangan cairan dan ragu-ragu meremas sangat meningkatkan efektivitas dari berbagai bahan. Balon Balon mengacu pada kerugian dan arus balik dari lumpur yang kadang-kadang diamati ketika sirkulasi dimulai dan berhenti. Hal ini disebabkan oleh perluasan fraktur kembali hilang karena ECD terkait dengan sirkulasi, dan kemudian kontraksi fraktur ketika ECD dihapus. Hal ini umumnya terkait dengan lembut, formasi permeabilitas yang rendah. Ini dapat terjadi pada permeabilitas lebih tinggi jika lumpur lowleakoff seperti NAF sedang digunakan. Pencegahan Ballooning Balon dapat dicegah jika berat lumpur berkurang sehingga total ECD kurang dari stres penutupan fraktur dan patah tulang tidak dapat dibuka kembali. Hal ini juga mungkin untuk menghentikan balon dengan memperlakukan fraktur dengan Flexplug (NAF) atau DOB2C (WBM) untuk membangun stres penutupan melebihi ECD. Semen juga telah berhasil digunakan, tetapi menciptakan potensi untuk sidetracking. Ini lebih mungkin berhasil jika fraktur terbatas pada pasir diskrit daripada jika balon yang terjadi di shale a. Kondisi lain untuk Kehilangan Pengembalian 1. Jika sumur tidak akan berdiri penuh, pil LCM akan overdisplaced oleh kepala hidrostatik lumpur bor-berat. Overdisplacement dapat dikontrol dengan memompa cairan cahaya yang cukup di akhir untuk menempatkan kolom pipa bor underbalance stres penutupan fraktur di zona loss. Mengisi cahaya disebut sebagai pipa bor â € œhydrostatic packerâ €. Perhitungan untuk merancang packer hidrostatik disediakan di Generik Hilang Pengembalian Prosedur. 2. Diskusikan pemotongan berat lumpur dengan Operasi Inspektur. Ketika kembali hilang BHP jatuh ke kekuatan menolak di fraktur, yang disebut sebagai stres penutupan fraktur (FCS). Jika anulus tetap stabil setelah mengisi, aliran tidak terjadi dengan BHP sama dengan FCS. Ini adalah diagnostik yang penting yang menunjukkan bahwa berat lumpur dapat dengan aman dipotong untuk sama dengan yang dihitung FCS tanpa memperhatikan aliran. 3. Menurut definisi, rembesan adalah hilangnya seluruh lumpur ke dalam tenggorokan pori formasi (tidak ada propagasi fraktur). Rembesan dihentikan ketika padatan baik pasang tenggorokan pori melalui mana seluruh lumpur melarikan diri. Di lumpur berat badan rendah (<10 ppb), tambahkan saja kalsium karbonat di 5-8 ppb untuk tujuan ini (5 mikron CaCO 3). Namun, penambahan bahan blocking baik dipertanyakan di bobot lumpur tinggi di mana sudah ada volume yang cukup partikel barit ukuran ini untuk memblokir tenggorokan pori. Misalnya, lumpur 13.0 ppg memiliki lebih dari 100 ppb partikel ukuran yang sama dengan baik kalsium karbonat. Juga, jangan menggunakan â € œlost returnsâ € LCM untuk kontrol rembesan. Bahan yang lebih besar seperti serat menengah dan kacang steker tidak sesuai dengan tenggorokan pori dengan baik dan menghasilkan kue yang lebih tebal. Sementara mereka memperlambat kerugian, mereka meningkatkan potensi diferensial mencuat. 4. Pengobatan sistem lumpur seluruh dengan pengembalian yang hilang LCM tidak disarankan. Efek merugikan dari LCM media tentang sifat lumpur dan padatan kontrol signifikan. Pengobatan sistem kadang-kadang dianjurkan bila interval yang sangat panjang kembali hilang diantisipasi yang tidak dapat diobati dengan pil diskrit. Namun, ketika hal ini terjadi secara umum mungkin untuk memotong MW dan bor seluruh selang sebelum melakukan pengobatan tunggal. 5. Jika rembesan dan kontrol filtrat sangat penting, mempertimbangkan penggunaan Bor dan Seal perawatan. Proses ini dijelaskan secara rinci dalam Generic Hilang Mengembalikan Prosedur diposting di Dunia Share. Bor dan Seal digunakan ketika filter cake terkait dengan lanjutan kerugian rembesan dan filtrasi rendah dapat menyebabkan diferensial mencuat, torsi dan drag, atau menempel wireline. 6. LCM konvensional tidak bekerja jika batu adalah kedap air dan cairan pembawa tidak dapat bocor off (serpih). Alternatif yang direkomendasikan untuk batuan kedap yang DOB2C dalam basis air lumpur atau Halliburtonâ € ™ s Flexplug di lumpur dasar minyak. Tidak membutuhkan leakoff agar dapat berfungsi. DOB2C adalah campuran minyak, bentonit, semen dan air yang membentuk bubur yang sangat kental yang akhirnya mengeras. Flexplug adalah produk eksklusif yang membentuk bahan karet pada suhu lubang bawah. Prosedur rinci untuk setiap disediakan dalam Generic Hilang Mengembalikan Prosedur Global Share. 7. Menurut definisi, formasi vugular adalah mereka dengan> 1 / 16A € bukaan. Definisi praktis adalah bahwa mereka formasi dengan leher pori yang tidak dapat diblokir dengan LCM konvensional (misalnya, karbonat, tempat tidur tiram, kerikil). Pengobatan yang dianjurkan untuk menurunkan vugular yang tidak akan menanggapi kasar LCM adalah semen di lumpur dasar minyak, atau DOB2C di lumpur dasar air. Semen juga dapat digunakan di WBM tapi DOB2C memiliki keuntungan dalam bahwa hal itu dapat dibor keluar tanpa memperhatikan sidetracking. DOB2C tidak dapat digunakan dalam NAF. Pengeboran Tanpa Pengembalian Jika semen atau LCM pil gagal untuk mengontrol sirkulasi hilang, dimungkinkan, (dalam jangka waktu pendek) untuk mengebor tanpa pengembalian. Sebuah stek tidur build-up di arah baik dapat menghasilkan pipa terjebak karena untuk membersihkan lubang yang tidak memadai. Pengeboran kering digunakan di banyak daerah operasi sebagai alternatif ketika kembali utama yang hilang yang ditemukan. Cairan pengeboran dipompa pada tingkat dikurangi untuk: Jauhkan bit dilumasi dan sejuk Jauhkan bit dari mencolokkan Membawa stek ke zona loss untuk membantu dalam memasukkan. Perawatan harus diambil ketika pengeboran kering, setiap sendi mungkin harus reamed beberapa kali untuk membersihkan lubang cukup, dan hanya boleh dilakukan dengan persetujuan Manajer Bidang Pengeboran. Penurunan tekanan hidrostatik harus dipertimbangkan ketika pengeboran kering. Pengeboran Melewati Shakers Membawa LCM dalam sistem dan melewati shaker. Ini (segel sementara Anda menelusuri) metode yang baik untuk menjaga dari menggunakan LCM untuk hanya satu sirkulasi sehingga mengurangi biaya, tetapi bisa menambah masalah jika berkepanjangan. Jika shaker yang memungkinkan untuk tetap olehmelewati terlalu lama, kandungan padatan dari sistem lumpur akhirnya akan mencapai titik yang lubang bor tidak dapat mempertahankan peningkatan berat badan atau viskositas. Padatan kecil memiliki kecenderungan untuk menempel, (piggy-back) pada LCM dan diedarkan kembali downhole meningkatkan padatan dan dengan demikian meningkatkan berat lumpur. Tentu saja ada pengecualian untuk kedua hal di atas, ini bukan untuk mengatakan bahwa mereka tidak boleh digunakan jika diperlukan, tetapi bereksperimen dengan salah satu atau kedua dan pengalaman dengan mereka akan meningkatkan kegunaan dan kesuksesan mereka. Plug semen Jika semen murni digunakan sendiri untuk melawan kembali hilang, berat bubur 15,8 ppg telah terbukti menjadi yang paling efektif. Colokan seimbang akan terlihat melalui pipa bor berakhir terbuka diposisikan di zona pencuri dan pipa bor ditarik ke sepatu casing. Jika lubang tidak mengambil lumpur apapun setelah bercak steker semen, sebuah bradenhead meremas lembut dapat diterapkan setelah pipa bor adalah dalam sepatu casing. Gel semen memiliki kepadatan yang lebih rendah mungkin diperlukan dengan zona yang memiliki integritas yang sangat sedikit atau mungkin patah menggunakan semen rapi. Dalam pencampuran jenis semen, bubur berikut ini: 13.2 ppg Massa jenis 100 sxs Kelas G Semen 8% Gel 24,3 bbls Air segar 1/4 ppb Sodium karbonat 1/4 ppb Pedas (The natrium karbonat dan kaustik digunakan untuk menghapus ion kalsium dan magnesium.) Semen seperti Cal-Seal (mengandung gypsum), Thixotropic (mengandung tanah liat dan polimer), dan Gilsonite (batu kapur hancur-up) juga dapat digunakan, meskipun mereka belum terbukti jauh lebih efektif daripada semen biasa dalam berat kejadian kembali hilang . DOB2C DOB2C efektif dalam menghentikan propagasi fraktur baik rendah atau tinggi permeabilitas batuan. Namun, keuntungan utama lebih LCM konvensional adalah permeabilitas rendah. Karena LCM konvensional membutuhkan leakoff dari cairan pembawa, itu tidak jadi € ™ t tampil baik di formasi yang sangat ketat atau shale. DOB2C hanya dapat digunakan di WBM. DOB2C mencapai integritas melalui proses yang berbeda dari LCM konvensional. Karena viskositas yang sangat tinggi, tekanan lubang sumur yang diperlukan untuk memeras itu turun kembali hilang disebabkan fraktur tinggi. Tekanan tinggi pada lubang sumur meningkatkan lebar fraktur dan fraktur stres penutupan (FCS). Tekanan diadakan sementara semen di set DOB2C, dan lebar rekahan dan peningkatan stres penutupan dipertahankan secara permanen. DOB2C sering juga disukai untuk semen dalam menghalangi kerugian vugular karena bahan rendahkekuatan yang tersisa di lubang sumur mudah dibor tanpa risiko sidetracking. Keuntungan lain adalah bahwa karena viskositas tinggi adalah mungkin untuk menerapkan tekanan squeeze tinggi untuk DOB2C yang memastikan bahwa bahan tersebut dipaksa semua bukaan vugular. Semen dapat mengalir bebas ke dalam yang terbesar dari bukaan tanpa mengembangkan tekanan kembali cukup untuk memaksa semen tambahan ke vugs lebih kecil. Meskipun diesel ini paling sering digunakan sebagai cairan dasar untuk membawa bentonit dan semen, minyak rendah toksisitas lain dan lumpur sintetis berbasis telah berhasil digunakan. Flexplug Halliburton FlexPlug adalah campuran dari lateks dan aditif lain yang bercampur dengan lumpur untuk membentuk bahan karet dalam kondisi downhole. Flexplug berhenti pertumbuhan fraktur dengan menghalangi fraktur dekat sumur bor, dan kemudian deformasi untuk mempertahankan penyumbatan sebagai fraktur melebar di bawah tekanan pemerasan. Tekanan ekstrusi bahan cukup tinggi bahwa tekanan lubang sumur tidak menular ke ujung fraktur dan pertumbuhan fraktur (pengembalian hilang) dicegah. Tekanan meremas diadakan sampai set suhu diaktifkan terjadi. Karena FlexPlug tidak mencapai kuat tekan yang signifikan (seperti halnya DOB2C) mungkin ada beberapa kehilangan lebar fraktur dan integritas ketika tekanan squeeze dilepaskan. Namun, pengalaman lapangan menunjukkan bahwa dalam banyak situasi stres berkelanjutan memadai. FlexPlug adalah sistem calon dalam 1) NAF, dan 2) permeabilitas rendah, karena tidak memerlukan leakoff untuk fungsi, seperti halnya LCM konvensional. Hal ini juga akan berfungsi dalam permeabilitas tinggi, LCM namun konvensional lebih murah dan sama efektif saya permeabilitas tinggi. 6,8 NON-AIR OPERATIONS FLUID Petunjuk umum Pertimbangan keamanan: 1. Bahaya tergelincir Kebersihan stres di sekitar rig: Menyediakan bahan penyerap untuk menjaga lantai rig dan catwalk kering. Sebuah vakum lumpur minyak rig, mirip dengan "Max Vac" sistem harus dipasang dengan outlet menghubungkan ke lantai rig, shaker, ruang pompa, BOP dek, dll mengandung lumpur yang terakumulasi selama perjalanan, ketika bekerja pada pompa, atau ketika tumpahan terjadi. Lantai rig nonselip, bertabur tikar putar harus digunakan. Sering menggunakan pembersih uap dianjurkan. 2. Bahaya kebakaran Menyediakan ventilasi yang baik di daerah tertutup, terutama pada lubang bawah geladak lepas pantai. Dua periode dari resiko kebakaran terbesar adalah ketika lumpur mengandung gas formasi, dan ketika lubang pertama pengungsi dan ringan, ujung lebih tidak stabil dari base oil yang hilang ke atmosfer. Api tidak terbuka, rokok, pengelasan, dll harus diizinkan dekat lumpur minyak. Rig harus diperiksa untuk celana pendek listrik dan untuk setiap peralatan atau operasi yang bisa menciptakan bunga api; motor listrik harus ledakan-bukti. Sebuah penekanan busa api sistem pertempuran harus dipertimbangkan untuk ruang pit dan daerah pengocok. 3. Kualitas udara Menyediakan ventilasi yang baik di ruang tertutup, terutama lubang lumpur, shaker dan daerah lumpur pencampuran. Pertukaran udara dari 90 volume kamar per jam biasanya memadai. Telah ruangan yang didedikasikan untuk pengujian lumpur yang tersedia; pengujian laboratorium insinyur lumpur juga harus memiliki ventilasi yang baik karena pelarut yang mudah menguap yang diperlukan untuk memecah emulsi selama banyak tes lumpur minyak. 4. Kontak kulit Semua kontraktor dan EMDCDO karyawan yang mungkin mendapatkan lumpur minyak pada kulit mereka harus dibuat sadar bahwa itu adalah iritasi dan harus dihapus secepat mungkin. Pakaian pelindung, sarung tangan, sepatu karet, dan keselamatan kacamata harus tersedia. Air krim pembersih larut (untuk menghilangkan lumpur dari kulit) dan pelindung krim tangan harus disediakan. Kru harus diberitahu pertimbangan kesehatan dan bagaimana mengatasinya. Ini harus konsisten dengan ExxonMobil OSHA (berlaku untuk operasi non-US East) Program Komunikasi Bahaya dan dikomunikasikan kepada keselamatan kontraktor dan pemimpin Pertolongan Pertama di rig. Melindungi Lingkungan dan Meminimalkan Kerugian Mud 1. A lebih rendah kelly, katup lumpur-saver harus dipasang (yaitu Drilco ini Mud Periksa Valve atau setara). 2. Sebuah ember lumpur dengan saluran ke saluran aliran harus digunakan. Pneumatik Bucket Jenis Mud telah terbukti sangat bermanfaat ketika membuat perjalanan basah atau kembali reaming keluar dari lubang. 3. Kedua OD dan ID bor wiper pipa harus digunakan ketika membuat perjalanan kecuali masalah kontrol juga mencegah penggunaan yang aman dari ID wiper. ID wiper harus memiliki tepat leher ukuran ikan. 4. Sebuah panci menetes harus digunakan untuk rak pipa dan wajan menangkap dipasang dimana tepat (misalnya, di bawah sentrifugal atau pompa transfer). 5. Wilayah kerja langsung di lantai rig harus disisir dengan 3 "datar bar dilas di tepi, atau setara, dan dikeringkan dengan garis aliran atau jebakan pasir dengan pilihan untuk pergi ke bah pembuangan. 6. Instal barang karet tahan minyak di valving; BOPs (elemen annular dan ram blok segel); memompa penyeka; tunggangan layar pengocok; dan selang fleksibel. Pompa sentrifugal harus dipasang dengan sil mekanik. 12. Rig up katup menutup-off untuk tangki pasokan minyak dasar jauh dari lubang. 13. Penghapusan stek dan sistem pembuangan harus dipasang. Stek kotak atau mengantongi sistem harus memenuhi semua persyaratan peraturan. 14. Penambahan agen pembasahan minyak dan pengenceran dengan minyak dasar harus dipertimbangkan ketika membangun OBM siput dalam sistem lumpur kepadatan tinggi. Siput viskositas rendah telah terbukti lebih efektif, terutama ketika menggunakan bor string yang runcing. 15. Sebuah sistem vakum memberikan banyak manfaat. 7. Pastikan air hujan tidak bisa mengkontaminasi lumpur di lubang terbuka. 8. Kosong off semua sumber air di sekitar lubang lumpur. Air merupakan kontaminan serius dalam lumpur minyak. 9. Sebuah pompa, jalur suplai, dan nozzle untuk membersihkan layar pengocok dan pengocok daerah kadang-kadang disediakan, namun perlu diingat bahaya kebakaran menghasilkan semprotan halus minyak, khususnya diesel dengan titik nyala rendah +/- 140-150º F . 10. "No Smoking" tanda-tanda harus ditempatkan di lokasi mencolok di sekitar lubang lumpur. 11. Sebuah tugas berat ledakan bukti listrik uap bersih / pressure washer harus tersedia. 16. Pit lumpur saluran air harus blanked off (penggorengan diinstal) untuk memastikan bahwa lumpur minyak tidak dapat diarahkan ke laut. OIL SPILL TINDAKAN PENCEGAHAN Komunikasi 1. Harus ada prosedur transfer tertulis di rig dan kapal pasokan yang menguraikan berikut (minimal): produk untuk mentransfer urutan operasi transfer transfer rate keterangan mentransfer dan menerima sistem prosedur darurat pemotongan dan pengelasan izin yang dikembalikan dan ditunda sampai transfer OBM atau base oil selesai tumpah prosedur penahanan menonton dan menggeser pengaturan Prosedur Transfer penutupan persyaratan pelaporan tumpahan dan prosedur 2. Pertemuan pra-Transfer harus dilakukan pada rig dan pasokan kapal untuk meninjau prosedur pengalihan dengan semua personil yang terlibat. 3. Sementara mentransfer base oil atau OBM dari kapal suplai untuk rig, anggota kru yang ditunjuk akan ditugaskan untuk mengamati kebocoran dari kapal rig / pasokan ke laut. 4. Komunikasi radio akan tersedia antara ruang rig kontrol, rig pengamat, dan kapal pasokan setiap saat selama operasi. 5. Sebuah izin kerja harus dikeluarkan sebelum mentransfer produk hidrokarbon apapun. Transfer Hose 1. Selang harus dinilai untuk cairan hidrokarbon. 2. Selang desain Peringkat meledak akan menjadi salah satu yang berikut, mana yang lebih besar: a. setidaknya 600 psi, atau b. Pengaturan tekanan katup empat kali pompa perpindahan plus hidrostatik cairan, atau c. empat kali output pompa perpindahan ditambah hidrostatik cairan bila tidak ada katup dipasang. 3. Selang tekanan kerja akan menjadi salah satu berikut, mana yang lebih besar: a. sedikitnya 150 psi, atau b. pelepas tekanan pengaturan katup pompa perpindahan ini ditambah hidrostatik cairan, atau c. empat kali output pompa perpindahan ini ditambah hidrostatik cairan bila tidak ada katup tekanan diinstal. 4. Selang akan diperiksa secara visual untuk air mata, tusukan, bintik lembut, atau tonjolan di selang eksterior, segera sebelum transfer. 5. Ini harus diverifikasi bahwa koneksi kapal rig dan pasokan yang kawin pasangan. 6. Sebuah katup bola akan dipasang pada pasokan akhir kapal dari selang transfer. 7. Akan ada topi penyegelan positif pada ujung selang transfer. 8. Panjang selang harus cukup untuk kapal pasokan untuk pindah ke batas luar garis mooring. 9. Selang harus memadai didukung untuk menghindari ketegangan yang berlebihan pada kopling selang 10. Tidak boleh ada Kinks dalam selang transfer ketika terhubung ke kapal pasokan. 11. Jika selang transfer terputus dari pipa riser, topi penyegelan akan dipasang di ujung riser. PERSIAPAN RIG SEBELUM MENGAMBIL ON NAF MUD 1. Harus ada prosedur rinci, dengan daftar periksa, (lihat Daftar Periksa Kesiapan NAF / OBM di Bagian 6 â € "Lampiran G-II) untuk mempersiapkan rig untuk mengambil lumpur minyak-base. Prosedur harus sangat menekankan tindakan yang harus dilakukan untuk mencegah terjadinya tumpahan sebelum memuat produk dan sementara itu digunakan. 2. Harus ada lumpur skema pipa yang tersedia di fasilitas untuk sistem sirkulasi. Skema ini harus menyoroti lokasi semua katup pembuangan dan setiap potensi sumber tumpahan lainnya. 3. Pertimbangan harus diberikan untuk warna coding semua menangani operasi katup pembuangan dengan mengecat warna khas mereka (misalnya, kuning dan hitam garis-garis). Katup ganda dengan katup gerbang di akhir dan tanda ijin kerja untuk membuka katup. 4. Sebelum menutup setiap katup pembuangan di jebakan pasir atau lubang lumpur, kursi dan katup Oring harus diperiksa secara visual akan memverifikasi bahwa keduanya bersih, bebas dari kotoran atau obstruksi, dan tidak rusak. Setiap katup kemudian harus ditutup sementara visual mengamati tempat duduk katup. Setelah penutupan penuh, katup kemudian harus dikemas dengan pasta gel-air untuk lebih meningkatkan segel. 5. Semua lubang lumpur dan perangkap pasir katup pembuangan harus double-valved, terkunci dalam posisi tertutup, dan diposting dengan tanda, dicetak dalam bahasa Inggris dan bahasa asli, yang menyatakan "izin kerja yang diperlukan untuk mengoperasikan". Dalam beberapa kasus, dua valving telah dicapai dengan memasang katup gerbang hilir katup pembuangan di garis debit umum untuk jebakan pasir dan / atau lubang lumpur. CATATAN: Jika katup gerbang belum diinstal di garis debit, menginstal satu kemungkinan besar akan memerlukan persetujuan oleh badan pengawas seperti ABS dll Metode lain untuk menghalangi OBM dari mendapatkan ke laut adalah dengan menginstal wajan di semua baris. 6. Pertimbangan harus diberikan untuk memasang garis pompa-out antara susunan ganda-valved (yaitu, antara katup pembuangan dan katup gerbang) untuk memungkinkan memompa keluar setiap polutan yang dapat bocor oleh katup pembuangan. 7. Persyaratan izin kerja harus di tempat untuk mengoperasikan katup pembuangan. Sebuah izin kerja juga harus diperlukan sebelum OBM dapat ditransfer ke setiap tangki atau pit yang telah memiliki katup pembuangan dioperasikan, diperbaiki, atau disegel kembali. 8. Transfer OBM tidak boleh dilakukan selama jam kegelapan, selama waktu makan, atau selama perubahan tur kecuali situasi darurat mendikte atau kecuali kebijakan tertulis telah dibentuk untuk secara efektif menangani situasi. 9. Sementara mentransfer OBM dari kapal pasokan ke lubang lumpur, anggota kru yang ditunjuk harus ditugaskan untuk mengamati kebocoran dari bagian bawah rig ke laut. 10. Checklist A harus diselesaikan untuk transfer ke / dari rig hidrokarbon (yaitu, Minyak Pangkalan Lumpur, Diesel, dll) dan harus mencakup pemeriksaan jalur pemuatan, pengujian tekanan pembebanan baris, proteksi kebakaran, sistem komunikasi verbal antara sumber kapal dan tujuan. Checklist telah dimasukkan dalam Bagian 3 â € "Lampiran GI. Frekuensi Sebelum koneksi selang OnLoading untuk setiap siklus perpindahan (Bagian Program Manajemen Keselamatan 5.4.1). 11. Lubang tikus / lubang tikus harus disegel dengan selang diarahkan ke tangki pembuangan. 12. Saluran ruangan pompa harus dialihkan ke tangki pembuangan. 13. Harus ada panci menguras bawah meja putar dengan garis kembali dialihkan ke jalur aliran. 14. Semua lantai saluran rig harus dialihkan ke tangki pembuangan. 15. Tergelincir kemasan sendi dan segel garis aliran harus karet tahan minyak. Menyelinap barel bersama harus diperiksa untuk memastikan permukaan yang halus dan bebas dari sabut. 16. Base oil atau OBM tidak harus disimpan dalam pit lebih lama dari yang sebenarnya diperlukan. Memegang lubang harus dibersihkan pada akhir setiap pekerjaan yang membutuhkan OBM. 17. Periksa semua BOP dan rig katup untuk karet dan tangguh segel kompatibilitas dengan OBM. 18. Sebelum loading Mud Minyak ke tangki lumpur rig, menginstal produk karet baru di semua tekanan rendah katup lumpur dan pompa katup hisap. 19. Persediaan pada produk karet cadang untuk katup dan peralatan pengolahan lumpur. 20. Periksa semua katup dalam sistem sirkulasi sebelum loading Mud Minyak ke dalam tangki rig. 21. Buat genangan air ekstra di sekitar pompa dan rig substruktur untuk minyak perangkap. 22. Menggunakan pompa vakum untuk membersihkan genangan air, dan untuk membersihkan pompa selama perbaikan kerja. 3. Pilot menguji perubahan yang signifikan direncanakan untuk sistem lumpur sebelum membuat perubahan. 23. Pastikan bahwa semua peralatan penanganan lumpur dan pencampuran pompa memiliki panci drip. 4. Ketika pengeboran, ukuran dan merekam pada interval 30 menit berat fluida pengeboran dan saluran viskositas dari garis aliran dan lubang pompa hisap. 24. Tambahkan baris 2 "menguras antara lubang tikus dan tangki perjalanan (atau tangki dengan kemampuan untuk memompa lumpur ke shaker). Dengan saluran ini, lumpur yang mengalir dari kelly dapat disimpan dan dipompa seluruh shaker. 25. Katup ganda semua lini tangki. Jika memungkinkan, gunakan pipa keras (dilas Jadwal 40) untuk jalur daripada selang. 26. Menginstal overflow umum antara tangki penyimpanan untuk mencegah tumpahan selama pemuatan dan mentransfer. NAF DRILLING CAIRAN Pedoman pengobatan 1. Lakukan minimal dua (2) lengkap (In and Out) pemeriksaan cairan pengeboran setiap 24 jam selama operasi pengeboran. 2. Memproses cairan pengeboran kembali dari lubang sumur sehingga sifat fluida cairan pengeboran akan kembali ke dalam sumur bor berada dalam kisaran yang dapat diterima sesuai dengan spesifikasi dalam Drilling Program disetujui. 5. Beritahu Driller dan Mud Logger perubahan direncanakan untuk volume sistem aktif. 6. Gunakan perangkat geser untuk memaksimalkan hasil pengemulsi, agen pembentuk gel, dan untuk mendapatkan emulsi minyak / air yang ketat. 7. Pastikan bahwa gerbong tertutup-off jika tidak digunakan untuk pencampuran. Uji Peralatan Alat uji yang tercantum dalam pameran B dari Bahan Lumpur dan Mud Engineering Services Kontrak harus dipelihara di rig. Lihat kontrak untuk rincian. Item tertentu yang diperlukan untuk menguji lumpur minyak dasar meliputi: 1. Peralatan untuk analisis kimia dari lumpur minyak sebagaimana tercantum dalam API RP 13B-2. 2. Referensi - API RP 13B-2 "Direkomendasikan Praktek - Prosedur Standar Untuk Bidang Pengujian Minyak Berbasis Pengeboran Cairan", Desember Edition 1991 atau yang lebih baru. 3. Mud Balance bertekanan dengan Kalibrasi Kit. 4. Fann 6-speed VG meter. 7. HPHT Filtrasi pada 500 psi diferensial pada suhu yang ditentukan dalam Program Pengeboran. 5. Termostatik dikendalikan cup viskometer. 8. Alkalinitas dan Lime Kelebihan. 6. Thermometer (32-220 ° F). 9. Air Tahap Salinitas. 7. HTHP filter press. 10. Kalsium. 8. 10 atau 20 cc retort lumpur. 11. Kegiatan oleh electrohygrometer. 9. Stabilitas meteran listrik dengan kalibrasi kit. 12. Stabilitas listrik. 10. Electrohygrometer dengan kalibrasi kit. 13. Air, minyak, dan kandungan padatan (retort). Rincian lebih lanjut tentang alat uji diberikan dalam ExxonMobil Oil dan Mud Sintetis Pedoman Pengujian. 14. Minyak Rasio Air. Lumpur Periksa Pedoman Rincian lebih lanjut tentang pemeriksaan lumpur diberikan dalam ExxonMobil Oil dan Mud Sintetis Pedoman Pengujian. Kecuali ditentukan lain dalam Program Pengeboran, yang Pengeboran Cairan Insinyur harus membuat pengukuran berikut untuk setiap "Mud Periksa" pada cairan pengeboran minyak-base. Cairan Pengeboran Laporan Pedoman 1. Lumpur Berat. The Drilling Fluids Engineer untuk memberikan Harian Pengeboran Cairan Laporan kepada harian operasi pengawas yang meliputi: 2. Corong Viskositas. Harian dan kumulatif Penggunaan Drilling Fluid Produk Biaya harian dan kumulatif Drilling Fluid Produk Digunakan Harian dan kumulatif Volume Dilusi 3. Plastik Viskositas (PV) pada 120  ° F. 4. Yield Titik (YP) pada 120  ° F. 5. Gel Kekuatan pada 120  ° F. 6. API Filtrasi pada 100 psi diferensial. Harian dan kumulatif Pengeboran Volume Cairan yang Hilang (Perkiraan) Lebih Padat kontrol peralatan, Sirkulasi Hilang, Atau Tidak Dicatat Untuk di The Volume Pengenceran Rekam kumulatif Drilling Cek Cairan Dicap sebagai Time dan Kedalaman Bit Awak yang bekerja dengan lumpur atau lumpur pompa harus mengenakan kimiatahan (misalnya Neoprene) sarung tangan. Kacamata keselamatan dengan perisai samping. Topi keras. Lengkap jas hujan jas atau apron kimia. Ekstra APD harus disimpan dalam rumah anjing untuk personil lainnya yang sering dipanggil untuk bekerja di lantai bor. Sepatu karet. Handuk kertas dispenser, tangan bersih, dispenser krim penghalang, dan mencuci air di daerah pit lumpur. "ZEE" krim kulit telah bekerja dengan baik dalam mencegah iritasi kulit. Alat Pelindung Diri dan Fasilitas 1. Memastikan bahwa pekerja melaporkan untuk bekerja setiap tur dalam pakaian kerja yang bersih dan bahwa setiap pekerja memiliki pakaian kerja ekstra bersih di lokasi. Secara umum, pakaian direndam minyak harus diubah sesegera mungkin. 2. Menyediakan sarana yang memadai bersih-bersih untuk pekerja yang memiliki kontak kulit dengan lumpur minyak. 3. Menyediakan pembersih tangan dan krim penghalang untuk menghilangkan minyak dari kulit dan melindungi kulit. Barang-barang ini harus disimpan di semua stasiun cuci mata. 4. Peralatan pelindung berikut pribadi (PPE) harus tersedia untuk digunakan oleh karyawan yang bekerja dengan lumpur minyak: Sarung tangan kerja (ganti ketika jenuh minyak). Sarung tangan tahan kimia yang dikenakan di bawah sarung tangan kerja dapat digunakan untuk meminimalkan kontak kulit. (Lateks-jenis sarung tangan bedah bekerja dengan baik) Pelatihan Industri Hygiene-Terkait 1. Sebelum memulai pekerjaan lumpur minyak, program pelatihan untuk personil rig harus dilakukan untuk menjelaskan bahaya kesehatan yang berhubungan dengan paparan lumpur minyak. 2. Kontraktor pengeboran harus memastikan bahwa pekerja yang akrab dengan MSDS (data keselamatan Bahan Lembar) untuk minyak dasar dan semua aditif lumpur minyak. 3. Program pelatihan harus menjelaskan penggunaan yang tepat dari APD. Persyaratan mengenai penggunaan APD harus dinyatakan dengan jelas sebelum menggunakan lumpur minyak. a. Gunakan volume yang diperlukan untuk mencapai ketinggian spacer dari 200-500 ft di anulus. Gunakan ketinggian yang lebih besar untuk lubang terbuka, ketinggian yang lebih rendah di dalam casing. Pemindahan Mud minyak Perpindahan sukses dari Air-Base Mud oleh Mud Oil-Base bisa sulit. Kecuali tercakup dalam Program Pengeboran, Prosedur Tambahan yang menggambarkan prosedur yang diperlukan akan ditulis oleh Drilling Insinyur. Prosedur contoh diselesaikan menggunakan EMDC Timur AS Pengeboran Kelompok Inti OBM Pemindahan Prosedur dapat ditemukan di Bagian 6 â € "Lampiran SI. 1. Gunakan spacer. Pertimbangkan untuk menggunakan pewarna. a. Di mana tekanan diferensial memungkinkan, spacer sederhana seperti minyak dasar murni sering bekerja terbaik. b. Jika spacer tertimbang diperlukan, lumpur minyak tanpa kalsium klorida yang terbaik. Dalam operasi penyemenan spacer yang tidak harus mengandung kalsium klorida atau pengaturan lampu kilat bisa terjadi. 2. Spacer Volume rekomendasi: b. BAIK PENGENDALIAN PERHATIAN: Hitung efek spacer pada tekanan hidrostatik. 3. Cairan menggusur harus lebih berat dari cairan yang akan mengungsi. Kepadatan dari kedua cairan harus diperiksa pada suhu yang sama. 4. Kondisi air lumpur oleh deflocculating ke titik hasil yang lebih rendah dan kekuatan gel. Beredar pantatup pada tingkat pompa tinggi segera sebelum memulai perpindahan. Prosedur perpindahan Hal ini sangat penting untuk merencanakan perpindahan dengan hati-hati. Memiliki tipis, baru beredar dasar air lumpur di lubang sebelum perpindahan. 1. Beredar dan tipis lumpur dasar air secara menyeluruh sebelum menutup untuk mengganti lumpur air di lubang dengan lumpur minyak. Pada beberapa rig, kembali dapat dialihkan ke palung logam (lumpur selokan) dari shaker ke pit hisap; jika demikian, sirkulasi lumpur air dapat terus sedangkan lubang yang tersisa dikeringkan lumpur air dan dibersihkan. 2. Membersihkan lubang setelah menghapus lumpur air. 3. Masukan 40-60 layar mesh pada shaker serpih untuk menangani lumpur minyak tebal. Memiliki layar yang lebih halus siap untuk instalasi setelah lumpur minyak telah beredar di sekitar. 4. Masukan spacer di slugging pit dan mengisi lubang lain dengan lumpur minyak. 10. Beredar di sekitar sekali, dan setelah menentukan bahwa lumpur air dan spacer telah datang kembali mengalihkan kembali atas shaker dan mulai perawatan lumpur minyak perbaikan dengan pengemulsi dan agen pembasahan. Perawatan khas berada di kisaran 0,5-1,0 ppb untuk setiap aditif selama sirkulasi berikutnya. 5. Nol pompa Stroke kontra setelah spacer dipompa dan sebelum pertama lumpur minyak yang baik dimulai downhole. Rekam jumlah stroke yang ketika lumpur air dan lumpur air antarmuka lumpur / minyak telah mengungsi dan kembali lumpur minyak yang cukup baik yang terlihat. Mulai shaker, lumpur langsung ke lubang. 11. Menjalankan pemeriksaan untuk sifat aliran, ES, dan HTHP sesegera mungkin setelah lumpur yang baik telah datang kembali (perawatan perbaikan harus sudah telah dimulai) dan menilai kondisi lumpur. Lanjutkan mengobati seperlunya, dan jangan berhenti beredar sampai sifat lumpur diterima tercapai. 6. Putar dan membalas pipa dur ing perpindahan. 12. Mengganti pengocok layar untuk mesh terkecil yang mungkin segera setelah shaker bisa mengatasinya. 7. Memompa pada tingkat yang cepat selama perpindahan. Tingkat mengurangi jika tekanan meningkat. Jangan berhenti memompa setelah perpindahan telah dimulai kecuali benar-benar diperlukan. 8. Membuang lumpur air atau pindah ke penyimpanan sementara memompa. 9. Menangkap spacer / air lumpur / antarmuka lumpur minyak dan buang sesuai kebutuhan disetujui. 13. Gunakan pompa hitungan langkah untuk memperkirakan tingkat penyaluran oleh lumpur minyak. Ini akan membantu menentukan berapa banyak air lumpur yang tersisa di dalam lubang. 14. Dimulai pengeboran ketika lumpur minyak pameran reologi stabil, stabilitas listrik, dan menunjukkan sedikit atau tidak ada air dalam filtrat HTHP. Pengujian dan penyejuk Selama Pemindahan 1. Tes untuk air lumpur / spacer antarmuka setiap 15-20 menit sampai 75% dari perpindahan telah dipompa, kemudian menguji terus menerus. 2. Rekor jumlah Stroke pompa ketika kembali lumpur minyak yang cukup baik terlihat pada shaker. Gunakan count Stroke untuk menghitung berapa banyak air lumpur yang tersisa di dalam lubang. Jika jumlah yang signifikan dari lumpur air-base yang tersisa di dalam lubang, itu mungkin disebabkan oleh lubang terbuka sangat washedout. Lumpur air dapat berdarah ke dalam lumpur minyak selama beberapa hari setelah perpindahan; pencampuran ini dapat melemahkan emulsi lumpur minyak. 3. PENANGANAN KONTAMINASI: Setelah kembali lumpur minyak baik diarahkan selama shaker, emulsifier dan pembasah dapat ditambahkan pada shaker, di hisap, atau di kedua tempat. Terus beredar dan kondisi lumpur selama beberapa sirkulasi dan sifat aliran tes, dan listrik Stabilitas. Periksa Suhu Tinggi / High Pressure kehilangan cairan untuk ada atau tidak adanya air; pengeboran tidak harus dimulai sampai HTHP adalah <1.0 cc atau air gratis. Proses menggusur dan kemudian pendingin dapat mengambil 24 jam atau lebih dan tidak boleh terburu-buru. Pastikan lumpur diperlakukan-sebelum baik pengeboran depan. 4. FLUIDA IDENTIFIKASI: Untuk membantu mengidentifikasi ketika lumpur minyak yang baik akan datang kembali, run Dispersi dan Listrik Stabilitas Tes sebagai berikut: Dispersibilitas Uji 1. Isi satu gelas bersih atau wadah plastik dengan minyak dasar, yang lainnya dengan air. 2. Tempatkan beberapa tetes cairan kembali di masingmasing dan mengamati tanda-tanda dispersibility: Jika cairan menyebar dalam air dan tidak dalam minyak, itu adalah lumpur air. Jika cairan menyebar dalam minyak dan tidak di dalam air, itu adalah lumpur minyak. Jika minyak bentuk licin di permukaan air atau fraksi tidak bercampur, itu adalah campuran air dan minyak. Listrik Uji Stabilitas 1. Memeriksa secara berkala ES pada sampel cairan kembali. 2. Jika ada lumpur air yang cukup dalam cairan, ES akan menjadi nol (sangat konduktif). 3. Ketika jumlah lumpur air menurun menjadi sekitar 20-25% dalam lumpur minyak, meteran ES akan mulai memberikan pembacaan yang rendah (100200 volt). Pada saat ini, memperlambat pompa dan mempersiapkan untuk menempatkan lumpur selama shaker. A. Persiapan Rig 1. Semua perbaikan pengelasan pada pompa, lubang, dan lantai rig harus diselesaikan sebelum mengambil Mud Oil. 2. Perubahan putar pengepakan dan kosong dari semua saluran air ke pit. Menjaga di situs pasokan drum pembuangan 55-galon untuk limbah berminyak. 2. Memanfaatkan jenis sekrup conveyor (s) atau unit vakum untuk stek mengumpulkan, pengumpulan dan debit dari Unit Mixing untuk area penyimpanan. B. Basis Penyimpanan Minyak MINYAK DASAR PEMANFAATAN DAFTAR 1. Banteng plug berakhir garis tangki bila tidak digunakan. 2. Menjaga base oil yang memadai di lokasi atau perahu. Gunakan checklist OBM dalam Program Manajemen Keselamatan 1. EPR - Mud Minyak manual 3. Menggunakan pompa mencuci-down udara didorong untuk layar mencuci botol dan peralatan lainnya. Pastikan bahwa pompa hisap dilindungi dengan layar. 2. EUSA - Lab Mud Pedoman Pengujian Mud Manual / Minyak C. Seluruh Storage Mud 4. NODO Operasi & Buletin Teknis No. # 94-21 / Bagaimana membangun high-density OBM siput. 1. Mempertahankan minimal 500 lumpur tertimbang bbl di tank di lokasi. 3. NODO - OBM Praktek operasi manual 5. Pengeboran Program Manajemen Keselamatan 2. Tangki penyimpanan lumpur seluruh harus terus gelisah jika memungkinkan. LOADING MUD MINYAK DASAR ATAU BASE OIL DARI PENAWARAN KAPAL UNTUK RIG 3. Memantau kekuatan gel pada lumpur disimpan; kekuatan gel yang lebih tinggi diperlukan untuk mencegah barit menetap. Tanggung jawab D. solidifikasi 1. Memanfaatkan Pengeringan Shaker untuk mendapatkan potongan bor sekering mungkin dan untuk mendaur ulang sebanyak base oil mungkin (misalnya Sweco LM-3 Shaker, Derrick Hi-G Shaker, dll). 1. OIM atau Barge Insinyur / Kapten bertanggung jawab operasi. 2. Alat pendorong adalah untuk bertanggung jawab untuk persiapan rig terkait. Asisten Driller dan Derrick manusia adalah untuk membantu Tool pendorong. Persiapan 1. OIM atau Barge Eng. / Kapten untuk pertemuan pralubang transfer dengan anggota kru yang terlibat. 2. Periksa secara visual Transfer selang untuk kerusakan segera sebelum mentransfer. Transfer selang harus dinilai untuk cairan hidrokarbon dan memiliki tekanan kerja yang aman dari 150 psi. Pastikan tekanan pasokan kapal memompa tidak akan melebihi tekanan kerja yang aman dari selang. 3. Transfer selang memiliki katup pada akhirnya, di sisi supply vessel, dan telah diperiksa untuk kerusakan. 4. Semua outlet lain pada garis beban yang ditutup dengan flens buta atau katup yang benar ditutup dan digembok (yaitu, daftar katup tertentu). 5. Katup pada outlet sampel di setiap stasiun pemuatan ditutup. 6. Katup pada semua berlawanan stasiun sisi memuat ditutup dan diamankan (yaitu, digembok). 7. Alat pendorong dan ExxonMobil pengeboran pengawas akan memverifikasi bahwa semua persiapan yang tercantum di sini telah dibuat sebelum memulai transfer. Juga, Alat pendorong dan ExxonMobil pengeboran pengawas akan memastikan bahwa "checklist" sepenuhnya selesai sebelum memulai operasi. Salinan selesai "checklist" akan diberikan kepada ExxonMobil pengeboran pengawas. 8. Transfer selang akan diperiksa secara visual untuk kerusakan sebelum mentransfer. 9. Lubang lumpur, lubang pengocok dan kotak pengocok telah dikosongkan dan dibersihkan per persetujuan insinyur lumpur. Semua katup pembuangan telah ditutup, dijamin, dan menandai. 10. Lumpur katup utama pada baris debit laut ditutup dan digembok (sebutkan katup). 11. Tangki perjalanan yang akan dibersihkan. Katup pembuangan tangki perjalanan yang akan ditutup dan diamankan. 12. Laut katup dari lantai rig menguras ditutup dan diamankan. Lantai rig saluran berbaris untuk menguras tangki. 13. Saluran air di ruang pompa, ruang perawatan lumpur, ruang shaker, daerah pencampuran lumpur, dan ruang semen disegel. 14. Semua katup unit semen ditutup. Katup pembuangan dari unit semen perpindahan dan pencampuran tangki ditutup dan digembok. 15. Katup isolasi di lumpur ruang pit antara garis OBM dan garis air bor ditutup dan diamankan. 16. Katup utama pada air laut jalur suplai dan semua katup air di lubang lumpur, ruang pompa, dan shaker serpih ditutup dan menandai. 17. Main jalur suplai diesel katup telah ditutup, digembok dan menandai. 18. Transfer pompa yang tersedia untuk digunakan dalam hal tumpahan di dek atau untuk mentransfer di pit. 33. Personil tambahan pada rig untuk memotong penanganan yang diperlukan. 34. Drillpipe dalam dan luar wiper berada di rig. 19. DeSander dan pakan desilter katup baris berjenis ditutup dan diamankan. Komunikasi 20. Katup pada possum perut debit ditutup dan diamankan. 1. Semua rig dan kapal pasokan personel yang terlibat untuk memiliki radio VHF. 21. Sistem pembilasan air di shaker layar ditutup dan diamankan. 2. Salah satu anggota awak rig yang ditunjuk untuk ditugaskan sebagai pengintai selama transfer untuk mengamati kebocoran dari rig atau pasokan kapal dan untuk memantau perpindahan selang. 22. Stek laut gerbang di shale pengocok pemotongan melalui disegel. 23. Stek mentransfer augers operasional. 24. Shaker memotong jalur ke lubang lumpur ditutup. 25. Gumbo garis kotak Bypass ditutup. 3. Mentransfer lumpur dasar minyak harus dilakukan di siang hari saja, kecuali operasi ExxonMobil pengawas menyetujui transfer malam. Langkahlangkah perencanaan tambahan akan diperlukan untuk mengatasi masalah yang bisa dihadapi dengan transfer selama kegelapan. 27. Retakan di lantai rig dimeteraikan dengan "Pembangun Foam". 4. OIM, alat pendorong, ExxonMobil pengeboran pengawas, insinyur lumpur, lumpur logger dan kontrol operator ruang akan diinformasikan sebelum transfer OBM. 28. Tersedak garis debit berjenis ditutup dan menandai. Mentransfer 29. Kantong sampah besar yang rig jika diperlukan. 30. Kotak pemotongan yang di rig. 1. OIM atau Barge Eng. / Kapten dan orang derek akan berlipat ganda cek line up dari loading stasiun ke lubang lumpur. 31. Absol adalah di rig. 2. Izin kerja akan selesai sebelum transfer. 26. Gumbo tampilan kotak menetas disegel. 32. Sistem vakum beroperasi. 2.a Cutting dan izin pengelasan harus kembali dan ditunda sampai transfer OBM atau base oil selesai. 3. Hubungkan Transfer selang untuk memasok kapal. OIM atau Barge Eng / Kapten. Mengkonfirmasi dengan kapten kapal pasokan yang mentransfer sambungan selang flange adalah pasangan yang tepat untuk flens di kapal pasokan. 4. Transfer sekarang siap untuk memulai. The derek pria akan memantau volume yang dipompa dan berubah dari yang diperlukan, membuka katup pada lubang berikutnya untuk diisi sebelum menutup katup pada lubang hanya diisi. Derrick manusia dan lumpur penebang akan memantau volume yang diterima secara berkala di seluruh operasi dan setelah selesai transfer cairan. 5. Jika ada perbedaan antara volume dipompa dan volume menerima harus terjadi, menghentikan transfer segera. Alat pendorong dan ExxonMobil pengeboran pengawas harus diberitahu tentang perbedaan dan penyelidikan akan dilakukan untuk menemukan alasan untuk penyimpangan. Solusi yang dapat diterima untuk masalah ini akan dilaksanakan sebelum melanjutkan operasi. 6. Insinyur lumpur akan melakukan pemeriksaan kualitas cairan ditransfer secara periodik selama operasi. 7. Ketika mentransfer selesai, menghentikan pompa pemindahan dan menutup katup loading baris di kamar pit. Menutup katup di stasiun pemuatan, selang pengalihan kemudian harus berdarah untuk kapal pasokan. Katup di ujung selang transfer di kapal pasokan harus ditutup sebelum melepaskan selang dari flens di kapal. 8. Semua garis campuran, garis hisap dan garis transfer ke unit semen dan tangki perjalanan harus memerah. Semua lumpur air / minyak antarmuka lumpur dari operasi pembilasan harus ditangkap dan dipompa ke tangki air kotor. Setelah pembilasan, semua katup harus ditutup. Menggusur AIR LUMPUR DASAR DARI sumur bor DENGAN MINYAK DASAR LUMPUR Tanggung jawab 1. Alat pendorong dan ExxonMobil Drilling Supervisor untuk bertanggung jawab atas operasi menggusur. Persiapan 1. Alat pendorong dan Mud Insinyur akan mengadakan pertemuan pra perpindahan dengan semua anggota kru yang terlibat. 2. Pastikan koneksi adaptor flowline diperketat. 3. Shaker memotong jalur ke lubang lumpur ditutup. 4. Shaker memotong garis ke dalam kotak gumbo diperiksa, ditutup, tagged dan dijamin. 5. Gumbo tampilan kotak menetas ditutup dan diperiksa. 18. Stek laut gerbang di shale stek pengocok melalui disegel. 6. Katup dump di degasser diperiksa, ditutup, tagged dan dijamin. 19. Menetas pada stek auger di posisi yang benar. 20. Stek mentransfer augers operasional. 7. Tangki perjalanan telah dikosongkan dan dibersihkan. 8. Perjalanan katup tangki dump diperiksa, ditutup, tagged dan digembok. 21. Saluran air di shaker, karung, semen dan kamar perawatan disegel. 22. Katup berjenis deSander dan feed line desilter diperiksa, ditutup, tagged dan dijamin. 9. Lantai rig saluran berbaris ke tangki air kotor. 10. Katup pada jalur laut dari lantai rig / tangki slop harus diperiksa, ditutup, tagged dan digembok. 23. Tabung meluap dan satuan semen garis tangki perpindahan saluran katup diperiksa, ditutup, tagged dan dijamin. 11. Shaker pit dan kotak pengocok dibersihkan untuk memenuhi persetujuan insinyur lumpur. 24. Retak / bukaan di lantai rig dimeteraikan dengan "busa Building". 12. Katup lubang pembuangan Shaker harus diperiksa, ditutup, tagged dan digembok. 25. Tersedak berjenis katup garis debit ditutup dan menandai. 13. Katup pada pelepasan possum perut diperiksa, ditutup, tagged dan dijamin. 26. Air dioperasikan ember lumpur di rig dan operasional. 14. Shaker debit berbaris untuk memotong jebakan pasir. 27. Pipa bor dalam / luar wiper adalah di rig. 15. Semua saluran air di mana OBM bisa habis akan dipasang atau diarahkan ke tangki air kotor. 28. Tas besar berada di rig jika diperlukan. 29. Sistem vakum pada rig dan operasional. 16. Transfer Air pompa yang tersedia di rig. 17. Katup sistem pembilasan air untuk layar pengocok akan ditutup dan menandai. 30. Personil tambahan yang tersedia untuk menangani stek auger / stek kotak. 31. Rencana telah dikembangkan untuk menangani lumpur dasar air yang dipindahkan dari sumur bor. 32. Rencana di tempat untuk menangkap lumpur dasar air antarmuka / OBM. 1. Alat pendorong dan manusia derek akan mengkonfirmasi satu sama lain bahwa semua katup berbaris dengan benar sebelum memulai operasi perpindahan. 34. Kedua insinyur lumpur berada di tur. 2. Jika ada kebocoran atau tumpahan terdeteksi, menghentikan operasi perpindahan segera. Menerapkan langkah-langkah korektif dan memastikan semua personil yang terlibat akan diberitahu sebelum restart operasi perpindahan 35. Jika operasi perpindahan harus dilakukan selama kegelapan, memastikan pencahayaan yang cukup tersedia. 3. Para insinyur lumpur berkala akan memeriksa ES dari lumpur kembali untuk menentukan whento menempatkan arus balik melintasi shaker shale. Komunikasi 4. Setelah perpindahan, semua lini campuran, penyedotan garis dan garis transfer akan memerah dan antarmuka apapun akan dibuang dalam tangki air kotor. 33. Bahan kimia onboard untuk mengobati OBM setelah perpindahan selesai. 1. Semua personel yang terlibat dalam perpindahan akan memiliki akses radio VHF. 2. Alat pendorong, ExxonMobil pengeboran pengawas, insinyur lumpur dan lumpur penebang akan terlibat dalam operasi perpindahan. 6,9 RIG-SITUS DIELEKTRIK PENGUKURAN KONSTAN Pendekatan umum 3. Salah satu anggota awak rig yang ditunjuk akan ditugaskan sebagai pengintai selama operasi perpindahan untuk mengamati kebocoran. 4. OIM, alat pendorong, ExxonMobil pengeboran pengawas, insinyur lumpur, lumpur logger dan kontrol operator ruang akan diinformasikan sebelum perpindahan operasi. Menggusur Secara umum, model stabilitas lubang sumur yang dibangun berdasarkan analisis stek (untuk menentukan area permukaan) dari beberapa mengimbangi sumur. Luas permukaan kemudian stratigrafi berkorelasi, konsistensi data dievaluasi, dan profil luas permukaan yang dihasilkan. Untuk menerapkan profil luas permukaan offset untuk calon baik, correlativity dari stratigrafi harus ditentukan (yaitu, Bagaimana sumur diimbangi mengikat untuk prospek baik?). Biasanya, penyesuaian sederhana untuk puncak stratigrafi dibuat untuk menghubungkan daerah permukaan. Kadang-kadang, kedalaman daerah permukaan offset "ditarik" atau "dikompresi" untuk mengakomodasi diantisipasi selang penebalan atau menipis. Profil luas permukaan ini digunakan sebagai data masukan untuk model stabilitas lubang sumur yang digunakan untuk perencanaan dengan baik. Stek daerah permukaan dapat diukur di rig-situs untuk memverifikasi atau memodifikasi model stabilitas lubang sumur sementara pengeboran. Kualitatif, kita dapat menentukan apakah sumur bor harus pengeboran lebih atau kurang stabil daripada model juga tergantung pada perbandingan nyata dibandingkan daerah permukaan diasumsikan. Kuantitatif, daerah permukaan nyata dapat digunakan untuk merevisi jadwal berat Model dan lumpur. umumnya item jalur kritis untuk analisis off-site. Sebuah biaya analisis khas adalah $ 15-20 per sampel. Independen opsi pengukuran, sekitar 30-50 sampel dapat dianalisis setiap hari. Frekuensi sampel normal adalah sekitar sekali setiap 30 kaki. Keterbatasan Tujuan dari pengukuran apapun untuk mengaktifkan beberapa respon, jika perlu. Dalam beberapa kasus, pilihan untuk bertindak atas pengukuran luas permukaan rig-situs mungkin terbatas. Sumur tertentu menghadapi situasi yang sulit di mana gradien runtuhnya pendekatan, atau bahkan melintasi gradien fraktur. Keadaan seperti itu dapat disebabkan oleh tekanan tektonik abnormal tinggi atau biasa anisotropic, atau ketika kekuatan batuan sangat lemah dibandingkan dengan bahkan tekanan normal. Karena persyaratan yang bertentangan untuk menstabilkan lubang sumur (berat lumpur yang lebih tinggi) dan menghindari pengembalian hilang (berat lumpur rendah) satu-satunya pilihan adalah untuk mengelola gejala ketidakstabilan saat mendekati gradien fraktur sedekat praktis. Pertemuan terakhir dengan situasi ini (lihat contoh di bawah) telah memotivasi penelitian URC saat ini pada peningkatan prediksi leakoff dan mitigasi kembali hilang. Sementara EPR korelasi kekuatan shale tergabung dalam perangkat lunak WBSD akurat untuk sebagian besar serpih, perilaku kekuatan serpih luas permukaan yang lebih rendah tertentu telah diamati untuk berada di luar database dari mana korelasi disampaikan. Serpih di Malaysia dan Laut Irlandia, Pengukuran Pilihan Real-time pengukuran luas permukaan dapat dibuat dengan portabel, di tempat DCM kit. Keputusan apakah untuk memobilisasi di tempat pengukuran luas permukaan harus mempertimbangkan hal berikut: DCM memerlukan terlatih, berdedikasi lumpur logger. Sebuah kit DCM biaya sekitar $ 16.000, ditambah biaya tambahan untuk persediaan habis Atau, stek telah dikirim dari wellsite ke EMURCo di Houston atau Î £ ª Labs di Aberdeen untuk analisis. Waktu transportasi (untuk Houston atau Aberdeen) misalnya, daerah permukaan rekor 100-200 m² / gm sementara menunjukkan sifat mekanik konsisten dengan 400-500 m² / gm. Kerja laboratorium sedang berlangsung untuk menyelesaikan pengecualian tersebut ke database ini. Aplikasi Berikut ini ikhtisar bagaimana real-time (on-site) pengukuran luas permukaan telah atau dapat digunakan untuk mempengaruhi operasi pengeboran: Elli: berat lumpur yang sebenarnya digunakan mengambil keuntungan dari 1 ppg "konservatisme" (berdasarkan pengalaman Laut Utara) di prediksi berat lumpur dari model stabilitas lubang sumur. Pengukuran luas permukaan realtime ditunjukkan shale sedikit lebih kuat dari yang diasumsikan, yang diperkuat kepercayaan berat lumpur yang dipilih. Bolivia: The pre-drill Model stabilitas lubang sumur dibatasi untuk data dari jauh lubang nearsurface inti untuk braket daerah permukaan diharapkan. Realtime pengukuran luas permukaan yang digunakan untuk kualitatif memeriksa sensitivitas serpih dan memonitor efek inhibisi glikol. 6.10 DRILLING PEDOMAN SISTEM FLUIDA Di tempat pengukuran luas permukaan dianjurkan jika: Data Offset jarang. Korelasi dengan sumur diimbangi dicurigai, dan atau Pemodelan awal menunjukkan fleksibilitas operasional untuk bertindak pada model stabilitas lubang sumur prediksi (yaitu, berat lumpur dan / atau kimia dapat diubah tanpa kehilangan keuntungan). Di tempat pengukuran luas permukaan menyediakan data yang berguna, tapi mungkin tidak mempengaruhi keputusan operasional saat: Berat lumpur dibatasi oleh gradien leakoff. Kimia lumpur dibatasi oleh persyaratan penghambatan hidrat, dan / atau Kekuatan Shale tidak konsisten dengan korelasi data base. Jika kondisi terakhir diduga sebelumnya, off-duduk pengukuran luas permukaan mungkin lebih nyaman dan hemat biaya karena data akan digunakan terutama untuk: Update / mengkalibrasi model stabilitas untuk sumur masa depan, dan / atau Melakukan analisis post-mortem untuk masalah lubang di dalam sumur saat ini. Pastikan ESD karya BAGIAN 6 - GI LAMPIRAN Sebelum transfer cairan, semua Rig dan Boat personil akan bertemu dan meninjau JSA sesuai yang, MSDS Sheets. Prosedur transfer cairan, dan membangun komunikasi dua arah. Setelah selesai pertemuan pengalihan pra-pekerjaan, semua orang yang terlibat dalam transfer akan menandatangani dokumen ini menunjukkan prosedur ini telah ditinjau. Individu ditugaskan untuk stasiun ESD selama transfer C. Cari dan Fire Fighting Equipment Periksa Tinjau Fire Fighting Prosedur Memastikan bahwa Peralatan Pemadam Kebakaran adalah dalam rangka bekerja dan dekat di tangan I. TRANSFER DARI PERUSAHAAN MUD KE BOAT D. Periksa Menerima Kapal A. Sebelum Memuat Boat Periksa Semua Selang, kopling, dan Garis Mencari celah dan selang berjumbai Menetas terbuka dan memeriksa untuk kebersihan (jika cuaca memungkinkan) Memastikan koneksi yang ketat Pastikan peralatan polusi di tempat (misalnya, 5-gal ember, panci tetes / menangkap) Individu ditugaskan untuk memantau perpindahan (memiliki radio tersedia) Absorben bantalan yang tersedia di lokasi B. Lokasi dan Ulasan ESD Operasi dan Prosedur Meninjau dan merumuskan (jika perlu) Prosedur ESD Catatan jika tangki diisolasi dari lautdada dengan wajan atau kosong Menginformasikan Kapten dan kru bahwa cairan tersebut tidak akan digulung atau dipindahkan selama transit E. Memuat Boat Pastikan semua personil di stasiun mereka ditugaskan (tidak meninggalkan kecuali lega) Memonitor kebocoran ketika transfer dimulai - menutup dan kembali pasangan jika perlu memverifikasi volume untuk ditransfer Individu ditugaskan untuk memantau perpindahan Sebelum memompa, sampel akan diambil di situs penyimpananAbsorben Mud bantalan yang tersedia di lokasi Perusahaan Meninjau dan akrab dengan prosedur tumpahan. Menangkap sampel komposit di perahu saat mentransfer pertama 10%, menengah, dan terakhir 10% dari produk dan membagi sampel antara perahu dan perwakilan Exxon B. Lokasi dan Ulasan ESD Operasi dan Prosedur Verifikasi volume transfer di selesai Meninjau dan merumuskan (jika perlu) prosedur ESD II. MEMINDAHKAN CAIRAN Tekankan bahwa cairan tidak akan meluncur, pindah dari ditransfer sementara pengangkutan ke lokasi Jika cuaca memungkinkan, secara berkala terdengar tank untuk memverifikasi tidak ada perubahan AKU AKU AKU. TRANSFER DARI KAPAL KE LOKASI (DRILLING RIG) A. Tahan Pre-Job Pertemuan Keselamatan dan Ulasan JSA, MSDS, dan Kebijakan transfer Perahu aman untuk menerima Rig Pastikan ESD karya Individu ditugaskan untuk stasiun ESD selama transfer C. Cari dan Fire Fighting Equipment Periksa Tinjau Fire Fighting Prosedur Pastikan Peralatan Pemadam Kebakaran adalah dalam rangka bekerja dan dekat di tangan D. Menerima Tank Mencari celah dan selang berjumbai Pastikan tangki bersih dan disegel Memastikan koneksi yang ketat Verifikasi volume untuk ditransfer Pastikan peralatan polusi di tempat (misalnya, 5-gal ember, panci E. Mentransfer Lumpur untuk Rig tetes / menangkap) Menangkap sampel lumpur pada awal transfer untuk memverifikasi komposisi Pastikan peralatan polusi di tempat (misalnya, 5-gal ember, panci tetes / menangkap) Pada penyelesaian transfer menutup katup di rig untuk mencegah menyedot Tiriskan selang transfer kembali ke perahu Individu ditugaskan untuk memantau perpindahan (memiliki radio tersedia) Signature / Perusahaan / Tanggal _________________ Signature / Perusahaan / Tanggal ______________________ Signature / Perusahaan / Tanggal _________________ Signature / Perusahaan / Tanggal ______________________ BAGIAN 6 - LAMPIRAN I (lanjutan) Sebelum transfer cairan, semua Rig dan Boat personil akan bertemu dan meninjau JSA sesuai yang, MSDS Sheets. Prosedur transfer cairan, dan membangun komunikasi dua arah. Setelah selesai pertemuan pengalihan pra-pekerjaan, semua orang yang terlibat dalam transfer akan menandatangani dokumen ini menunjukkan prosedur ini telah ditinjau. IV. TRANSFER DARI RIG KE BOAT A. Sebelum Memuat Boat Periksa Semua Selang, kopling, dan Garis Mencari celah dan selang berjumbai Memastikan koneksi yang ketat Absorben bantalan yang tersedia di lokasi B. Lokasi dan Ulasan ESD Operasi dan Prosedur Meninjau dan merumuskan (jika perlu) Prosedur ESD Pastikan ESD karya Individu ditugaskan untuk stasiun ESD selama transfer C. Cari dan Fire Fighting Equipment Periksa Tinjau Fire Fighting Prosedur Memastikan bahwa Peralatan Pemadam Kebakaran adalah dalam rangka bekerja dan dekat di tangan D. Periksa Menerima Kapal Menetas terbuka dan memeriksa untuk kebersihan (jika cuaca memungkinkan) Catatan jika tangki diisolasi dari dada laut dengan wajan atau kosong Menginformasikan Kapten dan kru bahwa cairan tersebut tidak akan digulung atau dipindahkan selama transit E. Memuat Boat Pastikan semua personil di stasiun mereka ditugaskan (tidak meninggalkan kecuali lega) A. Tahan Pre-Job Pertemuan Keselamatan dan Ulasan JSA, MSDS, dan Kebijakan transfer Perahu aman untuk menerima Rig Mencari celah dan selang berjumbai Memastikan koneksi yang ketat Pastikan peralatan polusi di tempat (misalnya, 5-gal ember, panci tetes / menangkap) Memonitor kebocoran ketika transfer dimulai - menutup dan memperbaiki jika perlu Individu ditugaskan untuk memantau perpindahan memverifikasi volume untuk ditransfer Absorben bantalan yang tersedia di lokasi Sebelum memompa, sampel akan diambil di situs penyimpananMeninjau Mud dan akrab dengan prosedur tumpahan. Perusahaan Menangkap sampel komposit di perahu saat mentransfer pertama 10%, B. Lokasi dan Ulasan ESD Operasi dan menengah, dan terakhir 10% dari produk dan membagi sampel antara Prosedur perahu dan perwakilan Exxon Meninjau dan merumuskan (jika perlu) Verifikasi volume transfer di selesai prosedur ESD V. TRANSPORTASI FLUID Tekankan bahwa cairan tidak akan meluncur, pindah dari ditransfer sementara pengangkutan ke lokasi Jika cuaca memungkinkan, secara berkala terdengar tank untuk memverifikasi tidak ada perubahan VI. TRANSFER DARI KAPAL KE DOCK PERUSAHAAN MUD Pastikan ESD karya Individu ditugaskan untuk stasiun ESD selama transfer C. Cari dan Fire Fighting Equipment Periksa Tinjau Fire Fighting Prosedur Pastikan Peralatan Pemadam Kebakaran adalah dalam rangka bekerja dan dekat di tangan D. Menerima Tank Pastikan tangki bersih dan disegel Verifikasi volume untuk ditransfer Menangkap sampel untuk memverifikasi komposisi sebelum mentransfer cairan Menangkap sampel komposit di perahu saat mentransfer pertama 10%, menengah, dan terakhir 10% dari produk dan membagi sampel antara perahu dan Mud perwakilan Perusahaan Signature / Perusahaan / Tanggal _________________ Signature / Perusahaan / Tanggal ______________________ Signature / Perusahaan / Tanggal _________________ Signature / Perusahaan / Tanggal ______________________ BAGIAN 6 - LAMPIRAN G-II Y N Y N Y N Kacamata keselamatan dengan perisai sisi dipakai Y N Banjir mandi â € "lumpur pencampuran area, lantai rig Y N Banjir mandi â € "lantai rig Y N Tanda Posted â € "â € Oeno Merokok & ada Hot Workâ € Stasiun pencuci mata â € "lantai rig, lumpur pencampuran daerah, daerah lain paparan potensial Y N Peralatan listrik ledakan bukti â € "motor, lampu Cuci cekungan dengan tangan bersih yang tersedia â € "lantai rig, lumpur pencampuran daerah, daerah lubang lumpur, wilayah rak pipa, daerah lain yang terkena dampak Y N Alat pelindung diri: Pengiriman Bahaya: Y N berat), sepatu, pelindung muka, respirator MINYAK DASAR LUMPUR KESIAPAN DAFTAR Form D-200 Rig lantai daerah â € "baju jas hujan (atau celemek), sarung tangan kerja, sarung tanganyaitu, karet, sepatu bot Kualitas & Ledakan Air: (daerah yang terkena lumpur dasar minyak, shaker, lubang) Celana panjang / kemeja lengan panjang yang dikenakan Ventilasi yang memadai â € "mengubah-out air setiap 5 menit. atau kurang Lab lumpur â € "yang didedikasikan untuk pengujian lumpur hanya Lab lumpur â € "ledakan Jadwal Bukti Lab lumpur â € "jauh dari lubang lumpur atau Pressurized Daerah lumpur â € "PPE ganti penuh dengan apron, sarung tangan (tugas Anak tangga dibungkus dengan goni atau memiliki permukaan non-selip Menangkap Pan bawah Rig Floor â € "terkuras untuk basin pembuangan Y N Tikar lantai ditempatkan di semua pintu masuk ke tempat tinggal Pelat tendangan sekitar utama dek / daerah rak pipa Y N Rotary memiliki non skid tikar Pelat tendangan di lantai rig Y N Bahan penyerap tersedia untuk lantai rig, daerah tumpahan lainnya Katup Dump valved ganda, terkunci, dan tanda-tanda diposting dengan â € œWork izin memerlukan operateâ € Y N Uap bersih atau tekanan tinggi Unit mencuci-down yang tersedia Wiper pipa bor yang digunakan â € "dalam dan di luar Y N Pembuangan: Lebih rendah kelly lumpur saver digunakan Y N Y N Y N Ratholes / Mouseholes disegel dengan selang ke baskom pembuangan Segel ember lumpur dalam kondisi baik Pencemaran Air: Saluran pipa Rack â € "terkuras untuk basin pembuangan Lubang lumpur terbuka tertutup Lubang dibersihkan dan katup isolasi diuji Garis lumpur minyak dasar dengan selang dan nozel dipasang â € "lantai rig, lumpur ruang pit, daerah pengocok Y N Y N Y N Roustabouts ekstra untuk tugas up bersih Y N Pembatasan kerja jam dijadwalkan Y N Rapat Keselamatan Umum â € "menjelaskan OBM bahaya dan tindakan pencegahan menjelaskan, yaitu, pakaian bersih, kamar mandi banjir, pembersih tangan Y N Gunakan dan perlu untuk menjelaskan PPE Y N Sumber air terisolasi â € "lantai rig, lumpur ruang pit, daerah shaker, lumpur pencampuran daerah Personil dan Pelatihan: Packing Elemen di sentrifugal pompa minyak didinginkan, bukan air didinginkan â € "tangki perjalanan, pompa pencampuran Dua insinyur lumpur di lokasi Menengah dan kasar non-air menyerap LCM di rig OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 2 Pertama Edition - Mei 2003 MINYAK DASAR LUMPUR KESIAPAN DAFTAR (lanjutan) Form D-200 Kerusakan barang karet: Pendapat umum: Base oil rendah hidrokarbon aromatik, yaitu anilin di atas 145 Deg. Tahan (nitrile) unsur minyak karet, yaitu, segel katup lubang lumpur, segel katup shaker, tunggangan shaker, dan selang Tahan (nitrile) unsur minyak yang digunakan dalam BOP, segel ram, annulars Laporkan Oleh: Posisi: Tanggal: Lokasi: Rig: Kontraktor: Distribusi: Operasi Inspektur File Rig OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 2 dari 2 Pertama Edition - Mei 2003 DETEKSI TEKANAN ABNORMAL DI klastik 7.0 DETEKSI TEKANAN NORMAL DI klastik 7.1 Latar Belakang 1 7.2 Indikator Tekanan Sementara Pengeboran 2 7.3 Abnormal Tekanan Deteksi Tim Tanggung Jawab 10 7.4 Mud Logging 11 7.5 Pedoman Operasional 15 __________________________________________ __________________________________________ __ OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING PERTAMA EDITION MAY 2003 Hidrostatik Tekanan - tekanan yang diberikan oleh ketinggian vertikal kolom cairan. 7.1 LATAR BELAKANG Untuk semua Operasi Pengeboran casing kursi atau TD berburu akan disiapkan bersamaan dengan Operasi Geologist. Parameter deteksi tekanan konvensional normal seperti yang dijelaskan dalam bab ini umumnya berlaku untuk urutan klastik. Tidak ada metode yang dapat diandalkan untuk mendeteksi terjadinya tekanan abnormal di bagian karbonat. Ketika pengeboran urutan didominasi karbonat, sangat hati-hati harus dilakukan termasuk pengeboran dikendalikan, sering aliran-cek, kesiapan untuk kehilangan keuntungan / patah tulang dan pertimbangan korelasi (bila memungkinkan). Sebaliknya, di klastik, teknik deteksi yang terkandung dalam bagian ini dapat diandalkan dengan tingkat yang jauh lebih tinggi keberhasilan. Definisi Tekanan yang normal - tekanan sama dengan tekanan hidrostatik yang diberikan oleh kolom air dari kepadatan tertentu memanjang dari permukaan ke kedalaman formasi. Tekanan normal biasanya mengacu 8,5 9,2 ppg formasi yang dapat dibor dengan aman dengan 9 - 10 ppg lumpur. Abnormal Tekanan - tekanan lebih besar dari tekanan normal untuk baskom diberikan. Transisi Tekanan - interval di mana perubahan gradien tekanan fluida normal gradien tekanan fluida yang abnormal. Kapan tekanan abnorma l terjadi Abnormal tekanan tinggi ditemukan di seluruh dunia. Tekanan tersebut terjadi ketika cairan dalam ruang pori mulai supp ort lebih overburden dari berat hanya cairan; yaitu, tidak semua kekuatan kompresi ditularkan oleh matriks batu. Banyak faktor yang dapat menyebabkan tekanan formasi abnormal tinggi. Di beberapa daerah, kombinasi faktor berlaku. Penyebab paling umum dijelaskan dari sedimen normal tertekan atau over-tekanan di bawah-pemadatan. Penyeba b tekanan abnorma l Penyebab lainnya dianggap: Diagenesis kimia Mengangkat Sebaliknya densitas fluida Diisi ulang atau re-tekanan formasi, dan Faulting. Karena kondisi dapat bervariasi, perawatan khusus harus diambil untuk tidak berasumsi bahwa penyebab tekanan abnormal didirikan dari pengalaman di daerah yang terkenal tentu adalah penyebab dari kondisi serupa di baskom lain yang belum cukup diuji oleh pengeboran. Dokumentasi Idealnya, Operasi Geologi harus mendefinisikan normal yang spesifik dari dikenal baik-penyebab tekanan untuk baik untuk meningkatkan pemahaman dan operasional tertentu perencanaan untuk menghadapi tekanan ketika mengalami. T e k a n a n n o r m a l 7.2 Indikator Tekanan Sementara Drilling Berikut alat & parameter, tercantum dalam urutan mereka keandalan, digunakan untuk memantau tekanan abnormal di bagian klastik sementara pengeboran: Tingkat Curves Penetrasi (termasuk d dan dc eksponen) Total Dibor Gas (BGG, CG, TG, dll) Properti lumpur (klorida, viskositas, suhu flowline, dll) Analisis stek (litologi, kepadatan shale) Paleontologi dan Paleobathymetry Ketidakstabilan lubang bor (lubang mengisi, torsi dan drag) Korelasi (Mud log & LWD dengan offset log) Real Time Pore Pressure Plot (LWD Sonic, Density atau Tahanan) Peningkatan ROP dengan parameter konstan menunjukkan tekanan diferensial, dan tren drill-off dan umumnya menunjukkan peningkatan litologi tekanan. Namun, mempertahankan ROP konstan selama interval panjang mungkin juga mengindikasikan peningkatan tekanan sejak itu diharapkan sedikit menumpulkan trend Referensi: Lihat Bagian III dari Tekanan Teknologi Abnormal (penurunan ROP) tidak terjadi. pengguna untuk informasi tambahan. Tergantung pada jenis bit, meningkat ROP di zona transisi secara konsisten menjadi salah satu indikator yang paling Catatan: Manual direferensikan harus ditinjau sebelum menafsirkan parameter definitif masuk ke overpressures ketika parameter pengeboran ini selama tekanan perburuan abnormal. lainnya maintaine d konstan. Peringk at dari Penetras i (ROP) Interpre tasi ROP plotting Plotting ROP digunakan untuk membedakan drill-off tren tekanandiinduksi dari biasanya diharapkan Faktor yang Keberhasilan penggunaan ROP untuk mendeteksi tren sedikit menumpulkan. mempengar menumpulkan tren dan tren drill-off tergantung pada Kecenderungan ini didasarkan pada uhi mempertahankan parameter pengeboran konstan. Faktor- asumsi umum bahwa ketika sedikit faktor berikut mempengaruhi semua ROP: adalah pertama kali dijalankan dalam ROP lubang dan mulai memutar, ia mulai aus atau kusam yang menghasilkan (trend menumpulkan) ROP lebih berat pada bit lambat. kecepatan putar Jenis bit / ukuran ROP dan Kondisi bit litologi viskositas lumpur hidrolika Hal ini penting untuk dicatat perubahan litologi ketika merencanakan ROP. Biasanya, bor-off (pengeboran istirahat) akan terjadi pada silty-serpih atau batu pasir. Dengan demikian, ketika mencari drill-off dan menumpulkan tren, "bersih" interval shale harus digunakan. "d" ekspone n Curv e kuantitatif antara unit gas dan tekanan Kurva lain digunakan untuk memprediksi peningkatan pori. tekanan pori adalah "d" eksponen kurva. Eksponen pengeboran ini digunakan untuk menormalkan ROP data dan perubahan berat badan sedikit, kecepatan putar, dan ukuran lubang untuk mendeteksi peningkatan tekanan formasi. Deteksi tekanan abnormal, dan bahkan evaluasi zona bunga, Interpreta Referensi: Lihat Bagian III dari adalah masalah membandingkan parameter melalui selang si yang bersangkutan dengan tren yang ditetapkan sebelumnya. Tekanan Teknologi Abnormal pembacaa Kunci untuk penafsiran bukanlah besarnya pembacaan gas pengguna untuk informasi tambahan. n gas tetapi perubahan relatif dalam pembacaan. Catatan: Manual direferensikan harus ditinjau sebelum menafsirkan parameter ini selama tekanan perburuan abnormal. Berbagai jenis gas adalah sebagai berikut: "dc" eksponen kurva lain yang digunakan dalam dikoreksi "d" eksponen ("dc"). Nilai ini kurva yang "d" nilai dikoreksi gradien cekungan di mana sumur dibor, dan untuk berat lumpur. Jenis gas Referensi: Lihat Bagian III dari Tekanan Teknologi Abnormal pengguna untuk informasi tambahan. Catatan: Manual direferensikan harus ditinjau sebelum menafsirkan parameter ini selama tekanan perburuan abnormal. Unit Gas Salah satu parameter pengukuran permukaan yang paling penting yang digunakan untuk menunjukkan tekanan abnormal adalah "unit gas". Tidak ada korelasi Latar Belakang Gas (BGG) Latar Belakang Gas (BGG), juga disebut Bor Gas Gas perjalanan (TG) Koneksi Gas (CG) Beredar Gas (CIRC BGG) Tampilkan Gas, dan Shutdown Gas. Latar Belakang Gas (BGG), atau Bor Gas adalah gas rata diamati saat pengeboran, eksklusif acara. Gas latar belakang merupakan gas dibebaskan dari pori-pori di batu yang sedang tanah oleh bit. alias Bor Gas Pengaruh pipa bor menarik kecepatan gas perjalanan Untuk menjadi parameter bermakna, koneksi harus dibuat secara konsisten, membutuhkan jumlah waktu yang sama dan kecepatan pick-up untuk menyelesaikan setiap koneksi. Ketika Konsiste mengambil untuk membuat sambungan, pompa harus Menarik pipa dapat membuat efek swabbing,nsi yang dibiarkan sampai alat bersama adalah di break titik keluar. menurunkan efektif lubang bawah tekanan hidrostatik koneksi selama Ketika pengeboran dengan top-drive, sering diinginkan untuk tersandung. Pipa bor menarik kecepatan harus dikurangi mensimulasikan koneksi untuk meningkatkan frekuensi bagian penting dari sumur ke tingkat wh indikator gas koneksi. swabbing untuk memastikan bahwa gas perjalanan akan menjadi parameter yang valid mencerminkan tingkat aktual lebihan dari tekanan pori dengan berat lumpur statis. Gas perjalanan (TG) perjalanan GAS (TG) adalah gas maksimum diamati di dasar setelah perjalanan. Gas perjalanan merupakan jumlah pakan gas ke dalam lubang ketika pompa yang shutdown dan pipa tersandung. Koneksi Gas (CG) Kelly memotong gas Fenomena kadang-kadang dikaitkan dengan koneksi adalah kelly memotong gas. Ini hasil dari udara masuk ke string bor saat sambungan berlangsung. Ketika ini "void" dalam pipa bor beredar di sekitar (bottoms up kapasitas ditambah pipa bor kapasitas), kadang-kadang menunjukkan puncak gas. Fenomena ini harus dibedakan dari gas koneksi. Koneksi Gas (CG) adalah gas maksimum diamati pada pantat up setelah sambungan. Gas koneksi mewakili jumlah pakan gas ke dalam lubang ketika pompa shutdown Circulat sementara ing membuat sambungan. Ketika pompa adalah shutdown, berat lumpur yang efektif, atau setara beredar density (ECD) Gasannulus. menurun karena kehilangan efek gesekan aliran Beberapa bagian dari gas koneksi mungkin juga karena swabbing ketika memilih untuk sambungan. (CIRC Beredar Gas (CIRC BGG) adalah tingkat stabil gas diamati setelah semua stek telah beredar keluar dari lubang. Ini merupakan gas sisa dalam sistem lumpur setelah gas stek baru-baru ini telah beredar keluar dari sumur. BGG) Waktu untuk beredar gas untuk menstabilka n Shutdown Gas Shutdown Gas adalah gas yang dihasilkan dari periode penutupan pompa; yaitu, untuk perbaikan B gas ackground (saat pengeboran) atau bottoms-up gas peralatan, dll (setelah tersandung) harus drop cepat ke tingkat stabil setelah beredar keluar stek atau perjalanan gas. Jika waktu yang signifikan diperlukan untuk mencapai tingkat stabil, gas bisa makan di karena berat lumpur cukup.Pelaporan Gas Tabel di bawah ini menjelaskan cara melaporkan berbagai jenis gas. Jenis gas Laporkan sebagai Tampilkan Gas acara Gas adalah gas stek diamati sementara pengeboran interval waduk potensial (biasanya berhubungan dengan istirahat pengeboran). Reaksi untuk menunj ukkan gas Latar belakan g Berat lumpur tidak harus dibesarkan semata-mata dalam menanggapi menunjukkan gas dari stek. Jika Gas ragu, beredar untuk menentukan tingkat gas latar belakang (BGG) yang beredar. Jika unit gas yang berlebihan turun dengan cepat aliaske bawah Bor Gas tingkat latar belakang pengeboran, gas berasal dari stek bor. Jika unit gas terus menjadi berlebihan setelah beredar keluar, baik bisa di atau dekat sangat kondisi keseimbangan. BGG (Depth ke Kedalaman) Contoh BGG 40 unit dari 7000 'untu k 7500 ' dan 60 unit dari 7500 'untu k 8000 '. 100 unit atau 100 unit lebih BGG Koneksi Gas (CG) Gas perjalan an (TG) Gas maksimum diamati dari perjalanan kedalaman dikurangi gas latar belakang sebelum perjalanan. Juga perhatikan waktu antara B / U puncak gas perjalanan dan kembali ke tingkat gas latar belakang dan melaporkan jika lebih dari normal. Gas maksimum diamati dari koneksi mendalam gas latar belakang dikurangi sebelum koneksi. Juga perhatikan waktu antara B / U puncak gas dan kembali ke tingkat sebelum gas dan melaporkan jika lebih dari normal. Gas latar bela kang sebel um kone ksi: 50 unit Gas maksim um diamati dari kedala man koneksi : 75 unit Lapork an Connec tion Gas Beredar gas jatuh ke 25 unit. Lapo ran CIR C BGG 25 unit atau 25 unit lebih Unit gas stabil tanpa gas bor atau gas perjalanan. Gas (CIRC BGG) BGG . Tampilk an Gas Gas maksimum diamati dari pengeboran istirahat gas latar belakang dikurangi. Gas latar bela kang sebel um peng ebor an istira hat: 50 unit Gas sebel um penu tupa n: 50 unit Gas maksim um diamati dari periode penutup an: 75 unit Laporka n Shutdow n Gas sebagai: 25 unit atau 25 unit lebih BGG Shutdo wn Gas Sifat lumpur untuk Gas maksimum diamati dari periode shutdownmerencanak yang an gas latar belakang dikurangi sebelum shutdown. Sifat lumpur yang akan diplot meliputi: density lumpur Total klorida (dititrasi atau resistivitas) suhu ion perubahan (kalsium dan natrium) viskositas lumpur (corong, plastik, titik luluh dan gel) dan â € ¢ faktor pH. corong viskositas â € ¢ viskositas plastik, dan yield point. Ketika mempertimbangkan beredar suhu lumpur untuk mendeteksi zona transisi, sangat penting untuk diingat bahwa suhu ini tergantung pada item berikut: Frekuensi sifat lumpur memeriksa Ketika mencari tekanan yang abnormal, sifat lumpur harus dijaga konstan mungkin. Sifat lumpur (baik dalam dan luar sampel) harus diperiksa setiap empat (4) jam atau lebih sering jika lumpur gas dipotong. Bottoms up setelah setiap perjalanan juga harus diperiksa. Faktor Metode merencanakan Sifat lumpur harus diplot dalam bentuk grafik atau kolumnar. Perubaha n sifat reologi Perubaha n klorida mempeng aruhi suhu Setiap perubahan signifikan dalam sifat reologi cairan pengeboran (terutama lumpur air tawar) ketika pengeboran over-tekanan formasi mungkin merupakan indikasi dari kondisi lubang sumur bawah seimbang. suhu lingkungan tingkat sirkulasi volume sistem (tangki lumpur, dll) kalinya sejak sirkulasi padatan konten di lumpur Selain cairan dan aditif (kelembaban, hujan lebat jika lubang terbuka), dan tingkat penetrasi. Peningkatan total klorida atas rata-rata untuk bagian tekanan normal dari lubang dapat menunjukkan masuknya air formasi dan Rasio / air minyak Jika pengeboran dengan lumpur masuk ke tekanan pori lebih tinggi. Peningkatan klorida menyebabkan perubahan kimia cairan pengeboran berbasis minyak, rasio / air minyak sebagai peningkatan: mungkin menjadi indikator masuknya air formasi. Sebuah gradien suhu perubahan yang ditunjukkan dengan suhu kembali lumpur di flowline mungkin menunjukkan bahwa over-tekanan sedimen sedang dibor. Umumnya, perubahan ini akan terjadi peningkatan suhu flowline karena lebih tinggi geotherma l gradien di zona overpressured. Namun, perubahan dalam gradien suhu juga dapat menunjukkan: Perubahan gradien suhu Pedoman suhu merencanaka n persimpangan dari kesalahan â € ¢ sebuah ketidakselarasan, atau perubahan litologi. n sifat fisik stek Memonitor dan merekam secara bersamaan inlet (hisap) dan outlet (shaker) suhu. Plot dengan parameter lainnya. Pertimbangkan jeda waktu berkorelasi suhu dengan kedalaman. Jangan menetapkan gradien suhu lumpur sampai setelah efek tersandung telah dinormalisasi (biasanya 30 '40' pengeboran). Mengamati peningkatan mendadak dalam diferensial outlet / inlet. Stek dari zona transisi akan memiliki sifat fisik yang berbeda dari stek biasanya tertekan. Beberapa perubahan fisik adalah: Pedoman berikut direkomendasikan untuk mendapatkan data suhu yang berarti yang dapat berasimilasi ke dalam Perubaha bentuk indikator tekanan. Membangun gradien untuk setiap bit run. Komposisi Warna Tekstur Ukuran Bentuk Fraktur â € ¢ kuantitas, dan bulk density. Berubah warna perubahan warna sering dicatat dari multi-warna coklat hijau, kemerahan, tan dan serpih non-laut abu-abu terang dalam sedimen biasanya tertekan ke abu-abu dan coklat tua sering gelap hingga abu-abu serpih laut di zona normal tertekan. mulai meledak ke dalam sumur bor. Kadang-kadang, ada secara bersamaan torquing dari pipa bor dan tekanan meningkat pompa. Juga, ini umumnya ketika Anda mendapatkan mengisi di bagian bawah setelah membuat sambungan. Kepadatan mengubah Penurunan atau keberangkatan Perubahan tekstur perubahan tekstur di shale mungkin dari berlumpur dan kasar untuk lilin, licin atau sabun. Shape mengubah Sebuah perubahan bentuk dapat terjadi dari semi-datar, bulat stek untuk sudut, datar, splintery dan sering bergerigi dan memanjang (balingbaling berbentuk) stek melengkung cekung. Stek kadang-kadang besar beberapa inci panjang, yang dikenal sebagai spalling shale, dicatat saat pengeboran underbalance. Kuantitas kuantitas stek sering meningkat ketika overpressure menjadi berubah lebih besar dari tekanan dari tren pemadatan normal pada kepadatan penjualan stek adalah indikasi lain dari pengeboran shale overpressured. 7.3 Abnormal Tekanan Deteksi Tanggung Jawab Tim Tim make-up Ketika dikerahkan tim deteksi tekanan abnormal harus terdiri dari anggota sebagai berikut: Rig Pengawas Wellsite Geologist Pengeboran Engineer (jika diperlukan) Paleontolog (jika diperlukan) kolom lumpur. Hal ini terjadi ketika formasi Mudloggers, dan personil MWD â € ¢ Tangan Rig Driller, dan tangan Shaker Wellsite Geologis t Tugas yang Wellsite Geologist adalah untuk merencanakan dan menafsirkan berbagai indikator tekanan abnormal geologi, menafsirkan dan berkorelasi log (log MDS / LWD, log wireline listrik, log lumpur, dll), dan menghitung tekanan pori estimasi dari kayu dan shale densit y plot. Pengebor an Insinyur Tugas Drilling Engineer adalah untuk menafsirkan parameter pengeboran. The Geologist dan Pengeboran Insinyur harus menjaga komunikasi yang erat dan erat menganalisis berbagai indikator seperti lubang yang dibor. Paleontol og Tugas yang Paleontolog (jika diperlukan) untuk mengidentifikasi zona mikrofosil korelatif, membangun peta paleobatimetri, dan membantu tim lebih memahami geologi. Lumpur Insinyur Ketika harus Semua anggota tim harus di lokasi sumur  ± 24 jam sebelum tim tiba zona transisi yang diharapkan. Hal ini memungkinkan waktu untuk memantau semua indikator sehingga "tren normal" garis referensi dapat dibentuk. MWD Misi tim Insinyur Anggota tim Tabel di bawah ini menjelaskan tanggung jawab masing-masing anggota tanggung jawab tim. Peran Rig Pengawas Tanggung Jawab Mudlogg er Tugas yang MWD Engineer adalah untuk mempertahankan QC kayu LWD, dan perkiraan perubahan tekanan pori dari plot log. Tugas yang Mudlogger adalah untuk merekam semua parameter tekanan abnormal, membuat deskripsi litologi dari stek, menonton untuk menunjukkan hidrokarbon, dan mempertahankan parameter log litologi / pengeboran diplot up to date terus juga sedang dibor. Tugas driller adalah untuk mempertahankan parameter pengeboran (WOB dan Rig Pengawas bertanggung jawab atas rig pengeboran dan semua kegiatan di lokasi dan ditunjuk sebagai KetuaMesin Tim. Supervisor RPM) sebagai konstan mungkin dan seperti yang ditentukan oleh memiliki wewenang penukaran tertinggi padapembor saat menaikkan Pengawas Rig. berat lumpur, berhenti pengeboran, dan log berdasarkan saran Dia harus segera memberitahukan Supervisor Rig perubahan dari lembaga lainnya anggota tim er. apapun. Lumpur Insinyur Tugas Mud Engineer adalah untuk mengukur berat lumpur pada ¢ interval yang ditentukan oleh Pengawas Operasional dan menjaga anggota tim lainnya diperbarui. Shaker Tangan â Tugas shaker tangan adalah untuk membantu insinyur lumpur dalam memantau sifat lumpur, memantau dipotong € dan volume, dan memantau untuk aliran ketika pompa turun. ¢ * Operasi deteksi tekanan Kebanyakan normal dilakukan oleh kontrak Geologist tanpa Geologist EMDC atau Insinyur di situs. Komunikasi yang tepat harus dilakukan melalui dengan anggota tim di lokasi rig dan kantor. 7.4 Mud Logging â € ¢ deteksi gas background gas koneksi gas gas perjalanan, dll â € Dimanak ah bacaan kromatografi ¢ Jasa logging lumpur dan selang akan ditentukan dalam Program Pengeboran. Spesifika si ditemuka n â € deskripsi litologi ¢ Parameter tekanan abnormal dipantau Parameter tekanan abnormal yang dipantau oleh mudloggers â dan mungkin termasuk yang berikut: â € Tingkat penetrasi d / dc € ¢ kepadatan shale, luas permukaan dan deskripsi â € ¢ "Dalam" dan "Out" sifat lumpur, dan berat suhu klorida, dll â € ¢ kondisi lubang momen menyeret mengisi, dll Merencanakan data Sementara pengeboran, yang Mudloggers akan plot data ditentukan pada log lumpur secara terus menerus dan mempertahankan pengawasan 24 jam dari sumur bor. The akan Mudloggers: Distribus i/ frekuensi laporan â € Semua instrumen di bagian non-bertekanan unit akan intrinsik aman. ¢ memberikan Pengeboran Pengawas salinan laporan log lumpur â dan lumpur logging harian, dan € memperbaiki salinan ke personel Perusahaan sebagaimana ditentukan oleh Geologist Drilling Supervisor / Wellsite. ¢ Catatan: Ini mungkin diperlukan untuk fax log lumpur ke kantor lebih sering ketika pengeboran di atau dekat zona transisi yang mungkin (biasanya, minimal dua kali sehari ke kantor untuk Operasi Geologist, dan review Inspektur itu). Spesifikasi Unit mud logging Tekanan insinyur (jika diperlukan), dan personil lain yang diperlukan. Unit harus memiliki alarm untuk mendeteksi depressurization. Spesifikasi rinci untuk unit mud logging dan peralatan yang terkait akan di kontrak mudlogging. gas â € ¢ A Hydrogen api ionisasi gas Unit mud logging harus memenuhi spesifikasiDeteksi sebagai Detector (FID) dan peralatan Hidrogen sistem api berikut: ionisasi gas Kromatografi akan â Sebuah unit logging bertekanan cukup besar untuk disediakan pada unit dengan € menampung personil yang dibutuhkan harus sistem kedua yang disediakan digunakan. Ini dapat mencakup: sebagai cadangan. ¢ Mudloggers Integrator akan dipasok untuk perhitungan persentase gas dari Wellsite Geologist kromatografi tersebut. Pembacaan gas akan dikalibrasi ke: Keseimbangan 2% metana di udara (2% = 100 unit), dan keseimbangan metana 20% dalam nitrogen (2% = 1000 unit). Sebuah lag karbida (atau di Oil Basis Mud beberapa jenis lain dari lag) akan dilakukan setiap 24 jam untuk memeriksa operasi detektor gas dan jeda waktu. Perangkap gas â € ¢ Perangkap gas utama harus dibangun sehingga lumpur yang masuk peralatan melalui 1,5 "untuk 2" lubang di piring bawah pada perangkap. Dua (2) bertentangan, behel terbuka pisau (melengkung atau lurus) agitator harus digunakan. Sebuah motor udara lebih disukai. Komputer â € ¢ Minimal tiga (3) monitor akan dipasang seperti ditunjukkan peralatan di bawah ini: satu di kantor Drilling Supervisor satu (Div 1, Kelas 1, secara intrinsik aman) di lantai rig, dan satu di unit mud logging. Perangkat lunak komputer dan instrumentasi mampu mengukur dan menampilkan data berikut ideal: ROP Momen tekanan pompa total gas Sebuah perangkap gas cadangan harus tersedia di lokasi setiap saat. tingkat pit Perangkap gas sekunder ekstrak jumlah yang tepat dari lumpur dari perut possum dan secara otomatis ekstrak gas entrained di lumpur. Ini harus mengkalibrasi-diri dan menggabungkan dua (2) Jumlah besar sebagai sensor. lumpur resistivitas Eksponen DXC (dihitung) suhu RPM WOB Stroke pompa laju alir tingkat tangki perjalanan torsi putar, dan density lumpur Perangkat lunak ini dan instrumentasi harus independen dari instrumentasi rig dan memiliki alarm dengan tinggi / tingkat rendah. Litologi â € ¢ kotak sinar UV dengan tow (2) 3600 lampu UV angstrom ditambah satu deskripsi (1) cahaya putih. Peralatan â € ¢ kualitas tinggi teropong mikroskop dengan cahaya intensitas tinggi. Litologi kimia menentukan (misalnya, HCL, Alizarin Red). Probe, pinset, sampel nampan dan saringan. Pedoman Pedoman untuk pengeboran di daerah The PVT dan FLO-SHO alarm harus ditetapkan untuk batas praktis terendah. BOP harus diuji dan berfungsi, dan kru bor bertekad untuk menjadi berkualitas dan kompeten (melalui pelatihan dan latihan) di FlowCheck dan prosedur baik menutup-in sesuai dengan Seksi Pengendalian Nah dari manual ini. Referensi: Lihat Seksi Pengendalian Nah manual ini untuk informasi tambahan. Parameter deteksi tekanan yang abnormal ditentukan dalam Program Pengeboran harus dipantau terus menerus. Parameter pengeboran harus distabilkan sesegera mungkin selama setiap bit run dan dijaga konstan untuk memungkinkan deteksi tekanan yang lebih akurat. Cairan pengeboran harus stabil pada berat yang telah ditentukan. Barit yang memadai harus berada di rig pengeboran untuk menurunkan berat sampai setidaknya berat lumpur diharapkan (minimal: semakin tinggi 1000 karung atau 1 ppg peningkatan lebih berat lumpur saat ini). Jika berat lumpur harus dinaikkan dalam menanggapi indikator tekanan abnormal, pengeboran harus berhenti dan baik harus diedarkan sampai sistem distabilkan pada berat lumpur baru. Setelah berkonsultasi dengan Operasi Inspektur, berat lumpur dapat ditingkatkan secara bertahap sementara pengeboran jika kondisi memungkinkan. Barit diperlukan harus ditangani di daerah kembali hilang. Kuantitas barit di tempat harus mematuhi peraturan Badan Negara MMS atau. Periksa persediaan perusahaan lumpur dari barit di pangkalan mereka dan seberapa cepat dapat dimobilisasi ke lokasi rig. Pertimbangan harus diberikan untuk menggunakan bit gigi pabrik karena mereka telah menjadi yang paling dapat diandalkan dalam merespon indikator tekanan abnormal. Sukses perburuan tekanan abnormal telah dilakukan dengan bit insert, dan PDC bit di daerah dengan pengetahuan lokal yang signifikan dan di mana mengimbangi pengalaman ada. tekanan abnormal adalah: The PVT dan FLO-SHO alarm harus ditetapkan untuk batas praktis terendah. Parameter deteksi tekanan yang abnormal ditentukan dalam Program Pengeboran harus dipantau terus menerus. Parameter pengeboran harus distabilkan sesegera mungkin selama setiap bit run dan dijaga konstan untuk memungkinkan deteksi tekanan yang lebih akurat. Jika berat lumpur harus dinaikkan dalam menanggapi indikator tekanan abnormal, pengeboran harus berhenti dan baik harus diedarkan sampai sistem distabilkan pada berat lumpur baru. Setelah berkonsultasi dengan Operasi Inspektur, berat lumpur dapat ditingkatkan secara bertahap sementara pengeboran jika kondisi memungkinkan. Pertimbangan harus diberikan untuk menggunakan bit gigi pabrik karena mereka telah menjadi yang paling dapat diandalkan dalam merespon indikator tekanan abnormal. Sukses perburuan tekanan abnormal telah dilakukan dengan bit insert, dan PDC bit di daerah dengan pengetahuan lokal yang signifikan dan di mana mengimbangi pengalaman ada. Pedoman Pedoman untuk pengeboran di daerah tekanan abnormal adalah: BOP harus diuji dan berfungsi, dan kru bor bertekad untuk menjadi berkualitas dan kompeten (melalui pelatihan dan latihan) di FlowCheck dan prosedur baik menutup-in sesuai dengan Seksi Pengendalian Nah dari manual ini. Referensi: Lihat Seksi Pengendalian Nah manual ini untuk informasi tambahan. Cairan pengeboran harus stabil pada berat yang telah ditentukan. Barit yang memadai harus berada di rig pengeboran untuk menurunkan berat sampai setidaknya berat lumpur diharapkan (minimal: semakin tinggi 1000 karung atau 1 ppg peningkatan lebih berat lumpur saat ini). Barit diperlukan harus ditangani di daerah kembali hilang. Kuantitas barit di tempat harus mematuhi peraturan Badan Negara MMS atau. Periksa persediaan perusahaan lumpur dari barit di pangkalan mereka dan seberapa cepat dapat dimobilisasi ke lokasi rig. PEMBENTUKAN EVALUASI ________________________________________ ________________________________________ ______ 1. PEMBENTUKAN EVALUASI OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING 2. Umum 1 PERTAMA EDITION MAY 2003 3. Coring konvensional 1 4. Program Logging Wireline 8 5. Sidewall Coring Operasi 11 6. Wireline Radioaktif Sumber 12 7. MWD / LWD Logging 12 8. Mud Logging dan Stek Sampel 14 1. UMUM Evaluasi pembentukan banyak bentuk dan dalam banyak hal adalah provinsi geologi wellsite. Namun, pengoperasian peralatan dan efeknya pada keselamatan baik, adalah tanggung jawab supervisor operasi. Oleh karena itu, setiap metode utama dari evaluasi formasi akan dibahas dalam pandangan pertimbangan operasional. 2. CORING KONVENSIONAL Untuk semua Operasi Pengeboran, prosedur tambahan akan disiapkan merinci operasi coring. Tujuan dari coring adalah untuk mendapatkan sampel formasi untuk evaluasi geologi atau reservoir, menentukan permeabilitas, porositas, komposisi batu, dan untuk melakukan studi aliran. Karena informasi yang berharga, yang menyediakan core, tujuan pengeboran adalah untuk memberikan pemulihan maksimum inti, kerusakan inti minimal, dan biaya operasional minimum. Untuk melakukan hal ini, perencanaan adalah langkah pertama penting untuk memastikan bahwa program analisis inti sukses dan bahwa uang yang digunakan untuk mendapatkan dan menganalisa inti dihabiskan dengan baik. Menentukan tujuan coring, jenis lumpur, metode pemotongan inti, dan prosedur penanganan inti di permukaan adalah langkah pertama dalam proses perencanaan. Metode yang paling banyak digunakan saat ini adalah coring tabung ganda konvensional (dalam dan luar) per barel inti dengan kepala inti PDC atau berlian. Berlian dipotong dengan tindakan geser dan dengan demikian sangat mengurangi patahan dari inti. Ini meningkatkan pemulihan karena inti non-retak kurang suka macet laras inti sebelum inti full-length telah dipotong. Penangkap inti standar secara rutin digunakan dengan sukses di daerah dengan formasi konsolidasi. Tertutup sistem inti penangkap seperti Baker Hughes Inteq ini "Hydro-Angkat", yang digunakan hampir secara eksklusif di Teluk Meksiko, yang digunakan dalam coring formasi yang tidak terkonsolidasi untuk meningkatkan pemulihan. Dalam kasus ini, penggunaan sedikit wajah debit (di mana barel inti dapat meluas ke daerah tenggorokan bit) dianjurkan untuk meminimalkan erosi inti seperti yang dipotong. Pre-Coring Rapat Pertemuan pra-coring harus dilakukan satu atau dua minggu sebelum coring, dan harus dihadiri (jika mungkin) oleh semua personel yang akan terlibat. Pada pertemuan tersebut, tujuan coring dan rencana coring dapat ditinjau dan perubahan kecil dapat dilakukan jika diperlukan. Peran dan tanggung jawab dari semua personil juga harus dibahas. Ini akan membantu setiap orang menyadari coring yang merupakan upaya tim, dan bahwa peran setiap orang adalah penting. Peralatan Coring konvensional Inti Bits Berlian bit inti tersedia dalam berbagai desain untuk pengeboran berbagai jenis formasi. Secara umum, untuk formasi lembut, berlian besar spasi relatif berjauhan, sedangkan di formasi keras, berlian yang lebih kecil diatur lebih dekat bersama-sama. Biaya bit inti tergantung pada berat total karat berlian ditambah biaya pengaturan. Bit yang digunakan dikembalikan untuk penyelamatan dari berlian dan untuk menerima kredit untuk batu dapat digunakan kembali. Selain penempatan PDC / berlian, perbedaan utama dalam desain kepala inti adalah lokasi, ukuran, dan jumlah pengeboran bagian cairan untuk membersihkan dan mendinginkan bit. Desain ini tergantung pada formasi yang akan berintikan bersama dengan pompa yang tersedia tenaga kuda. Kursus cairan besar relatif mengizinkan tarif sirkulasi cairan yang lebih tinggi untuk pembilasan lubang sementara memotong serpih lengket. Lebih kecil, berbagai kursus cairan memberikan pendinginan yang lebih baik dari berlian sementara coring formasi keras abrasif. Ketika coring di formasi lembut, EMDC dapat memilih untuk memiliki perusahaan coring memproduksi bit inti dengan "tenggorokan" mereka 1/8 "lebih kecil dari laras dalam atau kapal diameter dalam. Izin ini akan memungkinkan serpih membengkak dan mudah-mudahan mencegah laras dari kemacetan dan mengakibatkan pemulihan miskin. Hadapi kepala inti debit juga dapat mengurangi erosi karena aliran fluida melewati inti. Dalam lubang bor formasi keras, perjalanan awal dalam lubang dengan sedikit inti harus dilakukan dengan pemantauan cermat untuk tarik berlebihan, terutama di bagian bawah yang terakhir sedikit berjalan. Sebagai sedikit bor formasi keras, perlindungan mengukur bit dapat memakai menciptakan lubang di bawah diukur. Sebagai penuh pengukur coring perakitan memasuki bagian lubang, bit dan mengukur penuh stabilisator pada laras inti bisa menempel. Jika hambatan menjadi berlebihan, perakitan harus ditarik dari lubang dan pembuka lubang atau menjalankan reamer untuk membukanya untuk mengukur penuh. Konvensional barel ketebalan dinding umumnya tersedia dalam ukuran berikut: Outer Barrel Diameter inti Diameter 2-1 / 8" 4-1 / 8 " 4-3 / 4 " 2-5 / 8" 5-3 / 4 " 3-1 / 2" 6-1 / 4 " 4 " 6-3 / 4 â € 7" 43 / 8 " 8" 51 / 4 " Inti Barrel Laras inti konvensional untuk berlian coring terdiri dari laras luar yang rumah gratis, non-rotating, barel inti yang terbuat dari cahaya baja berat, aluminium, atau fiberglass. Dalam rangka untuk mendapatkan inti yang baik, laras batin tidak harus memutar dengan laras luar. Hal ini dilakukan dengan menangguhkan barel dalam pada perakitan putar yang memanfaatkan lumpur dilumasi bantalan antigesekan. Bit inti terdiri atas bagian bawah laras luar sementara barel batin dilengkapi dengan penangkap rakitan inti di bagian bawah nya. 4" Jika salah satu barel menjadi bengkok, unit harus diganti karena ban mungkin akan berputar dengan tabung luar. Laras batin harus memiliki bore seragam halus untuk memungkinkan bagian dari inti dan untuk mencegah wedging. Unit harus selalu diperiksa sebelum memulai dalam lubang. Perakitan dapat digantung di derek dan barel dalam tangan-diputar sebelum membuat kepala inti. diyakini mengurangi inti gesekan barel dalam dan oleh karena itu mengurangi kemacetan. Dalam Barrel Plastik Liners Pengukur penuh (1 / 32a € bawah) stabilisator berbilah terpisahkan dekat bagian atas dan tepat di atas sedikit akan terus laras dari bergoyang-goyang saat coring, dan harus diganti bila dikenakan turun lebih dari 1/8 ". Jika di bawah stabilisator diukur digunakan dalam pengeboran bagian dari lubang tepat di atas titik inti, ini stabilisator pengukur penuh dapat menyebabkan hambatan berlebihan sementara akan di lubang yang bisa menempel perakitan. Sebuah perjalanan tambahan dengan reamer atau lubang pembuka mungkin diperlukan sebelum coring dapat dimulai. Ketika coring di lembut, formasi yang tidak terkonsolidasi, liner plastik dapat dijalankan yang akan membantu mencegah barel dalam dari kemacetan, dan membantu melindungi dan melestarikan inti selama penghapusan dan transportasi. Dalam media untuk formasi keras, liners ini biasanya tidak berjalan. Ada tiga jenis liners plastik: 1) Polivinil klorida (PVC) dengan keterbatasan suhu hingga 150 derajat F, 2) Acrylonitrile Butadiene Styrene (ABS) dengan keterbatasan suhu hingga 180 derajat, dan 3) Butyrate, liner plastik bening yang memiliki keterbatasan suhu 140 derajat F. PVC kapal plastik biasanya dijalankan ketika coring formasi lembut, meskipun liners aluminium telah digunakan dalam lubang panas di mana BHT melebihi 180 derajat F. Penggunaan ini liners plastik akan mengurangi ukuran inti yang dapat dipotong, oleh 3/8 "untuk 1/2" tergantung pada ukuran barel yang digunakan. Bergalur Aluminium batin Barrel Pemulihan yang sangat tinggi dari interval waktu yang panjang buang biji telah dicapai dengan laras batin aluminium bergalur di Norwegia. Desain Stabilisator Keamanan Bersama Sebuah sendi keamanan di bagian atas laras inti memungkinkan pemulihan barel dalam dan inti harus laras luar menjadi terjebak. Ini akan meninggalkan hanya laras luar dan inti bit untuk memancing dari lubang. Perlu dicatat bahwa sendi keselamatan dibuat dengan benang kiri yang hanya membutuhkan 50% dari torsi make-up untuk melepaskan. Di sudut tinggi directional sumur mungkin mustahil untuk bekerja turun cukup torsi tangan kiri ke sendi keamanan tanpa dukungan-off string bor pada titik yang lebih tinggi. Pompa-Out Sub A (sub beredar) pompa-out sub harus dijalankan di atas perakitan coring yang dapat dibuka dalam hal ayat-ayat aliran sekitar sedikit harus menjadi terpasang selama operasi coring. Sebuah bola biasanya dijatuhkan dan string bor ditekan-up pecah disk yang terbuka port aliran di sub. Berbagai tekanan dinilai disk dapat dijalankan, biasanya menggunakan set yang pecah pada 3500 psi. Sirkulasi kemudian dapat melanjutkan dan lubang dibersihkan sebelum menarik keluar dari lubang. Perusahaan coring memberikan ini selam pompa-out. Jars coring Guci mekanik TIDAK harus dijalankan ketika coring karena mereka dapat melakukan kerusakan serius pada majelis inti barel. Jika string bor terjebak di sedikit, guci mekanik telah dikenal untuk merobek tenggorokan dari sedikit inti. Sebuah jar hidrolik (seperti Bowen atau Houston Engineering) lebih disukai oleh sebagian besar perusahaan inti karena pukulan menggelegar dapat dikontrol oleh overpull dari lantai rig. Guci ini ditempatkan baik ke bagian bawah dari pipa bor HeviWate, atau di bagian atas dari kerah bor. TEKNIK CORING KONVENSIONAL Mempersiapkan ke Core Hal ini sangat penting bahwa lubang menjadi bersih dari setiap puing-puing (gigi agak rock, bantalan, dll) untuk mencegah kerusakan pada PDC atau berlian. Jika perlu, keranjang sampah boot dapat digunakan selama yang terakhir sedikit lari sebelum coring. Jika ada sampah diduga di bawah setelah bit terakhir dijalankan sebelum coring menjalankan booting keranjang dianjurkan. Insinyur pengeboran harus bekerja sama dengan produsen inti bit untuk memilih desain terbaik dan jenis bit untuk jenis formasi yang akan buang biji, sifat lumpur diantisipasi, dan tersedia tenaga kuda hidrolik. Seperti dengan semua majelis pengeboran, pengukuran yang akurat dari laras rakitan inti termasuk BHA harus dilakukan sebelum masuk lubang. Setelah menyentuh bawah sementara beredar, bit harus diadakan sekitar 3 kaki off-bawah dan sirkulasi terus mencuci lubang bersih dari setiap mengisi yang mungkin telah terakumulasi selama perjalanan bit. Properti lumpur Sementara pengeboran hanya sebelum PDC / berlian coring, viskositas lumpur harus dikurangi sebanyak mungkin tanpa mengorbankan lubang pembersihan. Sebuah lumpur kehilangan air yang rendah akan mengurangi filter cake build-up dan meminimalkan kemungkinan mencuat. Viskositas rendah dan kehilangan air yang rendah juga akan membantu mengurangi tekanan pompa. Dalam studi yang dilakukan oleh Conoco pada tahun 1986, mereka menemukan bahwa pemulihan inti yang sangat baik (100%) diperoleh dalam operasi lepas pantai mereka ketika tekanan dari kolom lumpur disimpan setidaknya 300 psi di atas tekanan formasi menggunakan air asin / New Jenis Bor lumpur sistem. Coring berjalan di lubang menggunakan lumpur lignosulfonat air tawar tidak sesukses (serpih menjadi bengkak menyebabkan mereka menjadi lengket dan jamming laras inti), dan pada mereka operasi dilakukan dengan tekanan diferensial yang sangat rendah, tidak ada inti pulih. menghasilkan berdebar di bawah dan dapat mengakibatkan kerusakan parah pada kepala inti dan coring perakitan. Kecepatan putar harus tetap konstan selama operasi coring. Coring Operasi Pedoman LCM dapat dipompa melalui barel inti, tetapi bahan harus dibatasi untuk bahan halus saja. Batasi LCM untuk konsentrasi maksimum 15-20 ppb. WOB, RPM dan tingkat pompa harus sesuai dengan rekomendasi yang sedikit produsen inti ini. Pedoman umum adalah sebagai berikut: Coring Operasi Pedoman Untuk 8-1 / 2 "lubang, WOB umumnya harus antara 4.000 dan 6.000 lbs. Di lembut untuk menengah-keras formasi dan 10.000 hingga 20.000 lbs. Dalam formasi keras Sirkulasi maksimum harus dibatasi tingkat yang tidak akan mengikis sedikit matriks inti atau melemahkan inti. Tingkat sirkulasi 200-500 GPM yang paling umum ketika memotong "inti 4. Kecepatan putar umumnya harus antara 50 dan 100 rpm. Kecepatan putar di atas 100 rpm dapat merusak laras inti dari torsi yang berlebihan. Parameter pengeboran (tekanan pompa vs tingkat pompa, berputar torsi vs rpm, ROP vs WOB, dll) harus dimonitor selama operasi coring. Perubahan parameter apapun mungkin signifikan untuk coring sukses. Pemotongan Core Sebelum menjatuhkan bola untuk memulai coring, beredar pantat-up. Sebuah bola baja dipompa ke bawah string bor dan duduk di atas laras batin. Cairan coring kemudian dialihkan antara barel dalam dan luar dan muncul di pelabuhan cairan bit. Untuk performa maksimal, laras inti harus distabilkan sebaik mungkin dalam lubang. Sebuah stabilizer tepat di atas sedikit biasanya akan memberikan stabilisasi cukup jika tidak diperbolehkan untuk mendapatkan lebih dari 1/8 "di bawah diameter bit. Ketika memulai inti, itu adalah praktik yang baik untuk memotong pertama 12 sampai 18 inci dengan hanya 2.000 sampai £ 4000 menggigit berat badan dan dengan mengurangi kecepatan putar. Setelah stabilizer dimakamkan di lubang inti, bit berat dan kecepatan putar dapat ditingkatkan. Sementara coring, berat bit harus dipertahankan terus menerus dan berat tidak boleh diizinkan untuk mengebor-off. Memungkinkan berat untuk mengebor-off akan Ketika inti sedang dipotong dan mulai memasuki barel batin, tekanan pompa akan meningkat 200-300 psi dan merupakan hasil dari penurunan tekanan di seluruh bit berlian. Tekanan ini harus dipantau selama operasi coring, kenaikan atau penurunan biasanya menunjukkan bahwa sesuatu yang abnormal terjadi dan penyebabnya harus ditentukan. Operasi coring harus berhenti, bit harus mengambil-up dari bawah, dan tekanan pipa tegak diamati. Jika tetes tekanan tapi kemudian segera kembali ke tekanan abnormal tinggi ketika bit diatur kembali di bagian bawah, sedikit mungkin telah gagal. Sebuah cincin berlian yang telah rusak akan memungkinkan formasi untuk memotong ke dalam matriks, membatasi aliran air dan menyebabkan peningkatan tekanan. Ketika ini terjadi, tarik sedikit untuk mencegah kerusakan lebih lanjut. Jika peningkatan tekanan tetap ketika bit dinaikkan dari bawah, ditusuk dari bagian cairan di bit atau sistem peredaran darah mungkin menjadi penyebabnya. Terus tekanan tinggi juga dapat menjadi indikasi kegagalan putar sehingga menurunkan laras dalam dan penutupan saluran cairan. Dalam kondisi baik tarik bit. Peningkatan mendadak tekanan pipa tegak dapat disebabkan oleh penyumbatan laras inti dari akumulasi partikel asing dalam sistem lumpur seperti karet, LCM, atau skala pipa. Penurunan tekanan saat coring mungkin karena sejumlah faktor, termasuk kebocoran dalam peralatan permukaan, atau lubang di bor. Jika penurunan tekanan ini disertai dengan penurunan tingkat penetrasi DAN kurang torsi, inti terjepit mungkin telah dikembangkan memegang sedikit dari bawah. Jika kondisi ini terus berlanjut setelah mengambil dan menetapkan turun sedikit, tarik keluar dari lubang dan memulihkan apa inti telah dipotong. Ketika tekanan pompa berfluktuasi terus menerus dan ROP yang tidak menentu, adalah mungkin bahwa wedging alternatif dan menghancurkan inti terjadi. Laras harus ditarik untuk menghindari hilangnya pemulihan. Membuat Koneksi dan Menarik Core Sebuah set lengkap pipa bor sendi anjing harus tersedia ketika coring untuk mencegah membuat koneksi tambahan. Ini adalah praktik yang baik untuk meninggalkan kaki di atas kelly bersama sebelum membuat sambungan. Jika lebih dari 30 inti kaki sedang berusaha dan sambungan diperlukan, menghentikan meja putar dan memilih inti barel dari bawah perlahan-lahan. Sebuah lompatan terlihat pada indikator akan terjadi ketika istirahat inti. Jika inti adalah sulit untuk istirahat, menarik 15.000 untuk £ 30.000 di atas berat string, mengatur rem dan perlahan-lahan batu rotary sampai istirahat inti. Setelah membuat sambungan, kembali ke bawah dan memutar perlahan-lahan sampai bit tersebut lagi memotong dan inti baru memasuki barel batin. Prosedur yang sama harus digunakan sebelum menarik inti untuk menghindari meninggalkan bagian inti dalam lubang. Perlu dicatat bahwa tidak semua barel inti memiliki kemampuan untuk memotong lebih dari 30 kaki inti. Ketika keluar dari lubang dengan inti, sangat penting bahwa string bor ditarik perlahan dan tidak diputar untuk mencegah kehilangan inti. Jangan memompa siput, dan menggunakan tangki perjalanan untuk memastikan bahwa lubang sumur mengambil jumlah yang tepat dari lumpur. Membunuh baik dengan perakitan coring di dalam lubang akan sulit dan rumit karena laras inti penuh dalam string. Inti Penanganan Ketika laras inti ditarik ke permukaan, ada dua metode yang umum digunakan untuk menghapus inti. Di daerah formasi keras di mana kapal batin plastik tidak digunakan, laras dalam dapat dilepas dari bagian atas laras inti dan diletakkan di atas catwalk di mana inti pulih. Inti juga dapat dihapus sementara laras yang tersisa tergantung di derek beberapa inci di atas lantai rig. Penangkap inti dan sepatu yang lebih rendah akan dihapus dan inti meluncur keluar dari laras dalam dan dipotong menjadi 3 bagian kaki. Di daerah di mana lembut, formasi tak terkonsolidasi berintikan, liner plastik didorong keluar dari laras dalam dan dipotong menjadi bagian seperti yang dihapus di atas catwalk. Bagian ini ditandai dengan garis-garis orientasi, nama baik, dan kedalaman coring. Lubang kecil biasanya dibor ke setiap bagian 3 kaki melalui PVC / fiberglass / aluminium kapal untuk melampiaskan setiap gas yang terperangkap. Lubang ini kemudian direkam ditutup sebelum mengangkut. Inti dikemas dalam es kering untuk melumpuhkan cairan pembentukan dan disiapkan untuk pengiriman. Pembekuan inti di lokasi dengan baik dan menjaganya agar tetap beku di seluruh pengiriman dan pengambilan sampel fase akan meminimalkan gangguan sampel. Inti juga dapat distabilkan dengan resin atau gypsum. Ketika menarik inti melalui meja putar, Draeger Tabung detektor akan digunakan untuk menentukan apakah inti mengandung H 2 S. Jika bekerja di daerah H2S, semua personil di lantai rig akan mengenakan alat bantu pernapasan mandiri (SCBA) sebelum menarik inti melalui meja putar. Coring Tinggi Angle Lubang Coring sudut tinggi dan sumur horizontal akan memerlukan perubahan dalam coring perakitan khas. Bila menggunakan mekanisme downhole rotary drive, alat MWD, dll, bola konvensional untuk menutup barel batin tidak dapat dipompa ke bawah. Katup pelepas batin khusus harus dipasang di permukaan karena tidak mungkin bahwa bola akan tetap duduk di sumur horizontal. Jangan gunakan MWD atau motor saat coring. Dorong dan radial bantalan tambahan harus dibangun ke dalam perakitan coring juga untuk mencegah barel batin dari berputar. Stabilisasi internal barel batin untuk meminimalkan lentur nya di dalam laras luar mungkin juga diperlukan. Adalah bijaksana untuk menjalankan hanya 30 kaki inti panjang barel pada kebanyakan kasus, kecuali kondisi yang sangat menguntungkan. Fiberglass barel batin harus dipertimbangkan untuk mengurangi gesekan dari inti di sisi bawah dinding bagian mana inti bertumpu karena memasuki. Perintah berjalan logis, dengan GR run pada setiap log untuk kontrol mendalam, adalah: 1. IES atau IES-Sonic yang diperlukan; Sebuah barel core dengan benang torsi tinggi direkomendasikan untuk coring di sumur sudut yang lebih tinggi. Jenis barel memungkinkan coring dalam formasi yang lebih sulit, dan akan memungkinkan lebih banyak torsi yang harus diberikan kepada kepala inti. Ini thread torsi tinggi tidak mengubah kekuatan tubuh atau mengurangi ukuran inti. Sebuah prosedur penanganan inti rinci akan diberikan oleh Geologi berdasarkan tujuan coring dari sumur dan jenis analisis inti yang diperlukan. 8.3 WIRELINE PROGRAM LOGGING Sebuah program logging wireline, yang menentukan jenis kayu yang akan dijalankan, interval penebangan, dan urutan di mana untuk menjalankan log akan dimasukkan dalam prosedur pengeboran yang berlaku. Logging Urutan Untuk mengurangi waktu rig dan menyelesaikan sebanyak berjalan logging sebanyak mungkin sebelum perjalanan udara, Operasi Pengawas dan wellsite geologi harus benar-benar membahas berbagai log dan urutan yang tepat di mana mereka yang akan dijalankan. Jika ada pertanyaan, Operasi Pengawas harus memberitahukan Operasi Inspektur. 2. GR dan / atau FDC / CNL yang diperlukan; 3. Pendingin perjalanan jika diperlukan; 4. MDT / RFT sebagai diperlukan; 5. Dipmeter yang diperlukan; 6. survei Velocity jika diperlukan. 1. Pendingin perjalanan jika diperlukan; 2. Core dinding samping yang diperlukan; Timbangan yang benar (5 "atau 1") untuk setiap log harus didiskusikan dengan insinyur logging dan diperiksa untuk mencegah harus login kembali dengan baik. Insinyur logging harus diinstruksikan untuk melaporkan kepada Pengawas Operasional setiap hambatan pada berjalan logging berturut-turut dan menempel atau spudding dengan alat logging. Pedoman Logging Wireline 1. Pertemuan pra-pekerjaan akan dilakukan dengan insinyur penebangan sebelum memulai setiap pekerjaan logging. Perusahaan persyaratan teknis untuk penebangan dan program penebangan tertentu harus dibahas, bersama dengan prosedur keselamatan untuk penanganan alat radioaktif dan senjata sidewall inti (SWCs). 2. Penebangan Insinyur akan merekam data logging digital dan memberikan jumlah yang diperlukan salinan log akhir sesuai dengan program logging dan untuk kepuasan ahli geologi wellsite. 3. Dua termometer akan hadir pada setiap run logging. 4. Sebuah menjalankan perangkat kabel-kepalaketegangan, jika tersedia, untuk membaca ketegangan yang sebenarnya pada soket tali ("titik lemah" dari sistem) harus dijalankan. 5. Batas waktu stasiun harus ditetapkan sebelum menjalankan alat RFT dengan mempertimbangkan kondisi lubang dan pengalaman sebelumnya di daerah tersebut. Biasanya sampel harus diambil di zona terdalam dari bunga pertama dan sampel berikutnya diambil sebagai alat ini berhenti sumur bor untuk mengurangi potensi mencuat wireline. Namun, mungkin tepat bervariasi urutan, untuk memastikan interval prioritas tertinggi diuji, dalam hal kondisi lubang yang merugikan mengurangi atau mencegah semua pencobaan yang diinginkan. 6. Periode selama pengelasan dan radio harus ditutup (saat menangani bahan peledak, selama log tertentu, dll) akan ditentukan. Selalu menutup radio ketika alat ini adalah pada atau di atas BOP stack. 7. Perjalanan wiper untuk sepatu casing biasanya harus dibuat dan lubang harus diedarkan bersih sebelum menarik keluar dari lubang untuk penebangan. Sebuah tinggi gel menyapu viskositas untuk menghapus potongan longgar mungkin diperlukan selama sirkulasi ini. Sebuah pil logging dapat terlihat di bawah untuk membantu menangguhkan stek yang tersisa di lubang selama operasi penebangan. Pil ini akan dirinci dalam prosedur pengeboran yang tepat. 8. The Pengeboran Cairan Insinyur akan mengambil "Out" sampel cairan pengeboran sebelum berhenti beredar sebelum pooh untuk penebangan dan memberikan sampel cairan pengeboran, filtrat cairan, dan kue filter ke Logging Insinyur Wireline untuk merekam pada log. 9. Tangki perjalanan akan digunakan saat login untuk menjaga lubang penuh. Bor kru akan mencatat tingkat tangki perjalanan pada interval dijadwalkan (15 menit maksimum). The penebang Mud juga akan merekam tingkat tangki perjalanan pada interval yang sama sebagai crosscheck a. Jumlah cairan pengeboran diperlukan untuk mengisi lubang akan dilaporkan pada Daily Drilling Report. 10. Operasi Pengawas akan diberitahu setiap perubahan abnormal pada tingkat tangki perjalanan (mengingat volume line) ketika berjalan di / keluar dari lubang selama operasi penebangan. 11. Personil non-esensial akan menjauhkan diri dari semua alat logging, wireline, dan peralatan terkait setiap saat. 12. Hanya petugas yang berwenang akan memasuki unit logging selama operasi wireline. 13. Beban tidak akan bergerak melintasi kabel wireline logging ketika sedang berlangsung. 14. Sebuah wiper wireline akan digunakan untuk membersihkan kabel ketika sedang dihapus dari lubang. Membasuh air tidak akan digunakan karena hal ini akan mempersulit perjalanan pembacaan tingkat tangki. Wireline Perusahaan Tanggung Jawab 15. Informasi lubang caliper (jika tersedia) dan suhu logging lubang bawah akan dikirim ke Engineer Drilling dan Geologist secepat praktis selama operasi penebangan. 2. Pastikan bahwa alat yang cukup (primer dan backup) yang onboard rig pengeboran sebagaimana ditentukan dalam kontrak. 16. Semua tempat yang ketat dan tepian di lubang akan dicatat untuk kemungkinan reaming sebelum menjalankan casing. 17. Hanya penebangan personil perusahaan akan menangani setiap alat yang mengandung sumber radioaktif (misalnya, kepadatan neutron alat) atau bahan peledak. Sebuah ijin kerja diperlukan untuk radioaktif / peledak alat penanganan. 18. Logging personil perusahaan akan memakai perangkat monitoring radioaktif yang tepat dan mengambil tindakan pencegahan yang diperlukan ketika menjalankan alat logging dengan sumber radioaktif. 19. Semua personil di lantai rig akan mengenakan mandiri alat bernafas (SCBA) dalam H 2 daerah S sebelum mengeluarkan sampel dari alat pengambilan sampel seperti MDT / RFT (Atlas FMT). 20. Kontainer sampel yang mengandung H 2 gas S akan ditandai seperti itu. 1. Menjaga Unit Logging Wireline dan peralatan terkait onboard rig pengeboran sebagaimana ditentukan dalam kontrak. 3. Pastikan bahwa semua alat-alat yang dalam rangka operasi segera setelah tiba di wellsite tersebut. Memberikan sejarah pelayanan WL lingkungan merinci bekerja di dan layanan lalu. 4. Memberikan Operasi Pengawas dengan dimensi keseluruhan dan gambar masing-masing alat logging berjalan dalam lubang. 5. Pastikan bahwa Grapple overshot dan memotong jalur dan peralatan yang tersedia di rig pengeboran untuk setiap ukuran yang berbeda dari leher memancing sebelum menjalankan alat logging. 6. Pastikan bahwa penebangan alat yang tidak stasioner dalam lubang sumur kecuali ketika mengambil sampel / tekanan menggunakan MDT / alat RFT. 7. Beritahu operasi pengawas masalah lubang (drag berlebihan / kecenderungan menempel). 8. Pastikan bahwa geologi prospek memiliki semua log, kaset, dan / atau film strip, core dinding samping, dll, sebelum meninggalkan lokasi. 9. Pastikan bahwa daerah sekitarnya unit logging bersih dari semua puing-puing, sampah, dan jejak minyak atau pelumas sebelum meninggalkan lokasi. 10. Pastikan bahwa semua peralatan disimpan dengan benar (alat radioaktif di area penyimpanan yang ditunjuk, bahan peledak di majalah disetujui, dll). 11. Gunakan radioaktif dan ledakan checklist kesiapan dalam Program Manajemen Keselamatan. Terjebak Operasi Wireline Filosofi dasar untuk pemulihan alat logging terjebak adalah untuk memotong dan strip di kebanyakan kasus, khususnya di sumur directional dan alat sumber radioaktif. Pedoman berikut akan diamati ketika mencoba untuk alat terjebak gratis: 1. Sebuah 75% kriteria akan digunakan untuk overpull maksimum alat terjebak / wireline (yaitu, overpull tidak akan melebihi 75% dari nilai baik soket tali atau wireline yang). Jika kabel kepala tegangan permukaan membaca-out tersedia, tegangan garis permukaan akan digunakan untuk menentukan tarik pada wireline, dan kabel kepala tegangan permukaan membaca-out dapat digunakan untuk menentukan jumlah tarikan pada soket tali. CATATAN : Jika peralatan mengambang telah dibor keluar dengan sedikit berukuran yang menghasilkan inti dari semen yang tersisa pada sendi sepatu, perhatikan baris tempat duduk utama. Jika alat logging menjadi macet, menahan diri dari tarikan berulang pada wireline, untuk mencegah merusak dan memotong garis. Meskipun memakan waktu, pekerjaan striplebih memiliki risiko kurang dari pekerjaan wirelinememancing. 2. Semua personel akan dibersihkan dari lantai rig dan dari daerah manapun di bawah wireline ketika menarik pada wireline terjebak. 3. Persetujuan akan diperoleh dari Operasi Inspektur sebelum melebihi 75% kriteria overpull. 8.4 dinding samping OPERASI CORING Pedoman berikut akan diamati selama operasi sidewall coring: 1. Setelah gun inti dimuat, daerah sekitar gun (catwalk, dll) akan ditutup dan ditandai sebagai "Berbahaya Bahan Peledak Dalam Gunakan" sampai run dalam lubang. 2. Radio diam akan dipertahankan pada semua radio dan setiap pengelasan harus ditutup pada rig pengeboran ketika memilih-up, meletakkan-down dan tersandung di lubang dengan senjata sidewall inti sampai senjata yang jauh di bawah mudline tersebut. 3. Semua helikopter dan perahu di daerah akan diberitahu untuk menjaga keheningan radio sampai pemberitahuan lebih lanjut. 4. Dasar pantai akan disarankan dari awal keheningan radio dan akhir zaman. 5. Semua personil non-esensial akan dibersihkan dari lantai rig saat menangani pistol inti di lantai rig. 6. Semua karyawan yang bekerja di bawah lantai rig (misalnya, daerah dek Texas rig dan baik bay / + 15 daerah dari platform) akan diberitahu dan dihapus dari daerah ketika menjalankan pistol inti dinding samping ke dalam sumur bor. Setelah pistol adalah di bawah garis lumpur, kerja normal dapat melanjutkan. Ketika menarik pistol SWC dari sumur bor dan pistol berada pada atau di atas garis lumpur tindakan pencegahan yang disebutkan di atas akan diambil. * CATATAN: Lihat EMDC Keselamatan Manual untuk direkomendasikan praktek kerja yang aman di Wireline Perforating dan bagian lain elektrik meledakkan Operasi. Wellsite Geologist Tanggung Jawab: 1. Pilih poin dinding samping inti dalam relatif mengukur bagian lubang untuk menghindari "menembak off peluru" dan meninggalkan puingpuing di dalam lubang. 2. Membuat deskripsi dari inti sidewall di Wellsite segera setelah bongkar senjata. 3. Pastikan bahwa Operasi Pengawas memiliki laporan tentang pemulihan peluru yang mencakup jumlah misfires, jumlah peluru yang tersisa di lubang, jumlah core pulih, setiap bagian gun lainnya yang tersisa di lubang, dan kedalaman semua tembakan. 5. WIRELINE RADIOAKTIF SUMBER Lihat Program Manajemen Keselamatan 6. MWD / LWD LOGGING Logging Sementara Drilling (LWD) tujuan adalah: Memberikan korelasi real time dan deteksi tekanan. Memperoleh informasi untuk keputusan operasional awal. Gunakan sebagai pengganti atau asuransi untuk log wireline yang mungkin lebih mahal. Gunakan untuk mengevaluasi sumur yang sangat menyimpang di mana wireline logging tidak mungkin. Log LWD adalah log yang paling umum di Teluk Meksiko karena lubang sudut dan directional kendala. Alat Penempatan / stabilisasi 1. Alat MWD / LWD harus ditempatkan sedekat mungkin dengan sedikit praktis untuk mendapatkan data berkualitas tinggi sebelum erosi lubang dan invasi, dan untuk memfasilitasi perburuan normal tekanan, kursi casing, dan poin inti. 2. Alat MWD / LWD dengan stabilizer pisau terpisahkan harus digunakan jika dekat bit stabilizer perlu. Pipa terjebak Alat MWD / LWD harus dijalankan dekat bit sejak diameter dalam alat akan mencegah akses wireline untuk bebas menunjuk terjebak pipa. Beberapa sistem memungkinkan wireline bagian setelah mengambil paket elektronik. Penggunaan layar downhole tepat di atas MWD untuk mencegah jamming dapat digunakan tapi bisa menghilangkan mengambil sumber atau elektronik dalam hal terjadi BHA terjebak. Keputusan layar DP harus disetujui oleh Operasi Inspektur. Filter Layar & Tarif Arus 1. Filter layar pada debit pompa lumpur harus menjadi ukuran untuk menghilangkan kotoran apapun yang mungkin menyebabkan masalah dalam alat LWD (lihat Op Tek Buletin). 2. Jangan menggunakan layar filter dalam pipa bor pada setiap sambungan. Menempatkan layar filter di dalam pipa bor pada setiap koneksi akan mencegah penggunaan alat wireline jika pipa bor menjadi terjebak atau selama operasi kontrol dengan baik. Penggunaan layar penyaring downhole tepat di atas MWD diizinkan, tetapi dapat mencegah pengambilan sumber atau elektronik. Penggunaan layar downhole harus dikoordinasikan dengan Operasi Inspektur. 3. The MWD / LWD daya turbin (jika tidak baterai dioperasikan) harus menjadi ukuran untuk mendapatkan berbagai laju aliran yang dibutuhkan untuk pengeboran bagian lubang diharapkan akan menembus di jalankan itu (berkoordinasi dengan personel perusahaan jasa). Selain itu, persyaratan tekanan hidrolik MWD / LWD peralatan harus dimodelkan dan dimasukkan ke dalam pengeboran hidrolik. Penanganan 1. The MWD / LWD tray transportasi akan digunakan untuk gerakan alat LWD dari kapal suplai dan sekitar rig pengeboran. 2. Hati-hati harus dilakukan ketika bergerak alat MWD / LWD ke lantai rig untuk mencegah pukulan yang tidak perlu atau guci yang dapat menyebabkan kerusakan internal. Alat-alat ini tidak memiliki ketebalan dinding kerah bor dan mereka dapat menekuk cukup mudah. Penanganan yang kasar dapat merusak paket elektronik internal dari alat. 3. Hanya petugas layanan MWD / LWD akan menangani alat seperti beberapa log LWD memiliki bahan radioaktif. Sirkulasi kehilangan Material (LCM) Pilihan pengobatan sirkulasi hilang terbatas dengan alat MWD / LWD di lubang (memeriksa dengan personil LWD untuk rincian alat khusus). Jika sirkulasi parah hilang diharapkan, alat MWD / LWD tidak boleh digunakan. Alat ini beredar sangat mahal dan kalah dapat dengan mudah menghasilkan pipa terjebak dan hilangnya alat atau kerusakan pada alat. Harus kehilangan sirkulasi terjadi dengan alat MWD / LWD di dalam lubang, langkah-langkah berikut harus diambil Jika kembali kehilangan diharapkan, ukuran dan set-up yang MWD / LWD dan motor yang berlaku untuk mengakomodasi konsentrasi tinggi baik untuk LCM menengah. Tarik untuk sepatu casing dan membiarkan lubang menyembuhkan cukup untuk POOH dan meletakkan alat jika mungkin. Jika perlu, pompa halus atau menengah LCM kelas tercampur. Batas LCM (nutplug) untuk konsentrasi maksimum sekitar 30 ppb baik, atau 20 ppb media ketika memompa melalui alat MWD / LWD. Untuk bahan LCM tertentu atau konsentrasi berkonsultasi dengan perusahaan jasa dan mengacu pada prosedur pengeboran yang berlaku. Alat MWD / LWD generasi yang lebih baru memiliki toleransi yang lebih tinggi untuk bahan sirkulasi hilang; tenaga pelayanan dapat memberikan perkiraan yang baik pada konsentrasi bahan setiap alat dapat menahan sebelum memasang. Beberapa alat dapat "dimatikan" dengan menyesuaikan laju aliran. Hal ini dapat mengurangi potensi kemacetan saat memompa LCM. Nah Kontrol Alat MWD / LWD harus memiliki kemampuan untuk mengedarkan laju aliran minimum 1000 GPM bila digunakan di bagian atas dari lubang di mana membunuh dinamis mungkin diperlukan. 8,7 MUD LOGGING dan stek SAMPEL Jasa lumpur logging akan ditentukan dalam prosedur pengeboran. Mud logging, yang juga merupakan bagian dari evaluasi formasi, sebelumnya telah dibahas dalam Bagian 7 dari manual ini. Stek sampel juga akan dikumpulkan, sebagaimana ditentukan dalam program pengeboran. Biasanya, beberapa set stek dicuci dan kotor sampel akan diperlukan. Sampel ini akan dikumpulkan pada interval yang ditentukan dalam program pengeboran. Catatan: Dimana penebang lumpur unit memiliki gas hidrogen makan Flame Ionization Detector (FID), tanda-tanda peringatan posting yang menunjukkan mudah terbakar / karakteristik ledakan gas. Periksa selang (biasanya Polyflow) setiap 2-3 bulan, dan mengganti jika sudah terjepit, rapuh, atau berubah warna dari warna yang jelas atau putih normal (OIMS manual Element 6). OPERASI CASING ________________________________________ ________________________________________ ______ 1. OPERASI CASING OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING 2. Casing Menjalankan 1 3. Casing Connection Make-up 5 4. Casing Checklist 5 PERTAMA EDITION MAY 2003 9.0 CASING & LINER OPERASI Untuk semua operasi pengeboran, casing atau kapal berjalan prosedur rinci akan disiapkan. Ketika rig siap untuk memiliki casing dikirim ke lokasi, Operasi Supervisor adalah untuk memanggil dan mengatur pengiriman dari dasar pantai .. Kecuali jika disebutkan dalam prosedur yang berlaku, pedoman operasi casing dalam bagian ini akan berlaku. Ini adalah tanggung jawab Pengawas Operasional untuk memastikan bahwa casing berjalan atau kapal menjalankan operasi dilakukan sesuai dengan pedoman dan persyaratan dalam manual ini dan / atau prosedur disetujui. Dalam kasus konflik antara manual ini dan prosedur yang telah disetujui, prosedur yang disetujui harus diikuti. Sebuah Analisis Keselamatan Kerja (JSA) akan selesai sebelum semua operasi casing / kapal dan semua personel yang terlibat dengan casing / kapal berjalan akan meninjau JSA. OIMS PERSYARATAN: Gunakan spreadsheet Excel untuk menghasilkan laporan casing penghitungan. Asli harus diteruskan ke Drilling Engineer dan harus dimasukkan dalam laporan akhir dengan baik (OIMS Pedoman Bagian 4). Selain itu, OIMS membutuhkan laporan casing penghitungan DRS mana mungkin. 9.1 CASING RUNNING Casing Pedoman Penyusunan 1. Pastikan rak pipa bersih dan dibersihkan dari puing-puing, tersandung bahaya, dan daerah licin. 2. Membongkar casing menggunakan metode yang tepat. Segera setelah bongkar casing, jumlah sendi akan dihitung dan dibandingkan dengan manifes kargo. Setiap perbedaan akan dicatat dan direkam. kru rig untuk memastikan bahwa semua personil memahami apa bidang koneksi adalah daerah penyegelan. 6. Casing akan melayang sementara di rak pipa untuk memeriksa dan menghilangkan kotoran internal. Drift OD biasanya API penyimpangan tetapi mungkin drift khusus (referensi prosedur yang berlaku). Rekomendasi drift 'bar (3' 1 bar hanyut biasanya digunakan di halaman pipa). 7. Semua casing akan diberi nomor dan diikat. Tegap dinding penopang ulir casing untuk berlian sebagai benang membuat hanya untuk berlian (1-2 inci sebelum thread runout pada akhir pin). Hal ini dapat mengakibatkan sepatu casing yang lebih dalam daripada yang diantisipasi jika pengukuran dilakukan untuk thread runout. Pastikan tali adalah untuk memperbaiki posisi pada casing. Gunakan benang lari keluar template untuk koneksi premium dan mengukur dari ujung pin benang. 3. Berat dan kelas masing-masing bersama casing akan diperiksa untuk memastikan bahwa casing yang tepat disampaikan (cek casing ID untuk memastikan casing berat badan yang benar disampaikan). 4. Pastikan casing memeras benar untuk pick up dan berjalan. 5. Thread pelindung akan dihapus dan benang dibersihkan jika perlu. Sebagian besar koneksi waktu akan "lapangan disiapkan" dan diolah dengan senyawa benang yang tepat di halaman sebelum mengirimkan ke lokasi. Casing, benang dan kopling akan diperiksa secara visual untuk setiap tanda-tanda kerusakan. Mengambil tindakan pencegahan khusus untuk mencegah kerusakan daerah segel pada sambungan ketika menghapus benang pelindung, pembersih dll Ulasan dengan 8. Sebuah laporan casing penghitungan akan disiapkan untuk setiap casing atau kapal run, menunjukkan jumlah sendi, casing deskripsi termasuk sendi jenis (berat, kelas), panjang bersama, kedalaman sendi, jenis sambungan, dan lokasi komponen casing tali utama (peralatan pelampung , sendi anjing, crossover, tag RA, centralizers, lampiran kepala sumur, dll). Salinan laporan akan disimpan di rig untuk referensi selama penebangan, penyelesaian, P & A operasi, dll 9. Setidaknya dua orang akan memeriksa penghitungan casing. 10. Saat menjalankan casing produksi, sendi anjing harus ditempatkan di atas puncak zona produktif mungkin desain dalam rangka memfasilitasi korelasi masa depan. RA (radioaktif) Tags mungkin juga berguna untuk memastikan dasi akurat di saat pengeboran sudut tinggi directional sumur atau ketika thread casing premium mungkin sulit untuk melihat dengan casing kerah locator log (misalnya CRA casing, koneksi terpisahkan). Penggunaan perangkat tersebut akan ditentukan dalam prosedur casing sesuai. Jika tag RA digunakan, menginstal setidaknya satu tag 50m di atas paling zona membayar atas. 11. Rathole harus cukup bawah sepatu casing untuk memungkinkan mengisi, bersama ekstra, dll pedoman umum tentang rathole tidak lebih dari +/- 50 'TVD dari kedalaman izin, cukup dalam untuk mendapatkan semua informasi yang diperlukan LWD bawah pasir bawah, atau cukup dalam sehingga peralatan pelampung tidak perlu dibor pada casing produksi. Rathole lebih penting untuk jenis mandrel gantungan di mana casing tidak direncanakan akan dipotong. Penyemenan Pedoman Aksesori 1. Kecuali ditentukan lain dalam prosedur casing atau kapal berjalan berlaku, dua sendi casing harus dijalankan antara sepatu mengambang dan mengapung kerah sebagai sendi float. Biasanya satu sendi dengan float kerah dibuat pada akhir dan benang terkunci dan satu sendi dengan sepatu mengambang dibuat pada akhir dan benang terkunci dirakit di halaman dan dikirim ke rig. Sebuah cadangan set peralatan pelampung juga dikirim ke rig lepas. 2. Semua koneksi sampai dengan dua sendi di atas pelampung kerah akan threadlocked. 3. Centralizers menjalankan, turbolizers, scratchers, keranjang semen, dll seperti yang dijelaskan dalam prosedur yang berlaku. Pedoman casing Menjalankan CATATAN: Lengkapi pertanyaan dalam Bagian 9.3 sebelum operasi awal penyemenan. 1. Sebuah lubang pembuka run dilakukan setelah TD dari semua bagian lubang sebelum menjalankan casing jika dianggap perlu. 2. Sebelum menjalankan casing, pertemuan perencanaan akan diselenggarakan dengan personel yang terlibat langsung dengan pekerjaan casing untuk memastikan bahwa personil kunci memahami tugas dan tanggung jawab khusus mereka. Prosedur casing berjalan akan ditinjau dan akan diverifikasi bahwa tanggung jawab pekerjaan dan tindakan pencegahan keselamatan yang jelas untuk semua personil. 3. Jika gantungan jenis mandrel casing direncanakan, string mendarat lengkap dengan kepala semen harus spasi jika mungkin, sehingga gantungan casing mandrel dapat menjalankan semua jalan melalui stack dan mendarat tanpa harus membuat sambungan sementara gantungan adalah di BOP. 4. Casing hanger dan alat wellhead berjalan akan hati-hati diperiksa dan diservis sebelum menjalankan. Alat-alat ini harus dibuat dan berdiri kembali derek jika mungkin sebelum perjalanan wiper sebelum menjalankan casing. 5. Bor string yang harus diikat keluar dari lubang setelah TD dari bagian lubang. Jika perbedaan itu ada, pipa harus kembali diikat di lubang pada lubang pembuka run. 6. Bintik-bintik ketat harus reamed, yang diperlukan, di perjalanan wiper sebelum penebangan. 7. Ketika menarik keluar dari lubang pada perjalanan terakhir sebelum menjalankan casing, kemudian mengganti set top dari domba pipa casing domba jantan dan menguji segel kap ketika keluar dari lubang sebelum menjalankan casing .. (Urutan di mana domba casing dipasang mungkin kebijaksanaan berubah pada Opt tersebut. Supt. berdasarkan kondisi baik saat ini.) Sebelum menarik keluar dari lubang di perjalanan wiper setelah penebangan, cairan pengeboran akan dikondisikan untuk memastikan bahwa itu adalah hampir bebas dari stek dan kepadatan seragam, dengan sifat diterima. Berdasarkan kondisi lubang, pil casing berjalan dapat melihat setelah pengkondisian sifat fluida dan sebelum menarik keluar dari lubang. 8. Metode kontrol baik utama adalah berat cairan. The annular pencegah akan digunakan sebagai sarana sekunder kontrol baik dengan domba casing sebagai metode ketiga selama casing operasi berjalan. Sebelum menjalankan casing, mengurangi tekanan regulator pada pencegah annular sesuai spesifikasi pabrikan untuk ukuran casing untuk mencegah runtuhnya casing. 9. Memakai bushing harus ditarik sebelum menjalankan casing. 10. Pastikan rating dari semua alat casing (laba-laba, elevator dan link) sudah cukup untuk casing berat string pada kedalaman total ditambah £ 200.000. dari overpull. 11. Memastikan bahwa katup pengaman pada casingby-pipa bor crossover pembukaan katup bola lengkap seperti katup Tiw. â € ¢ Melakukan uji fungsi dari katup pengaman pada casing-by-pipa bor crossover dan casing swedge sebelum menjalankan casing. Merekam ini tes fungsi katup pengaman pada IADC Laporan Harian dan laporan pagi. 12. Untuk liners berat, beban casing dan keterbatasan overpull akan dihitung untuk memastikan bahwa pipa bor memiliki kekuatan tarik yang cukup untuk memungkinkan untuk digunakan sebagai string pendaratan. 13. Bagian dalam sendi mengambang akan diperiksa untuk sampah hanya sebelum membuat up. 14. Peralatan mengapung akan diperiksa untuk operasi yang tepat setelah menjalankan kerah mengambang dan satu sendi dari casing dengan mengisi casing dengan cairan dan mengambil untuk memastikan bahwa cairan tetes keluar dari casing dan tetap keluar setelah menjalankan itu kembali lubang (jika peralatan auto-Fill tidak digunakan). 15. Casing akan diisi secara teratur saat mengambil sendi berikutnya dan mengisi itu harus dikonfirmasi secara berkala. Casing harus diisi dengan cairan pengeboran digunakan saat pengeboran lubang. Berhenti di lubang cased dan mengisi casing sepenuhnya sebelum menjalankan casing / kapal ke dalam lubang yang terbuka. Setelah casing dalam lubang terbuka mengisi casing sebagai run tapi tidak berhenti untuk mengisi casing. (Penggunaan mengisi alat dapat membantu dalam casing mengisi.) 16. Jumlah yang benar bagian dalam slip dan klem akan digunakan untuk casing ukuran makhluk run. 17. Klem keselamatan akan digunakan sampai ada cukup berat untuk menahan slip bawah dan menangkal efek apung casing di lumpur (efek apung dapat mengusir casing dari slip dan casing bisa jatuh downhole). 18. Pengembalian akan dipantau (menonton untuk indikasi sumur mengalir) dan kecepatan lari disesuaikan untuk meminimalkan kehilangan cairan pengeboran untuk lubang. Setiap pembatasan casing kecepatan lari akan ditentukan dalam Program Pengeboran. 9.2 CASING CONNECTION MAKE-UP 1. Make-up torsi akan ditentukan dalam Program Pengeboran berdasarkan jenis sambungan, lapisan pabrik pada benang, dan senyawa benang yang akan digunakan. Untuk semua sumur lepas pantai menggunakan API STC dan koneksi LTC untuk setiap string, nilai EMURC Torque-Posisi akan digunakan. Untuk API koneksi BTC, menggunakan EMURC Torque-Posisi nilai Manual dan Torque Posisi untuk ukuran casing kurang dari atau sama dengan 7-5 / 8 ". Untuk koneksi BTC di casing ukuran lebih besar dari 7-5 / 8" menggunakan EMURC torque Posisi Pedoman metode 4-T. Untuk koneksi premium, koneksi akan dibuat per direkomendasikan prosedur produsen. (Referensi Operasi Teknologi Buletin 98-68 direvisi 1998/11/09.) Koneksi API Modified dengan cincin meterai harus dijalankan dengan hati-hati dan sesuai dengan Torque-Posisi catatan Manual. 2. Senyawa benang dinilai untuk suhu layanan dan sesuai dengan spesifikasi API akan digunakan. 3. Gunakan tong dipasang komputer untuk melacak setiap koneksi make-up. Perusahaan casing akan memastikan bahwa hard copy dari kurva make-up untuk semua sendi menjalankan dikirim ke Drilling Engineer. The Pengeboran Insinyur adalah untuk memastikan bahwa laporan ini di file baik dalam hal masalah casing depan ditemui (misalnya casing kebocoran) dan make-up torsi perlu ditinjau. 9.3 CASING DAFTAR T i d a k Selubung 1. Apakah kondisi casing diterima? Y a 5. Apakah kelebihan casing cukup di papan? 2. Apakah ukuran dan kondisi casing drift yang memadai? T i d a k Y a 6. Apakah penomoran sendi casing yang benar? 3. Apakah casing telah melayang, diikat, dihitung dan diverifikasi? 7. Apakah benang jenis senyawa dan kuantitas diterima? T i d a k Y a Operasi 4. Apakah kondisi benang casing diterima? T i d a k Y a 5 . Apakah lantai bor dan catwalk jelas peralatan non-esensial? 1. Apakah keuntungan teoritis dan casing mengisi perhitungan volume yang benar? T i d a k Y a 6 . Telah pertemuan keamanan telah digelar sebelum rigging up peralatan? 2. Apakah isi-up dan volume perpindahan yang benar? T i d a k Y a 7 . Apakah lubang dipantau pada tangki perjalanan sambil menyelesaikan rig up? 3. Apakah pengurangan tekanan hidrostatik karena volume spacer masalah? 8 . 4. Apakah sebanyak rig up selesai mungkin selama HO run, dan operasi penebangan? Ya Tidak Apakah Driller tahu kecepatan casing jalannya yang tepat? T i d a k Y a T i d Y a 3. Apakah peringkat laba-laba / elevator / link diterima untuk pekerjaan casing? 9 . Apakah tangan Tong mengetahui kecepatan make-up yang benar dan torsi? T i d a k Y a Casing Menjalankan Peralatan 4. Apakah tong mati ukuran yang benar dan dalam kondisi baik? 5. Apakah penjepit-on pelindung ukuran yang benar dan kuantitas pada 1. Apakah semua peralatan casing berjalan onboard dan dalam kondisi yang dapat diterima? papan diterima? 6. Apakah kekuatan tarik dari string pendaratan yang cukup? 2. Apakah casing slip ukuran yang benar dan dalam kondisi baik? T i d a k Y a T i d a k Y a T i d Y a Meningkatkan izin penggunaan stabbingi papan & review JSA. Penyemenan Peralatan / Aksesori T i d a k 7. Apakah casing / bor benang pipa Crossover cocok casing? Y a 1. Apakah penyemenan kepala ukuran yang benar, benang, dan dalam kondisi baik? 8. Apakah thread swedge beredar sesuai casing? 9. Telah katup pengaman telah digerakkan, kiri dalam posisi terbuka, dan dicatat 2. Apakah selam casing dan swedges ukuran yang benar, benang, dan dalam kondisi baik? laporan / pagi IADC? 10. Telah papan penusukan telah diperiksa dan ditemukan untuk dapat diterima? 3. Apakah inspeksi visual operasi pengawas dari semua benang lainnya lengkap? T i d a k Y a T i d a k Y a T i d Y a 4. Apakah peralatan float benar ukuran, berat, dan benang? T i d a k a k 5. Apakah centralizers ukuran yang benar, nomor, dengan cukup berhenti berdering? 9. Memiliki colokan wiper diperiksa dan terpasang dengan benar di kepala semen? 6. Apakah ada cukup Thread-Lok dan Threadkote atau setara untuk pekerjaan casing? ExxonMobil Drilling Superintendent untuk memverifikasi pemuatan tepat colokan di kepala. 7. Apakah mengapung sepatu dan mengapung kerah bersih dan bebas dari kotoran dan semen BAHAN REFERENSI 1. API Bul 5 A2, "API Bulletin pada Thread Senyawa untuk Casing, Tubing, dan Pipa Line," American Petroleum Institute, Dallas, Texas, Fifth Edition, April 1972. tidak rusak? 8. Apakah sendi arahan / penyemenan kepala terdiri? 2. API RP 5C1, "Praktek Direkomendasikan untuk Perawatan dan Penggunaan Casing dan Tubing", American Petroleum Institu te, Dallas, Texas, Kelimabelas Edition, 31 Mei 1987. 3. API Spec 5B, "Spesifikasi Threading, Mengukur, dan Thread Inspeksi Casing, Tubing, dan Pipa Line," American Petroleum Institute, Dallas, Texas, Ketigabelas Edition, 31 Mei 1988. 4. Hari, JB, Moyer, MC, dan Hirshberg, AJ, "Metode Makeup Baru untuk Koneksi API," SPE / IADC Y a T i d a k 18.697, makalah yang dipresentasikan pada SPE / IADC Drilling Conference, New Orleans, LA, Maret 1989. 5. ExxonMobil Hulu Penelitian Perusahaan, TorquePosisi Pedoman Ketiga Edisi 1 Desember 999, Wells dan Divisi Bahan. 6. EUSADO, Operasi Buletin Teknis 98-68, direvisi November 9, 1998. Penyemenan 1. Penyemenan 2. Umum 1 3. Penyemenan Pedoman 1 4. Primer Cementing 3 5. Remedial Cementing 5 6. Penyemenan Checklist 6 7. Referensi 7 Lampiran GI ExxonMobil Pedoman Pengujian Semen ________________________________________ ________________________________________ ______ OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING PERTAMA EDITION MAY 2003 1. UMUM Bagian ini memberikan pedoman dan prosedur penyemenan operasi. Bila mungkin, grafik perekam penyemenan (tekanan, volume, kepadatan vs waktu) harus digunakan untuk semua operasi (yaitu casing cementing, memeras penyemenan, pengujian tekanan garis dan peralatan, PIT, dll). Grafik harus dijelaskan dengan semua peristiwa yang signifikan seperti pengujian tekanan, memompa spacer, pencampuran memimpin dan ekor lumpur, perpindahan, menabrak steker, dll Untuk semua Operasi Pengeboran, prosedur penyemenan rinci akan ditulis. Untuk jenis lain dari operasi penyemenan prosedur harus ditulis dengan menggunakan panduan yang ada dalam bagian ini sebagai referensi (misalnya busi seimbang dan colokan KO). 2. Penyemenan PEDOMAN Perencanaan pekerjaan 1. Sebelum operasi penyemenan, pertemuan perencanaan harus dilakukan dengan semua personil yang terlibat langsung dengan pekerjaan semen untuk memastikan bahwa personil kunci memahami tugas dan tanggung jawab khusus mereka. Prosedur penyemenan harus ditinjau dan diverifikasi bahwa tanggung jawab pekerjaan dan tindakan pencegahan keselamatan yang jelas untuk semua personil. 2. Sebuah sistem komunikasi yang baik antara lantai rig dan unit semen diperlukan. Telepon rig atau radio genggam adalah alat komunikasi yang dapat diterima. 3. Menetapkan satu individu (sebaiknya Operasi Supervisor) untuk mengkoordinasikan dan operasi langsung antara lantai rig dan unit penyemenan. 4. Semua lini termasuk manifold semen harus tekanan diuji dengan tekanan yang ditentukan dalam prosedur penyemenan berlaku sebelum penyemenan. Untuk casing penuh tali penyemenan baik unit semen atau pompa rig dapat digunakan untuk perpindahan. Sebagai pedoman, menggunakan unit semen untuk perpindahan <200 bbls atau di mana casing tidak akan dibor keluar. Gunakan pompa rig untuk perpindahan> 200 bbls atau jika string akan dibor keluar. Setiap pekerjaan harus dipertimbangkan secara individual berdasarkan kondisi pada saat pekerjaan semen. Untuk liners, pompa penyemenan harus digunakan sampai steker atas diluncurkan, maka pompa rig dapat digunakan, jika diinginkan, untuk menyelesaikan perpindahan dan benjolan steker. Jika tekanan tinggi (yaitu> 3000 psi) diantisipasi mungkin terbaik untuk melanjutkan perpindahan dengan unit penyemenan. 5. Semua peralatan penyemenan, termasuk densiometer, harus benar-benar diperiksa untuk memastikan itu adalah dalam perbaikan dan fungsi yang baik benar. 6. Informasi lubang calliper dan suhu logging lubang bawah harus dikirim ke Drilling Insinyur sesegera praktis selama penebangan operasi untuk menyelesaikan volume semen dan mengkonfirmasi semen penebalan kali. Kaliper lubang dapat didukung dari data yang LWD sama dan beberapa alat wireline logging. Pemindahan 1. Perpindahan semen dapat dilakukan dengan baik unit semen atau pompa rig. Volume perpindahan, waktu kerja secara keseluruhan, tingkat pompa yang diinginkan, dan tekanan diharapkan adalah penting untuk dipertimbangkan saat memutuskan memompa digunakan untuk perpindahan. Berikut ini adalah panduan umum: Untuk bagian-string penyemenan, pompa penyemenan harus digunakan untuk seluruh operasi. Stinger harus dijalankan untuk sekitar 60 kaki di atas pelampung sepatu / kerah. Semen harus mengungsi ke sekitar 20 kaki di bawah stinger. 2. Jika semen harus mengungsi dengan pompa rig, pompa harus dikalibrasi menggunakan tangki perjalanan sebelum memulai pekerjaan semen. Sebagai kontingensi mud pit perpindahan untuk diamati untuk kehilangan cairan saat memompa dengan pompa rig. 3. Pastikan unit semen siap untuk menyelesaikan perpindahan semen jika pompa rig mengalami masalah dan sebaliknya. Memiliki kemampuan untuk beralih dari pompa rig ke pompa semen yang diperlukan. 4. Jangan terlalu menggantikan semen oleh lebih dari 50% dari volume sendi float. Jika casing yang akan dibor keluar, tidak lebih menggusur sama sekali. 5. Dua atau lebih mandiri perhitungan volume yang harus dilakukan pada perpindahan. 6. Tekanan harus dipantau dan dicatat untuk pekerjaan semen seluruh. Hal ini akan membutuhkan meninggalkan garis terbuka ke unit semen jika semen dipindahkan dengan pompa rig. Semen Kepala / Manifold 1. Semua katup pada semen kepala / manifold, serta mekanisme melepaskan, harus diperiksa untuk memastikan mereka berada di urutan kerja yang tepat dan bahwa perangkat keselamatan di tempat untuk mencegah peluncuran dini colokan. 2. Gunakan perpindahan positif untuk memulai busi (yaitu tidak bergantung pada gravitasi atau jatuh kadar cairan). Peluncuran Plug harus disaksikan oleh Pengawas Perusahaan atau utusannya. 5. Jika casing / kapal yang akan membalas atau diputar selama pekerjaan semen, atas semen berkendara kepala / Peringkat berjenis harus memadai untuk mendukung casing dan mendarat berat tali ditambah £ 100.000. dari overpull. Penyemenan Nah Kontrol 1. Menguji semua garis semen dan semen sebagaimana ditentukan dalam berlaku Cementing Prosedur. 2. Ketika menggunakan spacer unweighted, memastikan bahwa penurunan tekanan hidrostatik tidak cukup memadai untuk memungkinkan masuknya untuk masuk di mana saja di seluruh sumur bor. 3. Pastikan beredar swedges (Casing x Drill Pipe dan Casing x setengah laki-laki dari Chiksan Union) yang tersedia di lantai untuk sesuai ukuran dan benang casing. Fungsi menguji katup ini dan dokumen laporan pagi dan pada IADC. Pengatur jarak 1. Spacer akan digunakan pada semua pekerjaan semen. 3. Gunakan menalangi cukup lama untuk kait elevator di bawah kepala semen untuk memungkinkan balasan dari casing / kapal selama perpindahan dari semen. 2. Spacer air akan digunakan kecuali ditentukan lain dalam berlaku Cementing Prosedur. 4. Sebuah berjenis semen yang dirancang untuk sistem penggerak atas akan digunakan, jika berlaku. 3. Sebuah spacer pra-flush digunakan untuk menginduksi turbulensi, untuk membantu perpindahan lumpur yang baik, dan untuk membantu mencegah penyaluran. The postflush spacer digunakan untuk membantu mencegah kontaminasi semen. 10.3 PRIMARY penyemenan Primer Cementing Pedoman 1. Pastikan bahwa semen yang memadai di rig bersama dengan jumlah yang cukup cairan / aditif kering. Jika praktis, harus ada 50-100% kelebihan semen dan 100% kelebihan cairan / aditif kering di lokasi rig. 2. Pastikan bahwa fasilitas transfer dari P-tank ke unit semen beroperasi dengan benar. Pastikan Ptank telah menepuk-nepuk dengan udara yang jelas sebelum mentransfer. 3. Pastikan bahwa jalur udara tidak mengandung air (uap air atau air di jalur pasokan dapat menyebabkan penyumbatan selama transfer semen). 4. Setidaknya dua orang akan menghitung total volume pekerjaan semen, termasuk volume yang dibutuhkan untuk menggantikan steker atas ke float kerah. 5. Volume air campuran dipompa akan digunakan untuk menghitung volume aktual semen dipompa. Tidak pernah bergantung pada volume P-tank. 6. Beredar dan kondisi lubang sebelum penyemenan. Cairan pengeboran harus dikondisikan untuk memastikan bahwa itu adalah hampir bebas dari stek, gas yang kembali ke tingkat latar belakang dan bahwa itu adalah densitas seragam dengan sifat diterima. 7. Pastikan bahwa kepala semen / mekanisme melepaskan berjenis bekerja dengan benar dan bahwa personil akrab dengan operasi mereka. 8. Operasi Pengawas akan menyaksikan cementer yang memuat colokan wiper dalam penyemenan kepala / bermacam-macam. Disarankan bahwa pekerjaan semen dipompa dengan urutan sebagai berikut: steker bawah, preflush spacer, memimpin semen, ekor semen, atas steker, postflush spacer. 9. Memonitor pengembalian terhadap volume yang dipompa seluruh pekerjaan semen. Apa diduga kembali hilang selama operasi penyemenan harus dilaporkan pada laporan harian pagi, mencatat waktu kehilangan dan tekanan. Jalankan ECD menghitung perangkat lunak pada pekerjaan semen di mana pengembalian hilang adalah mungkin untuk tarif lagu perpindahan halus. 10. Bubur berat badan harus dijaga konsisten mungkin untuk menjaga dari memperluas atau memperlambat kali pengaturan. Aditif cair lebih sensitif terhadap fluktuasi berat daripada dicampur kering. 11. Berat bubur semen harus sering diperiksa menggunakan keseimbangan lumpur bertekanan untuk memverifikasi keakuratan alat ukur kepadatan pada unit semen. 12. Beberapa sampel, spasi seluruh pekerjaan, timbal dan ekor lumpur harus diambil selama penyemenan. Secangkir kopi styrofoam / kertas diisi tiga perempat penuh, disimpan dalam kawasan lindung adalah sampler memadai. 13. Setelah pencampuran semen, melepaskan steker atas dan pompa spacer dengan unit semen menempatkan volume kecil semen di atas plug wiper. Jika diinginkan, beralih ke pompa rig untuk menyelesaikan perpindahan. 14. Menggantikan casing volume yang dihitung atau sampai benjolan plug. Jangan lebih menggusur kecuali diperintahkan untuk melakukannya dalam prosedur penyemenan yang berlaku. 15. Berdarah tekanan casing ke nol cepat dan memeriksa mengapung. Jika mengapung tidak memegang, mencoba untuk rock mereka di kursi oleh repressuring string casing. Jika mengalir kembali berlanjut, ditutup di dan tahan tekanan pada casing setidaknya sampai sampel permukaan setup atau tidak arus balik terjadi. 10.4 penyemenan Remedial Penyemenan perbaikan kadang-kadang diperlukan untuk memperbaiki miskin kebocoran-off bawah casing sepatu, perbaikan casing atau kapal atas kebocoran, memeras off perforasi, dll teknik utama yang digunakan untuk operasi ini akan mengikuti prosedur yang sama dengan yang dijelaskan dalam prosedur inti dalam Bagian 10. Namun, diakui bahwa setiap situasi akan modifikasi yang berbeda dan luas untuk prosedur ini mungkin diperlukan. Ketika prosedur pemerasan disiapkan, dua bubur semen harus dirancang dan diuji. Jika tingkat injeksi yang rendah adalah semua yang dapat membentuk cairan kerugian lumpur semen rendah harus dipompa untuk mencegah semen dari menjadi dehidrasi karena diperas pergi. Jika tingkat injeksi yang tinggi dapat dibentuk, bubur semen dengan kehilangan cairan yang lebih tinggi (lebih murah) harus dipompa. Tergantung pada jenis pemerasan diperlukan, a-cairan rendah kerugian lumpur dapat diikuti oleh lumpur kerugian tinggi cairan. Prosedur Squeeze Braden Kepala 1. Rih dengan terbuka pipa berakhir bor (atau tubing stinger pada pipa bor tali kerja) ke bagian bawah yang diinginkan semen. 2. Beredar dan kondisi lubang sebelum penyemenan. Cairan pengeboran harus dikondisikan untuk memastikan bahwa itu adalah hampir bebas dari stek, gas yang kembali ke tingkat latar belakang, dan bahwa itu adalah densitas seragam dengan sifat diterima. 3. Rig up garis penyemenan untuk pipa bor, dengan katup pengaman pembukaan penuh dipasang di bagian atas string. Menguji garis semen untuk tekanan ditentukan dalam Prosedur penyemenan. 4. Pompa ditentukan preflush spacer (umumnya air), maka tempat plug semen seimbang dengan bagian atas minimal 165 'di atas sepatu casing. Mencoba untuk memutar bor string untuk meningkatkan perpindahan lumpur oleh semen. 5. Pompa postflush spacer (umumnya air) dan lumpur yang diperlukan untuk keseimbangan. k 6. Perlahan POOH sekitar 5 tribun atas puncak dihitung semen. Y a 7. Tutup BOP dan menekan volume semen ditentukan dalam Prosedur penyemenan dengan memompa lumpur ke bawah string kerja: 2. Apakah ada alat penanganan yang tepat untuk stinger di rig? Penyemenan Peralatan / Aksesori CATATAN: tekanan Squeeze tidak boleh melebihi tekanan tes casing. 8. Menutup dalam sumur sampai sampel permukaan telah menyiapkan atau sampai mencapai kuat tekan yang diinginkan. Jangan terus memompa, atau berdarah tekanan selama tertutup dalam periode. 9. Melepaskan tekanan pada string kerja, memeriksa aliran balik dan membuka BOP. Y a 1. Apakah colokan wiper ukuran yang benar untuk casing dan bebas dari luka dan / atau cacat? 10. Beredar pantat dan kondisi lumpur sampai kontaminasi semen di pengembalian lumpur diterima. POOH. T i d a k Y a 5. Penyemenan DAFTAR Memeras / Open Lubang Plug Kerja Strings T i d a k 2. Saksi pemuatan colokan wiper di penyemenan kepala / berjenis? Pasokan semen 1. Apakah ada (+/- 700 ') dari stinger (2-7 / 8 "atau 3-1 / 2" TBG, atau 3-1 / 2 "DP) di rig? 1. Apakah jenis yang tepat dan jumlah (50-100% berlebih jika praktis) semen di rig? T i d a k Y a Y a 1. Do cementer dan personil kunci setuju pada semua volume dan tarif? 2. Apakah jumlah yang memadai (100% kelebihan jika praktis) aditif onboard,? 2. Apakah cementer memahami rencana kontingensi / prosedur? 2. Pemeriksaan penyimpanan semen dan fasilitas transfer lengkap? 3. Apakah dua individu ditugaskan untuk mencatat volume perpindahan? Semen Pumping 3. Apakah ada sumber alternatif (s) semen jika garis pneumatik istirahat atau colokan? T i d a k Y a T i d a k Y a T i d a k Penyemenan Personil 1. Dalam kasus kegagalan pompa semen, adalah pompa rig siap mengambil alih? Y a Y a 2. Apakah efisiensi pompa rig dikenal dengan memompa ke dalam tangki dikalibrasi? Semen Mixing T i d a k a k 1. Apakah peralatan pencampuran semen bekerja dengan benar sebelum penyemenan? 1. Apakah kualitas dan pasokan dari campuran air semen memuaskan? 2. Apakah kalibrasi keseimbangan lumpur bertekanan menyelesaikan? 2. Apakah kualitas dan pasokan cairan perpindahan memuaskan? Pengujian tekanan / Keselamatan 3. Apakah densiometers beroperasi dengan benar sebelum penyemenan (dikalibrasi)? 1. Apakah garis Chiksan dari bermacam-macam semen aman dirantai untuk menghubungkan atau menalangi? 4. Apakah dicampur wadah sampel yang memadai tersedia? Y a T i d a k Y a T i d a k Y a T i d a k Mix Air / Pemindahan Cairan 2. Apakah pengujian garis semen untuk tekanan kerja yang ditentukan Y 3. Halliburton, Data Teknis Cementing Notebook 4. Halliburton, Cementing Tabel Handbook. selesai? 3. Memiliki berjenis semen menjadi tekanan diuji untuk tekanan kerja yang ditentukan? 4. Memiliki katup pengaman telah dipasang di atas tali kerja. 6. REFERENSI 1. EPR, Semen bubur Desain Pedoman 2. EPR, primer dan Remedial Cementing BAGIAN 10 - LAMPIRAN I EXXONMOBIL PENGEMBANGAN PERUSAHAAN DRILLING ORGANISASI 7-5 / 8 "CASING PELINDUNG SHOE SQUEEZE PROSEDUR 1. INFORMASI UMUM Bidang: fieldname Nah: WELLNAME Rig: RIGNAME 1.1 PERSETUJUAN Pengeboran Insinyur: Kantor: (____) ______ ______-Home: (_____) ________ DATE________ Mengawasi Engineer: Kantor: (____) _____-_______ Home: (_____) ________ DATE________ Operasi Inspektur: SETUJU DENGAN ATAU INGIN KLARIFIKASI ON DENGAN ENGINEER DAN / ATAU O perations S Kantor: (____) _____ ______-Home: (_____) ______ Pager: 1 -____-____-______ DATE________ UPERINTENDENT. D ISTRIBUTE PROSEDUR ke Rekayasa Arah S ignificant PERUBAHAN OPERASI DARI PROSEDUR MEMERLUKAN EVALUASI DAN DOKUMENTASI. D (Prosedur ini berisi teks tersembunyi yang luas, yang menyediakan penjelasan dan saran untuk menyesuaikan prosedur untuk aplikasi khusus. Komentar dan teks tersembunyi dapat dilihat dengan memilih View pada menu bar dan Komentar dari menu drop down. Simbol ayat (¶) pada standar toolbar juga ternyata teks tersembunyi dan mematikan.) Teknik / Operasi Komentar Revisi JWB / AMK 1.2 TUJUAN PROSEDUR DAN ISU UTAMA Prosedur ini memberikan rincian untuk memompa semen tambahan untuk memastikan integritas tekanan pada sepatu 7-5 / 8â € pelindung / produksi kapal atas / casing di 7500 '. Ini sepatu kapal atas / casing memerlukan tes tekanan sukses 2.500 psi dengan 12 lumpur ppg untuk mengebor depan (18,4 ppg EMW) (sesuai kebutuhan MMS). [Catatan]: Komentar tambahan yang berkaitan dengan isu-isu kunci yang sesuai. lapangan PERSONIL UNTUK PERALATAN DAN PROSEDUR VERIFIKASI. ISCUSS DENGAN ANGGOTA TIM YANG TEPAT DAN LENGKAP MOC FORMULIR. 1.3 SAFETY Sebelum memulai setiap jenis yang berbeda dari operasi, melakukan pertemuan keamanan dengan semua personel yang terlibat dan rencana job. Mempersiapkan dan meninjau JSA untuk semua operasi kritis. Rig Superintendent dan Toolpusher harus meninjau setiap JSA sebelum mulai bekerja untuk ketelitian, identifikasi bahaya yang tepat, dan mitigasi risiko. 1,4 DAFTAR BERLAKU Buletin OPTECH BUL ETI N NO MO R 26 Kegagalan untuk menggunakan direkomendasikan set sekrup w / EZ hasil punggawa semen dalam pekerjaan nelayan mahal. 56 Pertimbangan untuk kapal atas memeras penyemenan di OBM di Lu T HOROUGHLY BACA INI PROSEDUR DAN SELURUH MEMBAHAS SETIAP DETAIL ANDA MUNGKIN TIDAK TITLE Directional Terjebak "Fasdrill" punggawa pada baru-baru ini Pecan Pulau dengan baik. 98 1,6 DAFTAR ISI INFORMASI 1,5 SERVICE COMPANY SERVICE PERUSAH AAN LOKASI Houma Penyemenan Operasi Laboratorium BJ Service s New Orlean s New Orlean s Penjualan Houma Penyedia alat Squeeze Halliburt on New Orlean s New Orlean s PERWAKILAN 2. DESIGN DASAR 2.1 INFORMASI UMUM Casing Squee Sepatu ze Sebelum Pembukaan Setelah Squeeze Squeeze Alat Li ner Top Squeeze Sebelum Pembukaan Setelah Squeeze Squeeze Alat Peras ToolSqueeze Alat @ 9315 '@ 8800' A t a s L i n e r @ 9 1 5 0 ' Casing sepatu @ 9315 ' 2.2 STATUS LANCAR Pipa Set MD (ft) 24a € drive Pipa - 20A € Konduktor Casing - 16A € Permukaan Casing - 9-5 / 8â € pelindung Casing - 8.500â €: Drift diameter 9-5 / 8â € casing Casing di mana alat pemerasan akan diatur dalam: 7-5 / 8 "39,0 # 6,625" ID Casing Peringkat meledak w / (1,375) SF: - psi Casing berhasil diuji untuk - psi atau - ppg EMW @ casing sepatu / kapal atas Diperkirakan tekanan pori di casing sepatu: psi atau - ppg EMW Diperkirakan tekanan Frak di casing sepatu: Siku-siku maksimal dalam sumur bor di atas TVDdirencanakan alat pemerasan mendalam: 1,5  ° per 100 ' Lumpur Berat: - ppg Jenis lumpur (WBM / OBM): D EPTHS F ROM RKB Deskripsi MD (ft) TVD (ft) Mendalam untuk Top of Liner / Casing Sepatu 9315 9315 Kedalaman rencana Squeeze Packer 8915 8915 Direncanakan Tinggi Semen di Casing 150 200 Perkiraan TOC di casing 9165 9165 C APACITIES / D ISPLACEMENTS - psi atau - ppg EMW PIT diinginkan atau Liner Uji Top adalah - psi atau - ppg EMW Ukur an Berat No m. ID Sudut maksimum di sumur bor di atas direncanakan alat pemerasan mendalam: 5 ° 7-5 / 39 # - Dr ift ID - Panjan gnya 250 ' x Kapa sita s BP F Peminda han bbls 0,054 = 10.70 ---- Cf / sk hasil 8" 3-1 / 2 "JIK A - ---- Gal / sk mencampur air o F BHST 13. 3# S135 - - - 8915 ' x ---- Bbl Volume lumpur o F BHCT (jadwal sqz) - - - 2.3 SEMEN DATA RINGKASAN Semen Perusahaan: Dowell @ 512456-9874 Tingkat injeksi tinggi / rendah tekanan injeksi bubur x x ---- Bbl Volume air ---- Perkiraan pompa timePilot Uji Diminta Tingkat injeksi Rendah / injeksi Tinggi tekanan bubur Penyemenan Lumpur ---- Sacks Kelas "" Penebalan Waktu ---- Aditif psi 12 jam kuat tekan Penyemenan Lumpur Percontohan Tes t Hasil ---- Sacks Kelas "" Penebalan Waktu ---- Aditif psi 24 jam kuat tekan ---- Aditif cc kehilangan air / 30 min ---- Aditif psi 12 jam kuat tekan ---- Ppg slurryml / 250ml Air Gratis ---- Aditif psi 24 jam kuat tekan ---- Cf / sk hasil ---- Aditif cc kehilangan air / 30 min ---- Gal / sk mencampur air o F BHST ---- Ppg slurryml / 250ml Gratis Air ---- Bbl Volume lumpur o F BHCT (jadwal sqz) Pilot Tes t Hasil ---- Bbl Volume air Setelah menentukan bahwa meremas diperlukan, BH A tersandung dan diputar di bagian bawah casing beberapa kali untuk membersihkan ID casing semen yang tersisa. The SQZRETAINER akan ditetapkan dalam interval yang dibersihkan dengan stabilisator. Pompa berada di saat membersihkan casin g untuk menghilangkan stek semen. Rig beredar BU cukup sebelum POOH untuk memastikan semua stek semen telah dihapus. ---- Perkiraan pompa timePilot Uji Diminta 3. PROSEDUR 3.1 TOP OF LINER SQUEEZE - PACKER dibor 1. Membuat casing scraper dijalankan jika dianggap perlu sebelum menjalankan dengan SQZRETAINER. Casing kerja scraper secara menyeluruh di seluruh selang pipa di direncanakan SQZRETAINER kedalaman pengaturan. Beredar pantat up di bawah SQZRETAINER kedalaman pengaturan. POOH. Jika dipandang bahwa casing scraper run tidak diperlukan, berikut adalah reconcilers untuk tidak membuat casing scraper run: The SQZRETAINER akan ditetapkan di atas di mana semen ditandai ketika Rih. Sebuah dikemas BHA digunakan selama drillout tersebut. Penempatan Stabilizer adalah sebagai berikut: 8-1 / 2 "pengukur penuh dekat sedikit menusuk, 81 / 2" penuh pengukur menusuk 15 'di atas sedikit, dan 8-1 / 2 "penuh pengukur menusuk 45' di atas bit. 2. Pick up SQZRETAINER untuk CGOD CGWT casing dan TIH ke TOOLMD MD (305 â € ™ di atas puncak kapal). Set SQZRETAINER @ TOOLMD MD (tidak diatur punggawa bawah 10.005 â € ™ yang mana semen ditandai ketika berjalan di lubang untuk membersihkan). Pastikan bahwa punggawa tidak akan diatur dalam kerah casing. Verifikasi pengaturan dengan 15-20 kips berat di atas SQZRETAINER dan 500-1000 psi pada th e DP oleh casing annulus. 7,75 â € adalah OD maksimum dari SQZRETAINER Tekanan diferensial maksimum untuk SQZRETAINER = 5.000 psi Maksimum ditetapkan berat untuk SQZRETAINER = 50.000 lbs 3. Garis semen tes dan meremas manifold untuk 5.000 psi. (Uji terhadap T IW valve) 4. Tutup annular BOP dan tekanan pada DP oleh casing anulus ke 500-1000 psi. Membangun tarif injeksi pada 1/2, 1, 2, 3, dan 4 bpm tanpa melebihi tekanan injeksi 4500 psi (Engineer untuk mengomentari dasar untuk tekanan injeksi maksimum. Yaitu Untuk tetap dalam batas tekanan meledak bersih (7.927 psi w / 1,375 SF ) dari 9-5 / 8 â € casing dengan asumsi 15,7 ppg lumpur di sumur bor dan 9.0 ppg EMW back-up di belakang 9-5 / 8 â €). Memonitor annulus c arefully untuk respon tekanan indikasi packer atau DP kebocoran. Perhatikan bahwa CGOD CGWT casing terakhir diuji untuk 3.825 psi dengan 15,7 ppg lumpur, garis semen telah diuji untuk 5.000 psi, dan SQZTOOL berperingkat untuk 5.000 psi tekanan diferensial. Gunakan merencanakan teknik PIT tekanan rekor vs volume yang dipompa. Hubungi Operasi Inspektur dan Pengeboran Insinyur untuk membahas hasil tes injeksi (injektivitas akan menentukan jika perubahan yang diperlukan dalam desain semen atau pompa volume). Jangan melebihi tekanan tes atas kapal dari 3300 psi dengan 12,7 ppg lumpur (15,0 ppg EMW) jika injeksi belum ditetapkan pada saat ini. Ini bisa menunjukkan memuaskan uji kapal atas telah diperoleh. 5. Berdarah tekanan dari anulus, PU keluar dari SQZRETAINER, dan membangun tekanan membalikkan pada 3 - 6 bpm. 6. Campur dan menggantikan bubur berikut dengan menggunakan unit penyemenan [EUSADO20]: Catatan: Sementara menggusur semen turun DP sementara menyengat dari punggawa, laju aliran dapat berlari lebih cepat dari laju pompa karena tekanan Utube. Mengambil kembali melalui choke, jika perlu, sehingga tekanan yang kembali dapat diterapkan untuk mencegah semen dari beredar di DP sebelum menyengat ke SQZRETAINER. PUMP JADWAL SEBELUM menyengat KE SQZRETAINER Deskripsi 30 bbls pra-flush spacer (MCS-3) 38 bbls (150 karung) FL pemerasan bubur rendah (Lihat data Cement untuk resep) Mass a jenis 38 bbls (200 karung) tinggi FL (rapi) pemerasan bubur (Lihat 119 bbls lumpur data Cement untuk resep) 5 bbls Air Tawar 10 bbls pasca-flush spacer (MCS-3) Ini akan meninggalkan 2 bbls semen di atas SQZRETAINER di DP. (118 'di dalam DP di 38 bbls lumpur (lead posisi spacer ~ 15 bbls dalam DP di atas atas SQZRETAINER yang) SQZRETAINER yang) Posisi semen ~ 25 bbls dalam DP di atas SQZRETAINER. (1470 'di dalam DP di atas SQZRETAINER yang) 5a € 19,5 # S-135 kapasitas DP = 0,01701 BPF; 9-5 / 8â € 53,5 # kapasitas casing = 0,0708 BPF. 7. Tutup choke dan kemudian menyengat ke dalam SQZRETAINER. Set 15-20 kips berat di atas punggawa dan tekanan up 500 - 1.000 psi pada DP oleh casing annulus. Pompa tambahan 119 bbls dari 15,7 lumpur ppg di 4 bpm diikuti oleh 5 bbls dari air tawar ke DP. Ini akan meninggalkan 2 bbls semen di DP di atas ainer ret. Jangan overdisplace semen. PUMP JADWAL SETELAH menyengat KE SQZRETAINER Deskripsi Catatan: volume Pemindahan mengasumsikan 12 ppg FCS dalam G-series pasir di 10.000 'TVD. 5 bbls dari perpindahan air harus menyediakan sekitar 200 tekanan positif psi. Jika kendi baik atas atau tekanan permukaan naik ke 4500 psi selama operasi pemerasan dengan semen dalam pipa bor, lakukan langkah berikut: menyengat dari punggawa, POOH 2 berdiri, membalikkan beredar keluar 2 volume workstring pada tingkat maksimum sambil menjaga pipa bergerak (tidak melebihi tekanan tes casing dari 3520 psi sementara membalikkan). 8. PU dari punggawa dan membuang yang terakhir 2 bbls semen di atas SQZRETAINER (TOC @ ~ 9922 â € ™ MD. Hal ini membuat 2 8 'semen di atas SQZRETAINER yang). PU 2 berdiri dan membalikkan keluar pada tingkat maksimum yang mungkin (tidak melebihi tekanan tes casing dari 3520 psi sementara membalikkan). Membalikkan setidaknya 2 volume workstring dan menjaga pipa bergerak sementara membalikkan. 9. PO OH dan alat pengaturan LD punggawa. PU yang 8-1 / 2 â € membersihkan perakitan dan 15,7 8.3 TIH ke 9750 â € ™ MD. (180 'di atas TOC diharapkan). 10. Pastikan 18 jam telah berlalu sejak semen dipompa dan mencuci ke TOC. Bor semen / SQZRETAINER dan terus pengeboran turun ke LNROD kapal atas @ 10.255 â € ™ MD. Jangan memutar berlebihan di atas kapal untuk menghindari kerusakan wadah tie-back. C & C lumpur untuk membersihkan lubang sumur. Catatan: Jika semen usang dan / atau lembut ditemui sedalam 90 'di atas TOC diharapkan, PU 3 berdiri dan mengedarkan keluar 1 siklus. Memonitor kondisi lumpur / properti dan membuang semua lumpur buruk semen yang terkontaminasi. Hubungi Operasi Inspektur untuk membahas waktu WOC dan operasi maju jika semen tidak sulit. 11. Tekanan menguji LNROD atas kapal ke 2.300 psi dengan 15,7 ppg lumpur. Gunakan teknik PIT di 1/2 bpm dan merekam tekanan vs volume yang dipompa. Tahan tekanan tes selama 30 menit. Setelah tes, catatan volume lumpur berdarah kembali. POOH. menyeluruh di seluruh selang pipa di direncanakan SQZTOOL kedalaman pengaturan. Beredar pantat up di bawah SQZTOOL kedalaman pengaturan. POOH. Jika dipandang bahwa casing scraper run tidak diperlukan, berikut adalah reconcilers untuk tidak membuat casing scraper run: The SQZTOOL akan ditetapkan di atas di mana semen ditandai ketika Rih. Sebuah dikemas BHA digunakan selama drillout tersebut. Penempatan Stabilizer adalah sebagai berikut: 8-1 / 2 "pengukur penuh dekat sedikit menusuk, 81 / 2" penuh pengukur menusuk 15 'di atas sedikit, dan 8-1 / 2 "penuh pengukur menusuk 45' di atas bit. Setelah menentukan bahwa meremas diperlukan, B HA tersandung dan diputar di bagian bawah casing beberapa kali untuk membersihkan ID casing semen yang tersisa. The SQZTOOL akan ditetapkan dalam interval yang dibersihkan dengan stabilisator. Pompa berada di saat membersihkan casing untuk menghilangkan stek semen. Rig beredar BU cukup sebelum 12. Setelah tes berhasil, lanjutkan dengan prosedur pengeboran yang lebih dalam. 3.2 TOP OF LINER SQUEEZE - PACKER dpt 1. Membuat casing scraper dijalankan jika dianggap perlu sebelum menjalankan dengan SQZTOOL. Casing kerja scraper secara POOH untuk memastikan semua potongan semen telah dihapus. 2. Pick up SQZTOOL untuk CGOD CGWT casing dan TIH ke TOOLMD MD (305 â € ™ di atas puncak kapal). Set SQZTOOL @ TOOLMD MD (tidak menetapkan memeras terlalu l bawah 10.005 â € ™ yang mana semen ditandai ketika berjalan di lubang untuk membersihkan). Pastikan bahwa alat pemerasan tidak akan diatur dalam kerah casing. Verifikasi pengaturan dengan 15-20 kips berat di atas SQZTOOL dan 500-1000 psi pada DP oleh casing ann ulus. 7,75 â € adalah OD maksimum dari SQZTOOL Tekanan diferensial maksimum untuk SQZTOOL = 5.000 psi Maksimum ditetapkan berat untuk SQZTOOL = 50.000 lbs ppg EMW back-up di belakang 9-5 / 8 â €). Monitor anulus ca refully untuk respon tekanan indikasi packer atau DP kebocoran. Perhatikan bahwa CGOD CGWT casing terakhir diuji untuk 3.825 psi dengan 15,7 ppg lumpur, garis semen telah diuji untuk 5.000 psi, dan SQZTOOL berperingkat untuk 5.000 psi tekanan diferensial. Gunakan merencanakan teknik PIT tekanan rekor vs volume yang dipompa. Hubungi Operasi Inspektur dan Pengeboran Insinyur untuk membahas hasil tes injeksi (injektivitas akan menentukan jika perubahan yang diperlukan dalam desain semen atau pompa volume). Jangan melebihi tekanan tes atas kapal dari 3300 psi dengan 12,7 ppg lumpur (15,0 ppg EMW) jika injeksi belum ditetapkan pada saat ini. Ini bisa menunjukkan memuaskan uji kapal atas telah diperoleh. 3. Menguji garis semen dan manifold pemerasan ke 5000 psi. (Uji terhadap Tiw valve) 5. Tekanan berdarah off anulus, terbuka b ypass pada SQZTOOL. 4. Tutup annular BOP dan tekanan pada DP oleh casing anulus ke 500-1000 psi. Membangun tarif injeksi pada 1/2, 1, 2, 3, dan 4 bpm tanpa melebihi tekanan injeksi 4500 psi (Engineer untuk mengomentari dasar untuk tekanan injeksi maksimum. Yaitu Untuk tetap dalam batas tekanan meledak bersih (7.927 psi w / 1,375 SF ) dari 9-5 / 8 â € casing dengan asumsi 15,7 ppg lumpur di sumur bor dan 9.0 6. Campur dan menggantikan bubur berikut dengan menggunakan unit penyemenan: Catatan: Sementara menggusur semen turun DP dengan bypass terbuka, debit dapat berlari lebih cepat dari laju pompa karena tekanan U-tube. Mengambil kembali melalui choke, jika perlu, sehingga tekanan balik dapat diterapkan untuk mencegah semen dari yang beredar di atas SQZTOOL sebelum bypass ditutup. POMPA JADWAL SEBELUM MENUTUP BYPASS PADA SQZTOOL Deskripsi 30 bbls pra-flush spacer (MCS-3) 7. Tutup choke dan kemudian bypass pada SQZTOOL dan tekanan up 500 - 1.000 psi pada DP oleh casing annulus. Pompa tambahan 119 bbls dari 15,7 lumpur ppg di 4 bpm diikuti oleh 5 bbls dari air tawar ke DP. Ini harus meninggalkan TOC 250 'di bawah SQZTOOL, dan 250' di atas puncak kapal. PUMP JADWAL SETELAH MENUTUP BYPASS PADA SQZTOOL Deskripsi 38 bbls (150 karung) FL pemerasan bubur rendah (Lihat data Cement untuk resep) 119 bbls lumpur 38 bbls (200 karung) tinggi FL (rapi) pemerasan bubur (Lihat data Cement untuk resep) 5 bbls Air Tawar 10 bbls pasca-flush spacer (MCS-3) Ini akan meninggalkan TOC 250 'di bawah SQZTOOL, dan 250' di atas puncak kapal. 38 bbls lumpur (lead posisi spacer ~ 15 bbls dalam DP di atas SQZTOOL yang) Posisi semen ~ 25 bbls dalam DP di atas SQZTOOL. (1470 'di dalam DP di atas SQZTOOL) 5a € 19,5 # S-135 kapasitas DP = 0,01701 BPF; 9-5 / 8â € 53,5 # kapasitas casing = 0,0708 BPF. Catatan: volume Pemindahan mengasumsikan 12 ppg FCS dalam G-series pasir di 10000 'TVD. 5 bbls dari perpindahan air harus menyediakan sekitar 200 tekanan positif psi. Jika kendi baik atas atau tekanan permukaan naik ke 4500 psi selama operasi pemerasan dengan semen dalam pipa bor, lakukan langkah-langkah berikut: melepaskan alat pemerasan, POOH 5 berdiri, membalikkan beredar keluar 2 volume workstring pada Mass a jenis 15,7 8.3 P m a T g t tingkat maksimum (tidak melebihi tekanan tes casing dari 3520 psi sementara membalikkan), POOH 1 berdiri tambahan, mengatur packer dan menempatkan 500-1000 psi pada anulus. mungkin menjadi indikasi kebocoran baik dalam packer atau DP. (Diperbolehkan tekanan annulus maksimum adalah 1.585 psi dasar pada 21 EMW tes casing.) 8. Ragu-ragu meremas Tahap hingga 5.0 bbls semen ke dalam formasi. Pompa di 1,0 bbl di 1/4 bpm setiap 15 menit untuk pertama 10. Setelah menunggu 12 jam, tekanan hingga 500 psi selama tekanan squeeze akhir untuk memastikan semen diatur. Jika OK, tekanan rilis, menggeser SQZTOOL, dan beredar keluar. POOH. 3.0 bbls. Setelah itu, pompa di 1,0 bbl di 1/4 bpm setiap 60 menit untuk terakhir 2 bbls (total volume pemerasan = 5.0 bbls). Jika tekanan break-lebih terlihat sebelum menyelesaikan setiap tahap, berhenti memompa segera dan tahan tekanan apa pun yang dicapai untuk waktu tahap yang diperlukan sebelum melanjutkan dengan tahap berikutnya. Berhenti memompa pada titik apapun jika 1.675 psi tercapai (21,0 ppg EMW). Jika batas tekanan tercapai, menghentikan proses pementasan dan tahan tekanan akhir waktu WOC. Jika 1675 psi tidak tercapai setelah meremas 5.0 bbls, menghentikan proses pementasan dan tahan tekanan apa pun yang hadir. Perkiraan TOC setelah meremas ragu-ragu adalah 185 'di atas puncak kapal. 9. Tahan tekanan pemerasan akhir untuk 12 jam. Bor tekanan pipa harus meningkat karena ekspansi termal. Memungkinkan tekanan pipa bor untuk naik setinggi 4500 psi (21,0 ppg EMW) sebelum perdarahan off tekanan. Jika tekanan membangun ke 4500 psi, berdarah kembali ke 3500 psi sebelum melanjutkan untuk menahan tekanan pemerasan. Jika tekanan meningkat belakang di atas 500-1000 psi, 11. TIH dengan 8-1 / 2 "membersihkan perakitan ke tempat SQZTOOL ditetapkan dan mencuci ke TOC. Bor semen turun ke LNROD atas kapal @ 10.255 â € ™ MD. Jangan memutar berlebihan di atas kapal dan menghindari kerusakan wadah tie-back. C & C lumpur untuk membersihkan lubang sumur. Catatan: Jika semen usang dan / atau lembut ditemui sedalam 90 'di atas TOC diharapkan, PU 3 berdiri dan mengedarkan keluar 1 siklus. Memonitor kondisi lumpur / properti dan membuang semua lumpur buruk semen yang terkontaminasi. Hubungi Operasi Inspektur untuk membahas waktu WOC dan operasi maju jika semen tidak sulit. 12. Tekanan menguji LNROD atas kapal ke 2.300 psi dengan 15,7 ppg lumpur (20 ppg EMW di atas kapal). Gunakan teknik PIT di 1/2 bpm dan merekam tekanan vs volume yang dipompa. Tahan tekanan tes selama 30 menit. Setelah te st, rekor volume lumpur berdarah kembali. POOH. 13. Setelah tes berhasil, lanjutkan dengan operasi pengeboran per prosedur pengeboran yang lebih dalam. 3.3 SHOE SQUEEZE - PACKER dibor 1. Membuat casing scraper dijalankan jika dianggap perlu sebelum menjalankan dengan SQZRETAINER. W ork casing scraper secara menyeluruh di seluruh selang pipa di direncanakan SQZRETAINER kedalaman pengaturan. Beredar pantat up di bawah SQZRETAINER kedalaman pengaturan. POOH. Jika dipandang bahwa casing scraper run tidak diperlukan, berikut adalah reconcilers untuk tidak membuat casing scraper run: The SQZRETAINER akan ditetapkan di atas di mana semen ditandai ketika Rih. Sebuah dikemas BHA digunakan selama illout dr. Penempatan Stabilizer adalah sebagai berikut: 8-1 / 2 "pengukur penuh dekat sedikit menusuk, 8-1 / 2" penuh pengukur menusuk 15 'di atas sedikit, dan 8-1 / 2 "penuh pengukur menusuk 45' di atas bit. Setelah menentukan bahwa meremas diperlukan, BHA itu tersandung dan diputar di seluruh t ia bagian bawah casing beberapa kali untuk membersihkan ID casing semen yang tersisa. The SQZRETAINER akan ditetapkan dalam interval yang dibersihkan dengan stabilisator. Pompa berada di saat membersihkan casing untuk menghilangkan stek semen. Rig beredar BU cukup sebelum TOOH untuk memastikan semua potongan semen telah dihapus. 2. Pick up SQZRETAINER untuk CGOD CGWT casing dan TIH ke TOOLMD MD (305 â € ™ di atas sepatu). Set SQZRETAINER @ TOOLMD MD (tidak diatur punggawa bawah 10.005 â € ™ yang mana c ement tagged ketika berjalan di lubang untuk membersihkan). Pastikan bahwa punggawa tidak akan diatur dalam kerah casing. Verifikasi pengaturan dengan 15-20 kips berat di atas SQZRETAINER dan 5001000 psi pada DP oleh casing annulus. 7,75 â € adalah OD maksimum dari SQZRETAINER Tekanan diferensial maksimum untuk SQZRETAINER = 5.000 psi Maksimum ditetapkan berat untuk SQZRETAINER = 50.000 lbs 3. Garis semen tes dan pemerasan berjenis ke 5.000 psi. (Uji terhadap Tiw valve) 4. Tutup annular BOP dan tekanan pada DP oleh casing anulus ke 500-1000 psi. Membangun tarif injeksi pada 1/2, 1, 2, 3, dan 4 bpm tanpa melebihi tekanan injeksi 4500 psi (Engineer untuk mengomentari dasar untuk tekanan injeksi maksimum. Yaitu Untuk sta y dalam batas tekanan meledak bersih (7.927 psi w / 1,375 SF) dari 9-5 / 8 â € casing dengan asumsi 15,7 ppg lumpur di sumur bor dan 9.0 ppg EMW back-up di belakang 9-5 / 8 â €). Memantau anulus hati-hati untuk respon tekanan indikasi packer atau DP kebocoran. Perhatikan bahwa CGOD CGWT terakhir diuji untuk 3.825 psi dengan 15,7 ppg lumpur, garis semen telah diuji untuk 5.000 psi, dan SQZRETAINER berperingkat untuk 5.000 psi tekanan diferensial. Gunakan merencanakan teknik PIT tekanan rekor vs volume yang dipompa. Hubungi Operasi Inspektur dan Pengeboran Insinyur untuk membahas hasil tes injeksi (injektivitas akan menentukan jika perubahan yang diperlukan dalam desain semen atau pompa volume). Jangan melebihi tekanan tes PIT dari 3300 psi dengan 12,7 ppg lumpur (15,0 ppg EMW) jika injeksi belum ditetapkan pada saat ini. Ini bisa menunjukkan PIT memuaskan telah diperoleh. 5. Berdarah tekanan dari anulus, PU keluar dari SQZRETAINER, dan membangun tekanan membalikkan pada 3 - 6 bpm. 6. Campur dan menggantikan bubur berikut dengan menggunakan unit penyemenan: Catatan: Sementara menggusur semen turun DP sementara menyengat dari punggawa, laju aliran dapat berlari lebih cepat dari laju pompa karena tekanan Utube. Mengambil kembali melalui choke, jika perlu, sehingga tekanan yang kembali dapat diterapkan untuk mencegah semen dari beredar di DP sebelum menyengat ke SQZRETAINER. PUMP JADWAL SEBELUM menyengat KE SQZRETAINER Deskripsi 30 bbls pra-flush spacer (MCS-3) 38 bbls (150 karung) FL pemerasan bubur rendah (Lihat data Cement untuk resep) 38 bbls (200 karung) tinggi FL (rapi) pemerasan bubur (Lihat data Cement untuk resep) 10 bbls pasca-flush spacer (MCS-3) 38 bbls lumpur (lead posisi spacer ~ 15 bbls dalam DP di atas SQZRETAINER yang) Mass a jenis Posisi semen ~ 25 bbls dalam DP di atas SQZRETAINER. (1470 'di dalam DP di atas SQZRETAINER) 5a € 19,5 # S-135 kapasitas DP = 0,01701 BPF; 9-5 / 8â € 53,5 # kapasitas casing = 0,0708 BPF. 7. Tutup choke dan kemudian menyengat ke dalam SQZRETAINER. Set 15-20 kips berat di atas punggawa dan tekanan up 500 - 1.000 psi pada DP oleh casing annulus. Pompa tambahan 119 bbls dari 15,7 lumpur ppg di 4 bpm diikuti oleh 5 bbls dari air tawar ke DP. Ini akan meninggalkan 2 bbls semen di DP di atas retainer. Jangan overdisplace semen. PUMP JADWAL SETELAH menyengat KE SQZRETAINER Deskripsi Catatan: volume Pemindahan mengasumsikan 12 ppg FCS dalam G-series pasir di 10.000 'TVD. 5 bbls dari perpindahan air harus menyediakan sekitar 200 tekanan positif psi. Jika kendi baik atas atau tekanan permukaan naik ke 4500 psi selama operasi pemerasan dengan semen dalam pipa bor, lakukan langkah berikut: menyengat dari punggawa, POOH 2 berdiri, membalikkan beredar keluar 2 volume workstring pada tingkat maksimum sambil menjaga pipa bergerak (tidak melebihi tekanan tes casing dari 3520 psi sementara membalikkan). 8. PU dari punggawa dan membuang yang terakhir 2 bbls semen di atas SQZRETAINER (TOC @ ~ 9922 â € ™ MD). PU 2 berdiri dan membalikkan keluar pada tingkat maksimum yang mungkin (tidak melebihi tekanan tes casing dari 3520 psi sementara membalikkan). Membalikkan setidaknya 2 volume workstring dan menjaga pipa bergerak sementara membalikkan. 9. POOH dan alat pengaturan LD punggawa. PU yang 8-1 / 2 â € bor keluar perakitan dan TIH ke 9750 â € ™ MD. (180 'di atas diharapkan TOC) 119 bbls lumpur 5 bbls Air Tawar Ini akan meninggalkan 2 bbls semen di atas SQZRETAINER di DP. (118 'di dalam DP di atas SQZRETAINER yang) 10. Setelah WOC untuk 18 jam sejak semen dipompa, mencuci ke TOC. Bor semen / SQZRETAINER dan terus pengeboran keluar semen. Bor 5'-10 'lubang baru mencatat setiap rongga atau perubahan kondisi sumur bor. Jika gas yang tinggi dan atau pengembalian hilang ditemui di bawah sepatu, hubungi Operasi Inspektur segera. Catatan: Jika semen usang dan / atau lembut ditemui sedalam 90 'di atas TOC diharapkan, PU 3 berdiri dan mengedarkan keluar 1 siklus. Memonitor kondisi lumpur / properti dan membuang semua lumpur buruk semen yang terkontaminasi. Hubungi Operasi Inspektur untuk membahas waktu WOC dan operasi maju jika semen tidak sulit. 11. Lakukan PIT untuk 17,0 ppg EMW (2970 psi di permukaan dengan 11,8 ppg lumpur di 10.317 'TVD). Gunakan teknik PIT di 1/2 bpm dan merekam tekanan vs volume yang dipompa. Jangan menguji sepatu untuk lebih tinggi dari 17,0 ppg EMW. The SQZTOOL akan ditetapkan di atas di mana semen t agged ketika Rih. Sebuah dikemas BHA digunakan selama drillout tersebut. Penempatan Stabilizer adalah sebagai berikut: 8-1 / 2 "pengukur penuh dekat sedikit menusuk, 81 / 2" penuh pengukur menusuk 15 'di atas sedikit, dan 8-1 / 2 "penuh pengukur menusuk 45' di atas bit. Setelah menentukan bahwa meremas diperlukan, BHA itu tersandung dan diputar di bagian bawah casing beberapa kali untuk membersihkan ID casing semen yang tersisa. The SQZTOOL akan ditetapkan dalam interval yang dibersihkan dengan stabilisator. Pompa berada di sementara ing bersih casing untuk menghilangkan stek semen. Rig beredar BU cukup sebelum POOH untuk memastikan semua potongan semen telah dihapus. 12. Setelah tes berhasil, lanjutkan dengan operasi pengeboran per prosedur pengeboran yang lebih dalam. 3.4 SHOE SQUEEZE - PACKER dpt 1. Membuat casing scraper dijalankan jika dianggap perlu sebelum menjalankan dengan SQZTOOL. Casing kerja scraper secara menyeluruh di seluruh selang pipa di direncanakan SQZTOOL kedalaman pengaturan. Beredar pantat up di bawah SQZTOOL kedalaman pengaturan. POOH. Jika dipandang bahwa casing scraper run tidak diperlukan, berikut adalah reconcilers untuk tidak membuat casing scraper run: 2. Pick up SQZTOOL untuk CGOD CGWT casing dan TIH ke TOOLMD MD (305 â € ™ di atas sepatu). Set SQZTOOL @ TOOLMD MD (tidak diatur meremas alat di bawah 10.005 â € ™ yang mana semen ditandai ketika berjalan di lubang untuk membersihkan). Pastikan bahwa alat pemerasan tidak akan diatur dalam kerah casing. Verifikasi pengaturan dengan 1520 kips berat di atas SQZTOOL dan 500-1000 psi pada DP oleh casing annulus. 7,75 â € adalah OD maksimum dari SQZTOOL Tekanan diferensial maksimum untuk SQZTOOL = 5.000 psi Maksimum ditetapkan berat untuk SQZTOOL = 50.000 lbs 3. Menguji garis semen dan manifold pemerasan ke 5000 psi. (Uji terhadap T IW valve) 4. Tutup annular BOP dan tekanan pada DP oleh casing anulus ke 500-1000 psi. Membangun tarif injeksi pada 1/2, 1, 2, 3, dan 4 bpm tanpa melebihi tekanan injeksi 4500 psi (Engineer untuk mengomentari dasar untuk tekanan injeksi maksimum. Yaitu Untuk tetap dalam batas tekanan meledak bersih (7.927 psi w / 1,375 SF ) dari 9-5 / 8 â € casing dengan asumsi 15,7 ppg lumpur di sumur bor dan 9.0 ppg EMW back-up di belakang 9-5 / 8 â €). Memonitor annulus c arefully untuk respon tekanan indikasi packer atau DP kebocoran. Perhatikan bahwa CGOD CGWT casing terakhir diuji untuk 3.825 psi dengan 15,7 ppg lumpur, garis semen telah diuji untuk 5.000 psi, dan SQZTOOL berperingkat untuk 5.000 psi tekanan diferensial. Gunakan merencanakan teknik PIT tekanan rekor vs volume yang dipompa. Hubungi Operasi Inspektur dan Pengeboran Insinyur untuk membahas hasil tes injeksi (injektivitas akan menentukan jika perubahan yang diperlukan dalam desain semen atau pompa volume). Jangan melebihi tekanan tes PIT dari 3300 psi dengan 12,7 ppg lumpur (15,0 ppg EMW) jika injeksi belum ditetapkan pada saat ini. Ini bisa menunjukkan PIT memuaskan telah diperoleh. 5. Tekanan berdarah off anulus, terbuka memotong pada SQZTOOL. 6. Campur dan menggantikan bubur berikut dengan menggunakan unit penyemenan: Catatan: Sementara menggusur semen turun DP dengan bypass terbuka, debit dapat berlari lebih cepat dari laju pompa karena tekanan U-tube. Mengambil kembali melalui choke, jika perlu, sehingga tekanan balik dapat diterapkan untuk mencegah semen dari yang beredar di atas SQZTOOL sebelum bypass ditutup. POMPA JADWAL SEBELUM MENUTUP BYPASS PADA SQZTOOL Deskripsi Mass a jenis P m a T g a jenis 30 bbls pra-flush spacer (MCS-3) 38 bbls (150 karung) FL pemerasan bubur rendah (Lihat data Cement untuk resep) 119 bbls lumpur 38 bbls (200 karung) tinggi FL (rapi) pemerasan bubur (Lihat 5 bbls Air Tawar data Cement untuk resep) Ini akan meninggalkan TOC 250 'di bawah SQZTOOL, dan 250' di atas sepatu casing. 38 bbls lumpur (lead posisi spacer ~ 15 bbls dalam DP di atas Catatan: volume Pemindahan mengasumsikan SQZTOOL yang) 12 ppg FCS dalam G-series pasir di 10000 'TVD. 5 bbls dari perpindahan air harus Posisi semen ~ 25 bbls dalam DP di atas menyediakan sekitar 200 tekanan positif psi. SQZTOOL. (1470 'di dalam DP di atas 10 bbls pasca-flush spacer (MCS-3) SQZTOOL yang) 5a € 19,5 # S-135 kapasitas DP = 0,01701 BPF; 9-5 / 8â € 53,5 # kapasitas casing = 0,0708 BPF. 7. Tutup choke dan kemudian bypass pada SQZTOOL dan tekanan up 500 - 1.000 psi pada DP oleh casing annulus. Pompa tambahan 119 bbls dari 15,7 lumpur ppg di 4 bpm diikuti oleh 5 bbls dari air tawar ke DP. Ini harus meninggalkan TOC 250 'di bawah SQZTOOL, dan 250' di atas sepatu casing. PUMP JADWAL SETELAH MENUTUP BYPASS PADA SQZTOOL Deskripsi Jika kendi baik atas atau tekanan permukaan naik ke 4500 psi selama operasi pemerasan dengan semen dalam pipa bor, lakukan langkah-langkah berikut: melepaskan alat pemerasan, POOH 3 berdiri, membalikkan beredar keluar 2 volume workstring pada tingkat maksimum (tidak melebihi tekanan tes casing dari 3520 psi sementara membalikkan), POOH 1 berdiri tambahan, mengatur packer dan menempatkan 500-1000 psi pada anulus. 8. Ragu-ragu meremas. Tahap hingga 5.0 bbls semen ke dalam formasi. Pompa di 1,0 bbl di 1/4 bpm setiap 15 menit untuk pertama 15,7 8.3 m a T g t 3.0 bbls. Setelah itu, pompa di 1,0 bbl di 1/4 bpm setiap 60 menit untuk terakhir 2 bbls (total volume pemerasan = 5.0 bbls). Jika tekanan break-lebih terlihat sebelum menyelesaikan setiap tahap, berhenti memompa segera dan tahan tekanan apa pun yang dicapai untuk waktu tahap yang diperlukan sebelum melanjutkan dengan tahap berikutnya. Berhenti memompa pada titik apapun jika 1.675 psi tercapai (21,0 ppg EMW). Jika batas tekanan tercapai, menghentikan proses pementasan dan tahan tekanan akhir waktu WOC. Jika 1675 psi tidak tercapai setelah meremas 5.0 bbls, menghentikan proses pementasan dan tahan tekanan apa pun yang hadir. Perkiraan TOC setelah meremas raguragu adalah 185 'di atas sepatu. 9. Tahan tekanan pemerasan akhir untuk 12 jam. Bor tekanan pipa harus meningkat karena ekspansi termal. Memungkinkan tekanan pipa bor untuk naik setinggi 4500 psi (21,0 ppg EMW) sebelum perdarahan off tekanan. Jika tekanan membangun ke 4500 psi, berdarah kembali ke 3500 psi sebelum melanjutkan untuk menahan tekanan pemerasan. Jika tekanan meningkat belakang di atas 500-1000 psi, mungkin menjadi indikasi kebocoran baik dalam packer atau t dia DP. (Diperbolehkan tekanan annulus maksimum adalah 1.585 psi dasar pada 21 EMW tes casing.) 10. Setelah menunggu 12 jam, tekanan hingga 500 psi selama tekanan squeeze akhir untuk memastikan semen diatur. Jika OK, tekanan rilis dan menggeser SQZTOOL dan beredar keluar. POOH. 11. TIH dengan 8-1 / 2 "bor keluar perakitan ke tempat SQZTOOL ditetapkan, dan mencuci ke TOC. Bor keluar semen dan 5-10 'dari formasi baru mencatat setiap rongga atau perubahan kondisi sumur bor. Jika gas yang tinggi dan / atau hilang kembali ditemui di bawah sepatu, hubungi Operasi Inspektur segera. Catatan: Jika semen usang dan / atau lembut ditemui sedalam 90 'di atas TOC diharapkan, PU 3 berdiri dan mengedarkan keluar 1 siklus. Memonitor kondisi lumpur / properti dan membuang semua lumpur buruk semen yang terkontaminasi. Hubungi Operasi Inspektur untuk membahas waktu WOC dan operasi maju jika semen tidak sulit. 12. Lakukan PIT untuk 17,0 ppg EMW (2970 psi di permukaan dengan 11,8 ppg lumpur di 10.317 'TVD). Gunakan teknik PIT di 1/2 bpm dan merekam tekanan vs volume yang dipompa. Jangan menguji sepatu untuk lebih tinggi dari 17,0 ppg EMW. 13. Setelah tes berhasil, lanjutkan dengan operasi pengeboran per prosedur pengeboran yang lebih dalam. 5. ENGINEERING TINDAK LANJUT Nah Nama: WELLNAME Pengawas: Pengeboran Supts Engineer (s): Pengeboran Insinyur Nah engineer bertanggung jawab untuk lisan tindak lanjut dengan rig pengawas. Insinyur adalah untuk mengidentifikasi dan mendokumentasikan bawah bagian dari prosedur yang tidak memenuhi kebutuhan tim pengeboran dan menggambarkan pembelajaran kunci untuk dimasukkan ke dalam prosedur inti. Kembali tindak lanjut untuk pemilik prosedur inti: Modifikasi dianjurkan untuk Prosedur: _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ _____________________________________ _____________________________________ _______________ Disampaikan oleh: __________________________________________ ____________________ Telepon: () DATE___________ BAGIAN 10 - LAMPIRAN II p i Nama baik n d a Casing Sebelumnya Nama Rig h a n MISC. ENGINEERING calcs. 2 0 Gain pit dari casing (bbls): 81,2 b Gain pit dari b penyemenan (bbls) l 754,1 s 49 EMW setelah 0 displacment (ppg) 0 13.0 'M D Tekanan U-tabung @ 1 p 0 e 2, r 10, 0 p i n mengapung (psi 930 d a 1 C4 67 0 a3 2 a , s3 . n 7 i , 2 5 n1 g b Tb i l ts i 72. h M 8 48 K 60 6 e 0 8 o 0 n 3 n g 'T t a V i p D n kp u g e n e r g n Lubang Asumsi ukuran Pra-rata dengan 20 bbls 8,7 ppg air laut spacer. P a n 16,5 "Post-siram j s a i dengan 20 bbls 8,7 ppg air laut spacer. n Mengatur MW annular Volume SEMEN g 9.2 0,1523 BPF Timbal Lumpur: Class 'H' dengan aditif cair Campur ke: = 12.6 ppg OD = 16 49% Mixwater: Sea di 13.23 gal / sk Yield: 2,32 cu.ft / sk Jumlah karung: 1525 Volume: 630,1 bbls ID = 15,22 annular Volume USULAN CASING DESIGN (bawah ke atas) Dihitung = 1526 MD = 1000 0.1128 BPF WGHT GRADE / CONN PANJANG MD ID Bit Ukuran (di) Tail Lumpur: Class 'H' dengan aditif cair Campur ke: CAP. (BPF) CAP. (bbls) ALIH. 16,2 ppg TVD = 10001 45,5 K-55, BTC 4900 4900 10,05 0,0982 481,0 0,0166 bbls 13.5Mixwater: Sea di 4.68 gal / sk Yield: 1.11 cu.ft / sk Kelebihan semen pada 2 0,0000 0,0 0,0000 Jumlah karung: 425 Volume: 84,0 bbls permukaan jika lubang Dihitung = 425 ukuran 341 3 0,0000 0,0 0,0000 Ekor diperkirakan PEMINDAHAN 4 0,0000 0,0 0,0000 4400 'MD Setelah postflush, menggantikan w / 453,1 bbls lumpur 9.2 ppg. 4400 'TVD Tinggi req 'd ekor di atas sepatu 500 kaki. Spacer 500 'di atas PUMP KALI Tingkat Timbal Tail sepatu Usulan Casing 20 bbl postflush 6 3.3 3.3 casing (ukura n Mengapung Kapasitas = 7,9 bbls Waktu Perkiraan Pekerjaan 270 165 lubang diasu msika EJT (jam) 4.49 2.74 EJT dengan kontingensi 5.49 3.74 n). Camp Bawah lubang suhu statis 138 derajat F (est. Temps dari log) ur Bawah lubang sirkulasi suhu 110 derajat F (dari API Spec 10) Timbal Seme n6 105,0 0,0 OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 1 dari 2 Jika mengu Pertama Edition - Mei 2003 kur Nama baik kemud ian Casing Sebelumnya Nama 1.175, Rig OD = 16 10,75 3 'di "SHOE SQUEEZE atas Mix ID = 15.22CASING DESIGN (bawah ke atas) Tail Seme n6 MD = 1000WGHT GRADE / CONN PANJANG MD ID CAP. (BPF) CAP. (bbls) ALIH. 14,0 TVD = 10001 45,5 K-55, BTC 4900 10,05 0,0982 4900 0,0166 481,0 2 0 0 0 0 0 0.0000 0.0000 0.0 14,0 3 0 0 0 0 0 0.0000 0.0000 0.0 Penurunan Top Plug 5.0 5.0 WORKSTRING DESIGN (bawah ke atas) e r OD BERAT / CONN PANJANG MD ID CAP. (BPF) CAP. (bbls) ALIH. d 1. 5 19,5 # / i NC50 / X- s 954400 p 4400 4,276 0,017268 l a 76,0 c 0,0078 e 2. 0 0 0 0.000000 0,0 0.0000 m e n 3 t d MW perpindahan spacer i 9.2Pre-siram dengan 20 bbls 8,7 ppg air laut spacer. i n Ikuti semen dengan 10 bbls 8,7 ppg air laut spacer. g i SEMEN Memimpin Lumpur: Class 'H' dengan aditif cair Campur ke: 16 ppg n k a n CasingMixwater: Sea di 13.23 gal / sk Yield: 1,65 cu.ft / sk 10.75 "Jumlah karung: 257 Volume: 75,5 bbls p r U a n - d f l n u g s h d i D t i u k t i u r p a 5 bbl PEMINDAHAN = Tutup memotong setelah memompa 71,0 bbls dari preflush dan 2 semen 5 7 Remas packe k r e peng t atura i n k kedal a aman Setel m ah e space m r, o meng t gantik o an w / 80,5 bbls lump ur 9.2 ppg. 4400 'MD PUMP KALI Tingkat Squeeze Lumpur TOC diinginkan 250 kaki di atas sepatu Mix Squeeze Semen 4 18,9 Diinginkan pemerasan Volume 10 bbl spacer 4 2.5 50 bbl Casing Shoe 80,5 perpindahan bbl 4 20.1 4900 'MD 0 bbl lainnya 4 0.0 Panjang lubang baru: 10' 4883 'TVD Contingency 60 Ukuran bit: 9,875 "Perkiraan Waktu Kerja 102 New lubang Volume: 0,95 bbl EJT (jam) 1.69 EJT dengan kontingensi 2,69 Bawah lubang suhu statis 138 derajat F (est. Temps dari log) Bawah lubang sirkulasi suhu 110 derajat F (dari API Spec 10) OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG PENGEBORAN 2 dari 2 Pertama Edition - Mei 2003 TES TEKANAN INTEGRITAS 11,0 TEKANAN TES INTEGRITAS 11.1 Umum 1 11.2 Casing Test 2 11.3 Leak-Off Uji 3 11,4 Jug Test (Terbatas PIT) 4 11,5 Terbuka Lubang Leak-Off Test 4 ____________________________________________ __________________________________ OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING PERTAMA EDITION MAY 2003 11.1 UMUM Ada tiga jenis utama dari Tes Integritas yang dilakukan oleh EMDC pengeboran. The Casing Test, Leak Off Test (LOT), dan Uji Jug (PIT). Sebuah tes casing yang digunakan untuk memastikan casing tidak akan gagal dalam situasi kontrol dengan baik atau operasi selesai. The BANYAK dan PIT tes yang digunakan dalam lubang terbuka tepat di bawah sepatu untuk menentukan berat lumpur setara yang dapat diselenggarakan, atau yang akan memulai patah tulang dan menyebabkan kebocoran-off untuk formasi. Salah satu jenis tambahan tes yang mungkin dilakukan selama operasi pemboran adalah tes integritas lubang terbuka. Jika tes ini diperlukan prosedur yang berlaku pengeboran akan detail tes itu. Tes casing harus memetakan dan grafik dipertahankan pada rig dan di kantor sesuai kebutuhan badan pengawas. Persyaratan MMS adalah untuk menekan tes semua string casing kecuali pipa drive, untuk menahan tes selama 30 menit (umumnya untuk non-MMS operasi diatur, 15 tes menit sudah cukup) dengan <kehilangan 10% tekanan, dan untuk mendokumentasikan tes laporan IADC. Untuk semua sumur EMDC, mendokumentasikan tes pada laporan pagi juga. The EMDC Integritas Uji Workbook akan selesai untuk baik LOT atau PIT dan akan dilakukan sesuai dengan pedoman yang ditentukan di bawah (terletak di LAN atau Global Share). Excel workbook berisi file bantuan dengan pembahasan prosedur teori, dan interpretasi tes. Informasi tambahan mengenai prosedur pengujian dan analisis yang terkandung dalam publikasi EPR "Tekanan Integritas Uji Panduan Lapangan". Operasi Pengawas bertanggung jawab untuk mengisi formulir PIT dan meneruskan ke Engineer Drilling dan Operasi Inspektur secepat praktis setelah menyelesaikan tes. Tekanan Pedoman Umum Pengujian 1. Sebelum peralatan pengeboran float, tes casing yang akan dilakukan. Tes ini akan dijalankan untuk menguji tekanan disetujui oleh MMS atau badan pengawas yang mengatur lainnya. 2. Tes Integritas diperlukan di bawah setiap string dari casing kecuali pipa drive dan casing konduktor. Berdasarkan kondisi geologi atau kedalaman pengaturan yang direncanakan, tes konduktor casing sepatu dapat diamanatkan oleh badan pengawas yang mengatur. Sebuah tes yang akan dilakukan setelah 10 'lubang baru telah dibor untuk menentukan integritas formasi. Per MMS atau perintah badan pengawas yang mengatur lainnya, tes ini akan dilakukan setelah pengeboran formasi baru, tetapi harus dilakukan sebelum pengeboran 50 'dari formasi baru. Tes umumnya akan diambil bocor-off, (LOT) tapi tes kendi (PIT) dapat diminta (lihat prosedur pengeboran untuk rincian). Tekanan permukaan uji tidak akan dalam hal apapun melebihi tekanan tes casing atau tekanan garis permukaan. 3. Semua tes tekanan harus dilakukan dengan cara yang sama. Alat pengukur yang sama dan grafik tekanan harus digunakan pada setiap tes. Pengukur harus berukuran untuk rentang tekanan yang diharapkan. 4. Tes tekanan akan diulang jika ada keraguan mengenai validitas tes atau jika hasilnya kurang daripada yang diantisipasi. 5. Pompa semen akan digunakan untuk semua tes tekanan dan, sebelum melakukan apapun tes tekanan, semua lini permukaan akan diuji lebih besar dari tekanan permukaan diantisipasi sebagaimana ditentukan dalam Prosedur Drilling. 6. Data uji tekanan setelah akan disimpan seakurat mungkin: Pompa Tingkat Lumpur Berat Pompa Tekanan vs Barel Kumulatif Bergairah Total Barel Bergairah Diam-In Tekanan vs Waktu kumulatif (menit) Jumlah Barel Bled Kembali 7. Pedoman dalam "Integritas Pengujian Workbook" harus diikuti untuk interpretasi petak. 8. Setelah menyelesaikan Integritas Pengujian Workbook, fax atau email ke Drilling Engineer dan Operasi Inspektur untuk diperiksa dan dokumentasi. 11.2 CASING UJI The Casing Prosedur uji adalah sebagai berikut: 1. Setelah pengaturan casing permukaan dan semua string casing berikutnya, Test Casing akan dilakukan menggunakan salah satu metode berikut: a. Setelah menyelesaikan tes BOP yang diperlukan, domba-domba jantan buta akan ditutup dan casing akan diuji terhadap domba jantan buta dengan memompa bawah choke / membunuh line. b. Setelah menemukan semen keras atau sebelum pengeboran float kerah, BOP akan ditutup pada pipa bor dan casing akan diuji dengan memompa bawah pipa bor. Metode "b" adalah teknik yang lebih disukai. 2. Memompa cairan pengeboran di 1/4 - 1/2 BPM dan mencatat tekanan membangun menggunakan pompa semen hingga mencapai tekanan uji casing ditentukan dalam program pengeboran. Rekam bbls dipompa untuk mencapai tekanan tes. 3. Berhenti memompa dan mencatat tekanan menutupin selama 30 menit per persyaratan MMS atau persyaratan badan pengawas lainnya (umumnya, untuk non-MMS operasi diatur, tes 15 menit mungkin cukup). 4. Berdarah off tekanan dan merekam volume berdarah kembali. Merekam data tes dalam Integritas Uji Workbook. 5. Buka BOP. 11.3 LEAK-OFF UJI Sebelum melakukan Leak-Off Test, EMDC Integritas Uji Workbook adalah harus siap untuk merencanakan tekanan pompa dan menutup-tekanan sebagai fungsi bbls kumulatif dipompa dan menutup-waktu. Pipa bor mengambang katup, baik padat atau porting, dapat mempengaruhi hasil; mengambil menjadi pertimbangan. Persamaan menyertainya dapat membantu dalam menghitung tekanan dan volume selama tes kebocoran-off. Selain itu, spreadsheet untuk menghitung kompresibilitas air atau lumpur minyak berbasis dapat ditemukan pada LAN atau Global Share. Tes casing juga memberikan indikasi yang baik dari respon tekanan diharapkan jika jenis lumpur dan kepadatan belum berubah. 1. Lakukan tes casing seperti dijelaskan di atas, bor keluar sepatu casing dan 10 'lubang baru. 2. Beredar pantat dan kondisi cairan pengeboran untuk memastikan bahwa hampir bebas dari stek dan kepadatan seragam. Tarik sedikit di dalam casing. 3. Rig up pompa semen dan pompa bawah pipa bor untuk memastikan semua lini penuh. Garis tes untuk lebih besar dari tekanan permukaan diharapkan sebagaimana ditentukan dalam Prosedur Drilling. Tekanan permukaan uji tidak akan dalam hal apapun melebihi tes garis permukaan atau casing tekanan tes. 4. Tutup BOP. 5. Memompa cairan pengeboran bawah pipa bor atau tersedak jalur / membunuh dan mencatat tekanan membangun vs barel kumulatif dipompa. Pompa di 1/4 bpm jika volume lubang sumur adalah <1000 bbls dan 1/2 bpm jika lebih besar. 6. Masukkan data dalam 1/4 bertahap bbl sebagai tes hasil untuk menentukan titik kebocoran-off. 7. Lanjutkan memompa sampai mencapai tekanan permukaan, disesuaikan dengan berat lumpur, ditentukan dalam Prosedur Drilling, atau kebocoranoff ditambah 3-4 titik data, mana yang lebih dahulu. â € ¢ Jangan melebihi tekanan tes casing. 8. Berhenti memompa dan merekam menutup-tekanan sesaat 10 detik setelah menutup di. 9. Baca, catatan dan plot tekanan menutup-in pada interval 1 menit. Memungkinkan setidaknya 10 menit untuk tekanan untuk menstabilkan. Jika tekanan terus turun dengan cepat mempertahankan ditutup di sampai stabil. 10. Berdarah off tekanan dan merekam berdarah kembali volume dari sepatu anulus sehingga op mengambang tidak membatasi aliran. 11. Tinjau plot gradial di Integritas Uji Workbook dan determint LOT. Mengulang ujian jika interoperation tidak jelas. Ulangi tes PIT jika tidak dapat diterima. Jika tampak bahwa PIT itu tidak dapat diterima karena cairan bocor off menjadi pasir permeabel, tumpahan rembesan dapat melihat sebelum mengulangi tes. Gunakan 20-30 ppb dari 5 mikron (baik) CaCO 3. Diskusikan pilihan ini dengan Operasi Inspektur sebelum memompa tes kedua. 12. Buka BOP. 13. Mencoba untuk mengidentifikasi stres minimum (MS) dari menutup di data dan merekamnya dalam hasil bagian dari Integritas Uji Workbook. Jika infleksi yang berbeda tidak terlihat pada rekor penutupan fraktur MS sebagai "N / A". Lengkapi buku kerja, termasuk bagian komentar, bentuk dan fax atau email ke Engineer Drilling dan Operasi Inspektur secepat praktis. 14. Leak-off diasumsikan pada kedalaman vertikal sebenarnya dari sepatu casing yang harus digunakan untuk menghitung PIT. PIT (ppg) = [[MW (ppg) * 0,052 * TVD dari casing sepatu (kaki)] + tekanan Permukaan (psi)] / [0,052 * TVD dari casing sepatu (kaki)]. 11.4 PRESSURE INTEGRITAS TEST (JUG TES) Sebuah tes kendi atau PIT dari kursi casing identik dengan kebocoran-off tes kecuali bahwa itu tidak diambil bocor-off tekanan. Plot uji serupa di semua bidang kecuali atas tekanan build-up kurva. Dalam BANYAK, plot membungkuk ke kanan pada titik kebocoran-off. Pada uji kendi, seluruh plot build-up harus menjadi garis lurus karena tes ini dihentikan sebelum tekanan kebocoran-off tercapai. 11,5 OPEN LUBANG LEAK-OFF UJI Uji Integritas ini menentukan apakah ada penurunan yang signifikan dalam lubang tekanan fraktur terbuka di formasi baru dibor. Biasanya tes ini diperlukan setelah menembus pori / formasi permeabel yang memiliki potensi untuk kembali hilang dan / atau ketika berat lumpur mendekati nilai kebocoran-off lalu. Prosedur yang sama digunakan sebagai untuk melakukan tes lubang terbuka setelah sedikit ditarik di dalam casing. Tingkat pompa yang lebih tinggi mungkin mungkin diperlukan dari yang digunakan dalam PIT pada sepatu casing karena diperpanjang bagian lubang terbuka dan potensi permeabilitas, namun upaya awal harus dilakukan pada tingkat yang sama digunakan untuk uji sepatu. Tes ini bisa diganti dengan untuk berat sampai tes ketika berat lumpur yang lebih tinggi akan diperlukan untuk TD bagian lubang. CATATAN: Untuk melengkapi kurva kompresibilitas persamaan berikut dapat digunakan: Persamaan 1 Barel Basis Cairan Diperlukan = (Uji Tekanan) (Casing Volume Cairan) (Koefisien Compressibility â € "C f) Contoh â € "14,8 ppg Mud Berat Adj = (4,5 bbls) (10,24) = 3,4 bbls Disesuaikan dengan 24% padatan Integritas Uji Plot Baik Misalnya Nah Csg Ukuran (di) 9,625 Memperlengkapi Misalnya Rig RKB (AMSL, ft) 100 Kedalaman air (ft) 2.000 Bidang Misalnya Lapangan Negara Internasional Contoh - bbls = (1000 psi) (1500 bbls) (0,000003) = 4,5 bbls diperlukan Persamaan 2 â € "untuk menyesuaikan Eqn. 1 untuk Mud Berat Penyesuaian untuk Padat Mud = (Barrels Basis Fluid Diperlukan) (1-% Padat) komentar ... Akhir Interpretati Cf Air = 0.000003 Cf Diesel / SBM = 0.000005 Tes dan interpreta Uji Jen is Kedalaman (ft) Integ (ppg) Test 1 11.000 Test 2 0 Uji 3 0 pad a 16.2 BA NY AK MS (ppg) 15,6 Volume Sebelum ISIP (bbl), Waktu Setelah ISIP (1 menit / divisi minor) Casing Uji Test 1 Test 2 U j i 3 GAMBAR 11-1 (output Intergrity.xls) PENGUJIAN PRODUKSI 12,0 PENGUJIAN PRODUKSI 12.1 Pengujian Produksi Tujuan 1 12.2 Nah Uji Desain 1 12.3 Uji String 3 12.4 Permukaan Peralatan 4 12,5 Peralatan Pengukuran 4 12.6 Keselamatan 5 12,7 Personil Tanggung Jawab 6 Perencanaan 12,8 Pre-test dan Persiapan 9 12,9 Information Retrieval 10 12.10 Nah Membunuh dan Zona Pengabaian 11 PERTAMA EDITION MAY 2003 Pembangunan Jack-up, Platform, & Barge Rig Operasi Pengeboran, tes produksi tidak biasanya dilakukan. Sumur dibor di selama pengembangan biasanya selesai dan dibawa pada produksi oleh kelompok Produksi setelah rig pengeboran telah dipindahkan dari lokasi. Dalam hal tes produksi diperlukan (misalnya sumur eksplorasi), rinci Nah Pengujian Prosedur akan dikembangkan oleh Nah Test Engineer dan / atau Engineer Drilling secara baik tertentu. Prosedur ini akan mencakup peralatan penting dan langkah-langkah yang akan digunakan selama uji produksi (menggunakan pedoman industri dan informasi umum termasuk di bawah). Mengacu Produksi ExxonMobil dan Pengembangan Perusahaan Keselamatan Manual untuk panduan keselamatan mengenai drill stem pengujian, baik pengujian peralatan (yaitu, generator uap, treaters pemanas, flowlines, tank gauge, dll) dan persyaratan kontingensi H2S. Sebuah Penilaian Risiko akan dilakukan sebelum memulai operasi Nah Pengujian Produksi. 12.1 TUJUAN PENGUJIAN PRODUKSI 12.11 Prosedur Darurat 11 12.12 Hidrogen Sulfida 11 Sebuah tes produksi adalah teknik evaluasi formasi yang dapat dirancang untuk menyediakan data deskripsi waduk berikut: 12.13 Hidrasi 12 Jenis dan Sifat Cairan Pembentukan Dari Zona khusus Pengukuran Reservoir Tekanan dan Suhu Dibawah Berbagai Kondisi Arus _________________________________________________ _____________________________________ OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING Penentuan Efisiensi Nah Arus Keberadaan Waduk heterogenitas atau Batas Informasi ini akan diperoleh baik melalui pengukuran fisik langsung diambil selama tes produksi atau melalui metode analisis menggunakan reservoir Model deskripsi yang tepat, dalam hubungannya dengan informasi yang diperoleh dari uji sumur. Dalam eksplorasi pengujian sumur, sumur mungkin untuk sementara selesai sehingga fluida reservoir dapat mengalir ke permukaan dan pengukuran tekanan dan laju aliran dapat dibuat. Sejak hidrokarbon permukaan selama uji produksi, sangat hati-hati harus diambil oleh semua personil yang terlibat dengan operasi pengujian. Sangat penting untuk memilih peralatan dan mengadopsi prosedur pengujian yang akan menjamin keamanan rig pengeboran dan personilnya. 12.2 BAIK UJI DESIGN Sebuah tes produksi khas terdiri dari empat periode waktu yang berbeda: aliran awal, awal build-up, aliran akhir, dan akhir build-up. Tanggapan tekanan reservoir selama setiap periode waktu tersebut ditunjukkan secara skematis pada Gambar 12-1. Panjang setiap periode waktu tergantung pada reservoir memproduksi kemampuan dan jenis cairan yang diproduksi. Periode Arus awal Tujuan dari periode awal aliran adalah untuk membersihkan perforasi casing dan untuk memastikan bahwa ada perbedaan tekanan dari formasi ke lubang sumur. Periode awal aliran biasanya pendek dalam durasi (mana saja dari 2 menit sampai 1 jam). Untuk tes sumur minyak atau lubang bawah menutup-in test, umumnya tidak perlu mengalir fluida formasi ke permukaan selama arus awal. Untuk uji sumur gas, semua cairan harus benar-benar dihapus dari lubang sumur bawah pertama ditutup katup untuk mencegah punuk fase tekanan sumur bor dari pembentukan karena gas naik melalui cairan yang tersisa di lubang sumur. Untuk uji sumur gas menutup-in permukaan, periode awal aliran bisa bertahan beberapa jam. Periode Build-Up awal Setelah periode aliran awal, sumur ditutup-in untuk mengukur tekanan reservoir awal. Idealnya, masa build-up awal harus bertahan sampai tekanan lubang bawah telah benar-benar stabil; Namun, hal ini tidak selalu layak. Awal periode build-up biasanya akan 24 kali panjang periode aliran awal, dengan reservoir produktivitas rendah menerima multiplier yang lebih tinggi. Panjang minimum untuk awal build-up harus 1 jam tanpa panjang periode aliran awal. Dalam tes yang memanfaatkan pembacaan permukaan alat pengukur tekanan lubang bawah, adalah mungkin untuk memantau tekanan dasar sumur dan plot data secara real-time pada Horner atau superposisi petak. Periode shut-in harus, di mana praktis, lalu sampai suatu tekanan reservoir awal dapat diperoleh jelas dari ekstrapolasi dari tekanan penumpukan. Periode Arus akhir Tujuan dari periode aliran akhir adalah untuk membangun produksi stabil dari sumur dan untuk mendapatkan sampel cairan untuk analisis laboratorium. Transien tekanan diperkenalkan ke dalam formasi selama periode arus akhir akan digunakan untuk menentukan reservoir produk permeabilitas-ketebalan dan mengidentifikasi keberadaan heterogeneities waduk atau batas. Panjang periode aliran biasanya antara 6 sampai 12 jam, tetapi harus cukup untuk memperoleh data aliran definitif. Dalam beberapa kasus, periode aliran melebihi 12 jam mungkin diperlukan untuk memastikan kualitas data. Jika cairan yang dihasilkan dialirkan ke tangki penyimpanan, maka laju alir dan waktu aliran harus disesuaikan agar tidak melebihi kapasitas tangki (s). Fakta bahwa stabil produksi cairan diperlukan untuk mendapatkan data komposisi cairan yang berguna dapat mendikte panjang sebenarnya periode aliran akhir. Sampel cairan dari kedua aliran baik penuh dan separator harus diambil selama periode arus akhir. Periode Build-Up akhir Selama periode build-up akhir, sumur akan ditutup-in sehingga tekanan reservoir respon build-up dapat diukur dan dicatat. Informasi ini akan memungkinkan permeabilitas formasi, kerusakan sumur bor, dan indikasi heterogeneities waduk dan batas-batas yang ditentukan. Panjang periode build-up akhir harus setidaknya selama periode aliran akhir. Untuk waduk produktivitas rendah, periode build-up harus 1-1 / 22 kali panjang periode aliran akhir. Jika sampel lubang bawah yang diperlukan, mereka harus diambil setelah periode build-up final. 12.3 UJI STRING Uji String Tes string yang berisi komponen-komponen yang diperlukan untuk menyegel anulus tubing, menutup di downhole tubing (jika diinginkan), dan menangguhkan tekanan dan temperatur alat pengukur. Menutup-in metode yang digunakan akan tergantung pada pertimbangan seperti jenis cairan yang dihasilkan, tujuan dari tes, dan pertimbangan keamanan. Empat majelis tes lebih rendah tali dasar adalah: Permukaan Shut-in / permanen Packer; Permukaan Shut-In / dpt Packer; Lubang bawah Shut-In / permanen Packer; dan Bawah Lubang Shut-In / dpt Packer. Lihat Gambar 12-2 untuk rendah tes tali perakitan khas dengan Surface Shut-In / permanen Packer. Diam-In Metode 1. Permukaan Shut-In 2. Bawah Lubang Shut-In Metode paling sederhana untuk menutup dengan baik adalah dengan permukaan menutup-in. Dalam metode ini, kontrol baik primer di pohon tes permukaan. Tidak ada manipulasi string tes diperlukan sementara baik adalah "hidup". Sayangnya untuk tujuan waduk, selama permukaan menutup-dalam seluruh volume lubang sumur dalam komunikasi dengan formasi. Hal ini dapat menyebabkan dua efek merugikan, afterflow dan fase redistribusi dalam lubang sumur. Lubang bawah menutup-dalam metode adalah cara yang ideal untuk menutup-dalam dengan baik untuk tes build-up, karena menghilangkan efek afterflow dan fase redistribusi. Namun, lubang bawah menutup-in membutuhkan string agak rumit alat downhole, yang meningkatkan kemungkinan kerusakan mekanik. Dengan beberapa string tes, gerakan pipa yang diperlukan untuk mengoperasikan alat sementara baik adalah "hidup" yang dianggap merugikan dari sudut pandang keamanan. Afterflow didefinisikan sebagai aliran dari formasi ke lubang sumur setelah sumur menutup-in di permukaan. Fluida formasi dapat mengalir ke dalam sumur bor karena kompresibilitas cairan di lubang sumur. Afterflow biasanya tidak menjadi masalah di sumur minyak atau gas harus moderat untuk produktivitas yang baik. Di sumur produktivitas rendah, afterflow dapat menyebabkan kesulitan dengan analisis data. Sebuah lubang bawah menutup-in harus dipertimbangkan jika: Tahap redistribusi (pemisahan gas dan cair) dapat menyebabkan masalah dengan analisis data dari sumur gas rasio cair tinggi dan tinggi sumur minyak GOR. Jika fase redistribusi terjadi, biasanya dapat diakui sebagai punuk di plot data build-up. Jika tekanan humping berlangsung selama pengujian, data build-up mungkin nilai dipertanyakan untuk analisis sifat reservoir. Tahap redistribusi (tekanan humping) atau afterflow diperkirakan akan mendominasi data. Permukaan tekanan menutup-in dari sumur diperkirakan akan melebihi kondisi aman. 4. PERMUKAAN PERALATAN Peralatan pengujian permukaan dirancang untuk memproses diproduksi fluida formasi dari pohon tes permukaan ke titik pembuangan. Biasanya, komponen utama dari sistem ini adalah: header data, choke manifold, garis aliran, pemanas, pemisah, uji / tangki gauge, pompa transfer, dan burner (s). Permukaan dan lubang bawah alat uji yang dibutuhkan untuk uji sumur tertentu akan bervariasi tergantung pada kondisi baik individu dan persyaratan waduk tertentu dan akan ditentukan dalam Pengujian Sumur Prosedur. 5. PERALATAN PENGUKURAN Memperoleh pengukuran yang akurat dari lubang bawah dan tekanan permukaan dan suhu merupakan salah satu tujuan utama pengujian produksi ini. Tekanan bawah permukaan dan alat pengukur suhu dapat berupa alat perekam downhole mekanik atau elektronik atau wireline menjalankan alat pengukur elektronik yang menyediakan pembacaan permukaan. Tekanan permukaan biasanya diperoleh dengan baik alat pengukur cepat atau penguji bobot mati. Peralatan Pengukuran bawah permukaan Pengukur bawah permukaan dijalankan ke dalam sumur bor untuk merekam tekanan reservoir dan respon suhu selama mengalir dan menutup-dalam periode. Tekanan bawah permukaan dan suhu alat pengukur baik dapat mendarat di puting terletak di bawah sendi berlubang atau berjalan di operator gauge. Ada dua tipe dasar dari alat pengukur tekanan bawah permukaan yang tersedia, alat pengukur rekaman bawah permukaan dan bawah permukaan alat pengukur pembacaan permukaan. 1. Bawah Permukaan Recording pengukur Pengukur rekaman bawah permukaan membuat catatan tekanan dan / atau suhu terhadap waktu. Catatan dapat dibaca di permukaan ketika pengukur yang akan diambil. Pengukur Ini adalah perangkat perekaman mandiri yang tidak memerlukan link fisik untuk peralatan permukaan. Pengukur rekaman bawah permukaan baik akan mekanis atau elektronik dioperasikan. 2. Permukaan pembacaan Bawah Permukaan pengukur Permukaan alat pengukur pembacaan bawah permukaan memungkinkan real time tekanan lubang bawah dan suhu pengukuran untuk dibaca di permukaan. Pengukur ini mengirimkan data melalui kabel monoconductor. Karena kabel listrik, alat pengukur tersebut tidak dapat digunakan dengan standar lubang bawah shutin tes perakitan. Permukaan Peralatan Pengukuran Tekanan permukaan dan peralatan pengukuran suhu dapat dihubungkan ke header data yang terletak hulu manifold choke. Tekanan permukaan dapat diukur dengan kedua jenis alat pengukur cepat, tester bobot mati, dan / atau alat pengukur elektronik. 12,6 SAFETY Pedoman Keselamatan Umum 1. Pengeboran supervisor untuk mengadakan pertemuan keselamatan sebelum memulai setiap tes produksi. Semua personil untuk menghadiri pertemuan ini. 2. Jangan Bahan Peledak Oilfield subjek (perforating senjata, pemotong pipa, tali tembakan, biaya pemotongan, dll) ke tekanan yang lebih tinggi daripada yang diijinkan (dinilai) tekanan ditentukan oleh produsen. Ini termasuk pengujian tekanan lubricators yang berisi garis listrik disampaikan perforating senjata, pemotong, dll dan juga saat menjalankan peledak ke dalam sumur (misalnya beberapa berjalan dari tabung melalui perforasi senjata / menambahkan perfs pada "hidup" dengan baik). Jika perlu, mengganti bahan peledak dengan rating tekanan yang lebih tinggi. 3. Pengujian peralatan permukaan harus ditangani dalam Penilaian Risiko. Hal ini juga dianjurkan bahwa start-up dari uji produksi dimulai selama siang hari. Pencahayaan tambahan mungkin diperlukan untuk memastikan kebocoran potensial tidak terdeteksi jika pengujian berlanjut setelah siang hari. 4. Rig pengeboran yang akan dilengkapi dengan sistem peringatan, yang akan diaktifkan setiap saat sumur sedang diuji. Selama periode ini, akan diperlukan bagi personil untuk mengikuti ExxonMobil Keselamatan pedoman Manual untuk pengelasan, pemotongan, pekerjaan listrik, peledakan pasir, atau pekerjaan lain yang dapat mengakibatkan kebakaran atau ledakan. 5. Crane tidak akan dioperasikan lebih "hidup" alat uji. 6. Personil tidak diperlukan untuk tugas-tugas dalam hubungannya dengan ujian, atau untuk tugas pemeliharaan, harus tetap jelas dari peralatan pengujian produksi. Merokok diizinkan hanya di wilayah yang ditetapkan. 7. Jika H2S diantisipasi dalam cairan formasi, peralatan deteksi H2S akan digunakan untuk menentukan apakah hidrogen sulfida hadir dalam cairan formasi yang dihasilkan. 8. Pada akhir operasi pengujian, semua flowline harus benar-benar memerah dengan air. 9. Unit semen harus diikat ke pohon tes permukaan untuk digunakan dalam operasi juga membunuh, jika perlu. 10. Pohon permukaan katup induk lebih rendah harus panduan dioperasikan, master valve & sayap katup atas harus hidrolik atau pneumatik dioperasikan dengan remote terletak jauh dari pohon. 11. Seorang wakil kontraktor pemasok pohon harus hadir di lantai rig atau dekat unit kontrol setiap saat ketika baik adalah "hidup". 12. Jika metanol digunakan, memastikan bahwa kontinjensi api dan mitigasi deteksi berada di tempat dan Ulasan dengan semua personil. 12,7 PERSONIL TANGGUNG JAWAB Tanggung jawab keseluruhan untuk melakukan operasi pengujian yang aman terletak pada Operasi Pengawas. Operasi Supervisor adalah untuk bekerja sama dengan Drilling / Nah Test Engineer, dan Jasa Perusahaan Personil untuk memastikan bahwa semua tujuan pengujian tercapai. Pedoman tanggung jawab untuk tes produksi lepas pantai khas tercantum di bawah ini; lihat Bagian 2.6 manual ini untuk informasi tambahan. 10. Tentukan panjang aliran dan membangun-up periode dan ukuran choke. 11. Mengawasi permukaan dan bawah lubang sampling. Pengeboran / Yah Test Engineer 12. Mengkomunikasikan hasil-hasil tes untuk personil kantor selama dan setelah tes untuk membuat keputusan taktis. 1. Mengembangkan prosedur pengujian dan menentukan kebutuhan peralatan. 13. Membaca dan menganalisis grafik tekanan lubang bawah untuk evaluasi hasil tes. 2. Pastikan bahwa semua peralatan uji mekanis suara dan kompatibel dengan peralatan yang berdekatan. Pastikan bahwa suku cadang penting tersedia. 14. Menindaklanjuti alat uji dan kinerja personel perusahaan jasa. 3. Tekanan saksi dan tes fungsi permukaan dan bawah permukaan alat uji. Mengkoordinasikan Pihak Ketiga menyaksikan inspeksi peralatan dan pengujian sebelum pengiriman peralatan ke lokasi. 4. Mengawasi make-up dari string uji dan memeriksa izin. Memastikan bahwa string spaceout benar. Wellsite Geologist 1. Menentukan jumlah zona yang akan diuji dan memberikan informasi awal tentang tekanan, temperatur, dan jenis cairan yang terkandung dalam reservoir. 2. Menganalisis log listrik untuk menentukan perforating selang (s). 5. Pastikan packer itu, segel perakitan, dan majelis tail pipe memiliki OD yang tepat, KTP dan panjang. 3. Saksi perforating operasi (jika ada). 6. Saksi perforating operasi (jika ada). 4. Membantu dalam pengumpulan dan uji analisis data. 7. Pastikan bahwa semua alat wireline dan peralatan yang tersedia dan sesuai dengan kondisi tahan lama. Bawah permukaan Uji Alat Personil 8. Mengkoordinasikan dan mengumpulkan data uji. 9. Mengevaluasi data uji di tempat untuk kelengkapan dan akurasi. 1. Siapkan alat uji dan subs untuk make-up di lantai bor. 2. Fungsi dan tes tekanan alat di rak pipa. 3. Periksa precharge nitrogen pada tekanan anulus alat dioperasikan. 4. Mengawasi make-up dan menjalankan bawah lubang uji perakitan. 5. Mengoperasikan bawah alat lubang tes, dengan mengarahkan kru bor, di bawah pengawasan langsung dari Pengeboran / Yah Test Engineer. Pengujian produksi Perusahaan Layanan Personil 1. Mengoperasikan permukaan dan peralatan uji downhole di bawah pengawasan langsung dari Drilling \ Nah Test Engineer. Tanggung jawab ini akan mencakup berfungsinya pemisah, mengubah lubang dan tersedak ukuran, kalibrasi akurat dari gas dan cairan meter, operasi semua katup, mengamati tekanan separator, dan gas dan laju aliran cairan pemantauan, berjalan pengukur, dll 2. Mengkoordinasikan operasi pemisah dengan lantai rig untuk darurat menutup-in. 3. Menjamin berfungsinya burner (s) dan memonitor arah angin. Mengoperasikan semua valving bawah arahan operator pemisah dan membantu tekanan memantau sumur. Mengkoordinasikan operasi burner dengan lantai rig untuk darurat menutup-in. 4. Mengambil minyak, gas, dan sampel air. Pastikan label yang tepat. 5. Membantu dengan pemantauan tekanan kepala sumur dengan bobot mati tester dan suhu kepala sumur rekor. 6. Mengoperasikan injeksi kimia dari glikol / metanol, yang diperlukan. 7. Mengkoordinasikan operasi uji permukaan pohon dan lantai choke berjenis dan bersiaplah untuk menangani keadaan darurat shut-in. 8. Pastikan alat wireline yang tepat tersedia untuk pengujian tekanan tes tali. 9. Memastikan bahwa pengujian yang tepat dan pemeliharaan pohon tes permukaan dan lantai choke berjenis dilakukan. 10. Membantu dalam memantau tekanan annulus casing dan uji produksi data. 11. Siapkan tekanan rekaman bawah permukaan dan alat pengukur suhu. Terus memantau panel untuk tekanan bawah permukaan membaca permukaan dan alat pengukur suhu. Lumpur Logger 1. Mengambil sampel periodik gas pada manifold lantai choke selama periode aliran dan menganalisa sampel dengan kromatografi gas. 2. Menggunakan detektor gas untuk menentukan kemungkinan adanya gas di lantai rig dan di kepala sumur / daerah BOP. Pengeboran Cairan Insinyur 1. Menjamin pemeliharaan yang tepat dari cairan pengeboran di pit. 3. Membantu mengkoordinasikan berbagai langkah dari urutan uji produksi yang berkaitan dengan peralatan rig. 4. Memanipulasi / mengoperasikan alat downhole bawah arahan uji bawah permukaan alat personil. 2. Sampel menangkap kondensat dan / atau air yang diproduksi dan melakukan analisis filtrat dan air sifat. Mesin pembor Cementer 1. Memastikan integritas tekanan lantai rig pipa. 1. Tampil baik membunuh dan penyemenan operasi yang diperlukan. Telah memompa peralatan dalam keadaan kesiapan untuk membunuh dengan baik dan / atau semen pada pemberitahuan singkat. 2. Mengkoordinasikan Asisten Driller dan / atau floormen untuk memberikan pengamatan konstan data tekanan casing annulus dan uji produksi. 3. Memastikan bahwa uji produksi string benar dibuat. 2. Menjaga jumlah yang memadai pengikut semen dan kit konversi untuk menjembatani colokan untuk ukuran casing yang digunakan dalam uji produksi. 3. Membantu kru bor dan bawah permukaan personil lubang uji dalam pengujian pengoperasian peralatan downhole. 4. Membantu pengujian personil dalam peralatan uji permukaan pengujian. Rig Toolpusher 1. Memastikan bahwa peralatan juga membunuh siap dan mengkoordinasikan operasi dengan baik membunuh. 2. Mengawasi menjalankan tes tali dan tali-temali up dari peralatan kontrol permukaan. 12,8 PRE-TEST DAN PERSIAPAN PERENCANAAN Perencanaan yang baik dan persiapan sangat penting untuk melakukan tes produksi yang aman dan lengkap. Sebelum tes, pertemuan akan diadakan dengan semua personil kunci untuk membahas prosedur pengujian, tanggung jawab personel, dan pertimbangan keamanan. The BOPs harus dilengkapi dengan ukuran yang tepat domba yang diperlukan untuk mengakomodasi peralatan tes string di dalam lubang. Semua peralatan pengujian permukaan adalah menjadi tekanan dan fungsi diuji sebelum memulai tes. Pertemuan dan Drills Operasi Supervisor adalah untuk mengadakan pertemuan pre-test sebelum memulai setiap tes produksi. Semua personil untuk menghadiri pertemuan ini. Dalam pertemuan pre-test, item berikut ini untuk ditinjau dan dibahas: Prosedur Keselamatan Pencegahan Tumpahan Tujuan uji Uji Peralatan dan hook-up Prosedur pengujian Personil Tanggung Jawab Pengumpulan data Supervisor harus memastikan bahwa tanggung jawab semua personel yang terkait dengan tes dipahami dengan jelas. Permukaan Peralatan Persiapan Pada waktu yang tepat, baik sebelum string tes dijalankan dalam lubang, pemisah, pemanas, pompa pemindahan, tangki gauge dan burner (s) yang akan diperiksa dan dipersiapkan untuk operasi. Garis membunuh dan flowline koneksi pada pohon tes permukaan harus diperiksa untuk memastikan bahwa koneksi yang fleksibel kompatibel Chiksan atau lainnya yang tersedia. Gagal-aman katup tertutup di pohon uji flowline permukaan harus diperiksa untuk operasi yang tepat. Pohon permukaan uji, yang chiksans flowline, dan manifold lantai choke harus diperiksa untuk kompatibilitas koneksi. Lantai choke berjenis harus dicurangi dengan ukuran yang tepat untuk tersedak aliran awal. Header data akan diperiksa dan adapter, jika diperlukan, untuk berbagai alat pengukur dan transduser harus dibuat. Permukaan Pengujian Tekanan Peralatan Make up peralatan pohon uji permukaan dan lantai rig. Memastikan bahwa header data dan semua instrumentasi berfungsi dengan baik. Catatan: Punya OEM (Original Equipment Manufacture) perwakilan layanan pada lokasi selama instalasi dan tekanan pengujian semua peralatan pohon Natal. Tempatkan tanda peringatan permanen pada katup yang memiliki potensi untuk terjebak internal tekanan "Peringatan: Katup ini memiliki potensi untuk internal tekanan perangkap". Catatan: Setiap kali katup tekanan kembali (BPV) akan dihapus dari gantungan tabung, pelumas yang harus dipasang dan berlabuh. Sebelum mengambil steker, konfirmasi tekanan pemerataan harus dilakukan jika memungkinkan. Jika bekerja pada sebuah sumur gas H2S dengan, semua pekerja di daerah harus menutupi sampai saat mengambil steker. Tekanan menguji peralatan permukaan untuk 200 psi dan tekanan ditentukan dalam Program Pengujian Produksi, menggunakan unit cementing, sebagai berikut. Tekanan uji yang akan diadakan stabil selama minimal 5 menit pada tes tekanan rendah dan setidaknya 5 menit pada tes tekanan tinggi. 12,9 INFORMASI TEMU Tujuan utama dari uji produksi adalah untuk mengumpulkan data yang cukup untuk membuat deskripsi waduk akurat. Untuk mencapai tujuan ini, adalah penting bahwa kegiatan pengumpulan data diberikan prioritas tinggi baik dalam perencanaan dan selama operasi pengujian. Ini dapat disempurnakan dengan memastikan bahwa setiap individu yang terlibat dalam ujian sepenuhnya memahami tanggung jawabnya dan pengoperasian peralatan yang ditugaskan untuk mengawasi. Orang yang bertanggung jawab untuk benar-benar mengumpulkan data harus tahu data apa untuk mengumpulkan dan data formulir yang diperlukan untuk menyalin data. Dalam pertemuan pre-test, Drilling / Yah Test Engineer adalah untuk menetapkan bentuk yang sesuai untuk masingmasing individu yang terlibat dengan pengumpulan data. Lihat Manual EMPC Eksplorasi Nah Pengujian untuk daftar kebutuhan data yang disarankan dan bentuk. Tingkat pengumpulan data akan bervariasi sesuai dengan periode tes berlangsung dan keadaan baik selama periode tersebut. Secara umum, entri data harus dilakukan lebih sering selama periode ketika kondisi baik berubah dengan cepat dengan waktu (misalnya, segera setelah menutup-in atau aliran inisiasi) dan kurang sering selama kondisi stabil. Tujuan utama adalah untuk memastikan bahwa data yang halus dan kontinyu ketika diplot terhadap waktu. Frekuensi aktual untuk mengumpulkan data akan ditentukan oleh Drilling / Nah Test Engineer, tetapi untuk situasi tes yang paling, panduan berikut ini berlaku: 1. Semua Arus Periode: Bacaan harus dicatat setiap 30 menit selama kondisi aliran stabil dan pada peningkatan frekuensi selama arus awal. 2. Akhir Shut-In Periode: Rekam wellhead (permukaan) tekanan dan temperatur dengan perekam grafik dan perekam tekanan sebagai berikut- memastikan frekuensi tinggi membaca downhole untuk analisis penumpukan: Setiap menit untuk 10 menit pertama (atau peningkatan frekuensi, jika sesuai). Setiap 5 menit selama 20 menit berikutnya. Setiap 15 menit untuk satu jam berikutnya. Setiap 30 menit selama periode menutup-in. 3. Bawah permukaan Tekanan Bagan Reading: Pada akhir periode build-up akhir, alat pengukur tekanan bawah permukaan harus pulih dan diperiksa untuk kerusakan mekanik dan pembacaan tekanan diperoleh. Sampel Temu Sampel gas, minyak / kondensat dan air harus dikumpulkan selama setiap pengujian produksi untuk analisis laboratorium. Permukaan dan / atau lubang bawah sampel harus diperoleh seperti yang dijelaskan dalam Pengujian Sumur Prosedur. Sebuah daftar sampel master untuk dipertahankan. Daftar ini harus mengidentifikasi setiap sampel dan memberikan informasi yang diperlukan untuk melacak sampel di kemudian hari. Misalnya, harus mengidentifikasi sampel kontainer dengan nomor seri kontainer dan berisi semua data yang tercantum pada label sampel. Hal ini akan memungkinkan sampel untuk diidentifikasi dengan benar dengan botol sampel harus label dihancurkan. Semua sampel bertekanan harus dikemas dalam kotak dikirim ke rig pengeboran khusus untuk tujuan ini. Sampel lubang bawah mungkin diperlukan oleh Reservoir Engineering. Ketika sampel lubang bawah yang diperlukan, mereka umumnya akan diambil langsung berlawanan perforasi, jika mungkin, dan dengan baik mengalir melalui choke kecil. 12.10 BAIK DAN PEMBUNUHAN ZONE DITINGGALKAN akhir lainnya sebagaimana ditentukan dalam Sumur Pengujian Prosedur, maka dapat diselesaikan dan baik dapat dibunuh. Operasi pembunuhan akan bervariasi dengan string spesifik tes juga digunakan. Namun, titik penting adalah untuk memastikan bahwa kolom lumpur, dengan berat yang cukup untuk memastikan bahwa lebihan ada di formasi, yang diedarkan ke seluruh sumur bor. 12.11 PROSEDUR DARURAT Mengacu pada Prosedur Darurat spesifik dikembangkan untuk operasi rig. 12.12 hidrogen sulfida Hidrogen sulfida (H2S) adalah gas tidak berwarna yang baik beracun dan korosif. Kehadiran H2S dalam aliran produksi memerlukan prosedur khusus untuk melakukan tes dengan baik dan peralatan yang memiliki sifat metalurgi yang kompatibel dengan lingkungan H2S pengujian. Karena toksisitas ekstrim H2S, alat bantu pernapasan mandiri (SCBAs) harus tersedia selama pengujian jika H2S diharapkan. Jika ada potensi untuk H2S dalam cairan formasi, rencana kontingensi H2S harus dikembangkan dan dilaksanakan sebelum memulai operasi uji sumur. Nah Membunuh Prosedur Keselamatan H2S Pada akhir periode build-up akhir, sumur dapat mengalir pada tingkat tinggi untuk memanaskan sumur bor untuk tujuan menghindari pembentukan hidrat dalam string tes. Kerja downhole tambahan, seperti menarik alat pengukur tekanan, memperoleh sampel lubang bawah, atau melakukan tindakan Prosedur keselamatan berikut harus diamati pada semua tes baik di mana H2S dikenal, diharapkan, atau kontingen. Juga mengacu H2S Contingency Plan sumur. 1. Sebelum memulai tes dengan baik, semua personil harus diberitahu tentang bahaya hidrogen sulfida dan bersertifikat (yaitu Fit Diuji, dan sertifikasi yang berlaku). Latihan H2S yang harus dilakukan dengan semua personel di rig. 2. Semua permukaan dan peralatan downhole yang mungkin terkena H2S harus dirancang untuk digunakan dalam lingkungan H2S. 3. Setiap upaya harus dilakukan untuk ventilasi lantai rig dan pemisah daerah sebelum sumur dibuka. 4. Setiap individu yang akan di lantai rig atau bekerja dengan peralatan pengolahan hidrokarbon (pemisah, pembakar, dll) adalah memiliki alat bantu pernapasan mandiri tersedia di area kerja. dari suhu dan tekanan. Gambar 12-3 adalah hidrat kondisi formasi grafik. Daerah atas setiap kurva mewakili kondisi suhu dan tekanan di mana hidrat dapat terbentuk jika air yang cukup hadir. Pada konsentrasi air rendah dan tingkat aliran tinggi, pembentukan hidrat mungkin tidak cukup untuk menyebabkan penyumbatan aliran arus. Namun, setelah menutup di dalam sumur, hidrat dapat membentuk penyumbatan dan mencegah lebih lanjut baik mengalir. Bahkan pembentukan hidrat kecil dapat mengganggu operasi wireline / slickline untuk pengaturan colokan atau mengambil data. Sebuah rencana mitigasi hidrat harus di tempat jika kondisi hidrat yang mungkin. 5. Ketika permukaan fluida formasi, setiap usaha harus dilakukan untuk menjaga burner (s) yang beroperasi. 6. Ketika permukaan fluida formasi, dan pada 15 menit interval sesudahnya, detektor H2S akan digunakan untuk menentukan apakah hidrogen sulfida hadir dalam cairan yang dihasilkan. GAMBA R 12-1 GAMBAR 12-2 Produksi Tubing 12.13 hidrat Pembentukan hidrat Hidrat dibekukan atau senyawa kimia es seperti terbentuk ketika hidrokarbon ringan tertentu menggabungkan dengan air. Pembentukan hidrat dikaitkan dengan produksi gas dan merupakan fungsi Locator Seal Assembly Landing Nipple Berlubang Bersama Spacer Tabung No-Go Landing Nipple Wireline Masuk Gratis Perforasi Produksi Casing Lebih rendah String Asssembly untuk Surface Shut-in (Permanent Packer) GAMB AR 123 PLUG DAN ABANDOMENT 13,0 PLUG DAN DITINGGALKAN 13.1 Umum 1 13,2 permanen Plug dan Pengabaian 1 13.3 Sementara Plug dan Pengabaian 4 Verifikasi Jarak 13.4 Site 4 ____________________________________________ __________________________________ OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / barage RIG DRILLING PERTAMA EDETION MAY 2003 13,1 UMUM Sebelum melakukan Plug dan Pengabaian pekerjaan permanen atau sementara, persetujuan peraturan harus diperoleh dari lembaga peraturan yang berlaku. Tujuan dari pedoman umum berikut adalah plug dan meninggalkan sumur sesuai dengan badan pengawas yang mengatur dan persyaratan ExxonMobil; sehingga semua zona hidrokarbon, normal zona air tertekan, dan akuifer air tawar, terisolasi untuk mencegah permanen isinya melarikan diri ke strata lain atau ke dasar laut. Prosedur dapat disesuaikan agar sesuai kondisi lubang tertentu tetapi setidaknya harus memenuhi tujuan minimum yang dijelaskan dalam panduan ini (MMS atau badan pengawas lokal dan persyaratan ExxonMobil). Selama plug and ditinggalkan operasi permanen atau sementara, pedoman umum berikut, konsisten dengan peraturan daerah, berlaku: 1. Colokan ditinggalkan kritis yang mengisolasi hidrokarbon dan injeksi zona dari akuifer air tawar harus diverifikasi oleh penandaan dan / atau pengujian tekanan. Mengkoordinasikan setiap colokan yang harus dengan lembaga peraturan yang berlaku dan EMPC tag. 2. Pada setiap tahap dari plug dan ditinggalkan operasi, sarana melakukan pengendalian dengan baik adalah untuk dipertahankan. Ini berlaku sampai casing dengan anulus non-disegel luar (umumnya permukaan atau casing konduktor) yang akan dipotong atau dilubangi. 3. Ketika casing dipotong, kontrol tekanan harus dipertahankan dengan menutup pencegah annular sekitar pipa bor. Ini berlaku sampai casing dengan anulus non-disegel luar (umumnya permukaan atau casing konduktor) yang akan dipotong. Jika komunikasi dari formasi terbuka ke permukaan melalui anulus ditemukan, aliran itu harus dikendalikan dengan membunuh lumpur dan meremas anulus disemen melalui pemotongan atau perforasi. Anulus harus tekanan diuji setelah penyemenan untuk memastikan bahwa telah tertutup dengan benar. 4. Ketika melakukan plug and ditinggalkan operasi, semua kembali lumpur yang akan dianalisis oleh Mud Logging Unit / Mud Insinyur untuk mendeteksi formasi masuknya cairan yang mungkin terjadi. 5. Pertimbangan harus dilakukan untuk mengobati lumpur kiri antara colokan semen di dalam casing dengan inhibitor korosi dan / atau bakterisida a. 6. Pada setiap tahap dari plug dan ditinggalkan operasi, lumpur yang tersisa di lubang di atas semen dan / atau plug mekanis adalah memiliki berat badan yang cukup untuk menahan, bersama-sama dengan colokan, tekanan yang dapat berkembang di dalam sumur. 13,2 PLUG PERMANEN DAN DITINGGALKAN Berikut ini adalah urutan untuk plug dan ditinggalkan operasi permanen di mana semua string casing dan sumur bor anulus disegel secara permanen. Nah prosedur tertentu dapat bervariasi dan akan ditentukan dalam Program Plug dan Pengabaian: 1. Isolasi Zona di Terbuka Lubang Metode berikut mengisolasi interval lubang terbuka diterima. Dalam porsi uncased lubang, steker semen (s) harus spasi untuk memperpanjang dari 100 'di bawah bagian bawah untuk 100' di atas puncak zona (s) yang akan diisolasi. Zona berpori atau permeabel mengandung hidrokarbon harus diisolasi. Biasanya volume semen di lubang terbuka didasarkan pada lubang pengukur ditambah 10% berlebih. Metode lain ditinggalkan mungkin lebih praktis. Badan pengawas yang sesuai dan pengawas operasi harus menyetujui metode-metode alternatif. Catatan: Penempatan pil hi-vis bawah busi semen dapat bermanfaat dalam mencegah steker dari menetap sebelum menyiapkan. 2. Isolasi Terbuka Lubang dari Casing Sepatu Metode berikut mengisolasi lubang terbuka di bawah casing dapat diterima. Tempatkan plug semen seimbang di seluruh (100 'di atas dan 100' di bawah ini) sepatu casing. Mengatur punggawa semen di casing, 50 '- 100' di atas sepatu, memeras 100 'semen bawah sepatu dan menempatkan 50' semen di atas retainer. Jika kembali kehilangan telah mengalami tempat plug tipe jembatan permanen <150 'di atas sepatu dan menempatkan 50' semen di atasnya. Metode lain ditinggalkan mungkin lebih praktis. Badan pengawas yang sesuai dan pengawas operasi harus menyetujui metode-metode alternatif. Sebuah plug semen yang setidaknya 200 'panjang dapat ditetapkan dengan bagian bawah plug semen dalam pertama 100' di atas puncak interval berlubang. Metode lain ditinggalkan mungkin lebih praktis. Badan pengawas yang sesuai dan pengawas operasi harus menyetujui metode-metode alternatif. 3. Ditusuk atau Mengisolasi berlubang Interval Metode berikut mengisolasi interval berlubang dapat diterima. Perforasi dapat diperas. Sebuah plug semen seimbang ditempatkan berlawanan semua perforasi terbuka, memperluas 100 'di atas untuk 100' di bawah bagian bawah interval berlubang. Menetapkan semen punggawa 50 '100' di atas puncak interval berlubang, memeras semen untuk 100 'di bawah interval berlubang dan menempatkan 50' semen di atas retainer. Sebuah jembatan jenis-plug permanen dapat ditetapkan <150 'di atas puncak interval berlubang dengan 50' semen ditempatkan di atas jembatan-plug. 4. Penyumbatan Casing Rintisan Potong dan tarik setiap string casing diperlukan dan mengisolasi semua ruang annular dengan menempatkan sebuah plug semen seimbang, 100 'atas dan di bawah, rintisan yang tersisa atau salah satu metode berikut: Sebuah punggawa semen atau tipe permanen konektor jembatan diatur 50 'di atas rintisan dan 50' semen ditempatkan di atasnya. Sebuah plug semen, yang setidaknya 200 'panjang, diatur dengan bagian bawah steker dalam 100' dari rintisan casing. Jika rintisan berada di bawah lebih besar casing ukuran plugging harus diselesaikan seperti yang diperlukan untuk mengisolasi zona atau lubang terbuka seperti dijelaskan di atas. 5. Memasukkan dari annular Ruang Setiap ruang annular yang berkomunikasi dengan lubang terbuka dan memperluas ke garis lumpur akan terpasang dengan setidaknya 200 'semen. 6. Permukaan Plug â € ¢ Mengatur plug semen seimbang setidaknya 150 'panjang dengan bagian atas plug dalam 150' di bawah garis lumpur. Steker akan ditempatkan dalam string terkecil casing yang meluas ke garis lumpur. 7. Pengujian Plug Kondisi dan lokasi colokan semen tertentu harus diverifikasi oleh salah satu metode berikut: Dengan penandaan plug semen, punggawa semen, atau konektor jembatan dengan 15 kips sementara beredar terhadap steker. Semen ditempatkan di atas sebuah plug jembatan atau punggawa tidak perlu diuji. Dengan tekanan pengujian steker dengan tekanan pompa minimal 1000 psi dengan tidak lebih dari penurunan tekanan 10% dalam waktu 15 menit (MMS). ExxonMobil setidaknya 500 psi lebih dari tekanan formasi kerusakan atau dalam batas-batas kerja yang paling lemah terkena casing string yang mana yang kurang. Minimum Verifikasi Pengabaian Plug Steker pertama di bawah steker permukaan akan diverifikasi oleh salah satu metode di atas (MMS). 8. Clearance Lokasi Semua wellheads, casing, tiang, dan penghalang lainnya harus dihapus untuk kedalaman 15 'di bawah garis lumpur atau total kedalaman disetujui oleh badan pengawas yang berlaku. 13,3 PLUG SEMENTARA DAN DITINGGALKAN Sebuah ditinggalkan sementara berbeda dari ditinggalkan permanen bahwa semua string casing dan segel kepala sumur tetap utuh. Selama plug and ditinggalkan operasi sementara, pedoman umum berikut berlaku: 1. Tidak ada lubang dapat menekan casing kecuali diperlukan untuk pengujian produksi. Perforasi harus terpasang dengan benar dan terisolasi. 2. The wellhead daerah segel harus dilindungi dengan memasang topi korosi atau pohon ditinggalkan. Untuk periode ditinggalkan lama, juga mungkin tambahan dilindungi oleh menggusur lumpur di daerah segel dengan menghambat cairan. 3. Baik itu harus dilengkapi dengan penanda lokasi dan identifikasi. 4. Pemeriksaan struktur kepala sumur dan pelindung harus dilakukan setidaknya sekali per tahun. 5. Sebuah plug jembatan atau 'plug 100 semen panjang harus ditetapkan di dasar casing tali terdalam kecuali casing belum dibor keluar. 6. Sebuah plug jembatan dpt atau tipe permanen atau konektor semen setidaknya 100 'panjang, harus diatur dalam casing dalam pertama 200' di bawah mudline tersebut. 7. Pengecualian untuk panduan ini harus disetujui oleh badan pengawas yang berlaku, pengawas operasi dan EMPC. 13,4 SITUS CLEARANCE VERIFIKASI Situs akhir pembersihan setelah ditinggalkan harus disetujui oleh badan pengawas. Biasanya salah satu metode berikut akan diterima: 1. Tarik trawl di dua arah di lokasi. 2. Melakukan pencarian penyelam sekitar lubang sumur. 3. Scan di lokasi dengan sisi-scan atau di bawahscanning sonar. BAIK KONTROL 1. BAIK KONTROL 2. Nah Pengendalian â € "General 1 3. Lubang Pemantauan 5 4. Peralatan Pengujian 8 5. Peralatan Spesifikasi 10 6. Nah Kontrol latihan 16 7. Nah Pengendalian Prosedur 19 ________________________________________ ________________________________________ ______ DRILLING OPERASI manual-JACK-UP / PLATFORM / barage RIG DRILLING PERTAMA EDITION MAY 2003 14,1 BAIK KONTROL - UMUM Nah Pengendalian operasi dilakukan untuk mengurangi baik mengendalikan insiden dengan meminimalkan keparahan masuknya, benar menutup-dalam juga sesegera mungkin, dan permukaan masuknya dengan cara yang aman atau memompa / bullheading masuknya kembali ke dalam formasi (ketika membawa masuknya ke permukaan mungkin terlalu berbahaya, seperti dengan H 2 S). Arus yang tidak terkendali ke dalam sumur bor harus selalu dijaga di bawah tumpukan pencegah ledakan. Keselamatan semua personel di rig adalah pertimbangan utama ketika melakukan operasi kontrol dengan baik. Integritas unit pengeboran dan dampak ekonomi yang merugikan kepentingan sekunder. Umum prosedur langkah-demi-langkah dapat bervariasi, tergantung pada konfigurasi BOP pada setiap unit pengeboran individu. Prosedur shut-in spesifik Drilling Kontraktor untuk setiap unit pengeboran yang ditinjau untuk menentukan apakah mereka dapat diterima untuk operasi EMDC ini. Untuk semua lokasi, rencana pengendalian baik situs tertentu adalah untuk berada di tempat yang meliputi pengalir dan kontrol dengan baik prosedur khusus untuk unit pengeboran dan BOP tumpukan konfigurasi. General Nah Pedoman Pengendalian 5. Salinan dilaminasi dari rig prosedur shut-in tertentu harus dipasang di lantai rig dekat konsol pembor itu. Rig spesifik tagihan stasiun, daftar tugas awak, juga akan dipasang di lantai rig dan / atau papan pengumuman. Pedoman pengendalian umum juga adalah sebagai berikut: 6. Kehilangan Prosedur Sirkulasi akan diposting di lantai rig. 1. Semua peralatan kontrol juga akan dipertahankan dalam keadaan siap ketika melakukan operasi pengeboran. 7. The Driller akan diperintahkan untuk menutupdalam juga menggunakan penilaian dan indikator nya seperti keuntungan pit, mengalir setelah menghentikan pompa, atau tidak layak mengisi-up di perjalanan. The Driller tidak harus mendapatkan izin dari Pengawas Operasional sebelum menutup-dalam juga. 2. Melakukan latihan sesuai dengan "Yah Kontrol Drills" dari manual ini. 3. Uji peralatan kontrol dengan baik (yaitu, tekanan dan tes fungsi) sebagaimana tercantum dalam "Yah Kontrol Peralatan Pengujian" dari manual ini. 4. Sebuah papan status parameter pengeboran kritis akan dipertahankan pada konsol Driller ini terlihat jelas. Informasi di forum ini harus terdiri dari: Alat jarak sendi di atas lantai rig untuk menutup hang-off domba Kebanyakan tanggal tes BOP baru-baru ini BOP tumpukan dimensi jarak pencegah dari kepala sumur BOP tumpukan dimensi jarak pencegah bawah meja putar (sebagai alat gabungan ruang keluar biasanya diukur dari meja putar) 8. Bor String akan selalu menyertakan katup pelampung di atas bit dan, setelah pengaturan casing cukup untuk menutup dalam sumur, katup pelampung akan porting, kecuali pelampung yang solid disetujui oleh Operasi Inspektur. Modifikasi bidang mengapung pipa bor tidak diperbolehkan. 9. Setiap saat, pembukaan penuh, jenis bola, katup tekanan keselamatan seimbang (Tiw atau setara) untuk pipa bor dan BOP dalam, dengan subs Crossover untuk kerah bor dan casing, akan berada di lantai rig dan siap untuk segera digunakan (yaitu , membuka). Ini akan tersedia untuk semua ukuran drillstring digunakan. Katup pengaman (s) harus fungsi diuji dan tes harus didokumentasikan pada laporan IADC dan DMR. Katup pengaman akan selalu dijemput pertama. Sebuah katup pengaman akan dipasang dalam string selama periode downtime, seperti tergelincir dan memotong garis bor, dll CATATAN: API Spec. 7 (November edisi 2001) telah membagi katup pengaman dalam dua kelas. Saya katup kelas (katup standar) yang dinilai untuk tekanan kerja dari bawah dan mungkin tidak menutup dari kedua arah jika tekanan diterapkan dari atas. Katup kelas I tidak tekanan API dinilai eksternal dan mungkin bocor melalui batang. Kelas katup II dirancang untuk rated tekanan kerja dari bawah dan di atas bola dan eksternal untuk 2.000 psi minimum. Jika ada probabilitas bahwa operasi pengupasan akan diperlukan, Kelas II harus dimanfaatkan di rigsite tersebut. Bagian 8 di "ExxonMobil Pengeboran Permukaan Pencegahan ledakan dan Nah Pengendalian Peralatan Manual" menyediakan daftar produsen diketahui mampu memasok Kelas II katup pengaman terbukti. 10. Beredar tersedak dan membunuh garis untuk memastikan garis yang jelas (frekuensi akan tergantung pada cairan pengeboran). 11. Choke akan berada dalam posisi terbuka dengan katup pertama hilir choke dalam posisi tertutup juga. 12. Mempertahankan "Yah Bunuh Lembar Kerja" untuk konfigurasi sumur bor saat ini dan memperbarui lembar kerja (atau program PC KIK) setidaknya setiap hari sementara pengeboran sedang berlangsung, atau sebagai kondisi lubang perubahan. 13. Jauhkan choke dalam dan membunuh katup pada BOP dalam posisi tertutup sementara pengeboran. Jauhkan choke luar dan membunuh katup dalam posisi terbuka. 14. Memiliki manifold choke berbaris untuk mengambil kembali ke degasser miskin-anak. 15. Memiliki PVT dan FLO-SHO alarm diatur ke batas praktis terendah. 16. Rig up garis mengisi-up anulus dari pompa rig untuk cepat mengisi up dari annulus. 17. Gunakan annular untuk awalnya menutup-in sumur bor. On-site Operasi Pengawas akan menentukan apakah menggantung-off string bor diperlukan berdasarkan kondisi operasi yang ada. 18. Jika annular digunakan untuk mengedarkan keluar masuknya, tekanan penutupan dapat mundur per rekomendasi produsen untuk mengurangi keausan pada elemen. Tekanan operasi yang cukup akan dipertahankan untuk mencegah kebocoran dan menghindari gas melarikan diri ke lantai rig. Tekanan penutupan dapat dikurangi untuk memungkinkan gerakan pipa terbatas untuk menghindari mencuat drillstring sementara beredar keluar masuknya. Namun, sendi alat tidak harus bersepeda melalui elemen annular sementara beredar keluar masuknya. 19. Menutup annulus pengalir hanya setelah membuka katup pengalir baris (s) untuk mencegah broaching. Menetapkan personil untuk memantau menggerek jika mengalihkan baik dengan hanya dangkal casing set. Garis pengalir harus dialihkan ke laut dan melawan arah angin. 20. Memanfaatkan pompa lumpur dan / atau selang kebakaran untuk membasahi gas yang keluar dari garis pengalir. 5. Tentukan tekanan gesekan baru jika menggunakan tingkat pompa yang berbeda ketika restart sirkulasi setelah menutup untuk memeriksa tekanan. 21. Kaus kaki angin harus terlihat dari daerah yang bersangkutan dari rig. 6. Menentukan tekanan gesekan baru dalam cara yang sama seperti tekanan gesekan asli. Pedoman Recording tekanan Pedoman tekanan perekaman adalah sebagai berikut: 1. Merekam menutup-tekanan pada pipa bor dan casing setiap menit sampai tekanan menutup-in menstabilkan. Setelah stabilisasi, mencatat tekanan menutup-in pada pipa bor dan casing setiap 10 menit sampai operasi kontrol juga berakhir. 2. Merekam tekanan yang diperlukan untuk memompa membuka katup pelampung sebagai bor tekanan pipa stabil bila menggunakan katup pelampung nonporting di pipa bor. Catatan: Metode untuk menentukan kapan katup float membuka sama menentukan batas break-lebih selama tes integritas tekanan. 3. Menunjuk personil khusus untuk merekam tekanan dan pengamatan / komentar meskipun keluar operasi kontrol dengan baik. 4. Matikan pompa dan menutup-in baik untuk memeriksa tekanan jika masalah muncul ketika beredar keluar masuknya ke dalam sumur bor. Catatan: Tekanan maksimum pada setiap titik dalam sumur bor selama operasi pembunuhan akan terjadi ketika bagian atas masuknya adalah pada saat itu atau saat masuknya adalah di bagian bawah dalam kasus interval lubang terbuka pendek atau majelis lubang bawah panjang dan atas gelembung berada di atas sepatu casing. Hal ini terutama berlaku di sumur dalam. Pompa Tingkat Pedoman 1. Pastikan bahwa pemilihan tingkat sirkulasi mempertimbangkan faktor-faktor seperti: a) integritas formasi di sepatu casing, b) peralatan kontrol rig baik, c) kapasitas penambahan barit ke sistem lumpur, dan d) keterbatasan pompa rig meminyaki pada tingkat yang lebih lambat . 2. Pertimbangkan keuntungan sebagai berikut dari tingkat pompa rendah. Tingkat pompa khas adalah dalam kisaran 1 sampai 3 BPM: Tarif pompa rendah memungkinkan operator choke lebih banyak waktu untuk menyesuaikan choke. Tarif pompa rendah meminimalkan penanganan volume gas besar di permukaan Catat berat asli dari cairan pengeboran. Tarif pompa rendah mengurangi kemungkinan kembali hilang. Menghitung kenaikan diperlukan berat fluida pengeboran untuk menyeimbangkan tekanan formasi dan untuk memberikan lebihan. Menghitung berat membunuh cairan pengeboran. 3. Memahami keterbatasan pemisah gas lumpur ketika gas 100% mencapai permukaan. Bersiaplah untuk memotong pemisah gas lumpur dan langsung ke flare jika kaki cairan hilang. Nah Membunuh Lembar Kerja Sebuah Worksheet Nah Membunuh sangat penting untuk operasi kontrol juga sukses karena membantu Operasi dan personil Teknik berkomunikasi dengan jelas selama operasi dan melakukan perhitungan yang diperlukan. Setelah BOP stack diinstal, "Yah Membunuh Lembar Kerja" akan disiapkan. Worksheet akan dipertahankan untuk konfigurasi sumur bor saat ini dan memperbarui lembar kerja setidaknya setiap hari sementara pengeboran sedang berlangsung, atau sebagai kondisi lubang perubahan. Catatan: Program komputer KIK PC dapat digunakan sebagai pengganti worksheet. Langkah-langkah untuk penyelesaian "Lembar Kerja Nah Membunuh" adalah sebagai berikut: 1. Hitung berat lumpur membunuh. 2. Hitung tekanan permukaan maksimum yang diijinkan: Catat PIT di sepatu casing lalu. Hitung tekanan permukaan maksimum yang akan patah formasi. Catat casing pecah tekanan dan keselamatan faktor. Hitung tekanan permukaan yang diijinkan untuk setiap berat badan dan kelas casing. Pilih yang lebih rendah dari dua nilai dihitung sebagai tekanan permukaan maksimum yang diijinkan (yang akan digunakan untuk informasi saja). 3. Hitung kapasitas dan volume total sistem aktif. 4. Hitung barit diperlukan untuk berat sampai sistem aktif dan peningkatan volume yang sesuai. 5. Menghitung tingkat sirkulasi dan jadwal perubahan tekanan: Lubang Fill-Up Lubang Fill-Up Pedoman: Masukkan tingkat sirkulasi dan awal pipa bor tekanan beredar. Menghitung perubahan dalam sirkulasi tekanan yang akan terjadi karena berat cairan yang lebih berat. 6. Pilih metode sirkulasi dan mempersiapkan pengeboran jadwal berat cairan. Jika praktis, berkonsultasi dengan Operasi Inspektur untuk yang satu metode berikut untuk digunakan berdasarkan tekanan baik yang terlibat, integritas tekanan dari sepatu casing, rig kemampuan penanganan gas, kemampuan sistem lumpur, dan material lumpur di lokasi. Metode Driller ini (berat lumpur asli) Berat dan Tunggu Metode (keseimbangan berat lumpur atau membunuh lumpur berat badan) 7. Lakukan tinggi masuknya dan perhitungan gradien: â € ¢ Jika gradien masuknya kurang dari 0,2 psi / ft, masuknya tersebut mungkin gas. Jika gradien adalah antara 0,2 psi / ft dan 0,4 psi / ft, masuknya tersebut mungkin minyak. Jika gradien lebih besar dari 0,4 psi / ft, masuknya tersebut mungkin garam air. 14,2 LUBANG MONITORING Ketika tersandung keluar dari lubang, ke dalam lubang, atau ketika string bor keluar dari lubang (yaitu, penebangan, BHA mengganti, tergelincir dan memotong garis bor, dll) lubang akan terus dipantau untuk keuntungan atau kerugian menggunakan tangki perjalanan. Panduan berikut harus diikuti untuk memastikan kolom penuh lumpur dipertahankan dalam anulus setiap saat. 1. Lubang akan terus penuh menggunakan tangki perjalanan ketika tidak memompa bawah string bor. Tingkat tangki perjalanan akan disimpan minimal setiap 15 menit ketika pipa keluar dari lubang. Sebuah buku perjalanan akan dipertahankan untuk setiap baik dan setidaknya satu orang yang akan ditugaskan untuk memantau tangki perjalanan secara terus menerus sementara tersandung. Log book perjalanan harus membandingkan perjalanan volume untuk kedua volume teoritis dan volume perjalanan sebelumnya 2. Jika rig dilengkapi dengan sistem penggerak atas, back-reaming dan memompa keluar pertama 10 stand dari lubang terbuka ketika tripping harus dipertimbangkan. Hal ini sangat relevan sementara pengeboran sumur directional atau sumur dengan formasi yang sangat reaktif. 3. Bit akan dikembalikan ke bawah dan juga beredar pantat-up jika volume yang mengisi-up diamati kurang dari dihitung atau secara signifikan kurang dari mengisi-up direkam pada perjalanan sebelumnya. Jika lubang tidak mengambil jumlah dihitung cairan, Operasi Pengawas akan disarankan segera. â € ¢ tingkat Pit akan dipantau secara hati-hati ketika beredar pantat-up untuk mendeteksi perluasan gas dan / atau juga mengalir selama operasi beredar. 4. Berat lumpur yang cukup akan digunakan yang menyediakan setidaknya 200 psi dari lebihan sebelum mencoba untuk menarik atau memompa keluar dari lubang. 5. Sebuah tangki perjalanan dengan kapasitas minimal 40 bbls lebih disukai. Tangki perjalanan akan ditandai dalam setidaknya 1/2 bertahap per barel. 6. Sebuah jenis grease kemasan yang akan digunakan pada pompa sentrifugal yang feed tangki perjalanan. Injeksi air tidak akan digunakan. 7. Penebang lumpur juga harus memantau volume tangki perjalanan sementara tersandung keluar dari lubang dan mengkonfirmasi volume perpindahan dicatat oleh kontraktor pengeboran. Mereka juga harus memantau volume sementara tersandung di lubang jika diminta oleh Pengawas Operasional atau jika ditentukan dalam Program Pengeboran. 8. Jumlah maksimum pipa bor daripada yang dapat dijalankan di dalam lubang tanpa diisi harus ditentukan dalam Program Pengeboran dan akan didasarkan pada rencana baik tertentu (kedalaman casing, jumlah lubang terbuka, potensi lokasi pasir gas, dll) Bagian 4 menjelaskan metode untuk menghitung panjang maksimum pipa yang dapat dijalankan tanpa mengisi drillstring tersebut. 9. Ketika tersandung dalam volume lubang perpindahan dari sumur harus akurat dipantau menggunakan tangki perjalanan. FDM dapat memberikan pengecualian untuk menggunakan tangki perjalanan ketika tersandung di lubang. Catatan: Bidang modifikasi pipa bor mengapung tidak diperbolehkan. Tidak ada pengecualian untuk kebijakan ini. Perjalanan Pedoman Buku: Entri dalam buku perjalanan untuk perjalanan-keperjalanan perbandingan harus dilakukan sebagai berikut: 1. Volume perpindahan untuk setiap berdiri untuk pertama lima (5) berdiri dari pipa bor dan setiap lima (5) berdiri dari pipa bor setelahnya. 2. Volume perpindahan untuk setiap stand kerah bor dan HeviWate pipa bor. 3. Entri harus dibuat berdasarkan pada keakuratan volume pengukur tangki perjalanan (1/2 bbl atau kurang). Arus Periksa Pedoman Pemeriksaan aliran dan 10-10-10 adalah untuk digunakan sebagai indikator utama dari situasi yang seimbang di bawah. Pedoman melakukan pemeriksaan aliran adalah sebagai berikut: 1. Degasser yang akan dioperasikan setiap kali ada gas yang signifikan dalam aliran arus balik, seperti yang ditunjukkan oleh instrumen berat lumpur cut atau kromatografi bacaan di unit logging. 1. Juga akan aliran diperiksa sebelum membuat sambungan. 2. Berat fluida pengeboran akan diperiksa hilir degasser itu, serta di shaker, untuk menentukan apakah degasser tersebut bekerja dengan benar. 2. Juga akan diperiksa setelah aliran indikasi keuntungan pit. 3. Juga akan diperiksa setelah aliran indikasi tekanan abnormal. 4. Juga akan aliran diperiksa setelah istirahat pengeboran lebih dari 5 'pada sumur eksplorasi atau setelah istirahat pengeboran lebih dari 5' pada pembangunan baik jika mengharapkan tekanan abnormal atau hidrokarbon di zona tersebut. â € ¢ Istirahat pengeboran secara umum didefinisikan sebagai dua kali lipat dari tingkat penetrasi (ROP), tetapi dapat bervariasi tergantung pada daerah. 3. Membuang hisap degasser dan tangki pembuangan sesering praktis untuk memaksimalkan pemanfaatan. 14.3 PERALATAN PENGUJIAN Tekanan Tes The BOPs, tersedak dan membunuh garis, tersedak manifold, katup pengaman lantai, di dalam BOPs, dan sistem drive atas / katup pengaman kelly yang menjadi tekanan diuji sesuai dengan persyaratan sebagai berikut: BOP Tekanan Tes KEGIATAN 5. Cek aliran akan direncanakan pada interval kurang dari 100 'ketika pengeboran dengan sistem penggerak teratas di zona tekanan abnormal. 6. Perlu ditekankan kepada driller bahwa Perusahaan akan mendukung putusan driller ketika membuat pemeriksaan aliran tambahan (tidak termasuk dalam pedoman ini) atau ketika menutup-dalam sumur karena mengalir. Pedoman Degasser BOP PENGUJIAN PERSYARATAN 1) uji penerimaan BOP awal (saat rig berada di bawah kontrak) Tes dengan air untuk 200 psi rendah dan dinilai tekanan kerja pencegah / peralatan 2) Instalasi awal pada Wellhead jika tidak sepenuhnya diuji untuk dinilai tekanan kerja per 1) di atas. Tes dengan air untuk 200 psi WP rendah dan dinilai dari pencegah / peralatan atau kepala sumur, mana yang kurang. Setidaknya sekali per sumur domba jantan harus diuji untuk dinilai WP mereka ketika kepala sumur yang tepat diinstal. Tes dengan air untuk 200 psi rendah. Uji annular 70% dari tekanan kerja dinilai atau dinilai tekanan kerja kepala sumur, mana yang kurang. 3) instalasi awal pada wellhead jika sepenuhnya diuji untuk dinilai WP per 1) di atas. Untuk domba jantan psi 5k atau lebih rendah, ekor domba jantan uji / eq uipment untuk dinilai tekanan kerja. Untuk 10k ekor domba jantan psi atau lebih tinggi, ekor domba jantan uji / peralatan untuk tekanan yang melebihi maksimum diantisipasi tekanan permukaan tetapi tidak kurang dari psi 5k. Setidaknya sekali per sumur domba jantan harus diuji untuk dinilai tekanan mereka bekerja ketika kepala sumur yang tepat diinstal. Catatan: Pada sumur diatur oleh aturan MMS, semua domba / peralatan harus diuji untuk dinilai tekanan mereka bekerja atau dinilai tekanan kerja dari kepala sumur, mana yang kurang (kecuali disetujui lain oleh Kabupaten Pengawas). 4) Setelah pengaturan casing tali DAN sebelum pengeboran sepatu casing. Sama seperti 3) di atas. 5) tes berikutnya tidak melebihi setiap 14 hari. Sama seperti 3) di atas. Pada workovers diatur oleh aturan MMS, maka frekuensi uji setiap 7 hari bukan 14. 6) Setelah pemutusan atau perbaikan tekanan yang berisi segel namun terbatas untuk komponen yang terkena dampak. Catatan: formulir tes BOP yang dirancang khusus untuk rig Tes dengan air untuk 200 psi dan diberi pengeboran. Laporan ini harus ditinjau oleh tekanan kerja pencegah / peralatan atau Pengawas Operasional untuk memastikan mereka kepala sumur, mana yang kurang. puas bahwa data yang cukup akan disimpan untuk memastikan kepercayaan dalam operasi yang tepat dari peralatan BOP. 1. Persyaratan peraturan mungkin memerlukan variasi dari atas dan akan memerintah, jika lebih ketat. 2. Tes tekanan akan berganti-ganti antara stasiun kontrol. Setelah pengujian tekanan dari salah satu stasiun kontrol, melakukan tes fungsi lengkap dari BOP di stasiun lain lain. 3. Tekanan tes akan sesuai dengan di atas atau yang ditetapkan dalam Program Pengeboran. Tekanan akan diselenggarakan stabil selama minimal 5 menit pada kedua tes tekanan rendah dan pada tes tekanan tinggi atau sebagaimana ditentukan dalam Program Pengeboran. 4. Peralatan BOP akan tekanan diuji ketika awalnya diinstal dan setidaknya setiap 14 hari sesudahnya, seperti yang dipersyaratkan oleh OIMS. Sisi tekanan tinggi dari manifold choke harus tekanan diuji untuk BOP tekanan tes ram yang dibutuhkan. Sisi tekanan rendah dari manifold choke akan diuji untuk dinilai WP-nya (OIMS Pedoman Bagian 6). Hasil semua tes BOP dan setiap kekurangan dan / atau perbaikan akan disimpan pada Pengeboran Laporan Harian dan IADC Laporan. Data uji rinci juga akan disimpan oleh kontraktor pengeboran pada Bentuk tes BOP yang selesai harus ditandatangani oleh OIM dan Cementer dan akan diberikan kepada Operasi Supervisor, bersama dengan grafik rekaman tekanan mendukung operasi pengujian BOP. Semua grafik tekanan harus tanggal dan benar diberi label untuk setiap komponen diuji. Semua catatan yang berkaitan dengan tes BOP harus dipertahankan pada rig pengeboran sampai selesai dengan baik. Catatan yang kemudian diteruskan ke Operasi Inspektur untuk dimasukkan dalam file baik atas permintaan. Tes fungsi Sistem pengalir harus diuji fungsi sehari-hari dan sistem BOP harus diuji fungsi mingguan. Ketika melakukan tes ini, semua menutup dan membuka kali dibutuhkan untuk berfungsi setiap komponen harus dicatat untuk perbandingan dengan tes sebelumnya. Jangan menarik keluar dari lubang hanya untuk uji fungsi BOPs. Tes pengalir Pedoman untuk pengujian diverters adalah sebagai berikut: 1. Waktu respon yang dibutuhkan untuk membuka katup pengalir, dan menutup tas pengalir sekitar pipa bor akan dicatat dan dilaporkan pada formulir tes BOP. 2. Setelah instalasi awal, semua lini pengalir akan dipompa melalui pada tingkat maksimum yang mungkin, untuk mendeteksi kebocoran, pastikan benar berbaris, dan memeriksa untuk getaran yang berlebihan. 14,4 PERALATAN Spesifikasi peralatan untuk peralatan kontrol baik yang disediakan di bawah. Penyimpangan kurang dari pedoman ditampilkan harus didasarkan pada penilaian risiko dan harus memiliki kedua EMDC dan persetujuan manajemen Kontraktor Pengeboran. Pengalir Sistem Sebuah "pengalir System" akan diinstal pada semua string casing sebelum casing permukaan. Sistem pengalir harus sesuai dengan spesifikasi sebagai berikut: Pengalir Desain: 1. Sistem pengalir terdiri dari: Jenis annular pengalir packer Baris pengalir (2 baris, 10 "ID min, 300 psi WP) Terpencil digerakkan Ball Valve pada setiap baris Katup pengalir 10 "ID di garis pengalir Membunuh baris inlet bawah diverter (3 "nominal) Katup di garis kill 2. Semua komponen pengalir (katup, garis, dll) akan dinilai untuk minimal 300 psi tekanan kerja. Aktuator katup harus menjadi ukuran untuk menutup di atas minimal 300 psi. 3. Semua Katup pengalir akan membuka penuh (katup bola disukai). Pengalir Sistem Penutupan 1. Aktuasi dari pengalir harus tersedia dari lantai rig dan setidaknya satu lokasi terpencil lain yang jauh dari lantai rig. Semua fungsi pengalir harus tersedia dari lokasi tersebut. 2. Jika regulator hydro-pneumatik digunakan, nitrogen back-up diperlukan. 3. Unit pengalir hidrolik kontrol harus menyediakan 1,5 kali cairan yang dapat digunakan yang diperlukan untuk membuka katup pengalir, dan menutup annulus pengalir dan mampu dioperasikan dari panel kontrol utama dan jarak jauh dari konsol pembor itu. BOP Sistem Tumpukan BOP dan sistem penutupan harus dipasang untuk semua pengeboran dan penyelesaian operasi dengan annular dan domba jantan mampu menutup di atas semua ukuran pipa bor digunakan untuk bagian lubang sesuai dengan spesifikasi sebagai berikut: Catatan: Jika gas Hidrogen Sulfida diharapkan, semua komponen BOP dan segel elemen harus disertifikasi untuk layanan H2S. 4. Semua ekor domba jantan, tersedak / membunuh garis, dan tersedak / membunuh katup harus memiliki kerja rating tekanan setara atau lebih besar dari kepala sumur bekerja rating tekanan. Annular harus memiliki kerja penilaian tekanan minimal 50 persen dari preventers ram. 5. Ram dan Choke / Membunuh penempatan stopkontak baris harus menyediakan kemampuan untuk: BOP Stack Menutup dalam pada string bor dan casing atau kapal dan memungkinkan sirkulasi. 1. BOP tumpukan harus diatur sebagaimana ditetapkan dalam Permukaan Pencegahan ledakan dan Nah Kontrol Peralatan Manual. Tutup dan segel pada lubang terbuka dan memungkinkan operasi pengendalian volumetrik dengan baik. 2. Elemen BOP akan kompatibel dengan jenis lumpur digunakan. Strip drill string menggunakan pencegah annular. Bullhead bawah ekor domba jantan buta. 3. Dua ekor domba jantan harus berukuran untuk pipa bor lebih besar dan seekor domba jantan untuk pipa bor kecil jika dua ukuran pipa dan / atau string runcing yang digunakan. Variabel ekor domba jantan bore dapat digunakan untuk memenuhi kriteria ini. Bagian bawah ram harus berukuran untuk ukuran pipa yang lebih besar. VBRs tidak dapat digunakan untuk ram induk. Lihat Bagian 4.0 dari Permukaan Pencegahan ledakan dan Nah Kontrol Peralatan Manual untuk rincian dan skenario tambahan. 6. Outlet choke harus menjadi minimal 3 "ID. 7. Penggunaan klem akan memerlukan persetujuan pengecualian dari manajer Lapangan Drilling. 8. Outlet samping pada tubuh ram harus disegel dengan flange buta (katup dapat diterima hanya jika mereka adalah tekanan diuji pada frekuensi yang sama seperti domba jantan). 9. Rams harus memiliki kemampuan penguncian (jika kunci yang manual, engkol dengan roda harus tersedia di rig). 10. Rams harus mampu menggantung maksimum diantisipasi beban drill string dengan sendi alat yang digunakan dan mempertahankan segel terhadap tekanan lubang sumur setara dengan tubuh ram rating tekanan kerja. VBRs tidak direkomendasikan sebagai hang-off ekor domba jantan. Jika VBRs yang akan digunakan sebagai domba jantan hangoff, spesifikasi pabrik akan diperiksa untuk ukuran pipa dan hang-off nilai beban. Hanya "hang-off" blok jenis ram, dengan daerah mengeras di sekitar bibir blok ram, harus digunakan. 11. Gulungan pengeboran harus memiliki setidaknya ID cukai dan bekerja rating tekanan seperti yang dari tubuh ram. Mata air 1. "A" bagian harus memiliki katup ganda pada satu outlet dengan tekanan kerja setidaknya setara dengan "A" bagian atas flange. 2. Semua bagian kepala sumur harus memiliki katup flens dengan dinilai tekanan kerja paling tidak setara dengan bagian atas flange. 3. Sebuah katup kedua dari tekanan kerja yang sama harus dipasang pada setiap bagian kepala sumur di mana casing string yang ditangguhkan oleh bagian tidak disemen ke permukaan. Mata air Tersedak dan Bunuh Garis The Choke dan Bunuh Garis harus dilengkapi dengan dan memiliki tekanan kerja dinilai setidaknya setara dengan ram BOP Peringkat pencegah. Spesifikasi lainnya sebagai berikut: 1. Satu katup hidrolik (misalnya, gagal-aman dekat) pada baris choke berdekatan dengan spool pengeboran BOP. 2. Satu katup manual pada baris choke antara katup hidrolik dan manifold choke. 3. Satu katup hidrolik dan satu katup manual pada baris membunuh antara pipa tegak atau pompa berjenis dan BOP pengeboran spool. 4. Garis Choke harus memiliki minimal ID dari 3 ". Bunuh garis harus memiliki minimal ID dari 2". 4. Semua bagian atas "A" bagian harus dilengkapi dengan outlet kedua yang memiliki flens buta diinstal pada outlet. 5. Sebuah pengukur tekanan harus dipasang pada semua bagian kepala sumur di luar katup untuk memfasilitasi pemantauan tekanan casing annulus. BOP Control System BOPs dikuasai oleh pertemuan Control System kriteria yang tercantum di bawah ini dan harus memenuhi tujuan sebagai berikut: Menyediakan sistem kontrol berlebihan. Menyediakan darurat back-up dalam kasus hilangnya rig udara dan / atau daya listrik. Memungkinkan tekanan operasi disesuaikan independen untuk annular dan fungsi BOP lainnya. Tutup setiap Ram Preventer dalam waktu 30 detik. Tutup setiap annular Preventer <18-3 / 4 "dalam waktu 30 detik dan 45 detik untuk jarak preventers 18-3 / 4". Permukaan Botol Accumulator 1. Sebuah jumlah yang memadai botol akumulator akan dipasang, minimal, untuk memenuhi spesifikasi teknis EMDC ini, API RP 16D (Bagian I & II), dan / atau persyaratan lokal untuk unit akumulator sizing. Lihat Bagian 5.0 dari Permukaan Pencegahan ledakan dan Nah Kontrol Peralatan Manual untuk rincian tentang persyaratan EMDC. CATATAN: â € œAPI RP 16E sebagai direferensikan di manual BOP sejak itu telah ditarik. Referensi API yang benar untuk desain akumulator sekarang API Spec 16Dâ €. 2. Tekanan precharge untuk semua botol akumulator akan diverifikasi pada mobilisasi unit pengeboran dan kira-kira setiap 60 hari sesudahnya. 3. Botol akumulator akan dibagi menjadi setidaknya dua bank atau lebih yang terpisah dari umumnya jumlah yang sama botol dan masing-masing bank harus mampu dipisahkan oleh katup isolasi. Akumulator Control Unit 1. Back-up pompa, didorong oleh sumber listrik yang berbeda dari pompa utama (udara didorong ketika primer adalah drive listrik) akan dipasang. 2. Setiap pompa adalah untuk mampu terisolasi untuk perbaikan sementara yang lain tetap beroperasi. 3. Reservoir cairan hidrolik akan menjadi ukuran yang memadai untuk menahan dua kali kapasitas bisa digunakan yang dibutuhkan cairan dari botol akumulator. 4. Cairan hidrolik akan disaring melalui 20 mesh atau saringan hisap kecil. 5. Sebuah katup jarum ganda akan dipasang berdarah off berjenis dan akumulator ke dalam tangki cadangan (yang dibutuhkan untuk melakukan minicek). 6. Pengisian berjenis akan memiliki pembukaan penuh, valved outlet untuk pompa eksternal. 7. Manifold akan dilengkapi dengan tekanan mengurangi regulator (0 tekanan maksimum yang diijinkan) ditambah memotong dan isolasi katup. 8. Katup pelepas tekanan akan dipasang hulu dan hilir dari regulator bermacam-macam. 9. Seluruh sistem harus di daerah yang mudah diakses personil rig dan dilindungi dari kerusakan dari sumber rig lainnya. 10. Periksa jenis sistem alarm yang terpasang. Lihat alarm diperlukan di bawah ini. mencegah operasi yang tidak disengaja. Penjaga di unit akumulator tidak mengganggu kemampuan operasi jarak jauh. Regulator 1. Sistem kontrol akan memiliki regulator permukaan untuk tekanan manifold. 2. Sebuah back-up pasokan pneumatik, independen dari sistem udara rig, akan tersedia untuk regulator permukaan, kecuali regulator adalah cacing jenis gigi atau setara, untuk menghindari kehilangan tekanan pasokan dalam hal kegagalan rig udara. 3. The annular dan regulator berjenis akan ditetapkan ke minimal 1500 psi untuk normal menutup-in. Mengacu pada produsen operasi panduan untuk informasi tentang persyaratan tekanan penutupan tambahan untuk tinggi diharapkan menutup-tekanan dan tekanan annular Untuk ukuran lebih besar dari pipa dan casing. Panel BOP Operasi 1. Dua panel operasi akan tersedia, berisi semua fungsi BOP, salah satunya akan berlokasi di unit kontrol akumulator dan yang lainnya di lantai bor. 2. Semua fungsi harus disimpan dalam posisi kekuasaan dan tidak dalam posisi blok. Fungsi Ram buta adalah memiliki penjaga keamanan dipasang di semua panel dan pada akumulator stasiun unit kontrol untuk 3. Jika sistem relai listrik digunakan, daya generator darurat atau back-up sistem baterai akan tersedia untuk mengoperasikan panel remote untuk unit akumulator. 4. Jika rig udara digunakan, pasokan udara back-up akan tersedia untuk mengoperasikan panel terpencil. 5. Semua fungsi pada semua panel operasi akan jelas ditandai untuk tujuan dan posisi mereka. 6. Kecuali alarm umum dapat didengar di kedua daerah, panel lantai bor dan unit kontrol akumulator akan memiliki alarm untuk: Tekanan akumulator rendah Tingkat cairan rendah dalam tangki penampungan Kehilangan pasokan udara Choke & Bunuh Manifold Choke dan membunuh garis akan terikat ke manifold choke dan harus sesuai dengan spesifikasi sebagai berikut: 1. Choke berjenis akan memiliki kemampuan untuk mengambil keuntungan melalui salah satu setidaknya dua (2) choke adjustable yang satu harus menjadi choke hidrolik. 2. Minimal dua (2) katup akan hulu setiap choke dan satu (1) katup antara setiap outlet lain di manifold seperti manifold pipa tegak, tangki perjalanan garis berdarah, dan unit semen. 3. Tersedak dan pengukur harus dilengkapi dengan dan menyediakan berikut: Sebuah metode back-up petunjuk dari beberapa jenis (misalnya, back-up botol nitrogen, pompa manual, dll) akan tersedia untuk daya choke hidrolik dalam kasus kegagalan rig udara. Sebuah panel kontrol untuk choke hidrolik (s) yang memiliki alat pengukur untuk membaca tekanan pipa bor dan tekanan casing segera hulu dari choke beroperasi. Jika panel kontrol memiliki choke ganda, pengukur tekanan casing akan tersedia untuk memantau hulu tekanan masing-masing choke. Sebuah panel choke yang berisi alat pengukur menunjukkan posisi choke, pengukur untuk membaca tingkat pompa dan stroke pompa kumulatif, dan kontrol ke nol kumulatif tak pompa counter. Sebuah pilihan alat pengukur dikalibrasi dari berbagai rentang yang dapat membantu menentukan menutup-dalam pipa bor dan tekanan casing akurat. 4. Sensor tekanan yang memadai akan dipasang pada manifold choke dan pipa tegak berjenis untuk memantau anulus dan bor tekanan pipa dari semua lokasi choke. 5. Rating tekanan dari semua komponen (selang fleksibel, katup, garis, sensor tekanan, dll) antara BOP dan katup tekanan tinggi hilir choke akan memiliki tekanan kerja Peringkat setara dengan atau melebihi BOP Peringkat ram pencegah. 6. Semua ternyata di choke dan membunuh garis dari BOP ke manifold choke, dalam choke dan membunuh manifold, dan garis hilir manifold choke akan tee diinstal ditargetkan. 7. Outlet Manifold akan dikonfigurasi sehingga cairan kontrol juga dapat diarahkan dari manifold choke untuk bidang sebagai berikut: Lumpur Gas Separator Shaker Tank perjalanan Langsung ke laut atau ke pit cadangan melewati Mud Gas Separator Lumpur Gas Separator Sebuah pemisah gas lumpur akan dipasang dan harus sesuai dengan spesifikasi sebagai berikut: 1. Mampu ventilasi gas ke daerah yang aman melawan arah angin dan menyelamatkan cairan pengeboran ketika beredar melalui manifold choke selama operasi kontrol dengan baik. 2. Memberikan kepala yang cukup untuk memaksa gas keluar garis ventilasi serta gas yang terpisah dari cairan pengeboran. â € ¢ Lihat Permukaan Pencegahan ledakan dan Nah Kontrol Peralatan Manual (halaman 8-19 dan 820 untuk rincian). 3. Melampiaskan garis dari pemisah gas lumpur akan memiliki diameter minimal 8 "dan mengandung jumlah minimum bergantian untuk mengurangi tekanan gesekan gas. 4. Port pemeriksaan akan tersedia pada pemisah gas lumpur untuk inspeksi visual dari separator. Selama mobilisasi dan setelah digunakan untuk kontrol dengan baik, separator harus dikeringkan, dicuci dan diperiksa secara visual. 5. Sebuah katup by-pass akan dipasang ventilasi yang gas keluar garis ventilasi langsung dan mengisolasi ruang pengocok shale ketika kaki cair hilang di pemisah gas lumpur. Lokasi katup by-pass harus hulu lumpur pemisah gas baris ke shaker. 14,5 BAIK PENGENDALIAN latihan Pedoman Bor umum BOP Nah control latihan harus dilakukan sesuai dengan pedoman dalam bagian ini untuk memastikan bahwa personil pengeboran dapat mendeteksi dan menutup-in dengan baik dalam waktu sesingkat mungkin. Latihan pencegah ledakan akan dilakukan sampai prosedur untuk menutup-dalam sumur kedua sementara pengeboran dan tersandung otomatis. Para anggota kru bor harus mendeteksi aliran baik simulasi dan bereaksi dengan cara yang tepat dalam batas waktu yang diperlukan. Skema dari BOP akan diposting di lantai bor menunjukkan jarak dari RKB ke berbagai komponen BOP. The Driller harus tahu setiap saat posisi bor tali alat bersama dalam kaitannya dengan BOP stack. Sumur awalnya akan ditutup-in menggunakan annular Preventer. Untuk memungkinkan untuk "cepat menutup-in", katup pertama hilir choke hidrolik harus dalam posisi terbuka dengan choke ditutup juga. Latihan harus diumumkan atau tanpa pemberitahuan kepada kru bor dan disimulasikan dengan mengubah tingkat pit, tingkat tangki perjalanan, dll Namun, toolpusher kontraktor pengeboran bertugas harus dibuat sadar bor sebelum mengubah tingkat pit untuk menghindari reaksi berlebihan oleh kru bor ia mengawasi. Bor perjalanan Tujuan dari latihan ini adalah untuk mengurangi waktu yang dibutuhkan untuk Driller untuk mendeteksi dan bereaksi terhadap masuknya sementara membuat perjalanan. Setelah BOP terinstal, bor ini harus dipegang dengan masingmasing kru sampai mereka benar-benar akrab dengan prosedur dan selanjutnya dengan masing-masing kru pada frekuensi yang ditentukan oleh OIMS. Sementara tersandung dan setelah string bor telah ditarik ke casing, tanpa pemberitahuan sebelumnya, tingkat tangki perjalanan jelas adalah untuk secara bertahap meningkat secara manual menaikkan lumpur tingkat pit mengambang atau secara lisan memberitahukan Driller dari perjalanan Tank Tangan atau Logging Mud Unit (jika digunakan) bahwa peningkatan tingkat tangki perjalanan telah terjadi. Driller itu, Bor Crew, dan Penebang Mud harus mengakui keuntungan tangki 10 perjalanan bbl dalam 1 menit dan menutup dalam baik dalam tambahan 1 menit dengan melakukan hal berikut: 1. Mendeteksi tendangan dan suara alarm. 2. Mencatat waktu untuk mendeteksi gain tangki perjalanan (tujuannya adalah 1 menit atau kurang). 3. Mengatur slip dengan alat bersama di meja putar. 4. Matikan perjalanan pompa tangki dan memeriksa aliran kembali ke dalam tangki perjalanan. 5. Make up (tangan ketat) merupakan katup pengaman terbuka pada pipa bor. Katup dekat. 6. Periksa baik untuk aliran. 7. Menutup-di dalam sumur dengan membuka katup HCV dan menutup BOP anular dalam satu gerakan, torqueup katup pengaman. Pastikan choke valve berjenis hilir kekuatan choke ditutup. 8. Segera memberitahukan ExxonMobil Pengeboran Pengawas dan Toolpusher. Mencatat waktu untuk shutin baik setelah aliran terdeteksi (tujuannya adalah 1 menit atau kurang untuk meminimalkan volume yang masuknya). 9. Menginstal dan make-up dalam BOP. Tutup nside B OP. Buka Keselamatan Valve. (Untuk operasi stripping). 10. Tekanan casing merekam dan keuntungan dalam tangki perjalanan. Periksa tekanan akumulator. Periksa komponen sistem BOP dan tersedak ragamnya untuk posisi yang benar. Periksa kebocoran dan / atau aliran. 11. Bersiaplah untuk memadamkan sumber api. Waspada setiap perahu berdiri di rig pengeboran. 12. Memiliki derek Operator siaga untuk kemungkinan personil evakuasi. 13. Dan mengkaji kemampuan bor dengan anggota kru. Log bor dan waktu reaksi pada Pengeboran Laporan Harian dan IADC Laporan. Catatan: Sebuah bor khas akan berhenti di Langkah # 10, meskipun dokumentasi di bawah Langkah # 13 masih akan dilakukan. Langkah # 11 - # 12 dapat dilakukan untuk pelatihan tambahan dan latihan diperpanjang. Pit Bor Tujuan dari latihan ini adalah untuk mengurangi waktu yang dibutuhkan untuk Driller untuk mendeteksi dan bereaksi terhadap perubahan dalam tingkat pit. Setelah BOP terinstal, bor ini akan diadakan dengan masing-masing kru sampai mereka benar-benar akrab dengan prosedur dan selanjutnya dengan masing-masing kru pada frekuensi yang ditentukan oleh OIMS. 7. Rekam pipa bor dan casing tekanan. Timbang lumpur hisap pit. Periksa tekanan akumulator. Periksa komponen sistem BOP dan tersedak ragamnya untuk posisi yang benar. Periksa kebocoran dan / atau aliran. Sementara pengeboran di bawah, tanpa pemberitahuan sebelumnya, tingkat pit jelas adalah untuk secara bertahap meningkat secara manual menaikkan tingkat mengambang lubang lumpur atau dengan memompa lumpur dari tangki perjalanan ke sistem aktif. Driller itu, Bor Crew, dan Penebang Mud harus mengakui keuntungan 10 lubang bbl dalam 1 menit dan ditutup di sumur dalam tambahan 1 menit dengan melakukan hal berikut: 8. Lengkapi Lembar Kerja Nah Membunuh. Tentukan bahan yang dibutuhkan untuk mengedarkan keluar tendangan. 9. Bersiaplah untuk memadamkan sumber api. Waspada setiap perahu berdiri di unit pengeboran dan / atau memiliki blok keamanan dari daerah jika pada rig darat. 1 Memiliki derek Operator siaga untuk kemungkinan evakuasi personel jika pada jack-up. 2 Dan mengkaji kemampuan bor dengan anggota kru. Log bor dan waktu reaksi pada Pengeboran Laporan Harian dan IADC Laporan. 1. Mendeteksi tendangan dan suara alarm. 2. Mencatat waktu untuk mendeteksi gain tingkat pit (tujuannya adalah 1 menit atau kurang). 3. Mengambil string bor sampai alat bersama membersihkan meja putar. Pastikan alat bersama tidak di BOP. 4. Matikan pompa lumpur (s) dan periksa baik untuk aliran. (Gunakan tangki perjalanan jika ragu tentang sumur mengalir). 5. Jika mengalir, menutup di dalam sumur dengan membuka BOP garis choke valve (HCV) dan menutup annulus tersebut. 6. Melaporkan keuntungan pit dan mengalir hasil cek ke Pengawas Operasional dan Toolpusher. Catatan: Sebuah bor khas akan berhenti pada Langkah # 6, meskipun dokumentasi di bawah Langkah # 12 masih akan dilakukan. Langkah # 7 â € "# 11 dapat dilakukan untuk pelatihan tambahan dan latihan diperpanjang. Daya Choke Bor Kru didorong untuk melakukan latihan kekuatan choke sebelum pengeboran-out setelah pengaturan dari setiap string casing. Bor memberikan latihan untuk Drilling Supervisor, Toolpusher, dan anggota kru dalam mengoperasikan kekuatan choke. Jika dilakukan dari rig mengambang, itu adalah waktu yang tepat untuk mengukur garis choke dan membunuh tekanan gesekan line di berbagai tingkat membunuh. Bor harus dilakukan sebagai berikut: 1. Mengedarkan baik bersih. 2. Melakukan Bor Pit dan dekat di dalam sumur menggunakan annular BOP. 3. Ambil tarif sirkulasi lambat pada 20, 30, dan 40 spm bawah pipa bor dan keluar garis choke dengan kekuatan choke hidrolik terbuka penuh (langkah opsional jika sudah tercapai). 4. Melakukan pelatihan awak menggunakan kekuatan choke. Membawa pompa pada kebohongan sambil menjaga tekanan casing konstan untuk kecepatan pompa yang diinginkan. Tekanan casing dapat divariasikan untuk menggambarkan waktu yang dibutuhkan untuk pulsa tekanan untuk melakukan perjalanan ke anulus dan cadangan pengukur tekanan pipa bor. tugas awak, juga akan dipasang di lantai bor dan / atau papan pengumuman. Selama semua operasi kontrol dengan baik, aturan berikut akan ketat. 1. Merokok akan terbatas pada wilayah tempat. Pelanggar akan dikenakan pemecatan langsung. 2. Tukang las tidak akan melakukan pekerjaan apapun tanpa instruksi spesifik dan pengawasan langsung oleh Senior Kontraktor Pengeboran toolpusher dan pekerjaan tersebut harus dibersihkan dengan Operasi Pengawas di muka. 3. Semua penggiling, senjata jarum, dll, akan ditutup. 4. Off-tugas dan personil yang tidak diperlukan akan tetap di daerah tempat atau area kerahkan ditunjuk. 5. Jika salah satu dari berikut terjadi, situs rig yang akan segera ditinggalkan: Permukaan gas yang tidak terkendali di lantai rig Nah cairan memulai pembicaraan sekitar casing Nah aliran terdeteksi tanpa pengalir atau tidak ada BOP diinstal. 5. Menilai bor dan penggunaan choke hidrolik dengan awak. 6. Catat bor, tarif pompa lambat / tekanan, dan bobot lumpur digunakan pada IADC dan Harian Drilling Report. 14,6 BAIK PENGENDALIAN PROSEDUR Salinan dilaminasi dari rig prosedur shut-in tertentu harus dipasang di lantai rig dekat konsol pembor itu. Rig spesifik tagihan stasiun, daftar 6. Pertemuan keselamatan pra-pekerjaan akan diselenggarakan dengan semua personil yang terlibat sebelum mencoba baik membunuh operasi. Pengalir Terpasang Berhasil mengalihkan aliran baik sebelum permukaan gas dan tanpa broaching mensyaratkan bahwa semua peralatan permukaan siap untuk menutup tas pengalir segera belum memiliki jalur bantuan bagi cairan dengan baik untuk mencegah broaching. Sementara pengeboran dengan Sistem pengalir menggunakan Remote Operated Ball Valve, katup fungsi terbuka harus menyelami ke dalam garis dekat pengalir sehingga katup akan membuka sebelum penutupan annular. Lumpur harus dipompa melalui jalur pengalir setiap tur untuk memastikan garis dan jalur bantuan yang tidak terpasang. Jika aliran terdeteksi, prosedur berikut harus diikuti untuk mengalihkan aliran: 7. Jika kondisi memungkinkan, mencoba membunuh dinamis dengan memompa semua lumpur yang tersedia dari lubang diikuti oleh air dari lubang air jika lumpur tidak membunuh baik. Memompa juga akan menjaga aliran gas basah dan mengurangi bahaya kebakaran. Catatan: Jika tersandung, berjalan casing, atau keluar dari lubang, mungkin perlu untuk strip kembali ke bawah sebelum mencoba membunuh dinamis. 8. Personil harus dipasang di sekitar lokasi untuk mendeteksi tanda-tanda broaching. BOP Operasi Prosedur pengendalian baik dalam bagian ini berlaku ketika pengeboran bawah permukaan casing dengan sepatu yang kompeten dan setumpuk BOP diinstal. 1. Matikan pompa lumpur jika pengeboran. Operasi Pengawas harus memastikan berikut ini di tempat: 2. Ambil untuk menghapus kelly atau alat bersama di atas kantung pengalir. Diagram alur yang diposting di lantai rig dan lokasi lain yang sesuai untuk "Shut-In Prosedur untuk pengeboran, Tripping, & Running Casing" dan "Stasiun Bill selama Nah Pengendalian Operasi" The Choke Manifold berbaris untuk mengambil kembali melalui "Mud Gas Separator" Katup hilir dari choke hidrolik adalah dalam posisi tertutup selama operasi pengeboran. 3. Periksa aliran jika tidak pasti juga mengalir. 4. Tutup annular pengalir. 5. Mengevakuasi personil ke daerah yang aman. 6. Beritahu Operasi Inspektur. FlowCheck Prosedur - Pengeboran 1. Baik itu harus diperiksa untuk aliran jika salah satu dari berikut terjadi kapan saja selama pengeboran atau beredar operasi: Setiap kali aliran terdeteksi, Driller adalah untuk menutup-dalam sumur atas inisiatifnya sendiri tanpa persetujuan lebih lanjut dengan cara berikut: 1. Membuka remote katup choke baris pada baris Choke. Kenaikan Tingkat Penetrasi. Kenaikan Mud Kembali Flow. Keuntungan di Pits. 3. Pastikan bahwa Choke Manifold ditutup hilir kekuatan choke. Penurunan Pompa Tekanan dan / atau Gain di Pompa Strokes. 4. Merekam menutup-dalam pipa bor dan tekanan casing, dan keuntungan tingkat pit. Unit Gas tinggi. 5. Beritahu Operasi Pengawas dan Toolpusher secepat praktis. Kenaikan mendadak Torque. Kenaikan klorida lumpur. Penurunan klorida lumpur. 2. Prosedur berikut akan digunakan untuk memeriksa aliran: Mengambil string bor dan posisi alat bersama di posisi menutup-in yang telah ditentukan. Matikan pompa lumpur (s) Periksa baik untuk aliran. Gunakan tangki perjalanan jika ragu tentang sumur mengalir. Diam-In Prosedur - Pengeboran 2. Tutup pencegah annular. 6. Periksa tekanan akumulator. Periksa komponen sistem BOP dan mengkonfirmasi bahwa manifold choke berbaris dengan benar. Periksa kebocoran dan / atau aliran. 7. Rekam pipa bor dan tekanan casing setiap menit sampai tekanan menstabilkan kemudian setiap 10 menit sesudahnya. 8. Lengkapi "Yah Membunuh Lembar Kerja '. Pilih metode membunuh dan menentukan bahan yang dibutuhkan untuk mengedarkan keluar tendangan. 9. Sesuaikan tekanan regulator pada pencegah annular. Membalas pipa, jika mungkin, untuk menghindari mencuat. 10. Bersiaplah untuk memadamkan sumber api. FlowCheck Prosedur - Tripping 1. Baik itu harus diperiksa untuk aliran jika salah satu dari berikut terjadi kapan saja selama operasi tersandung: Lubang tidak mengambil jumlah yang benar cairan. Keuntungan dalam tangki perjalanan. 2. Prosedur berikut akan digunakan untuk memeriksa aliran: Mengatur slip dengan alat bersama di meja putar. Membuat sebuah katup pengaman terbuka pada pipa bor. Katup dekat. Catatan: Ketika pengeboran dengan TDS, jangan membuat drive atas ke string bor. Melepaskan katup yang lebih rendah di drive atas memakan waktu dan memerlukan 65/8 kotak Reg x 41 / 2 "JIKA kotak crossover. 3. Amati baik untuk aliran. Jika ada pertanyaan apakah sumur mengalir, itu harus ditutup-in dan check. Diam-In Prosedur - Tripping Setiap kali aliran terdeteksi, Driller adalah untuk menutup-dalam sumur atas inisiatifnya sendiri, tanpa persetujuan lebih lanjut, dengan cara sebagai berikut: 1. Matikan pompa tangki perjalanan. 2. Membuka katup choke terpencil di garis choke. 3. Tutup pencegah annular sekitar pipa bor atau drill collars. 4. Menginstal dan membuat dalam BOP di atas katup pengaman. 5. Membuka katup pengaman bor pipa. 6. Beritahu Operasi Pengawas dan kontraktor toolpusher secepat praktis. 7. Rekam menutup-tekanan casing. Tangki catatan perjalanan dan / atau keuntungan pit. Periksa tekanan akumulator. Periksa tekanan akumulator. Periksa komponen sistem BOP dan tersedak ragamnya untuk posisi yang benar. Periksa kebocoran dan / atau aliran. 8. Sesuaikan tekanan penutupan annular dan membalas pipa bor untuk mencegah pipa menempel. Catatan: Jika casing memiliki tekanan dan / atau sumur akan mengalir melalui pipa bor, maka akan diperlukan untuk strip pipa bor kembali ke bawah sebelum beredar keluar masuknya. Lihat Pedoman Stripping dan Prosedur untuk informasi tambahan. Diam-In Prosedur (kerah Bor di BOP stack) 1. Menginstal crossover dan membuat katup pengaman jika kerah bor di atas meja putar. 2. Memulai menutup-dalam sumur menggunakan prosedur yang sama seperti untuk pipa bor. FlowCheck Prosedur - Menjalankan Casing 1. Periksa baik untuk aliran harus salah satu dari berikut terjadi kapan saja selama casing operasi berjalan: Anulus mengalir. Keuntungan di lubang lebih besar dari casing / pipa perpindahan. 3. Meningkatkan tekanan penutupan annular jika perlu untuk mendapatkan segel di sekitar kerah bor spiral atau pipa spiral HeviWate bor. 2. Berhenti casing operasi berjalan. Diam-In Prosedur (Bor String Out Of Lubang) Diam-In Prosedur - Menjalankan Casing 1. Tutup domba buta jika baik mulai mengalir sementara string bor keluar dari lubang. 1. Membuka katup choke terpencil di garis choke. 3. Periksa aliran. 2. Tutup pencegah annular. 2. Buka baris choke katup pada gerai pertama di bawah ekor domba jantan buta. Pemantauan tidak akan mungkin melalui jalur choke pada BOP tumpukan konfigurasi mana ram buta terletak di bawah choke dan membunuh line. Ini akan membutuhkan tekanan pemantauan melalui katup anulus. 3. Rekam menutup-tekanan casing dan keuntungan dalam tangki perjalanan. 4. Beritahu Operation Supervisor dan Kontraktor toolpusher. 5. Siapkan untuk strip ke dalam lubang menggunakan annular yang. Lihat Stripping Pedoman dan Tata. â € ¢ Tekanan penutupan annular seharusnya disesuaikan dengan OD pipa yang lebih besar sebelum memulai untuk menjalankan casing. 3. Menginstal crossover dan membuat katup pengaman. Catatan: Jika kebocoran peralatan casing float, mungkin perlu untuk membuka annular sementara untuk meringankan aliran membentuk casing sementara menginstal katup pengaman. Nah Membunuh Pilihan - Menjalankan Casing Ada beberapa kemungkinan membunuh baik, tergantung pada jumlah casing run, jumlah aliran baik, kondisi peralatan float, dan tekanan annulus. Opsi yang dipilih harus didasarkan pada kondisi sumur bor yang sebenarnya, setelah berkonsultasi dengan Operasi Inspektur. Pilihan meliputi: 1. Menghapus casing keluar dari lubang. 2. Membunuh baik di kedalaman casing ini. 3. Mengupas casing ke dalam lubang pada pipa bor. Cairan Berat / Tingkat Beredar Cairan Berat 1. Berat cairan untuk beredar keluar influxes dan membunuh sumur harus dipilih setelah berkonsultasi dengan Operasi Inspektur, ketika praktis, untuk yang satu metode berikut untuk digunakan berdasarkan kondisi sumur bor yang sebenarnya: Metode pengebor - Edarkan keluar masuknya menggunakan cairan berat asli, kemudian beredar membunuh berat cairan di sekitar. Keuntungan utama dari metode ini adalah kecepatan relatif dan kesederhanaan. Namun, metode ini akan menghasilkan tekanan permukaan maksimum yang lebih tinggi. Jika tidak cukup barit adalah di tangan untuk berat sampai cairan, metode ini umumnya harus digunakan daripada menangguhkan operasi sampai barit menjadi tersedia. Berat dan Tunggu Metode - Edarkan keluar masuknya dalam satu sirkulasi menggunakan berat cairan yang seimbang. Metode ini umumnya menghasilkan tekanan permukaan terendah dan meminimalkan waktu yang hilang dengan kembali ke operasi pengeboran normal secepat mungkin jika volume yang cukup cairan berat tersedia di rig pengeboran dan siap untuk memompa. Dalam beberapa kasus, waktu yang diperlukan untuk menurunkan berat sampai cairan dapat berlebihan. 2. Pencampuran kemampuan tingkat rig pengeboran yang harus dipertimbangkan. Umumnya, incremental meningkat berat lumpur harus 1.0 ppg atau kurang. 3. Cairan Berat membunuh akhir adalah memiliki margin perjalanan minimal sekitar 200 psi tergantung di sumur. Margin perjalanan yang lebih tinggi mungkin diperlukan untuk sumur dengan masalah swabbing, dll Beredar Tingkat Seleksi: 1. Tingkat beredar untuk operasi baik membunuh harus dipilih setelah berkonsultasi dengan Operasi Inspektur, ketika praktis. Tingkat pompa di kisaran 1-3 BPM harus biasanya digunakan untuk beredar keluar masuknya. Keuntungan dari tingkat yang rendah pompa adalah: Memungkinkan More Time untuk Choke Operator untuk Mengatur Choke. Meminimalkan Penanganan Volume besar dari Gas di Permukaan. Mengurangi Kemungkinan Hilang Returns. 2. Faktor-faktor seperti integritas formasi pada peralatan kontrol sepatu casing dan rig dengan baik (misalnya, keterbatasan pemisah gas lumpur) yang harus dipertimbangkan ketika memilih tingkat yang beredar. 3. Tingkat pompa harus dikurangi, jika perlu, ketika gas mencapai permukaan untuk mencegah hilangnya kaki cairan dalam separator gas lumpur. 4. Bila diperlukan untuk mengubah suku beredar, baik itu harus menutup-in dan tekanan gesekan baru ditentukan. Konstan Bawah Lubang Metode Tekanan Nah Bunuh Prosedur Tujuan beredar keluar influxes adalah untuk mempertahankan tekanan bottom-lubang konstan yang cukup untuk mencegah influxes lanjut meminimalkan sirkulasi hilang di sepatu casing. Berikut ini adalah langkah-langkah untuk mencapai tujuan ini. 1. Dengan choke hidrolik ditutup, buka katup hilir choke untuk memungkinkan pengembalian yang akan diambil dari garis choke melalui manifold choke dan ke Separator Gas Lumpur. 2. Membawa pompa sampai dengan kecepatan perlahan-lahan ke tingkat sirkulasi yang direncanakan. Gunakan choke hidrolik untuk mengadakan tekanan casing konstan pada anulus sama dengan menutup-tekanan asli pada casing ditambah 25 sampai 50 psi margin keamanan. 3. Baca dan merekam bor tekanan pipa setelah pompa mencapai kecepatan konstan yang diinginkan dan setelah casing tekanan menstabilkan ke nilai yang diinginkan. Catatan: The bor tekanan pipa pada saat ini adalah tekanan yang diperlukan untuk mempertahankan tekanan dasar lubang konstan ketika beredar pada kecepatan tertentu pompa saja. Perbedaan antara shut-tekanan awal pada pipa bor dan tekanan pemompaan pada pipa bor adalah tekanan gesekan yang diperlukan untuk mengedarkan cairan pengeboran pada kecepatan tertentu pompa saja. 4. Mempertahankan tekanan pipa bor yang diinginkan pada konstan tingkat pompa sementara beredar keluar masuknya dengan memanipulasi choke hidrolik mengambil keuntungan dari annulus. Perubahan tekanan akibat tersedak manipulasi membutuhkan sekitar 2 detik per 1000 bor string untuk mendaftar di gauge pipa berdiri; Namun, lag ini dalam waktu respon dapat lagi jika tendangan gas besar hadir. Jika berat lumpur asli digunakan, tekanan pipa bor akan diadakan konstan pada mencapai nya bit. Bersiaplah setiap saat untuk mengalihkan aliran ke laut atau ke suar sebagai degasser miskin-anak mungkin tidak dapat dengan aman menangani gas 100%. 5. Edarkan menggunakan bertahap berat fluida yang diinginkan sampai lumpur berat kill beredar di sekitar dan itu diverifikasi bahwa sumur mati. Gunakan hati-hati setiap saat sejak influxes tambahan bisa masuk sumur bor. 4. Memastikan bahwa pengukur tekanan mudah dibaca dan akurat diinstal pada manifold choke. 5. Pastikan bahwa sistem komunikasi visual antara orang yang mengoperasikan choke dan orang pemantauan tangki perjalanan telah ditetapkan. 6. Pastikan semuanya siap untuk mengambil keuntungan dari manifold choke melalui pemisah gas lumpur dan ke dalam tangki perjalanan. Jangan berdarah kembali ke penyemenan tank perpindahan. General Stripping Pedoman: Stripping Operasi 1. Hanya mengupas dalam lubang jika berat didukung dari string bor lebih besar dari gaya ke atas dari sumur bor ketika string bor di seluruh BOP stack. Bagian ini berlaku setelah membuat keputusan untuk strip di lubang untuk melakukan operasi membunuh selama insiden kontrol dengan baik. 2. Menggunakan teknik pelumasan jika berat didukung dari string bor kurang dari gaya ke atas dari sumur bor. Pengupasan Pedoman Penyusunan: 3. Memonitor dengan baik menanggung tekanan dan mengontrol tekanan permukaan menggunakan teknik migrasi gelembung / prosedur sementara rigging up untuk strip dalam lubang. 1. Pertemuan pra-pekerjaan yang akan dilakukan dengan anggota tim stripping. 2. Tugas pekerjaan yang ditinjau dan tanggung jawab yang ditunjuk dengan setiap individu di tim stripping. 3. Prosedur pengupasan adalah untuk ditinjau dan perhitungan yang harus dilakukan untuk kapasitas dan perpindahan dari string bor untuk operasi stripping. 4. Menginstal katup pelampung non-porting dalam bit sub jika string bor benar-benar keluar dari lubang. 5. Membuat kerah bor tambahan, jika perlu, untuk berat untuk strip dalam lubang. 6. Menginstal BOP dalam antara setiap kerah bor dan pipa bor atau di atas bit sub jika tidak menggunakan kerah bor. Catatan: Ini hanya mungkin untuk menjalankan alat wireline bawah ke atas dalam BOP. 7. Jika keluar dari lubang, perjalanan di dalam lubang dan posisi bit antara annular BOP dan domba jantan buta tertutup. 8. Bullhead lebih tinggi cairan pengeboran berat badan turun tersedak dan membunuh garis untuk menurunkan menutup-tekanan casing dan mengurangi gaya ke atas dari sumur bor jika diperlukan. 9. Tutup pencegah annular dan tekanan up string bor dengan unit penyemenan untuk tekanan casing setara. Catatan: Pastikan katup pengaman pipa bor dibuka sebelum pengupasan dalam lubang. 15. Selalu gunakan katup pengaman di lantai rig dan tidak drive atas ketika menutup di dalam sumur di perjalanan. Setelah pemasangan katup pengaman, memastikan bahwa katup cadangan di lantai rig sebelum operasi pengupasan dimulai. Stripping Prosedur: 1. Catat menutup tekanan casing. 2. Menginstal dalam BOP dan membuka katup pengaman. Catatan: Jangan lupa untuk membuka katup pengaman. 10. Buka domba buta. 11. Berdarah dari tekanan pipa bor untuk memastikan bahwa dalam BOP memegang. 12. Membalas string bor lambat jika di lubang terbuka untuk mencegah pipa dari mencuat saat rigging up untuk strip. 13. Mengurangi tekanan penutupan pada pencegah annular yang diperlukan untuk meminimalkan keausan pada elemen sementara reciprocating string bor. 14. Rig sampai katup pengaman dan mendapatkan tekanan pipa bor sebelum pengupasan jika string bor memiliki katup pelampung porting. 3. Isi pipa bor dengan pil gel di atas dalam BOP untuk mencegah sampah di string bor dari plugging katup. 4. Make up berdiri dari pipa bor dan perlahan perjalanan di dalam lubang. 5. Terapkan pipa ganja untuk setiap tubuh bersama alat untuk memudahkan perjalanan melalui pencegah annular. 6. Gunakan tekanan penutupan minimum pada pencegah annular selama operasi stripping. 7. Memonitor garis aliran untuk kebocoran dari pencegah annular sementara pengupasan di dalam lubang. Catatan: Beberapa kebocoran dari pencegah annular diinginkan untuk meningkatkan pelumasan antara karet melingkar dan pipa bor. 8. Baca dan mencatat tekanan casing sebelum mulai menurunkan masing-masing berdiri dari pipa bor. 9. Perlahan-lahan berdarah kembali dari lubang sumur dengan menggunakan tangan choke disesuaikan untuk mempertahankan berikut, mana yang lebih dahulu: Sebuah volume pengembalian yang sama dengan kapasitas dan perpindahan dari pipa yang dilucuti ke dalam lubang, OR: Tekanan casing yang sama dengan tekanan yang tercatat sebelum pengupasan berdiri di lubang, OR: Gas dikembalikan pada choke. Catatan: Cairan kadang-kadang hilang dengan pembentukan mengakibatkan mencapai tekanan casing yang sama dengan tekanan yang tercatat pada awal berdiri, sebelum volume kembali sama dengan kapasitas dan perpindahan dari pipa dapat berdarah. Catatan: Jangan berdarah off gas. 10. Ketika gas mencapai permukaan, mempertahankan tekanan konstan casing dan terus strip ke dalam lubang sampai bit adalah kembali di bagian bawah. 11. Membunuh baik menggunakan Bawah Konstan Metode Hole. Catatan: Ini mungkin tidak diperlukan untuk meningkatkan berat fluida pemboran untuk membunuh baik jika masuknya karena untuk swabbing kecuali margin perjalanan tidak cukup untuk tersandung aman. Nah Control untuk Wireline Operasi Prosedur dan persyaratan untuk peralatan tambahan untuk kontrol baik selama operasi wireline biasanya dihasilkan oleh tim pengeboran afiliasi, kecuali spesifikasi peraturan lokal yang berlaku. Dalam banyak kasus juga benar-benar stabil dengan berat lumpur yang digunakan pada saat operasi penebangan terjadi dan tidak ada sistem pelumas diperlukan. Karena pencegah annular mungkin tidak benar-benar menutup sumur bor dengan wireline dalam lubang, wirecutters harus tersedia untuk memotong kawat, jika diperlukan. Setiap tim operasional harus merencanakan untuk kemungkinan ini, termasuk mengamankan bagian dipotong permukaan kawat, jika mungkin, untuk mencegah kawat lari setelah dipotong. Sistem pelumas harus dipertimbangkan di mana arus juga mungkin terjadi selama berjalan logging. Daerah dengan zona terbuka produktif (terutama sumur gas bertekanan tinggi), daerah sensitif lingkungan, dan daerah dengan konsentrasi H2S yang signifikan bisa dipertimbangkan untuk penggunaan lubricators, yang dapat menutupi seluruh alat logging tali. Pelumas yang biasanya dibuat untuk pompa-in sub dan riser perakitan yang berlabuh di elemen tertutup dari pencegah annular atau flens ke puncak pencegah annular. Jika baik mulai mengalir sementara alat logging adalah di dalam lubang, alat string ditarik ke pelumas dan domba jantan buta ditutup untuk mengisolasi lubang sumur. Tekanan ini kemudian berdarah dari pelumas dan wireline peralatan aman dicurangi bawah. Barit Plug Dalam kebanyakan kasus, tujuan menggunakan bubur barit adalah untuk membunuh juga menggunakan tekanan hidrostatik lebih besar dari tekanan formasi. Berikut tiga karakteristik dari colokan barit adalah hasil dari analisis industri pengalaman dan laboratorium penelitian: 1. Kepadatan tinggi dan kemampuan pompa yang baik adalah parameter yang paling penting untuk dipertimbangkan saat merancang sebuah bubur membunuh berat. 2. Pengendapan barit dari plug barit adalah proses yang lambat yang biasanya nilai yang kecil di sebagian besar insiden kontrol dengan baik. 3. Lignosulfonat adalah deflocculant terbaik untuk digunakan saat merancang bubur untuk barit untuk menetap. Barit Plug Persiapan Pedoman: 1. Rencana di muka untuk penggunaan plug barit sebagai bagian dari operasi pengeboran. 2. Pastikan bahwa bahan yang diperlukan tersedia selama fase perencanaan untuk membantu meminimalkan kebingungan selama operasi pengaturan plug. 3. Pastikan bahwa setiap operator penyemenan akrab dengan masalah pencampuran dan memompa plug barit. 4. Merancang rencana tentatif untuk pencampuran, memompa, dan perpindahan dari bubur barit. 5. Memanfaatkan keahlian personil Kontraktor pengeboran selama fase perencanaan yang diperlukan. 6. Pastikan bahwa ada garis crossover yang dilepas di tempat untuk kapal barit dari tangki bulk ke unit semen jika plugging terjadi. 7. Pastikan bahwa tes barit deliverability ke unit penyemenan dilakukan sebelum mencoba untuk mengatur plug barit. Barit Plug Mencampur Pedoman: 1. Gunakan baik "Settling Resep" atau "Non-Settling Resep" yang ditunjukkan di bawah saat pencampuran plug barit. Settling Resep 1. bbl A i r ( a i r l a u t s e g a r a t a u ) £ 1 5 l i g n o s u l f o n a t 2. LB. c a u s t i c ; p H = 1 0 , 5 1 1 , 5 NON-menetap Resep 1. bbl A i r ( a i r l a u t s e g a r a t a u ) £ 1 5 l i g n o s u l f o n a t 2. LB. c a u s t i c ; p H = 1 0 , 5 1 1 , 5 £ 1 XC Polimer Sebagai requiredDefoamer Resep ini untuk satu barel air campuran. 2. Pertimbangkan untuk menggunakan "Non-menetap Resep" untuk operasi membunuh besar. 3. Siapkan air campuran sebelum menambahkan barit tersebut. Kebutuhan air campuran adalah 54% dari volume lumpur akhir. 2. Sebuah putar Chiksan akan dipasang pada katup pengaman bor pipa dan chiksans cukup harus dicurangi hingga mencapai manifold penyemenan. Jangan memompa melalui sistem penggerak kelly atau atas (TDS) bila menggunakan "Settling Resep" untuk plug barit. 3. Sebuah garis memotong akan dipasang untuk membuang barit bubur awal. 4. Semua koneksi yang menjadi tekanan diuji dari pompa pencampuran ke katup pengaman bor pipa. 5. Katup berjenis harus berbaris yang diperlukan untuk menggunakan pompa rig untuk perpindahan steker dalam kasus pompa penyemenan gagal atau garis colokan. â € ¢ Hal ini diperlukan untuk menjaga plug barit bergerak setiap saat sementara di pipa bor untuk mencegah penyumbatan. 6. Katup pada unit penyemenan mengisi lini harus diuji untuk kebocoran dan untuk memastikan mereka berfungsi dengan baik. 4. Siapkan 21 ppg barit bubur dengan mencampur £ 700 dari barit dengan 0,54 bbl air campuran. Campur resep non-pengendapan oleh sirkulasi melalui hopper pencampuran beberapa kali jika perlu. 7. Pastikan bahwa keseimbangan lumpur bertekanan digunakan untuk menimbang bubur. Barit Plug Memompa Prosedur: 8. Katup pengaman pada pipa bor harus ditutup dan garis memotong dibuka untuk membuang lumpur barit, sampai mendapatkan berat badan yang benar. 1. Jika memungkinkan, Bor kru yang sama akan digunakan selama pencampuran atau menggusur plug barit (tidak mengubah Bor kru sampai operasi selesai). 9. Mulai pencampuran dan memompa lumpur barit ke garis memotong. 10. Tutup garis memotong dan membuka katup pengaman setelah mengukur berat bubur yang benar di garis memotong. 11. Nol laras counter dan terus pencampuran bubur menggunakan unit penyemenan dan tank perpindahan semen. 2. Jangan meluangkan waktu untuk keluar katup pengaman dan putar sebelum menarik keluar dari steker. Memastikan bahwa katup pengaman lain tersedia di lantai rig. 3. Tarik secepat mungkin, sesuai dengan jumlah drag, dan memutar pipa di slip sambil berdiri kembali setiap berdiri. 12. Menggantikan steker barit tanpa mematikan. Catatan: volume perpindahan sebenarnya tergantung pada apakah mungkin untuk menarik keluar dari steker atau jika pipa macet. 13. Menggantikan bubur barit pada tingkat yang cukup cepat untuk mendapatkan memompa tekanan di pipa berdiri. The berat barit dalam pipa bor akan cenderung turun, dan itu diinginkan untuk bersaing dengan itu dengan memompa pada tingkat yang cukup cepat untuk menghasilkan tekanan pompa di pipa berdiri. 14. Tarik pipa bor dari steker barit setelah plug barit di tempat. Kesempatan berhasil menarik keluar dari plug barit menggunakan "Settling Resep" kecil. Menarik Prosedur Pipa - barit Plug: 1. Bor kru adalah untuk berada dalam posisi untuk segera keluar dari steker barit secepat perpindahan selesai. 4. Tarik pipa setidaknya 10 stand di atas dihitung barit steker atas. 5. Beredar bottom up "jalan panjang" setelah pipa di atas plug setidaknya 10 stand. 6. Tunggu kira-kira 8-10 jam sebelum tersandung kembali lubang dan penandaan bagian atas plug barit agar yakin bahwa steker di tempat. ExxonMobil Pengembangan Perusahaan Pengeboran CREW STATION BILL DAN TANGGUNG JAWAB SELAMA BAIK PENGENDALIAN OPERASIONAL DRILLER 1. Mendeteksi masuknya lubang sumur dan alarm suara. 2. Mengambil pipa bor untuk ruang keluar posisi yang tepat. 4. Periksa katup (s) dari pompa lumpur (s) untuk mengalir kembali dari sumur. 3. Matikan pompa lumpur (s). 5. Berat cairan laporan Pengeboran dan keuntungan pit aktif untuk pembor. 4. Memeriksa atau memverifikasi bahwa sumur mengalir. 6. Bersiaplah untuk berat sistem lumpur. 5. Buka katup choke rendah. Tutup annular. 7. Siaga untuk instruksi dari Driller. 6. Beritahu Operasi Pengawas dan Toolpusher. 7. Periksa tekanan akumulator. Pastikan juga dengan benar menutup-in. DRILLER ASSISTANT (jika berlaku) 1) Pastikan choke hidrolik ditutup. 2. Periksa katup manual pertama hilir choke ditutup. 3. Periksa sisa choke berjenis untuk keselarasan. 4. Laporkan ke Driller. 5. Mulai merekam pipa bor dan casing tekanan. 6) siaga untuk ns instructio lebih lanjut dari Driller. SHAKER TANGAN 1. Periksa juga untuk aliran di shaker. 2. Laporkan ke Driller. 3. Memeriksa berat fluida pengeboran di shaker. 4. Memonitor saluran kembali dari choke berjenis dan flowline. 5) Siaga instruksi dari Driller. TANGAN LANTAI 1. Siaga rotary untuk menandai pipa untuk ruang keluar yang tepat. 2. Siaga untuk instruksi lebih lanjut dari Driller. DERRICK MAN 1. Tingkat pit catatan dan keuntungan. 2. Mark tingkat pit baru. 3. Timbang cairan pengeboran di lubang. 3. Menginstal katup pengaman (seperti yang diperlukan) dan menutup sama. DRILLING SUPERVISOR OPERASI 1. Periksa untuk memastikan baik adalah pr operly menutup-in. 2. Periksa tekanan baik dan keuntungan pit. 3. Mengembangkan baik rencana membunuh. 2. Periksa tekanan akumulator. Penebang MUD 4. Sebut Drilling Operations Superintendent. Toolpusher 1. Mengawasi Driller setelah sumur ditutup-in. 1. Memantau stroke pompa, unit gas, dan tingkat pit. 2. Bekerja sampai lembar membunuh. 2. Periksa untuk memastikan baik benar menutup-in. 3. Memonitor pipa bor dan tekanan casing. 4. Notif y Kepala Mechanic, Electrician, dan Crane Operator. 5. Siapkan peralatan untuk operasi membunuh baik. CRANE OPERATOR 1. Merakit buruh pelabuh kru. 2. Siaga untuk membantu dalam operasi pengendalian baik. 3) Mengkoordinasikan barit gerakan material. MUD ENGINEER OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG DRILLING dari 5 Pertama Edition - Mei 2003 OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG DRILLING dari 5 Pertama Edition - Mei 2003 OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG DRILLING Pertama Edition - Mei 2003 1. Periksa volume pit, memverifikasi berat lumpur, dan melaporkan kepada Derrick Man. OPERASI PENGEBORAN MANUAL - JACK-UP / PLATFORM / TONGKANG RIG 2. Tentukan barit diperlukan untuk meningkatkan berat DRILLING dari 5 lumpur. 3) Siaga untuk membantu Derrick Man. MECHANIC / LISTRIK 1. Periksa Unit penutupan. 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