Well Control Manual

WELL CONTROL MANUALIntroduction and How to Use Volume 1 Procedures and Guidelines Volume 2 Fundamentals of Well Control BP EXPLORATION © 1995 British Petroleum Company PLC Text originated by BP Drilling Department Manual produced by ODL Publications, Aberdeen, Tel (01224) 637171 BP WELL CONTROL MANUAL WELCOME Click here to zoom in on text, then click on text to scroll through Ladies and Gentlemen: Following is the Second Edition of the “BP Well Control Manual” first issued in 1987. When issued it was expected to be a living document, accounting for changes in technology and experience, it still is. Now, eight years later, horizontal and extended reach wells, coil tubing drilling and under balance drilling have or will become part of our kit for improved profitability. Our objective with this Second Edition is to bring three changes to the operating groups: 1) Issue the manual in an electronic version as a pilot which may lead to collecting all of the manuals on a server or CD-ROM. 2) Make available Excel based well control worksheets which have been incorporated into the manual. 3) Modify parts of Volume I Chapters 1 and 6 for high angle and horizontal well operations. In a separate file we have issued the “HTHP Well Control Manual”. Future updates will tie this manual with the “BP Well Control Manual”. Publication of the manual in electronic format should make the abundance of information in it more accessible to you. A powerful search capability and “hot button” references are part of the software package we have selected. Software used is compatible with Macintosh, MS-DOS and DEC hardware platforms making it accessible to BP and our contractors when needed. Electronic publishing makes modifications easier and we solicit your suggestions for correction, clarification, change or addition to the manual. If we have not managed to make the resource more useful and clear to you we have failed our objective. Your views on how well we have done are important. To open and use the manual please read the section below. While use of the electronic version of the manual is encouraged there is still the option of printing a hard copy of the manual. Hard copies can still be obtained from ODL in Aberdeen at a cost for printing and shipping. Originally this manual was not issued as “policy”. In the October 1994 Drilling Managers Meeting this and two other documents, the “Drilling Policy Manual” and “Casing Design Manual”, were designated as the three core policy documents covering our operations. Every effort has been made in this edition to tie to the other two documents. March 1995 BP WELL CONTROL MANUAL HOW TO USE This manual has been converted into Adobe Acrobat software and is a ‘read only’ version, ie you cannot make any changes to text or figures, you can copy the text and figures and paste them in to another application. Navigating through the Manual When you have read this you will be able to navigate quickly through the manual, to and from volumes, sections, subsections and figures. Clicking the mouse on the `Main Contents' button at the bottom of this page will take you to the Well Control Manual overall contents list, ie Volume 1 or 2. For additional help use the Acrobat Help files. The header at the top of each page has been hot spotted, to return you to the Main Contents page of the Volume you have selected. To go back or forward to a previous move you have made, use the Acrobat arrows in the Menu Bar. Once you have reached the section you require (e.g. 1.1 General), the hand cursor will appear with an arrow inside it. Press the mouse button on the section you require to read, and you will be zoomed into the section, press it again and it will scroll through that section, at the end of the section it will reset to the beginning of the section. Excel Worksheets Each example of a Worksheet in the manual is linked to a blank Excel Template for you to use for your own calculations, just click on the example Worksheet and Excel will automatically open. To return to the manual, simply Quit out of Excel. Printing When printing to a US Letter size printer please click on the “Shrink to Fit” box in the Print dialogue box. Printing of Excel Worksheets is through Excel. Manual Contents March 1995 BP WELL CONTROL MANUAL Volume 1 – Contents Nomenclature Abbreviations 1 PREPARATION Section 1.1 1.2 1.3 1.4 1.5 Page INSTRUMENTATION AND CONTROL MANPOWER ORGANISATION DRILLS AND SLOW CIRCULATING RATES USE OF THE MUD SYSTEM KICK TOLERANCE 1-1 1-9 1-15 1-27 1-35 2 THE PREVENTION OF A KICK Section 2.1 2.2 2.3 CORRECT TRIPPING PROCEDURES MAINTAIN SUITABLE HYDROSTATIC PRESSURE CONTROL LOST CIRCULATION 2-1 2-9 2-17 3 WARNING SIGNS OF A KICK Paragraph 1 2 3 4 5 GENERAL DRILLING BREAK INCREASED RETURNS FLOWRATE PIT GAIN HOLE NOT TAKING CORRECT VOLUME DURING A TRIP 6 CHANGE IN PROPERTIES OF RETURNED MUD 7 INCREASE IN HOOKLOAD 8 CHANGE IN PUMP SPEED OR PRESSURE 3-2 3-2 3-2 3-3 3-4 3-6 3-6 March 1995 BP WELL CONTROL MANUAL 4 ACTION ON DETECTING AN INFLUX Section 4.1 4.2 4.3 Page SHALLOW GAS PROCEDURE SHUT-IN PROCEDURE DURING SHUT-IN PERIOD 4-1 4-9 4-17 5 WELL KILL DECISION ANALYSIS Paragraph 1 2 3 4 5 6 7 GENERAL PIPE ON BOTTOM PIPE OFF BOTTOM – (Drillpipe in the Stack) PIPE OFF BOTTOM – (Drillcollar in the Stack) NO PIPE IN THE HOLE WHILE RUNNING CASING OR LINER UNDERGROUND BLOWOUT 5-2 5-2 5-2 5-5 5-5 5-7 5-9 6 WELL KILL TECHNIQUES Section 6.1 6.2 6.3 March 1995 STANDARD TECHNIQUES – Wait and Weight Method – Driller’s Method SPECIAL TECHNIQUES 1. Volumetric Method 2. Stripping 3. Bullheading 4. Snubbing 5. Baryte Plugs 6. Emergency Procedure COMPLICATIONS 6-1 6-2 6-3 6-31 6-33 6-47 6-67 6-75 6-84 6-93 6-97 BP WELL CONTROL MANUAL NOMENCLATURE SYMBOL DESCRIPTION UNIT A a An b c C Cp Ca CL CR D Dshoe Dwp dbit dh dhc do di dcut dc F Fsh FPG g G Cross sectional area Constant Total nozzle area Constant Constant Annular capacity Pipe capacity Cuttings concentration Clinging constant Closing ratio Depth Shoe depth Depth of openhole weak point Bit diameter Hole diameter Hole/casing ID Pipe OD Pipe ID Average cuttings diameter Drilling exponent (corrected) Force Shale formation factor Formation Pressure Gradient Gravity acceleration Pressure gradient Gi H Hi Hp ITT K L λ MR M m MW Influx gradient Height Height of influx Height of plug Interval Transit Time Bulk modulus of elasticity Length Rotary exponent Migration rate Matrix stress Threshold bit weight Mud weight in.2 – in.2 – – bbl/m bbl/m % – – m m m in. in. in. in. in. in. – lb – SG – psi/ft psi/m SG psi/ft m m m µsec/m m – m/hr psi lb SG March 1995 BP WELL CONTROL MANUAL SYMBOL DESCRIPTION UNIT N OPG P Rotary speed Overburden Pressure Gradient Pressure ∆P Pa ∆Pbit Pcl Pdp Pf Pfrac Pfc Pi Pic Plo Pmax S Sg Sw t Adjustment pressure Annulus pressure Bit pressure drop Choke line pressure loss Drillpipe pressure Formation pressure Fracture pressure Final circulating pressure Hydrostatic pressure of influx Initial circulating pressure Leak off pressure Maximum allowable pressure at the openhole weak point Wide open choke pressure Pore pressure Slow circulating rate pressure Plastic Viscosity Flowrate Mud flowrate Gas flowrate Reynolds number Resistivity Resistivity of water Rate of Penetration Shale factor Overburden pressure Gas saturation Water saturation Time rpm SG psi/SG (The units of subsurface pressure may be either psi or SG) psi psi psi psi psi psi/SG psi/SG psi psi psi psi/SG TR T Transport Ratio Temperature TD TVD V Total Depth True Vertical Depth Kick tolerance Poc Pp Pscr PV Q Qmud Qgas Re R Rw ROP March 1995 psi/SG psi psi/SG psi cP gal/min gal/min gal/min – ohm-m ohm-m m/hr meq/100g psi Fractional Fractional seconds min – degrees C, F, R m m bbl BP WELL CONTROL MANUAL SYMBOL DESCRIPTION V Volume v vmud vp vs W w w wb wcut WOB x YP Z µ ν σ’1 σ’t Ø Ø600 β ρ ρb UNIT bbl cc ml l Velocity m/min m/s Mud velocity m/min Average pipe running speed m/min Slip velocity m/min Weight gm kg lb Weight lb/ft lb/bbl SG Weight of pipe lb/ft Baryte required for weighting up lb/bbl Average cuttings weight SG Weight on Bit lb Offset () Yield Point lb/100ft2 Compressibility factor – Viscosity cP Poissons’s Ratio – Maximum effective principle stress psi/SG Tectonic stress psi/SG Porosity Fractional Fann reading lb/100ft2 Tectonic stress coefficient – Density SG Bulk density SG March 1995 BP WELL CONTROL MANUAL ABBREVIATIONS API RP BHA BOP BRT DWT ECD EMW H2S IADC ID KTOL LCM LMRP LO MAASP OBM OD PMS PV ROP SCR SG SPM YP March 1995 American Petroleum Institute Recommended Practice Bottomhole Assembly Blowout Preventer Below Rotary Table Dead Weight Tester Equivalent Circulating Density Equivalent Mud Weight Hydrogen Sulphide International Association of Drilling Contractors Internal Diameter Kick Tolerance Lost Circulation Material Lower Marine Riser Package Leak off Maximum Allowable Annular Surface Pressure Oil Base Mud Outside Diameter Preventive Maintenance System Plastic Viscosity Rate of Penetration Slow Circulating Rate Specific Gravity Strokes per Minute Yield Point 1 INSTRUMENTATION AND CONTROL 1-1 1.3 DRILLS AND SLOW CIRCULATING RATES 1-15 1.5 KICK TOLERANCE 1-35 March 1995 .2 MANPOWER ORGANISATION 1-9 1.4 USE OF THE MUD SYSTEM 1-27 1.BP WELL CONTROL MANUAL 1 PREPARATION Section Page 1. 1 Suggested Instrumentation for a Floating Rig 1-3 1.BP WELL CONTROL MANUAL 1.3 Suggested Fluid Measurement System 1-7 1-1 March 1995 .1 INSTRUMENTATION AND CONTROL Paragraph Page 1 General 1-2 2 Pressure Gauges 1-2 3 Pump Control 1-4 4 Fluid Measurement 1-6 Illustrations 1.2 Suggested Instrumentation for a Fixed Installation 1-5 1. Each rig will normally be equipped with gauges to read standpipe pressure and annulus pressure. However equipment failure is most likely when the equipment is highly stressed. In general. Although the standpipe and choke manifold will generally be fitted with ‘Cameron’ gauges. in the majority of cases. In order to be able to install additional pressure gauges it may be necessary to fabricate manifolds and install high pressure instrument hose between the choke panel and the standpipe/choke manifold. The gauges that are fitted to the choke panel and at the driller’s console are often the only gauges available for well control purposes. The level of instrumentation that is recommended will ensure that a suitable level of control is afforded during unusually critical operations. All this equipment must be rated to the working pressure of theequipment. this means that it will be necessary to install gauges of lower rating in order that relatively low pressures can be accurately recorded. these are considered to be so inaccurate as to have little application to well control. 2 Pressure Gauges When a well is under pressure it is important that accurate pressure measurements can be made. All of these gauges will have a fullscale deflection that is at least equal to the working pressure rating of the equipment.BP WELL CONTROL MANUAL 1 General It is essential that an appropriate level of control equipment is provided on every rig in order that a well that is under pressure can be accurately monitored. This will apply to land rigs which may be equipped only with manual chokes and the majority of rigs that are equipped with both manual and remote operated chokes. This evaluation should ideally be carried out inconjunction with the pre contract rig audit and any deficiencies made good prior to contractaward. much of this equipment would not be necessary in routine circumstances. there is a necessity for more accurate instrumentation than under conditions encountered during routine drilling. The purpose of this section is to highlight the important aspects of instrumentation and control and to recommend a standard level of equipment for all rig types. 1-2 March 1995 . and that adequate back-up is provided. all that is required. during a well control incident. It is also important that suitable pressure gauges are installed at the choke manifold in case the well has to be controlled from this position. However an extra pressure reading is required on a floating rig in order that the wellhead pressure can be monitored through the kill line. This will be especially important with high pressure equipment. In all cases. Therefore. Accurate readout of pump pressure and choke pressure is. The level of instrumentation on every rig therefore must be evaluated in order to assess itssuitability for well control purposes. It is in these situations that serious incidents can develop if a suitable level of back-up instrumentation and control equipment is not to hand. 001 1-3 March 1995 .BP WELL CONTROL MANUAL Figure 1.1 Suggested Instrumentation for a Floating Rig STANDPIPE 1 CAMERON GAUGE STANDPIPE 2 1/4in NEEDLE VALVE D TRANSDUCER K CHECK VALVE C STANDPIPE MANIFOLD HYDRAULIC FLUID INLET CHOKE PANEL CAMERON GAUGE D SW K C AC O PUMP OUTPUT MONITOR KILL LINE REMOTELY OPERATED CHOKE CHOKE MANIFOLD MANUAL CHOKES CHOKE LINE BUFFER TANK FROM BOP DRAIN OVERBOARD LINE D – DRILL PIPE K – KILL LINE POORBOY DEGASSER C – CHOKE LINE – 1/4in NEEDLE VALVES FLOWLINE – CHECK VALVE/HYDRAULIC FLUID INLET WEOX02. in the majority of cases. • A stroke counter. In most cases the rig pumps will be used. • Sensitive low pressure rated gauges should be removed from the system unless required. A suitably isolated terminal should be located at a convenient point at the choke manifold. The following points should be noted from the proposed systems: • A good selection of gauges should be available. • A hydraulic fluid hand pump should be available to purge the lines at suitable points as shown. This would ensure that the original system was closed and hence in no way susceptible to leaking needle valves or misuse of the supplementary system. It is suggested that the gauges are checked at each BOP Test and at this stage the pressure monitors in the mud logging unit should be checked against the rig equipment. • It must be possible to easily install and remove low range pressure gauges at the choke panel and at the choke manifold. • It must be easy to change the gauges. • The gauges that are used to measure the slow circulating rate pressures should be used to monitor well pressures in the event a kick is taken. The piping and manifolding should be permanently installed. if the well is controlled with a remote operated choke. 3 Pump Control It is desirable that the remote control of the pump used to kill a well that is under pressure is located reasonably close to the choke operator.BP WELL CONTROL MANUAL So in general: • There must be gauges available to read choke pressure. Most choke panels contain a meter that displays the cumulative output of the pump. Gauges should be calibrated on a regular basis with a Dead Weight Tester. similar to the battery operated ‘Swaco’ unit. in order that the signal from the limit switches on the pumps can be transmitted to the counter. Generally. 1-4 March 1995 . standpipe pressure and kill line static pressure in the case of a floating rig. The proposed systems can also be used for measuring slow circulating rate pressures (SCRs). is recommended for remote installation at the choke manifold. It would be a good idea to fabricate a cover for the manifolding at the choke manifold and choke panel. the man on the pump will be able to co-ordinate with the choke operator.2. • Consideration should be given to completely isolating the supplementary pressure monitoring system from that originally fitted to the rig.1 and 1. It should be removed when not required. the Driller will control these pumps from a position that is close to the choke panel. • The above gauges must be readable from the manifold if manual chokes are fitted to the manifold. Therefore. Suggested pressure recording systems for a floating rig and a fixed installation are shown in Figures 1. BP WELL CONTROL MANUAL Figure 1.2 Suggested Instrumentation for a Fixed Installation TO STANDPIPE TO STANDPIPE STANDPIPE MANIFOLD D C D C CHOKE PANEL D SW AC O 1/4in HYDRAULIC FLUID FILLED HIGH PRESSURE HOSE TO PUMP/ CHOKE PANEL FROM BOP CHOKE CHOKE PRESSURE GAUGE TO DEGASSER TO BURN PIT REMOTELY OPERATED CHOKE TO BURN PIT TRANSDUCER CHOKE MANIFOLD CAMERON GAUGE TO BURN PIT TO DEGASSER C – CHOKE LINE D – DRILL PIPE – 1/4in NEEDLE VALVES – CHECK VALVE/HYDRAULIC FLUID INLET WEOX02.002 1-5 March 1995 . it is desirable that it is possible to control and monitor the kill/cement pump from the rig floor. during a long operation this is likely to wash out and so provision should be made to easily and quickly replace the valve. or pumped into a well within an accuracy of half a barrel isrequired’. such as the trip tank (hydraulically activated chokes are not suitable for this application). API RP 53 recommends that ‘a trip tank or other method of accurately measuring the drilling fluid bled off. 1-6 March 1995 . it may be sufficient to use a Lo-Torq valve instead of amanual choke to bleed fluid to the tank. This tank would typically have a 3 to 4 bbl capacity so that very small volumes of fluid can be measured.BP WELL CONTROL MANUAL However. it is recommended that a remote pump output meter is positioned at the choke manifold. it is important to beable to accurately measure small volumes of fluid bled from. as well as during a volumetric kill. the tank contents can be emptied into the trip tank where the total volume of mud bled from the well. in most cases this will not be a satisfactory arrangement because of the relatively large volume in the line between the choke and the tank. However. The most satisfactory arrangement is to use a strip tank as shown in Figure 1. terminating at a manual choke positioned directly above a measuring cylinder. A further complication may arise if a kill pump or cement pump is used during a well control operation. together with the mud leaked past the preventers. Most rigs will not have suitable equipment to do this. This will be especially important on land rigs which may be equipped only with manual chokes and where often the choke manifold is located at some distance from the rig floor. Although it is not ideal. on a floating rig. Therefore. After bleeding into the strip tank. can be measured. leaked from. but the use of a relatively small displacement pump will be standard well control procedure on a floating rig that is drilling in deep water. However a bleed line from the well to the mixing tanks on the cement/kill pump may be sufficient. However . if the choke manifold contains manual chokes. or pumped into thewell. In such cases. It is not recommended to bleed mud into a measuring tank that is situated in a confined area when there is a possibility that gas is entrained in the mud. the choke operator may be some considerable distance from the man on the pump and a monitor of the pump output. 4 Fluid Measurement During stripping operations.3. In general. It may become necessary to use these pumps on any rig. It is usually assumed that the choke manifold lined up across a manual choke to the trip tankis a suitable fluid measurement system. there is a requirement for a line from the well. 003 Figure 1.3 Suggested Fluid Measurement System 1-7/8 1-7 March 1995 .BP WELL CONTROL MANUAL PRESSURE GAUGE FROM CHOKE MANIFOLD/BOP MANUAL CHOKE 3in PIPE LEVEL INDICATOR STRIP TANK (3 – 4bbl capacity) LARGE ID DRAIN WORKING PLATFORM FLOWLINE RETURNS TRIP TANK WEOX02. 4 An Example Communication System 1-13 1-9 March 1995 .BP WELL CONTROL MANUAL 1.2 MANPOWER ORGANISATION Paragraph Page 1 General 1-10 2 Individual Responsibilities 1-10 3 Communication 1-12 Illustrations 1. • To assign the responsibility of keeping a diary of events. 1-10 March 1995 . Circumstances at the rigsite may dictate that these responsibilities be modified in the event of an incident. the following can be used as guidelines for the allocation of responsibilities in the event of a well control incident: (a) The Company Representative • Once the well has been shut-in and is being correctly monitored. • To monitor and supervise the implementation of these procedures. however. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation. • The Company Representative has the right to assume complete control of the work required to regain control of the well. • To provide specific well control procedures. It is Company policy that a well control contingency plan should include the allocation of individual responsibilities. • To be present on the rig floor at the start of the kill operation. 2 Individual Responsibilities The well control contingency plan must allocate the responsibilities of all those concerned in the operation. • Has the responsibility for supervising the contractor staff that are not directly involved in the well control operation. • To maintain communication with the Operations base.BP WELL CONTROL MANUAL 1 General This section is intended to provide a guideline for the allocation of individual responsibilities during a well control incident. to organise a pre-kill meeting for all those involved in the supervision of the well control operation. The contingency plan should be drawn up in conjunction with the drilling contractor and should be regularly reassessed. Well control drills provide an opportunity to assess the effectiveness of the contingency plan and to identify and make good any inadequacies. (c) The Senior Contractor Representative • Has the overall responsibility for all actions taken on the rig. (b) The Company Drilling Engineer • Will provide technical back-up to the Company Representative. • To keep a diary of events. using the contingency plan as a guideline. • Must be present at the rig floor during the start of the kill operation.BP WELL CONTROL MANUAL • However. (e) The Driller • Has the responsibility for the initial detection of the kick and closing in the well. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation.) (d) The Contractor Toolpusher • Has overall responsibility for the implementation of the well control operation. (f) The Mud Engineer • Has continuous responsibility for monitoring the mud system and the conditioning of the mud. • Has the responsibility for ensuring that the driller and the drill crew are correctly deployed during the well control operation. It may be prudent to send an extra Mud Engineer to the rig in the event of a well control incident to ensure constant supervision of the mud system. in the event that the well gets out of control. (j) The Mud Logging Engineers • Have the responsibility for continuously monitoring the circulating system during the well control operation. 1-11 March 1995 . (g) The Cementing Engineer • Will ensure that the cement unit is ready for operation at any time. • Has the responsibility for briefing the off duty drill crew prior to starting a newshift. (h) The Subsea Engineer (where appropriate) • Should be available for consultation at all times during the well control operation. (This entitlement is a standard condition of Company drilling contracts. • Has the responsibility for supervising the drill crew during the well control operation. • Has the responsibility for checking all the BOP equipment during the operation. • One member of the crew must keep a diary of events. the Company Representative has the right to assume complete control and supervise the work required to regain full control of the well. • Will operate the cement unit at the discretion of the Company Representative. the well is shut-in and closely monitored. This meeting is also the first stage in the process of communication during the well control operation. – Depending on the type of operation it may be necessary to include others within the broken line. The objectives of a suitable system of communication are: • To ensure that all information relevant to the well control operation is communicated to the Company Representative. The purpose of this meeting is to ensure that all those involved in the supervision and implementation of the well control operation are familiar with the procedures that will be used to kill the well. • To ensure that communication equipment on the rig is adequate. and is used during the well control operation in the most effective manner possible. • To ensure that those involved in the supervision of the operation are at all times in communication with the Company Representative. The following can be noted from this example: • After the kick is taken. • To ensure that all those involved in the operation are aware of the line and method of communication that they should use. – The most important lines of communication to and from the Company Representative (denoted by those inside the broken line) are best maintained with the use of hand held radios. • Responsibilities are allocated to those involved in the operation by the supervisors who attended the meeting. 1-12 March 1995 . It is therefore most important that the well control contingency plan details the method and line of communication for each individual involved in the operation. Experience has shown that even the most well conceived well control procedures can go badly wrong if communication before and during the operation is not properly organised and effective. • Each line and method of communication is defined. – The use of intrinsically safe hand held radios ensures that all those inside the broken line can listen in on each others communication.BP WELL CONTROL MANUAL 3 Communication One of the Company Representative’s responsibilities is to organise a pre-kill meeting once the well has been shut-in. Figure 1.4 shows an example of a possible communication system on a semi-submersiblerig for use during standard well control operations. It should be noted that: – The rig telephone system is not overloaded. • The Company Representative calls a pre-kill meeting of those involved in the supervision of the operation. 004 1-13/14 1-13 March 1995 .4 An Example Communication System (1) KICK TAKEN – WELL SHUT-IN – WELL BEING MONITORED (2) PREKILL MEETING COMPANY REPRESENTATIVE COMPANY DRILLING ENGINEER SENIOR CONTRACTOR REPRESENTATIVE TOOLPUSHER MUD ENGINEER MUD LOGGING ENGINEER (3) ALLOCATE RESPONSIBILITIES OFF DUTY DRILL CREW SENIOR CONTRACTOR REPRESENTATIVE MUD ENGINEER TOOLPUSHER SUBSEA ENGINEER CONTRACTOR STAFF MATES CONTRACTOR SHOREBASE DRILLER DRILL CREW PUMPMAN/ DERRICKMAN (4) MAJOR LINES/METHOD OF COMMUNICATION DURING THE WELL CONTROL OPERATION DRILL CREW CONTRACTOR SHOREBASE DRILLER MARINE STAFF PUMPMAN/ DERRICKMAN RT RT RT SENIOR CONTRACTOR REPRESENTATIVE TOOLPUSHER S/S MUD ENGINEER H/H H/H S/S H/H COMPANY REPRESENTATIVE RT RT SUBSEA ENGINEER COMPANY SHOREBASE RT – RIG TELEPHONE SYSTEM SERVICE COMPANY ENGINEERS S/S – SHIP TO SHORE MUD LOGGING ENGINEER H/H – HAND HELD SET WEOX02.BP WELL CONTROL MANUAL Figure 1. 3 DRILLS AND SLOW CIRCULATING RATES Paragraph Page 1 General 1-16 2 BOP Drills 1-16 3 D1: Kick while Tripping 1-17 4 D2: Kick while Drilling 1-17 5 D3: Diverter Drill 1-19 6 D4: Accumulator Drill 1-19 7 D5: Well Kill Drill 1-21 8 Slow Circulating Rate Pressures. SCRs 1-22 9 Choke Line Losses 1-23 Illustrations 1.BP WELL CONTROL MANUAL 1.6 Choke Line Pressure Loss Data Sheet 1-25 1.7 An example Determination of Choke Line Losses 1-26 1-15 March 1995 .5 SCR Pressure Plot 1-23 1. the Company Representative should stipulate that the Drills are conducted more frequently. to regularly record SCRs. The smaller the influx. The following Drills should be practised where applicable: D1 – Tripping D2 – Drilling D3 – Diverter D4 – Accumulator D5 – Well Kill (Suffix R to be included if the remote panel was used) These codes should be used to record the results of the Drill on the BOP Drill Record Proforma. It is important that returning drillcrews have frequent Drills. This form should be sent to the Drilling Superintendent fortnightly. and as hole conditions permit. 2 BOP Drills The purpose of BOP Drills is to familiarise the drillcrews with techniques that will be implemented in the event of a kick. the Drills (D1. D2 and D3. until the Company Representative and the Contractor Toolpusher are satisfied that every member of the drillcrew is familiar with the entire operation. If standards fall unacceptably. there should be no difference between the Drill and actual control procedures. The results of each Drill must also be recorded on the IADC Drilling Report. Drills should be designed to reduce the time that the crew take to implement these procedures. In this respect. the less severe will be the pressures during the well kill operation. as appropriate) should be held at least once per week. Every effort must be made to ensure that the Drill is carried out in the most realistic manner possible. This section covers the reasons why it is necessary to carry out BOP Drills. The relevant Drills should be carried out as often as is necessary. Once satisfactory standards have been achieved. One of the major factors that influences the wellbore pressures after a kick is taken is the volume of the influx.BP WELL CONTROL MANUAL 1 General Both BOP Drills and the recording of slow circulating rate pressures will be carried out on a routine basis on all rigs. Where practical. it is important that the drillcrew react quickly to any sign that an influx may have occurred and promptly execute the prescribed control procedure. 1-16 March 1995 . as well as recommended procedures. Install the drillpipe safety valve. 7.BP WELL CONTROL MANUAL 3 D1: Kick while Tripping The purpose of this Drill is to familiarise the crew with the shut-in procedure that will be implemented in the event of a kick during a trip. 5. Shut-in procedures to be adopted in the event of a kick while tripping are detailed in Chapter4. Open the choke line valve. 4. 3. Record the casing and drillpipe pressure. However if the drill is conducted when the drillstring is in openhole. This Drill may be conducted either in open or cased hole. Having shut-in the well. 4 D2: Kick while Drilling The purpose of this Drill is to familiarise the crew with the control procedure that will be implemented in the event of a kick while drilling. 1-17 March 1995 . the Company Representative will start the Drill by manually raising the trip tank float to indicate a rapid pit gain. Record the time for the Drill on the IADC Drilling Report. This will detail the action that the crew should take in the event a kick is detected. 6. the Contractor Toolpusher will instruct the Driller to assume that a positive flowcheck has been conducted. These preparations should include lining up the equipment as required. assigning individual responsibilities and preparing the Stripping Worksheet. and to implement the prescribed control procedure as detailed in the Standing Orders. The Contractor Toolpusher must ensure that the crew are correctly deployed and that each individual completely understands his responsibilities. as a guideline the following procedure should be initiated: • Without prior notice. The time taken for the crew to shut in the well should be recorded. This Drill should only be conducted when the BHA is inside the last casing string. • The Driller is expected to take the following steps to shut in the well: 1. Stop other operations. However. preparations should be made to strip pipe. Close the annular preventer. 2. When directed by the Company Representative. the well will not be shut-in . Before the trip is started. the Standing Orders to the Driller will have been posted. Notify the Company Representative that the well is shut-in. the Company Representative gradually increases the apparent pit level by manually raising the float. the following procedure can be used as a guideline for the drill: • Without prior notice. Shut down the pumps. 4. Double check spaceout. 3. Close the annular preventer. 8. Record the time taken for the crew to shut-in the well on the IADC drilling report. Pick up the kelly (or topdrive) until the tool joint clears the BOPs and the kelly cock is just above the rotary table. 2. These procedures are outlined in Chapter 4. 5. 4.BP WELL CONTROL MANUAL When the pipe is on bottom. 5. • The Driller is expected to detect the pit gain and take the following steps: 1. Notify the Company Representative that the well has been shut-in. Pull up until the tool joint clears the BOPs. * If on a floating rig The procedures adopted during these Drills should be in line with the shut-in procedures as outlined in the Standing Orders. 3. 7. 2. Check the well for flow. • Having been instructed to do so by the Company Representative. Record the casing and drillpipe pressure. the Driller is expected to take the following steps to shut-in the well: 1. Record the time required for the crew to react and conduct the Drill on the IADC drilling report. * 6. Shut down the pumps. Therefore after tripping the bit to the shoe. 1-18 March 1995 . close and lock hang-off rams and hang-off pipe and check that the kelly cock is just above the rotary table. Open the choke line valve. a further Drill may be conducted that will result in the well being shut-in. the following procedure may be used as a guideline for this Drill: • Stop tripping operations and install the kelly (or topdrive) and start circulating. Report to the Company Representative. When the bit has been tripped to the previous casing shoe. 2. A Drill should be carried out prior to drilling out of the conductor casing. recharge that bottle (with nitrogen gas only) to achieve the specified desired precharge pressure. The following specific tests are recommended: (a) Accumulator precharge pressure test This test must be conducted on each well prior to spudding and approximately every 30days thereafter at convenient times. The time recorded in the log should be the time elapsed from initiation of the Drill until the rig crew (and marine staff) are ready to initiate emergency procedures. The Contractor Toolpusher must ensure that the drill crew. the hydraulic fluid line to each bank must have a full opening valve to isolate individual banks. Drain the hydraulic fluid from the accumulator system into the closing unit fluid reservoir. Drills should be designed in line with the specific procedure that will be adopted in the event of a shallow gas kick. The procedures that should be implemented in the event of a shallow gas kick are covered in Chapter 4. Remove the guard from the valve stem assembly on top of each accumulator bottle. On closing units with two or more banks of accumulator bottles. 3. are correctly deployed during the Drill and that each individual understands his responsibilities. a sufficient volume of nitrogen gas must be bled from the accumulator bottle to provide the specified desired precharge pressure. The time taken for each diverter function to operate should be recorded. Diverter Drills should therefore be carried out to minimise the reaction time of the crews. 6 D4: Accumulator Drill The purpose of the Accumulator Drill is to check the operation of the BOP closing system. It is therefore important that crew initiate control procedures as soon as possible in the event of a shallow gas kick. 5.BP WELL CONTROL MANUAL 5 D3: Diverter Drill If shallow gas is encountered and the well kicks. If the nitrogen precharge on any bottle is greater than the maximum acceptable precharge pressure listed below. servicing or transporting. 1-19 March 1995 . The precharge test should be conducted as follows: 1. Attach the charging and gauging assembly to each bottle and check the nitrogen precharge. Shut-off all accumulator pumps. blowout conditions may develop very quickly. If the nitrogen precharge pressure on any bottle is less than the minimum acceptable precharge pressure listed below. 4. A further objective of the Drill is to check that all diverter equipment is functioning correctly. The valves must be in the open position except when accumulators are isolated for testing. and marine staff (offshore). 5. Isolate the accumulators from the closing unit manifold by closing the required valves. record the volume used. the time taken. 4. The pressure should be the designed operating pressure of the accumulators. Having completed the tests. The test should be conducted according to the following procedure. Acceptable Precharge Pressure 1500 psi 2000 psi 3000 psi 750 psi 1000 psi 1000 psi 750 psi 950 psi 950 psi 850 psi 1100 psi 1100 psi (b) Accumulator closing test This test should be conducted before BOP stack tests.BP WELL CONTROL MANUAL Accumulator Working Pressure Rating Desired Precharge Pressure Min. After each function. For the floating rig: Close and open all the well control functions (apart from blind/shear rams). 2. Record the time taken to recharge the system. the closing unit reservoir should be inspected to be sure it does not contain any foreign fluid or debris. Close off the power supply to the accumulator pumps. 3. Adjust the regulator to provide 1500 psi operating pressure to the annular preventer. Position a joint of drillpipe in the blowout preventer stack. Position a joint of drillpipe in the blowout preventer stack. Record the initial accumulator pressure. 1-20 March 1995 . (c) Closing unit pump test Prior to conducting any tests. The residual accumulator pressure after completing all the tests must be at least 200 psi greater than the precharge pressure. This test can be conveniently scheduled either immediately before or after the accumulator closing time test. 1. The closing unit pump capability test should be conducted before BOP stack tests. and the residual accumulator pressure. Turn on the accumulator pumps. 2. For a land rig: Close the annular preventer and one pipe ram (sized for the pipe in the stack). Open the HCR valve on the choke line. Acceptable Precharge Pressure Max. Duplicate the operation of the blind/shear rams. Operate the sequence of functions as relevant to the rig type. recharge the accumulator system to its designed operating pressure. The test should be conducted as follows: 1. Run in hole and tag the top of cement. Break circulation and establish slow circulating rate pressures. isolate the rig air system from the pumps. Close the annular preventer and open one choke line failsafe valve (orHCR valve). 2. resulting in the well being shut-in. It should never be carried out when openhole sections are exposed. 4. A drillpipe pressure schedule should be drawn up and carefully adhered to. so that it can be used for reference should a kick be taken in the next hole section. When a dual power (air and electric) source system is used. 1-21 March 1995 . This Drill should be carried out prior to drilling out the intermediate and production strings. 5. Pull back one stand and install the kelly (or install topdrive). both power supplies should be tested separately. It is recommended that the time required for the closing unit pumps to accomplish these operations does not exceed two minutes. Open the accumulator system to the closing unit and charge the accumulator system to its designed operating pressure using the pumps. Carry out standard BOP Drill D2. If the accumulator pumps are powered by air. It is important that the choke operator develops a feel for the lag time between manipulation of the choke and its subsequent effect on the drillpipe pressure. The following procedure is recommended: 1. 3. (Consider circulating bottoms up prior to this if the annulus may contain contaminated mud).BP WELL CONTROL MANUAL 3. It is important that this opportunity to circulate across a choke is used to maximum effect. 4. Close the choke line failsafe (or HCR valve) and open the annular preventer. Consider applying low pressure to the casing (typically 200 psi). The lag time should be recorded. A separate closing unit air storage tank should be used to power the pumps during this test. bring the pump up to kill speed controlling the drillpipe pressure according to a predetermined schedule. 5. 7 D5: Well Kill Drill The objective of this Drill is to give drillcrews the most realistic type of well controltraining and a feel for the equipment and procedures that they would use to kill a well. Record the time (in seconds) required for the closing unit pumps to close the annular preventer plus open the choke line valve and obtain 200 psi above the accumulator precharge pressure on the closing unit manifold. For this reason. SCRs There are many reasons why a kick should be displaced from the hole at a rate that is considerably slower than that used during normal drilling. it is useful to have determined the SCR pressure before a kick is taken. It is useful to plot the SCRs on a graph as shown in Figure 1. • When the BHA is changed. • When the mud weight or properties are changed. These include: • To minimise the pressure exerted on the openhole. it is necessary to know the friction pressure in the circulating system at low rates. when back on bottom after a trip. The annulus frictional pressure is a major factor that will influence the rate at which the kick will be displaced from the hole (using standard well control procedure the annulus frictional pressure will be added to wellbore pressure as the pump is brought up to speed to kill the well). • To permit adequate degassing of the returned mud. At these relatively low pump speeds the volumetric efficiency of the rig pumps may be significantly less than at normal speeds used during drilling. However the absolute upper limit for the displacement rate may be restricted by the pressure rating of the surface equipment. but should fall within the limits of 1/2 and 4 barrels per minute. • To reduce the pressure exerted on well control equipment. Company policy states that SCRs should be conducted regularly and at least: • Once per tour (or at 300m intervals during the tour). circulate bottoms up before measuring SCRs. • To limit the speed of required choke adjustments. It is therefore recommended that the volumetric efficiency of the rig pumps is checked at low pump speed. in particular the setting of the pump relief valve. the initial circulating pressure can be estimated from the sum of the shut-in drillpipe pressure and the SCR pressure.5. If oil base mud is in the hole. It should be noted that it is potentially hazardous to displace a kick from the hole when the surface pressure is close to the relief valve setting. The drillstring internal friction should be calculated at the SCRs and used to determine the annulus frictional pressure as shown. At a given rate of circulation.BP WELL CONTROL MANUAL 8 Slow Circulating Rate Pressures. All these factors must be taken into account when deciding at what rate to displace the kick. • To allow weighting of the mud as the kick is displaced. 1-22 March 1995 . • When the bit is changed. such as when pumping a slug prior to a trip. The range of circulation rates used will be dependent upon many factors. In order to estimate the circulating pressures during the displacement of a kick. 1-23 March 1995 . If the wellhead pressure remains constant as the pump is brought up to speed then the choke line friction will in most cases be automatically compensated for. can cause additional pressures to act in the wellbore. In most cases however.5 aids the selection of circulation rates other than these actually measured and also provides a guide to the size of the annulus circulating losses over a range of circulation rates. These pressures are not significant in the case of land. (This technique is outlined in detail in Chapter 6. The recommended method is to monitor the wellhead pressure through the kill line as the pump is started. the choke line frictional pressure should be accounted for as the kick is displaced out of the hole.005 Figure 1. 9 Choke Line Losses The frictional pressure caused by circulating through the choke line.STANDPIPE PRESSURE (psi) BP WELL CONTROL MANUAL PSCR3 Drillstring internal pressure drop PSCR2 Annulus pressure drop PSCR1 SCR1 SCR2 SCR3 PUMP OUTPUT (bbls/min) (stks/min) Other SCRs can be selected to displace the kick WEOX02. This method is not considered to be as reliable as using the kill line monitor. if the correct procedures are adhered to. while displacing a kick from the well. but can be critical in the case of a floating rig. platform and jack-up rigs.) It is also possible to account for the choke line losses by reducing the choke pressure by an amount equal to the choke line loss as the pump is brought up to speed.5 SCR Pressure Plot A graph similar to Figure 1. Circulate down the drillpipe and up through the choke line until returns are uniform. 8. 7. Route returned flow through the poorboy gas separator to the shakers. 5. The choke line losses should be adjusted for changes in mud weight as shown on the form. Open choke line valves. Record the choke pressure at each rate. 3. The form also shows how to determine the choke line friction pressure from the recorded data. Record SCR pressure at same rates as before. The following procedure should be implemented in order to properly assess the choke line frictional pressures at slow circulating rates. 2. Space out to ensure no tool joint is opposite annular preventer. 4. Close annular preventer. Install suitable pressure gauges to record standpipe and choke pressures during circulation. 9. Line up choke manifold to route flow across a fully opened remote operated choke. it is acceptable to isolate the well and pump down the choke line at the range of slow circulating rates.BP WELL CONTROL MANUAL It is important that the choke line frictional pressure is accurately known at a wide range of circulating rates.7 shows an example determination of choke line losses. This procedure should be carried out initially when the BOP and riser are installed and before drilling out of each subsequent casing shoe.6 shows a form that can be used to record the data. 1. Figure 1. In order to verify choke line losses after drilling out of the casing shoe. Figure 1. Record SCR pressure at a range of rates from 1/2 to 4 bbl/min down drillpipe and up the riser. The accuracy of this adjustment is however questionable over a wide range of mud weights. 1-24 March 1995 . Calculate the choke line frictional pressure at each rate. 6. From this information the additional load on the wellbore can be assessed at a range of displacement rates and subsequently the most suitable rate can be selected. 00 120 190 25 45 0.58 30 680 985 250 2.400 (4in PLUNGER) 1.160 985 1435 80 370 3. P.25 50 65 10 0 0 0 0 (1) (2) (3) (2)-(1)-(3) 0 March 1995 WEOX02.4 SG AT…………… MUD WEIGHT (psi) AT…………… MUD WEIGHT (psi) AT…………… MUD WEIGHT (psi) AT…………… MUD WEIGHT (psi) 6.39 20 400 590 SCR PRESSURE UP CHOKE LINE (psi) CHOKE PRESSURE AT SCR (psi) 55 40 150 CEMENT PUMP .P . CORRECTED CHOKE LINE LOSS CORRECTED CHOKE LINE LOSS CORRECTED CHOKE LINE LOSS 1.5 0.HT .4SG OBM/PV24CP/YP100 lb/100ft2 RECORDED BY J.WELL No 25 RIG 19 RIG WELL STATUS DURING TEST DATE 25/7/87 133/8in CASING RUN AND TESTED / 135/8in STACK INSTALLED AND TESTED PROPERTIES OF THE MUD IN THE HOLE DURING THE TEST 1.5 ……………in LINER PUMP RATE ……………in LINER PUMP RATE SCR PRESSURE UP RISER (bbl/min) (SPM) (SPM) (psi) 4.006 BP WELL CONTROL MANUAL MEASURED CHOKE LINE LOSS Figure 1.78 1-25 CIRCULATION RATE 40 RIG PUMPS: NATIONAL 12 .6 Choke Line Pressure Loss Data Sheet CHOKE LINE PRESSURE LOSS DATA SHEET . BP WELL CONTROL MANUAL Figure 1.007 1-26 March 1995 .7 An example Determination of Choke Line Losses CIRCULATING @ 20SPM UP RISER CIRCULATING @ 20SPM UP CHOKE LINE (CHOKE WIDE OPEN) 400 600 PSCR @ 20SPM = 400psi POC = 50psi 50 PCL = PSCR (up choke line) – PSCR (up riser) – POC = 600 – 400 – 50 PCL = 150psi where PSCR = Slow Circulating Rate Pressure (psi) PCL = Choke Line Pressure Loss at SCR (psi) POC = Choke Pressure recorded at SCR with choke wide open (psi) WEOX02. 8 An example Mud Gas Separator – operating at maximum capacity 1-32 1-27 March 1995 .4 USE OF THE MUD SYSTEM Paragraph Page 1 General 1-28 2 Pit Management 1-28 3 Building Mud Weight 1-29 4 Dealing with Gas at Surface 1-31 5 Chemical Stocks 1-34 Illustrations 1.BP WELL CONTROL MANUAL 1. 1-28 March 1995 . • The nature and toxicity of the influx fluid. the volume and weight of which will be determined by the nature of the next hole section. • The usable surface pit volume in relation to the hole volume.BP WELL CONTROL MANUAL 1 General Well control contingency plans should outline the manner in which the mud system will be utilised during standard well control operations. 2 Pit Management The following guidelines should be considered when specifying pit arrangements: (a) While drilling a critical hole section • Keep the active mud system surface area as small as is practical to ease kick detection. (b) When displacing a kick The major factors that will determine the most satisfactory pit arrangement for displacing a kick include the following: • The technique that will be used to displace the kick. • How to deal with contaminated returns. This section is intended to highlight the major factors that will determine the most satisfactory arrangement of the mud system in such circumstances. • Keep all mud treatments and pit transfers to the absolute minimum at critical sections of the well. • Ensure all pit level systems and tank isolating valves are working correctly before drilling into possible gas-bearing zones. especially if oil based mud is in use. Any reserve mud stocks in the tanks should be positively isolated from the active system. Ensure that the gates on the trough are sealing properly. and emphasise the importance of early detection. • Adequate reserve stocks of mud should be held. • How to deal with the kick when it is displaced to the surface. Mud engineering and mud logging personnel should attend these meetings. • The method of weighing up the mud. Ensure that the Driller and the Mud Logging Engineer are aware in advance of any changes to the system. • The monitoring of pit levels in the active system. • How to deal with the pit gain caused by influx expansion during displacement. • Crew safety meetings should discuss the problem of gas kicks. a complete hole volume of kill mud can be prepared before displacement of the kick. In the unusual situation when there is adequate surface volume. For this reason it is important to measure the rate at which both the conventional hopper system and the high rate system (if fitted) can supply baryte. If the Wait and Weight Method is used. for a given hole capacity. 3 Building Mud Weight (a) Baryte delivery to the mud pits The rate at which baryte can be added to the original mud influences the time required to increase the weight of a volume of mud. if the mud is weighted as the kick is displaced. There are three different stages at which the mud can be weighted up for these two techniques: • The Wait and Weight Method – – • In a typical situation when it is impractical to weight up a complete hole volume prior to displacement of the kick. the maximum rate at which baryte can be supplied to the mud will: • Determine the time required to weight the hole volume of mud before the kick is displaced. If the Driller’s Method is used this will determine the time required to build the mud weight after the kick has been displaced from the hole. The most satisfactory arrangement of the pits will be different for each technique and clearly will be rig-specific. The maximum rate at which the mud can be weighted can be determined for a given required mud weight increase from the following formula: Maximum possible rate = at which the mud can be weighted (bbl/min) Baryte delivery rate (lb/min) Baryte required to weight up (lb/bbl) 1-29 March 1995 . on the rate at which baryte can be added into the system in relation to the desired rate of displacement.BP WELL CONTROL MANUAL The kick can be displaced from the hole using either the Wait and Weight Method or the Driller’s Method. The Driller’s Method – In this case the mud is weighted either while the kick is displaced with original weight mud or after the first circulation depending on the availability of baryte and tank space. This will therefore entail that some mud is weighted while the kick is displaced from the hole. The volume that is weighted prior to displacement of the kick will depend. • Or it may limit the rate at which the kick can be displaced. This rate is determined by shearing a known volume of new mud until the minimum viscosity is reached. Shear equipment is required for building viscosity using clay viscosifiers in new base oil. This may be the case in the following situations: • If considerable losses are experienced. The bulk system should be included in the rig PMS (Preventive Maintenance) system. 1-30 March 1995 .BP WELL CONTROL MANUAL Therefore for the following example: Required mud weight increase = 0.25 . (c) Building viscosity into the mud There may be well control situations which require that considerable volumes of weighted mud are built from a water or oil base.7 SG) Baryte required = 1490 X (1.5) = 117 lb/bbl 4.2 SG (from 1. the minimum viscosity would be represented by a yield point of 10. and as such. As a guideline.7 If the maximum barytes delivery rate for the rig = 350 lb/min Then: Maximum rate at which the = 350 = 3 bbl/min mud can be weighted 117 This figure therefore gives an indication of the maximum displacement rate if the mud is weighted as the kick is displaced from the hole. Some offshore rigs have jet line mixers to help build viscosity. it is recognised that these polymers can cause high temperature gelation of the mud.1. (b) Baryte storage When possible at least one full barytes storage tank should be pressured up at all times and the bulk delivery system tested regularly. However. The limiting factor for an oil base mud may be the rate at which viscosity can be built into the base oil. In circumstances in which large volumes of new oil mud must be built.5 SG to 1. • If the required volume of kill weight mud is greater than the surface stocks of active and reserve weighted mud. In emergency situations. it would be useful to know the rate at which new mud can be sheared to a level at which barytes can be suspended. and a 10 second gel reading of 3.1. • If the returns are severely contaminated and have to be dumped. Building viscosity is usually a less important factor when water base muds are used. they are not recommended for use in high temperature wells. viscosity can be built quickly using an oil mud polymer (Baroid’s LFR 2000 as an example) at 4 lb/bbl in conjunction with organophilic clays.7 . An estimation can be made of the maximum gas flowrate that the separator can handle. there exists the possibility that gas will blow through into the shaker header box. Returns should be piped through the mud gas separator and then on to the degasser for further treatment. The separator is used to remove large gas bubbles from the mud and to deal with a flow of gas once the influx is at surface. This may be significant when large mud weight increase is required in a large volume of mud. the gas will blow through to the shaker header tank.48 = 80 bbl 2205 4 Dealing with Gas at Surface It is important that suitable equipment is available on the rig to deal with the influx once it is displaced to surface.BP WELL CONTROL MANUAL (d) Volume increase due to baryte addition The volume of a given amount of mud will increase as baryte is added to it. When this limit is exceeded. See Figure 1. 1-31 March 1995 . When the back pressure due to the gas flow is equal to. The volume increase due to baryte addition can be determined from the following relationship: Volume increase = 1. The mud outlet should be configured to develop a suitable hydrostatic head (minimum recommended head is 10 feet). the vent line should be as straight as possible and have a large ID.8. The limiting factors will be the back pressure at the outlet to the vent line in relation to the hydrostatic head of fluid at the mud outlet of the separator.48 bbl per metric ton of baryte added Therefore in the following situation: The required addition of baryte = 200 lb/bbl Volume to weight up = 600 bbl Volume increase due to baryte addition = 600 X 200 X 1. There will be a limit to the volume of gas that each separator can safely deal with.8. (a) The mud gas separator (poorboy) The mud gas separator should be lined up at all times when a kick is being displaced. the hydrostatic head available at the mud outlet. or greater than. In order to minimise the possibility of a gas blow-through. See Figure 1. 8. GAS OUTLET 8in ID MINIMUM GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi) STEEL TARGET PLATE INLET INSPECTION COVER APPROX HEIGHT 1/2 OF A SECTION A-A TANGENTIAL INLET 30in OD A 4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD BRACE 10ft MINIMUM HEIGHT INSPECTION COVER HALF CIRCLE BAFFLES ARRANGED IN A ‘SPIRAL’ CONFIGURATION TO SHAKER HEADER TANK MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1.BP WELL CONTROL MANUAL The back pressure due to the flow of gas should be monitored with a pressure gauge as shown in Figure 1.008 . Some warning of the possibility of a gas blow-through will be given when the registered pressure approaches the hydrostatic head of the fluid in the discharge line. If the safe operating limit of the separator is approached. the choke can be closed in (while ensuring that the well is not overpressured) or the flow switched to the overboard line or the burn pit.75 SG GIVES 7.8 An example Mud Gas Separator – operating at maximum capacity 1-32 March 1995 WEOX02. It should be noted that the maximum hydrostatic head available may not be that of the mud in the event that large volumes of oil or condensate are displaced tosurface.6psi MAXIMUM CAPACITY 10ft APPROX 8in NOMINAL ‘U’ TUBE 4in CLEAN-OUT PLUG 2in DRAIN OR FLUSH LINE Figure 1. • The gas is found to contain H2S. This will generally be either an overboard line. • Hydrates are forming in the gas vent line from the mud gas separator. Measure mud weight at the degasser outlet and the shaker header box using a pressurised mud balance. the degasser has removed all the gas from the mud. If the mud weight at this stage is not equal to the active system mud weight. 1-33 March 1995 . whether on land or offshore. It should be easy to switch the returns from the mud system to the flare line.BP WELL CONTROL MANUAL (b) The degasser The degasser should be lined up at all times during the well control operation. If the actual mud weight measured at this stage is equal to the active system mud weight. If the actual mud weight at the outlet of the degasser is equal to the reading onthe pressurised mud balance. or the returns are at a lower weight than the mud in the active system. the degasser can be checked as follows: 1. The degasser is designed to remove the small bubbles of gas that are left in the mud after the mud has been through the mud gas separator. Measure actual mud weight at the degasser outlet using a non pressurised mud balance. Significant erosion is likely to occur in the path of high velocity gas and solids. then the degasser is working. • The mud system is overloaded. 3. If the actual mud weight at the outlet of the degasser is greater than the actual mud weight at the inlet. therefore the redundancy in flowlines and manifolds downstream of the choke must be analysed on all rigs. Measure actual (gas cut) mud weight at the shaker header box using a non pressurised mud balance. While drilling with gas cut returns. It is important that the degasser is working properly and as such it should be tested every tour. It may be necessary to use the flare line during a well control operation in the following situations: • The gas flowrate is too high for the mud gas separator. or a flare line to the burn pit on land. then either the degasser is not working properly. Lines that are required to handle high velocity gas must be as straight as possible to minimise erosion. then the degasser is working properly. (c) Overboard lines/Flare lines It is recommended that a second method of dealing with severely gas cut returns be available at the rigsite. 2. the Company Representative may wish to stock a greater quantity of baryte and chemicals. Batch mix tanks should also be onsite during the drilling of such reservoir sections. in high pressure wells. The policy states that: ‘Sufficient weighting material stocks must be maintained on site such that the entire mud circulating volume can be raised by a minimum of 0. (b) Cement stocks Cement stocks should not drop below the quantity of cement and additives that will be required to set 2 X 150m of cement plugs in the hole section being drilled.BP WELL CONTROL MANUAL 5 Chemical Stocks (a) Baryte and mud chemical stocks Company policy details the minimum stocks of baryte and mud chemicals that should be held at the rigsite. ‘Where transport and logistics are not assured (offshore and remote locations) the minimum onsite weighting material stock must be 100 tonnes’. Reserve stocks of bentonite or viscosifier must also be on site to enable this increase in mud weight to be effected’. This is a minimum standard. Additionally. and as such. 1-34 March 1995 . an abandonment plug recipe should be onsite prior to drilling into the reservoir.25 SG (See formula in Paragraph 3). 5 KICK TOLERANCE Paragraph Page 1 General 1-36 2 Kick Tolerance Calculation Methods 1-36 3 Procedure for Kick Tolerance Calculations 1-37 4 Considerations for High Angle and Horizontal Wells 1-40 5 When to Calculate Kick Tolerance 1-41 6 Excel Kick Tolerance Calculator 1-42 Illustrations 1.10 Excel Kick Tolerance Calculator – Example Calculations 1-43 1-44 1-35 Rev 1 March 1995 .BP WELL CONTROL MANUAL 1.9 Kick Tolerance Values Through a Zone of Increasing Pore Pressure 1. 1-36 March 1995 1995 Rev 1 March . It is now an accepted part of the Company Casing Design policy to determine the casing setting depth by the Limited Kick Method. Therefore the same kick tolerance between two wells may not mean that they share the same level of risk ! 2 Computer Kick Simulators In the recent years many sophisticated computer simulators have been developed which can provide a good approximation of kick conditions from the stage when it flows into the wellbore to that when it is circulated out. In general. Although these assumptions may seem unrealistic. the influx is at the bottom of the openhole. the simple methods have gained wide acceptance in the drilling industry because they are simple and generally yield conservative (safer) kick tolerance. It is therefore particularly important that the kick tolerance in critical hole sections be accurately monitored. they can predict how much time the rig crew have to shut in the well before the influx exceeds the kick tolerance limit. gas solubility. Within BP. However these methods have an inherent shortcoming: they do not measure how quickly an influx will grow. Among many other applications. these methods can be classified into two categories: 1 Simple Methods In these methods kick tolerance calculations are simplified based on several assumptions: • The kick influx is a “single bubble”. Kick Tolerance is defined as the maximum volume of kick influx that can be safely shut-in and circulated out of the well without breaking down the formation at the openhole weak point. They can predict the maximum pressures at any point of the annulus and the results are more accurate and less conservative than using the simple methods.BP WELL CONTROL MANUAL 1 General Many definitions of kick tolerance have been used in the drilling industry. gas dispersion. assumptions used in the simple methods are replaced by mathematical models. Therefore simulators can be used to provide direct indications in the level of risk involved under various scenarios. • At the initial shut-in condition. as simulators can simulate how quickly an influx will flow into the wellbore. formation pressure and influx type. In critical hole sections. This section explains how to calculate kick tolerance and when to calculate kick tolerance. In the simulations. it is important to calculate kick tolerance on a regular basis. • The effects of the gas migration. BHA geometry. a number of methods exist for kick tolerance calculations. In addition. the kick simulators can be used for kick tolerance calculations. mud weight. 2 Kick Tolerance Calculation Methods Depending upon how kick tolerance is defined. etc. This is to say that in some cases formation deliverability may be such that the well could not be shut in before the kick tolerance volume was exceeded. This is because kick tolerance changes as a function of hole depth. downhole temperature and the gas compressibility are ignored. Sunbury. 2 Calculate the Maximum Allowable Annular Surface Pressure (MAASP) Without Breaking Down the Weak Point Formation: MAASP = Pleak – 1.421 x MW x TVD wp – SF (psi) where: MAASP MW Pleak SF TVDwp Maximum allowable annular surface pressure (psi) Mud weight in hole (SG) Leak-off pressure at the openhole weak point (psi) Safety factor (psi) Vertical depth at the openhole weak point (m) It should be seen that MAASP is determined based on the consideration of the formation fracturing pressure at the openhole weak point. etc. If lighter fluids (such as a gas influx) occupy the annulus above the weak point. So it is considered only when there is a full mud column from the weak point to the surface (i. the surface pressure in excess of MAASP may not cause downhole failure. mud properties. operator ’s experience.e. Some computer kick simulators are available from the Drilling & Completions Branch. kick simulators are recommended only in the situations where kick tolerance is considered critical based on the simple methods.etc. 3 Procedure for Kick Tolerance Calculations The method illustrated in the following is one of the simple methods. The method calculates the maximum allowable kick influx volume when the well is shut in. due to complexity.) • Annular friction pressure (depending on the hole size. BP Exploration. Therefore from the moment the top of an influx has been displaced past the openhole 1-37 Rev 1 March 1995 . The drilling engineer must use his/her judgement to determine the most appropriate safety factor. The following are some of the possible causes of such additional pressures during circulation: • Choke operator error (depending upon the choke’s condition.) • Choke line losses (in particular on floating rigs) The safety factor (SF) to be applied to the MAASP will be the sum of these additional pressures.BP WELL CONTROL MANUAL However. there will be additional pressures acting in the wellbore. The method considers two scenarios: • When the influx is at the bottom of the hole at the initial shut in condition • When the top of the influx has been displaced to the openhole weak point (with the original mud weight) The following procedure can be used to calculate the kick tolerance: 1 Estimate the safety factor to be applied to the Maximum Allowable Annular Surface Pressure (MAASP) When the influx is displaced from the hole. the influx is still below the weak point). the hole angle used in the calculation should be the openhole angle immediately above the horizontal section. 3 Calculate the maximum allowable height of the influx in the openhole section: H max = where: Hmax Gi Pf TVD h 4 MAASP – ( Pf – 1. 5 Calculate the maximum allowable influx volume that Hmax corresponds to when the top of the influx is at the openhole weak point Vwp = Hmax where: Vwp C2 θwp x C2 / cos(θ wp) (bbl) Maximum allowable influx volume when top of the influx is at the openhole weak point (bbl) Annular openhole capacity around drillpipe (bbl/m) Hole angle in the openhole section below the weak point (degree) In cases where Hmax /cos(θwp ) is greater than the openhole drillpipe length below the weak point. In cases where Hmax /cos(θbh ) is greater than the length of BHA.1.421 X (m) (MW – Gi) Maximum allowable height of the influx (m) Influx gradient (SG) Formation pore pressure (psi) Vertical depth of openhole (bit) (m) Calculate the maximum allowable influx volume that Hmax corresponds to at the initial shut-in conditions Vbh = H max where: Vbh C1 θ bh x C1 / cos(θ bh) (bbl) Maximum allowable influx volume at initial shut-in condition (bbl) Annular capacity around BHA (bbl/m) Hole angle in the bottom hole section (degree) If the bottom hole section is horizontal (or above 90 degree).I.421X MW X TVD h) 1. Section 6. The method for estimating the position of the influx top is described in Vol.BP WELL CONTROL MANUAL weak point. The kick tolerance should be the sum of the calculated volume (Vbh ) plus the annular volume of the horizontal section. the maximum allowable influx volume (Vwp) should be calculated partly based on the annular openhole capacity around drillpipe and partly around BHA. Chapter 6. 1-38 March 1995 Rev 1 March 1995 . MAASP is no longer a consideration and may be exceeded by a margin which should be determined based on the casing burst strength and the pressure ratings of BOP stack and choke manifold. the maximum allowable volume (Vbh) should be calculated partly based on the annular capacity around BHA and partly around drillpipe. 58 SG 2695 m 1.BP WELL CONTROL MANUAL 6 Convert the maximum allowable influx volume at the weak point (Vwp ) to what would be at the initial shut in condition Based on Boyle’s law.8 = 0. Estimate the safety margin to be applied to MAASP: SF = 70 + 150 = 220 psi 2.421 X (1.1.2743 = 49 bbl 5.421 x 1.(8981 . Calculate the maximum allowable influx volume at the initial shut-in condition: Annular capacity around BHA.252 .421 1. C2= (12.72 MAASP = 6587 .421 x x 2695 = 6587 psi 1. Calculate the maximum allowable influx height in the openhole section: Pore pressure gradient.2) 4.252 . C1= (12.5 2) / 313.182 = 1123 m ( > H max of 178 m) 1-39 Rev 1 March 1995 .0. the maximum allowable influx volume at initial shut-in corresponding to Vwp will be: V bh' = V wp X Pleak Pf 7 (bbl) The actual kick tolerance should be the smaller of Vbh (Step 4) and Vbh' (Step 6) Example: Bit depth: Current hole size: Hole angle: Mud weight in hole: BHA length / OD: Drillpipe OD: Estimated pore pressure at 4000 m: Last casing shoe: Leak-off test EMW: Annular back pressure at SCR: Safety margin for choke operator error: 4000 m 12-1/4" Vertical 1.8 = 0. Therefore: Vbh = 178 x 0.2743 (bbl/m) As the BHA length (182 m) is longer than Hmax (178 m). so the influx is around BHA only when it is at the bottom of the hole.6X 4000) x 4000 = 8981 psi = 178m 1.58 H max = X 240 .2695 .3985 (bbl/m) Openhole DP length = 4000 .72 SG 70 psi 150 psi 1.60 SG 182 m / 8" 5" 1. Pleak = 1. Calculate MAASP: Leak-off pressure. P f = 1.8 2) / 313.421 x 1.220 = 240 psi 3.1.60 .6 x 2695 . Calculate the maximum allowable influx volume when the top of influx is at the casing shoe: Annular capacity around openhole DP. 4 Considerations for High Angle and Horizontal Wells In high angle and horizontal wells. it is often the case that the maximum allowable gas height (determined by step 3 in the previous section) extends from the openhole bottom to inside the casing/liner. Therefore the actual kick tolerance is 49 bbl.421X MW X TVD h) 1. On the other hand.SF) .( f . When drilling a high angle or horizontal well. reservoirs are often drilled at a high or horizontal angle with the last casing or liner string set on top of the reservoir. the kick tolerance volume in this case should be determined not only by the formation fracture gradient at the openhole weak point but also by the maximum allowable surface pressure based on the casing burst strength and the pressure ratings of the surface equipment. When considering kick tolerance for the reservoir section.BP WELL CONTROL MANUAL Vwp = 178 x 0.3985 = 71 bbl 6. etc. because of the long openhole section through the reservoir in a high angle or horizontal well. Note its difference with MAASP which is based on the formation fracture gradient at the weak point. Convert Vwp to the initial shut-in condition: Vbh' = 71 x 6587 / 8981 = 52 bbl 7. Determine the maximum allowable surface pressure Psurf based on the casing burst strength and the pressure ratings of the surface equipment (BOP stack. So when the influx is circulated to surface. This implies that the well can tolerate an infinite volume of gas influx without fracturing the openhole weak point.421 X (MW . Therefore. choke manifold. it may fill up the entire annuli of the vertical and low angle sections and result in very high choke pressures at surface. the influx volume can be potentially high.). c Calculate the maximum allowable gas height Hmax when the gas influx top has reached the surface: H max = where: Gi Pf SF TVD h P (Psurf . the following procedure should be used to determine the kick tolerance: a.Gi) Influx gradient (SG) Formation pore pressure (psi) Safety factor mainly determined by the choke operator error margin (psi) Vertical depth of openhole (bit) (m) 1-40 March 1995 Rev 1 March 1995 . Calculate kick tolerance volume as V1 using the method as described in the previous section (Step 1 through 7) b.1. If the kick tolerance is less than 50 bbl the Drilling Superintendent must be informed. However. 5 When to Calculate Kick Tolerance Company policy states that: “The kick tolerance of the weakest known point of the hole section being drilled must be updated continuously whilst drilling.BP WELL CONTROL MANUAL d Calculate the influx volume that Hmax corresponds to when the gas influx top has reached the surface: Vsurf = Hmax x Ccsn (bbl) where: Vsurf Ccsn Maximum allowable influx volume when the influx top reaches surface (bbl) Annular capacity in the casing near surface (bbl/m) e Convert Vsurf to the corresponding volume at the initial shut-in condition: V 2 = V surf X f Psurf (bbl) Pf The actual kick tolerance volume is the smaller of V2 (step e) and V 1 (stepa). not only based on the current condition but also on the future conditions which are expected to occur deeper in the well. • If any factors that affect the kick tolerance (such as mud weight. evaluate the kick tolerance at suitable intervals throughout the next hole section with a number of mud weights that are likely to be used.” Kick tolerance will change if there is a change in hole depth. the kick tolerance below that point in the section should be re-evaluated. in hole sections where kick tolerance is likely to be a critical factor. drilling may only continue when dispensation has been given by the Manager Drilling in town. formation pressure or BHA. The frequency with which the kick tolerance should be re-evaluated is dependent on the nature of the well. • If the hole section contains a zone of rapid pore pressure increase. the Company Representative and the Drilling Engineer must assess the possibility of the pore pressure developing in a manner different to that predicted and hence its effect on the kick tolerance. BHA) change as the section is drilled. If the kick tolerance is less than 25 bbl for offshore wells or 10 bbl for land wells. the following guidelines should be considered: • After LO test. • At each stage in the hole section. the kick tolerance should be evaluated frequently based on the anticipated pore pressure. Therefore kick tolerance must be constantly re-evaluated as the well is drilled. 1-41 Rev 1 March 1995 . mud weight. together with a range of other parameters. the kick tolerance would be small if the high pressure zone was unexpectedly encountered. The calculator is based on the same method as described in the previous sections. will be displayed automatically. for the maximum mud weight anticipated for the section. As shown. The kick tolerance figures shown are those that would typically be calculated before a transition zone. The decisions that are made on the basis of kick tolerance figures such as these will be largely dependent upon the particulars of each situation. These figures show a final minimum kick tolerance of 50 bbl at that mud weight. The kick tolerance is finally calculated at the maximum mud weight. From these figures. On the basis of these figures. The kick tolerance volume.10 is an Excel Kick Tolerance Calculator. except that it uses the pressures at the mid-point of the gas influx. or if the steady increase in pore pressure was undetected at the surface. The kick tolerance figures for the intermediate mud weight show that even at this weight. 6 Excel Kick Tolerance Calculator Figure 1. The kick tolerance has been calculated for the mud weight currently in use. which can be activated to calculate the kick tolerance by entering data into green-shaded cells. This might occur if either the pore pressure developed more rapidly than predicted. and intermediate weight. it is clear that a serious situation would develop if a kick was taken from the high pressure zone with the mud weight currently in the hole. In general these figures indicate that drilling should proceed cautiously through the zone of increasing pore pressure. the current bit depth is 3500 m and the kick tolerance has been calculated at various intervals across the zone of increasing pore pressure.9 shows an example of the type of calculations that should be worked. it may be decided to weight up the mud a certain amount before the predicted increase in pressure occurs. The table also shows the kick tolerance if the pore pressure developed higher than predicted of 1.BP WELL CONTROL MANUAL Figure 1.6 SG. including the level of confidence placed in the pore pressure prediction. So the calculator is slightly less conservative. 1-42 Rev 1 March March 1995 1995 . 2 11.3 13.3 13.6ppg 12.630 12.6 9.3 13.2 11.2ppg 11.470 12.3 13.2 9.123 12 (0) 12.2 10 13.5 13.960 12 12 12 12 12 9.3 13.123 13.470 12.2 9.3 13.795 12.3 600 600 450 280 153 13.BP WELL CONTROL MANUAL Figure 1.3 9.000 DEPTH (ft) 11.795 12.480 12.6 9.3 13.3 12.630 12.6 9.2 9.2ppg 10.123 9.3ppg 13.480 12.2 12.960 12.480 12.990 13.630 12.000 CURRENT BIT DEPTH MW = 9.3ppg TVD (ft) MW (ppg) 600 600 450 246 112 11.960 13.3 10 (0) 13.3 13.960 13.6ppg) TVD (ft) MW (ppg) 11.2 FOR MUD AT 12ppg TVD (ft) MW (ppg) 600 600 460 215 30 7 (0) 11.2 35 40 PORE KTOL PRESSURE (bbl) (ppg) PORE KTOL PRESSURE (bbl) (ppg) WEOX02.2 11.2 10.8ppg EMW 9000 9.470 12.123 13.2 10.123 12 12 PORE KTOL PRESSURE (bbl) (ppg) FOR MUD AT 13.795 12.123 13.2 13.4 13.000 FOR CURRENT MW (9.2 10.6 13.3 12.2 50 13.000 9.6 9.6 9.009 1-43 Rev 1 March 1995 .9 Kick Tolerance Values though a Zone of increasing Pore Pressure PORE PRESSURE (psi) 3000 4000 5000 6000 7000 8000 9000 CASING SHOE Maximum Allowable Pressure 13.6 9.2ppg 13.3 12.3 12.960 9.6 9. BP Exploration. Sunbury.57 33 41 Kick Tolerance (bbl) For more infor or help.59 1. March 1995 Example Calculation Well: Kick Zone Parameters: 1 2 3 4 5 6 7 UK Units: (UK/US): Input Messages: Openhole Size ? Measured Depth ? Vertical Depth (m) ? Horizontal Length (Angle>87 deg) ? Tangent Angle Above Horizontal ? Min Pore Pressure Gradient ? Max Pore Pressure Gradient ? (inch) (m) (m) (m) (deg) (sg) (sg) 12.60 1.58 1.580 1.600 Annular Capacity Around BHA: Annular Capacity Around DP: Fracturing Pres at Weak Point: Max Allowable Shut-in Csg Pres: (bbl/m) (bbl/m) (psi) (psi) Min Pore Pressure at Kick Zone: Maximum Allowable Gas Height: Kick Tolerance at Min Pore Pres: (psi) (m) (bbl) 8981 178 48.60 1.720 Bottom Hole Assembly OD ? Bottom Hole Assembly Length ? Drillpipe OD ? Gas Hydrostatic Pres Gradient ? Pressure Safety Factor ? Mud Weight in Hole ? (inch) (m) (inch) (sg) (psi) (sg) 8 182 5 0. please contact YUEJIN LUO.7 Max Pore Pressure at Kick Zone: Maximum Allowable Gas Height: Kick Tolerance at Max Pore Pres: (psi) (m) (bbl) 9094 120 33.59 1. Tel: 853-2424. Deviated or Horizontal Wells Version 1.0 Non-Horizontal Weak Point Parameters: 8 9 10 11 Measured Depth ? Vertical Depth ? Section Angle (<87 deg) ? Fracture Gradient / EMW ? Other Parameters: 12 13 14 15 16 17 0.58 1.25 4000 4000 0 0 1.60 1.2.27426 0.2 220 1.BP WELL CONTROL MANUAL Figure 1.600 (m) (m) (deg) (sg) 2695 2695 0 1.39854 6587 240 Comments: Pore Pressure Gradient 1.10 Example Calculations using Excel Kick Tolerance Calculator KICK TOLERANCE CALCULATOR For Vertical.59 33 41 49 1.58 1. Fax: 853-4183 1-44 March 1995 Rev 1 March 1995 49 . 10 Example Calculations using Excel Kick Tolerance Calculator (cont'd) APPENDIX: Maximum Allowable Gas Influx Volume Based on Surface Equipment Rating & Casing Burst Max Allowable Surface Pressure ? Casing ID in Surface Section ? (psi) (inch) 5000 12.58 1.419456 At Minimum Pore Pressure Gradient: Maximum Allowable Gas Height When Gas Arrives at Surface: Max Allowable Gas Vol.60 1.59 1. Sunbury. BP Exploration.515 Annular Capacity: (bbl/m) 0.59 1. Tel: 853-2424. Fax: 853-4183 1-45 Rev 1 March 1995 . on Shut-in: (m) (bbl) 2403 547 Pore Pressure Gradient 1. on Shut-in: Comments: (m) (bbl) 2460 613 At Maximum Pore Pressure Gradient: Maximum Allowable Gas Height When Gas Arrives at Surface: Max Allowable Gas Vol.60 547 580 613 1.58 540 550 560 570 580 590 600 610 620 Max Allowable Gas Volume on Shut-in (bbl) For more infor or help.BP WELL CONTROL MANUAL Figure 1.60 1.59 1. please contact YUEJIN LUO. Industry wide experience has shown that the most common causes of loss of primary control and hance the well kicks are: • Swabbing during trips.BP WELL CONTROL MANUAL 2 THE PREVENTION OF A KICK Section Page 2. • Not adequately filling the hole during a trip. • Lost circulation. and to minimise influx volumes if a kick occurs.2 MAINTAIN SUITABLE HYDROSTATIC PRESSURE 2-9 2. The evidence also shows that the majority of kicks have occurred during trips. If primary control is lost the blowout preventers are closed and secondary well control techniques are used to kill the well.1 CORRECT TRIPPING PROCEDURES 2-1 2. Primary control is maintained by ensuring that a full column of drilling fluid of an appropriate weight is allowed to exert its full hydrostatic pressure in the hole. • Insufficient mud weight. March 1995 . This chapter outlines the measures that are required to eliminate or minimise the risk of a kick due to the above causes.3 CONTROL LOST CIRCULATION 2-17 Formation pressures are contained by the hydrostatic pressure of a column of drilling fluid – this is primary well control. 3 Example of Standing Orders for Driller 2-6 2-1 March 1995 .1 Typical Trip Tank Hook-up – on a floating rig 2-3 2.1 CORRECT TRIPPING PROCEDURE Paragraph Page 1 General 2-2 2 Prior to Tripping 2-2 3 Tripping Procedure 2-5 4 Special Procedure for Oil Base Muds 2-8 Illustrations 2.BP WELL CONTROL MANUAL 2.2 BP Trip Sheet – example of a completed sheet 2-4 2. The following are among the most important actions that should be carried out prior to tripping: • Circulate the hole – The mud should be conditioned to ensure that tripping will not cause excessive swab/ surge pressures.) – The maximum average pipe speed should be selected bearing in mind the estimated overbalance or trip margin. It is therefore particularly important that special attention is paid to ensuring correct tripping procedure.BP WELL CONTROL MANUAL 1 General Industry wide experience has shown that the majority of well control problems have occurred during trips. – Any entrained gas or cuttings should be circulated out. • Determine the maximum pipe speed – Swab/surge pressures should be calculated at various tripping speeds using the appropriate formulae. The procedures required to deal with an influx when the pipe is off bottom are not so straightforward as when the pipe is on bottom. and that correct tripping procedure is strictly adhered to. Volume 2. The trip tank level must also be monitored from the Mud Logger’s cabin. – The mud weight should be such as to ensure an adequate overbalance will exist at all times during the trip. (See Chapter 3. • Swab pressures due to pipe motion. • Line up the trip tank – Company policy states that: “A trip tank must be available on every rig and be complete with a mechanically operated indicator of the trip tank level. Every effort must therefore be made to ensure both that the well is stable prior to initiating a trip out of the hole. During tripping the potential exists for a significant reduction in bottomhole pressure due to the following effects: • Reduction in ECD as the pumps are stopped. visible from the Driller’s position. 2 Prior to Tripping Considerable preparation is required before the trip is commenced.” 2-2 March 1995 . • Reduction in height of the mud column as pipe is removed from the well. spare parts for the hole fill pump/motor should be kept at the rig site.BP WELL CONTROL MANUAL TRIP TANK LEVEL INDICATOR REMOTE CONTROL VALVE RIG FLOOR OVERBOARD ROTARY TABLE DIVERTER RETURNS TO SHAKERS HOLE FILL UP LINE FLOWLINE TELESCOPIC JOINT FROM MISSION PUMPS RISER CHECK VALVE DRAIN TRIP TANK PUMP WEOX02.1 Typical Trip Tank Hook-up – on a floating rig Figure 2.010 Figure 2. – In order that maximum use is made of the trip tank on trips in and out of the hole. a trip sheet should be used to record the mud volumes required to keep the hole full. – It is considered unsafe to trip without a trip tank and as such. • Fill in the trip sheet – Company policy states that: “A trip sheet will be filled out by the Driller on every trip.1 shows a typical trip tank hook-up on a floating rig.” 2-3 March 1995 . 35 bbl/stand 91/2 in 0.4 2.9 23.3 2.9 7.8 1.011 2-4 March 1995 .4 1. SHEET No 1 DRILLER 3250m 3250m INITIAL BIT DEPTH DISPLACEMENT OF 5 in DRILLPIPE : 0.1 3.5 0.5 -0.4 28.5 1.0246 bbl/m : 0.1 -0.5 4.0 10.0564 0.3 -0.7 0.6 13.1 0 -0.6 27.2 -0.6 0.2 -0.1 0 +0.3 -0.1 1.5 3.2 -0.2624 bbl/m DISPLACEMENT OF HEAVYWEIGHT DRILL COLLARS DISPLACEMENT OF in : bbl/ : DISPLACEMENT OF in : bbl/ : Trip On: Doubles Singles Stands NO OF STANDS TO TOP OF BHA AT THE STACK STAND STAND ……… ……… No Increment 1 2 3 5 7 10 15 20 25 1 1 1 2 2 3 5 5 5 Single Double Stands Single Double Stands Measured Hole Fill/Disp Trip Tank Volume increment (bbl) (bbl) 30.5 3.1 -0.5 3.2 BP Trip Sheet – example of a completed sheet TRIP SHEET WELL No 26 RIG HOLE DEPTH RIG 20 DATE AND TIME CHANGE BIT No 20 REASON FOR TRIP 15.E.C.3 0.7 3.2 25.2 -0.30 27/8/87 A.1 -0.5 0.7 1.1 3.5 30.8 20.2 : bbl/stand bbl/stand bbl/stand NO OF STANDS TO CASING SHOE 53 STANDS 108 STANDS AND 1 SINGLE Calculated Fill/Disp Discrepancy Remarks accum (bbl) increment (bbl) accum (bbl) increment (bbl) accum (bbl) 0.2 (1) (2) (3) (4) (1)-(3) (2)-(4) WEOX02.4 0.3 4.4 1.4 2.60 7.3 -0.6 6.7 0.1 +0.1 3.BP WELL CONTROL MANUAL Figure 2.7 10.7 1.9 3.9 17.2 0 -0.5 14.0 17.0 29.4 13.697 bbl/stand DISPLACEMENT OF 5 in : : bbl/m : 1.1 16. he came on shift. It should be kept in the open position. The basic requirement for a trip sheet is that a clear method of comparing calculated with actual hole fill volumes is provided.2 shows a completed example of the BP trip sheet. their responsibilities in the event of a kick. – A back-up safety valve. or if stripping in the hole is required and no dart sub is fitted. This trip sheet should be used if the contractor cannot provide a similar sheet. – An example of the standing orders that should be provided to the Driller is shown in Figure 2. 2. – He should be told of any indicators of increasing pore pressure or near balance that were identified during drilling before. 2-5 March 1995 . – A drillpipe safety valve (kelly valve) should be available on the rig floor. • Provide the Driller with the necessary information – The Driller should be told the reason for the trip. This valve should only be used in the event that the drillpipe safety valve does not hold pressure. – The trip sheet for the last trip out of the hole should be available for comparison. or since. The following procedure is proposed as a guideline: 1.3. 3 Tripping Procedure Having completed the preparations as outlined in the previous section. • Drill floor preparation – Crossovers should be available on the rig floor to allow a full opening drillpipe safety valve to be made up to each tubular connection that is in the hole. the trip out of the hole can be started. – The rig crew should be completely familiar with. and practiced in. Flow check the well with the pumps off to ensure that the well is stable with the ECD (equivalent circulating density) effect removed. should be available close to the rig floor. Pump a slug. The cumulative discrepancy between the two values should also be recorded. – He should be fully aware of the procedures to be adopted in the event of a kick while tripping. This enables the pipe to be pulled dry and the hole to be accurately monitored during a trip. such as a Gray valve.BP WELL CONTROL MANUAL – Figure 2. …………………………………………………………………………… 6. CHECK THAT WELL IS SHUT IN …………………………………………………………… 7. …………………………………………………………………………… Or if there is any other possible indication of a kick.BP WELL CONTROL MANUAL Figure 2. SMB TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: 1. OPEN DP SAFETY VALVE …………………………………………………………… 11. IF IN OPENHOLE: ENGAGE …………………………………………………………… BUSHINGS. …………………………………………………………………………… 8. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 8. FLOWCHECK THE WELL IF NECESSARY YES IS THE WELL FLOWING? NO 1.3 Example of Standing Orders for Driller STANDING ORDERS TO DRILLER WHILE TRIPPING WELL NO 15 ORDERS EFFECTIVE DATE 15/6/87 RIG RIG 12 ON ALL TRIPS COMPANY REP K. STOP TRIPPING OPERATIONS 2. …………………………………………………………………………… 4. CLOSE ANNULAR PREVENTER …………………………………………………………… 6.D. ROTATE THE PIPE …………………………………………………………… 13. PROCEED AS DIRECTED 3. INSTALL OPEN DP SAFETY VALVE …………………………………………………………… 2.012 2-6 March 1995 . CLOSE DP SAFETY VALVE …………………………………………………………… 4. …………………………………………………………………………… 7. LINE UP STANDPIPE MANIFOLD …………………………………………………………… 10. …………………………………………………………………………… 5. INSTALL KELLY …………………………………………………………… 9. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1. 1. RECORD DP AND CSG PRESSURE …………………………………………………………… 12. OPEN CHOKE LINE VALVE (S) …………………………………………………………… 5. HOLE NOT TAKING CORRECT VOLUME DURING THE TRIP 2. SET THE SLIPS …………………………………………………………… 2. THE WELL IS FLOWING 3. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… WEOX02. For the first 5 – 10 stands off bottom. 6. the string should be returned to bottom while paying particular attention to displacement volumes. The pipe wiper should therefore be installed only after the first stands have been pulled. L. Circulate the hole across the trip tank and continue to trip out. the slug should be mixed to maintain a minimum of 2 stands of dry pipe. the overbalance can be assessed from the level of the trip gas at bottoms up. Be aware that the required hole fill volume per stand of heavy weight and drill collars will be greater than for drillpipe as the BHA is being removed from the hole. Subsequent action will be dependent upon the conditions at the rigsite (See Chapter 5). If the flowcheck indicates no flow and the cause of the discrepancy cannot be accounted for at surface. after each stand. the Driller will know the weight. If the hole does not take the correct amount of fluid at any stage in the trip. It is important to accurately displace the slug to the pipe. depth and height of the slug at all times during the trip.BP WELL CONTROL MANUAL The following formula can be used to calculate the volume of slug to ensure a length. Once back on bottom. consideration should be given to conducting a short round trip. If unsure of the overbalance. the well should be shut-in according to the procedure indicated in the standing orders. monitor the hole through the rotary. This is to check that the annulus is falling as pipe is removed from the hole. it may be necessary to increase the mud weight before restarting the trip out of the hole. Conduct a flowcheck prior to pulling the BHA through the stack. of dry pipe: Vsl = MW X L X Cp (bbl) (MWsl – MW) where Vsl L Cp MWsl MW = = = = = volume of slug (bbl) length of dry pipe (m) internal capacity of the pipe (bbl/m) slug weight (SG) mud weight in the hole (SG) As a general rule. The circulating pump should be switched off at this stage and the hole filled from the trip tank. The trip tank should not be overfilled at this stage to ensure that swabbing is clearly indicated. 2-7 March 1995 . should it occur. monitoring hole volumes with the aid of the trip sheet. 5. Conduct a flowcheck when the BHA is into the casing shoe. If the flowcheck is positive. 4. After circulating bottoms up. 3. In this manner. a flowcheck should be carried out. This procedure can be relaxed if. Circulate bottoms up. 2. • On prediction of an increase in pore pressure. Close in the BOP and circulate through the choke when the potential influx is at 500m below the stack. • On detecting significant levels of gas in the mud. Circulate bottoms up. The possible consequence of this is that a small influx that was undetected at depth may suddenly break out of solution close to the surface. It is therefore recommended that tripping procedures are modified to take account of this potential problem when oil base mud is in use in the following situations: • When drilling or coring in a potential pay zone. 5. If necessary increase the mud weight and perform a further check trip. 1. 2-8 March 1995 . Circulate until potential influx is at 500m below the stack. Check trip to the shoe monitoring hole volumes. watching for any pit gain. after several trips under the same conditions. The following procedure is recommended in these circumstances after a round trip. This may cause a dangerous liberation of gas at surface as well as significant reduction in hydrostatic pressure in the well. 3. Close in the well and circulate the potential influx through the choke. Flow check at the shoe and run back to bottom. Flow check the well. Consideration should also be given to the possibility of thermal expansion of the mud at high temperatures. When back on bottom prior to any further drilling or coring. gaseous fluids have a tendency to go into solution with the mud at high temperature and pressure. the well remains stable. This can cause a reduction in effective mud weight and hence in the overall hydrostatic head. it will not break out of solution until the bubble point is reached. circulate bottoms up to check for trip gas. Experience has shown that once an influx has gone into solution.BP WELL CONTROL MANUAL 4 Special Procedure for Oil Base Muds When oil base mud is in use. typically at 1000 – 1500psi (this will depend on the fluids concerned). 6. 2. In these circumstances the following procedure is recommended prior to pulling out of the hole: 1. 3. watching for any pit gain. 4. 4 Bottomhole Pressure Reduction – due to gas cutting 2-12 2-9 March 1995 .BP WELL CONTROL MANUAL 2.2 MAINTAIN SUITABLE HYDROSTATIC PRESSURE Paragraph Page 1 General 2-10 2 Gas Cutting 2-10 3 Cuttings Contamination 2-14 Illustrations 2. This section outlines the techniques that can be used to predict the effect of drilling fluid contamination on the hydrostatic pressure. These contaminants can significantly alter the effective hydrostatic pressure exerted by the drilling fluid.285 X 25 X 0. is given by the following formula: Qgas = dh 24 2 X (gal/min) 1.285 X ROP X Ø X Sg Therefore as an example in the following conditions: ROP dh Ø Sg Bottomhole pressure Hole depth and depth at which gas enters the mud.25 24 2 X = = = = = = 3020m 1. D Qgas = 12.) • Formation porosity. Sg (fractional) The rate of gas entering the mud at bottomhole conditions. and in certain circumstances. Qgas (gal/min). 2 Gas Cutting When drilling through a formation that contains gas.75 = 1. it is inevitable that the mud will become contaminated with gas from the drilled formation even if the formation is penetrated overbalance.BP WELL CONTROL MANUAL 1 General Primary well control is achieved by controlling formation pressures with the hydrostatic pressure of the drilling fluid.75 6000psi . The drilling fluid may be contaminated with cuttings and formation fluids during drilling. this can cause loss of primary control. 0. The settling of cuttings to the bottom of the hole may significantly reduce the hydrostatic pressure further up the hole. Hydrostatic pressure will be reduced once drilling stops as a result of the loss of annulus frictional pressure and the removal of cuttings from the annulus.2 X 0. ROP (m/hr) • Hole diameter.26 gal/min at 6000psi 2-10 March 1995 25 m/hr 12 1/4 in. Ø (fractional) • Gas saturation. Drilled gas will enter the mud system at a rate determined by the following factors: • Rate of penetration.2 0. d h (in. 7 (1.26 X 6000 = 514 gal/min at atmospheric pressure 14. In this case: ∆P = 14.81 SG 700 + 514 It should be stressed that this figure is an estimation of the actual mud weight at the flowline and as such will not reflect the actual density of the mud in the hole. It should be noted that these curves represent an ideal gas.4 – 0.81) ln (96.4 X 100 = 42% cut The following formula can be used to estimate the bottomhole pressure reduction due to gas cut mud: ∆P = 14.81 1000 (psi) ∆P = 64psi 2-11 March 1995 .46 X MW X D) MW act 1000 (psi) where ∆P = bottomhole pressure reduction due to gas cutting (psi) D = depth at which gas enters the mud (m) Figure 2.7 This simplified calculation treats the gas as ideal and does not consider the effects of temperature.4 X 3020) 0.46 X 1.81 1. temperature and solubility effects are not considered.BP WELL CONTROL MANUAL Therefore at atmospheric pressure the gas flowrate is given by: Qgas = 1.7 (MW – MW act) ln (96. In this hole section the flowrate of mud is 700 gal/min. The percentage gas cutting is given by: Percentage cut = MW – MWact X 100 MW Which in this case gives a figure of: Percentage cut = 1.4 – 0. the actual mud weight at surface can be calculated using the following formula: MW act = MW X where MWact MW Qmud Qgas = = = = Qmud Qmud + Qgas actual mud weight at surface (SG) uncut mud weight (SG) flowrate of mud (gal/min) flowrate of gas (gal/min) Therefore in this case the actual (or gas cut) mud weight at surface is given by: MW act = 1.4 shows the effect of various levels of gas cutting for two different mud weights using the above formula.4 X 700 = 0. 05 SG 2.05 SG -3000 2.05 SG 2.1 SG 1.4 Bottomhole Pressure Reduction – due to gas cutting 0 20 40 60 80 100 0 -1000 -2000 TRUE VERTICAL DEPTH (m) 2.1 SG 1.05 SG -6000 2.1 SG 1.1 SG 1.05 SG -5000 2.BP WELL CONTROL MANUAL Figure 2.1 SG 1.1 SG -4000 1.013 2-12 March 1995 .05 SG 5% 10% 20% 30% 40% 50% PERCENT GAS CUT AT THE FLOWLINE -7000 0 20 40 60 80 100 DECREASE IN BOTTOMHOLE PRESSURE (psi) WEOX02. 7 = 21.6 X 1. 2-13 March 1995 .7 The actual mud weight at surface is given by: 750 750 + 645 X 1.285 X 80 X 0. However the effect of near surface expansion may be critical in relatively shallow hole sections.61 1000 The average mud weight in the hole is given by: (1.13 = 0. The actual reduction in bottomhole pressure is caused by the gas when it has considerably expanded.BP WELL CONTROL MANUAL Therefore the average mud weight in the hole is equal to: MW = (6000 – 64) = 1.6 gal/min at bottomhole conditions Gas flowrate at surface is given by: 21. This expansion does not occur until the gas has been circulated to near the surface.02 SG.61 SG Corresponding to a pressure reduction of: 14. As can be seen from the previous example. caused a very small reduction in the bottomhole pressure and actually only reduced the effective mud weight by 0.3 X 0. given that the pore pressure at this depth is assumed to be normal at 1.02 SG 300 X 1.7 750 gal/min 1. 80 m/hr 300m 1.13 X 300) = 44 psi 0.13 X 1.4%.421 X 300) – 44 = 1. The effect of gas cutting in a relatively shallow hole is demonstrated with the following example: dh Instantaneous ROP D MW = = = = 24 in.7 X (1.61) ln (96.421 It can be seen that what appeared to be significant gas cutting.3 0. or by a factor of 1.421 Quite clearly the potential exists for the well to kick in this situation.421 X 300 = 645 gal/min 14.13 – 0.38 SG 3020 X 1.46 X 1.13 SG Ø Sg Pump output Formation pressure = = = = 0.03 SG Gas enters the mud system at a rate given by: = 24 24 2 X 1.03 X 1. at 42%. this near surface expansion has a small effect on the bottomhole pressure in a deep well for moderate levels of gas cutting.03 SG. In order to be able to estimate this additional pressure. Re is given by: Re = 422.BP WELL CONTROL MANUAL Industry experience has shown that excessive gas cutting in shallow hole has in many cases been the cause of shallow gas blowouts in offshore environments. If this increase is excessive. however the following relationship can be used to estimate its value: Slip Velocity. thereby further reducing the hydrostatic head of the mud column. The cuttings slip velocity is defined as the velocity of the cuttings relative to the velocity of the mud. The presence of cuttings in the annulus will increase the effective hydrostatic pressure of the fluid column.78 X MW X v s µ X d cut 2-14 March 1995 .56 dcut (w cut – MW) 1. v s = 108 where vs µ MW wcut dcut = = = = = X d cut X (wcut – MW) MW 0.333 X µ0.667 slip velocity (m/min) average viscosity (cP) mud weight (SG) average cuttings weight (SG) cutting average diameter (in. a measure of the ability of the drilling fluid to remove the cuttings from the well is required. There are many factors that influence the cuttings slip velocity. High pump output should also be maintained to disperse the gas within the mud to minimise variations in SG. It is therefore important that the ROP is restricted in shallow hole. and the expansion of the gas may cause mud to be unloaded at surface.333 0. the following formula should be used to calculate the slip velocity: vs = 34. It is therefore useful to be able to estimate the additional pressure caused by the cuttings in the annulus.5 X 1 2 MW The particle Reynolds number. The previous example shows the possible effect of gas cutting in shallow hole. it can cause losses which may possibly lead to the loss of primary control.) However. However it should also be noted that in shallow hole the annulus pressure loss during circulation will be negligible. if the particle Reynolds number is greater than 2000. 3 Cuttings Contamination One of the most important functions of the drilling fluid is to transport cuttings from the bit to the surface. hole is given by: Velocity = 0. it is therefore determined as follows: Transport ratio.4 m/min 2-15 March 1995 . section: Velocity = 0.134(d hc 2 – do 2) (m/min) and vm = mud velocity (m/min) Q = pump output (gal/min) dhc = hole/casing ID (in. Bit size = 17./180m Mud weight = 1.667 1. Casing shoe at 900m Casing ID = 22 in.50.5 2 – 82) = 21.6 m/min In the 22 in.3 in.4 X Q X TR where ROP = rate of penetration (m/hr) dbit = diameter of the bit (in.5 SG = 0.3 X (2.333 = 7.421 X sum (L X Ca) where L = the length of each section (m) The cuttings concentration must therefore be determined for each section of hole. Collar OD/length = 8 in. hole section drilled from a floating rig.5)0.) do = pipe OD (in.134 X 700 (17.333 X 50 0. Drillpipe OD = 5 in.5 – 1. TR = v m – vs vm where vm = Q 0.) Ø = porosity The extra pressure caused by the cuttings in the annulus is given by the formula: ∆P = (w cut – MW) X 1.7 m/min The velocity of the mud in 17 1/2 in.5 in.5 SG The slip velocity Average viscosity Pump output ROP Openhole length Cuttings density Cuttings diameter = 50 cP = 700 gal/min = 50 m/hr = 180 m = 2. Riser ID = 22 in. = 108 X 0.) The concentration of cuttings in the annulus can be calculated from the following formula: Ca = ROP X d bit2 X (1 – Ø) 448. Consider the following example for a 17 1/2 in.BP WELL CONTROL MANUAL The transport ratio is defined as the ratio of the actual cuttings velocity to the mud velocity.134 X 700 (22 2 – 52) = 11. 4 X 700 X 0.5 .5) X 1.5 2 448.421 X [(0.152 (= 15. hole.32 = 0.1.076 X 180) + (0.BP WELL CONTROL MANUAL This gives a transport ratio of 64% in 17 1/2 in.421 = 1.152 X 900)] ∆P = 214 psi This additional pressure therefore increases the effective mud weight to a figure givenby: MW = (1.64 = 0.5 2 448. Ca.421 X 1080) + 214 1080 X 1. The additional hydrostatic pressure due to the cuttings is determined as follows: ∆P = (2. hole is given by: Ca = 50 X 17. hole section: Ca = 50 X 17.6%) In the 22 in. in the 17 1/2 in. The cuttings concentration.5 X 1.64 SG 2-16 March 1995 . hole and of 32% in 22 in.2%) The porosity is not considered.076 (= 7.4 X 700 X 0. BP WELL CONTROL MANUAL 2.6 Lost Circulation Remedies 2-24 2-17 March 1995 .5 Balanced Plug Technique 2-22 2.3 CONTROL LOST CIRCULATION Paragraph Page 1 General 2-18 2 Causes of Lost Circulation 2-18 3 Classification of Lost Circulation 2-19 4 Identification of Loss Zone 2-19 5 General Procedure for Spotting Plugs 2-20 6 Lost Circulation Decision Analysis 2-23 7 Drilling Blind 2-27 Illustrations 2. Thirdly. 2-18 March 1995 . mud cake can reach a level where the hole packs-off around the drillstring. • Drilling with excessive overbalance • Drilling too fast Overloading the annulus can cause excessive ECDs or the formation of mud rings as the concentration of cuttings increases. it precludes accurate monitoring of the hole. • Mud cake build up In severe cases. • Cavernous formations. to determine the most appropriate remedy. • Swab/surge pressures when running pipe The mud properties and tripping procedures must be controlled to ensure that surge pressures are not excessive when running pipe. Firstly. that the cost of the replacement mud required may be considerable. This section is intended to outline how to identify the different types of loss zone and. The drilled solids content of the mud must be carefully controlled. Lost circulation is undesirable primarily for three reasons. possibly by breaking circulation at several depths on the trip in the hole. by dilution if necessary.BP WELL CONTROL MANUAL 1 General Lost circulation can occur as a result of the following: • Unconsolidated or highly permeable low pressure formations (including depleted reservoirs and at the base of long permeable reservoirs). in each case. • Induced fractures. To minimise this problem good fluid loss control and maximum use of the solids-control equipment must be coupled with a low fluid-loss mud. that a loss of hydrostatic head may lead to the well kicking and secondly. 2 Causes of Lost Circulation These are as follows: • Setting intermediate casing too high Optimum casing design ensures that weak formations are isolated prior to drilling into known areas of higher pressure. Care should be taken when breaking circulation. • Natural fractures. • Partial Losses (10 – 500 bbl/hr) Because these losses are more severe the cost of the mud in use becomes more important and so it is more likely to be economical to take some rig time to cure them. Each type of lost circulation zone will exhibit certain characteristics which can be outlined as follows: • Unconsolidated formations Occur mainly at shallow depth. Other factors such as the need for a good cement job. formation damage or the risk of possible stuck pipe need to be considered in specific cases. For whole mud to be lost to a formation. immediately pump water down the annulus. the hydrostatic head that the hole can maintain should be determined. From the volume required. consideration may be given to drilling blind. In this case consideration should be given to pulling out and circulating in stages to clean the hole. • Complete Losses (500 bbl/hr – No returns) If complete loss of returns is experienced.) Curing this level of loss is sometimes not economical if a cheap mud is in use and the rig rate is high. Will cause a gradual loss of mud to the hole. this may be due to filtration loss due to poor fluid loss control. may worsen if no remedial action is taken. monitoring the volumes required to fill the hole. If pressure constraints are tight the losses may have to be cured. In some instances. in the absence of fractures. (The identification of seepage losses may be confused with the removal of cuttings from the mud at the shakers. however. Drilling with losses can be considered if the fluid is cheap and the pressures are within operating limits. If efforts to cure the losses are unsuccessful.BP WELL CONTROL MANUAL 3 Classification of Lost Circulation The severity of the loss zone can be assessed as follows: • Seepage Losses (0. When drilling in top hole sections with high ROP. requires permeability of the order of 10 Darcies. complete losses may be caused by overloading the annulus.25 – 10 bbl/hr) This takes the form of very slow losses or sometimes undetectable loss to a permeable formation. 4 Identification of Loss Zone The formation type determines the most appropriate remedial treatment required to cure losses. 2-19 March 1995 . It is therefore important that the loss zone is correctly identified. Generally indicated by unstable pressure readings at surface. May cause a gradual loss of mud to the hole. • Induced fractures Horizontal fractures may be induced at relatively shallow depths after the formation of mud rings and by overloading the annulus. The depth of the loss zone must be established in order to calculate the hydrostatics involved and to determine the remedial action required. Kick fluids flow. The loss zone can be located using a Temperature Survey. When drilling in areas of potential lost circulation. usually from the lower active zone to the zone which has been fractured. Loss of returns may be sudden and complete. To do this. coarse LCM must not be pumped through a bit with nozzles. wherever possible the slurry formulation should be tested by the cementing contractor to determine thickening time. Vertical fractures may occur at greater depth and may be caused by any pressure surge on the formation. When the bit in the hole contains small nozzles and an LCM pill is required. consideration should be given to tripping the pipe and running a bit with large nozzles or even open ended drillpipe. keep the pipe moving to avoid getting stuck.BP WELL CONTROL MANUAL • Natural fractures Can occur in many rock types. 5 General Procedure for Spotting Plugs Accurate placement of plugs downhole is vital if the loss zone is to be sealed. Correlation with the known lithology at the confirmed loss zone is very important to identify the type of formation that has been fractured. May be accompanied by the bit dropping up to several feet depending on the height of the cavern. • Underground blowout Condition where the act of shutting in on a kick induces a fracture in the openhole above the point of influx. 2-20 March 1995 . When the plug is being spotted. • Cavernous formations Normally only experienced in limestone formations. Usually indicated by sudden and complete losses. The formation of a mud ring will be indicated by an increase in pump pressure and the drillstring becoming tight. However. When placing plugs containing cement. accurate measurement of pump efficiencies and internal pipe sizes must be made. complete losses may be experienced. large nozzles should be fitted to the bit. which operates by identifying a discontinuity in the temperature gradient within the wellbore. however if drilling proceeds and more fractures are exposed. A noise log may also be used. The use of bits with a centre jet will also increase the area available for spotting plugs. 4A. or by squeezing. In general. the BOPs closed and then squeeze pressure applied on the annulus below the rams. placement techniques will be as follows (refer to Paragraph 6 for recipes): (a) Conventional circulation Used for techniques 2A and 2B. the bit should be tripped into the casing and the non-balanced plug technique used (See/(c)).0bbl/min until the losses cease. This is however not always possible to achieve or desirable. The balanced plug method should be used for the above techniques. the balanced plug technique should not be used. If it is decided to squeeze the plug.BP WELL CONTROL MANUAL The best displacement method for placing plugs is to use the balanced plug technique. The basic requirement for a balanced plug is that the correct volume of spacer is pumped behind the slurry. It may be desirable to reverse circulate the pipe contents. if cement in any of the above techniques and it becomes necessary to spot the plug through a bit. if this is possible after pulling out of the plug. Pump at 1. The pipe is then pulled out of the plug. 3C. In this case. However. depending on the rate of loss or the type of slurry to be pumped. (b) Balanced plug Used for techniques 3A. to ensure that the hydrostatic pressure in the annulus is balanced with that in the pipe before the pipe is pulled out of the plug. 2 bbl should be pumped down the pipe. 3B. Place the plug through open ended pipe (if possible) opposite the loss zone. 4B. 4C and 4D. Plug balancing calculations are as follows: • Calculate the volume of cement plug for the required height of plug Volume (bbl) = height (m) X hole capacity (bbl/m) X factor for excess No of sacks required = volume (bbl) slurry yield (bbl/sk) 2-21 March 1995 . Balanced plugs can be allowed to lose to the formation under the hydrostatic head of the column alone. 5) If the same fluid is used before and after the plug: h = Spacer vol ahead (bbl) annulus capacity (bbl/m) Spacer vol behind (bbl) = h X pipe capacity (bbl/m) where h = height of spacer (m) 2-22 March 1995 .5 Balanced Plug Technique • With the volume of spacer ahead known calculate the height and volume of spacer behind (See Figure 2.014 Figure 2.BP WELL CONTROL MANUAL TUBING MUD L SPACER where h = height of spacer (m) H = height of plug (m) L = drillpipe/tubing length (m) h H PLUG WEOX02. then pump down the annulus only. vugs and caverns where the overburden is self-supporting. cane. a lost circulation pill can be mixed (eg/2A or 2B). Where the loss zone depth is known with certainty then the pipe can be placed approximately50m above it. • Technique 1 Pull up and wait The bit should be pulled up to safety inside casing and the hole left static for 4 to 8/hours without circulation. at comparatively low cost. 6. pump simultaneously down the annulus and pipe at 2bbl/min. mica or similar) 5 lb/bbl large cellophane flakes (1. 5B.0 in. For a downhole mixed plug. mica or cane) 5 lb/bbl medium to fine fibres (wood.BP WELL CONTROL MANUAL • Calculate the height of the cement plug before the pipe is pulled out H(m) = Volume of slurry(bbl) annulus cap (bbl/m) + pipe cap (bbl/m) where H = height of the plug (m) • Calculate the plug displacement volume Displacement volume (bbl) = (L – H – h) X pipe cap (bbl/m) where L = Drillpipe/tubing length (m) (c) Non-balanced plug Used for techniques 5A. diameter) Pump the pill as recommended in Paragraph 5. for use in case the zone does not self heal. 4B and 4C through a bit. For a spotted plug pump the slurry out of the pipe plus 5 bbl excess. 2-23 March 1995 . natural fractures.6 can be used as a guide to determining the most suitable method of dealing with a lost circulation problem. The techniques referred to in Figure 2. (While waiting. 6 Lost Circulation Decision Analysis Figure 2.) This technique is only likely to succeed in zones of induced fractures. It is therefore not applicable to naturally occurring horizontal loss zones eg/gravels. If the hole is still not filling go on to use a ‘High filter loss slurry squeeze’. The slurry is displaced to the end of the pipe and the BOP is closed.6 are specified below. • Technique 2A LCM pill Mix a 100 – 500 bbl pill as follows: 100 – 500 bbl mud 15 lb/bbl fine walnut/sawdust/etc 10 lb/bbl fine fibres (wood. 7A and 7B or whenever using techniques 3C. 4A. Repeat if the hole still takes fluid. calcium chloride.BP WELL CONTROL MANUAL LOST CIRCULATION REMEDIES TYPE OF LOSS SEVERITY OF LOSS. cement squeeze. calcium chloride. calcium chloride. natural fractures. EFFECTIVE IN LOST CIRCULATION REMEDIAL TECHNIQUE Technique 2A – Plug of fine bridging agents in mud Technique 3A – High-filter-loss slurry squeeze with fine bridging agents Technique 1 – Pull up and wait (primarily for induced vertical fracture) Technique 2B – Plug of medium bridging agents in mud Technique 3A – High-filter-loss slurry squeeze with coarse bridging agents Technique 3B or 3C – High-filter-loss slurry squeeze with coarse bridging agents Technique 4B – Thixotropic cement or other cements (4A. They consist of porous sands and gravels. cellophane or similar material as can be mixed and remain pumpable. Flo-Check) WBM OBM* yes yes yes yes yes partial yes yes yes yes yes yes yes no yes no yes yes yes yes yes no yes yes yes yes partial no no yes yes yes yes yes yes yes WBM – water-base mud OBM – oil-base mud Figure 2. Flo-Check) Technique 3B or 3C – High-filter-loss slurry squeeze with coarse bridging agents Technique 4A – Neat portland cement Technique 7B – Downhole-mixed plug (sodium. 4C.0 lb/bbl XC Polymer) 0. • Technique 3A High filter loss slurry squeeze (Diearth. cement squeeze Flo-Check) Technique 3A.0 lb/bbl Drispac (or 1.6 Lost Circulation Remedies • Technique 2B LCM pill As above but using larger concentrations of coarse materials eg coarse mica. 4D) Technique 5B – Mud + diesel-oil-bentonite plus cement Technique 5A – Downhole-mixed soft plug (mud-diesel oil-bentonite) Technique 7B – Downhole-mixed hard plug (sodium silicate. 2-24 March 1995 . bbl/hr Seeping 1 – 10 to horizontal loss zones** to induced vert fractures Partial 10 – 500 to horizontal loss zones** LOSS ZONE GEOMETRY to induced vert fractures Complete 500 – complete to horizontal loss zones** Long honeycomb or caverns (only in limestones) Complete to horizontal loss zones** Deep induced fractures Complete Vertical in WBM or OBM in WBM in WBM in WBM in OBM in OBM in OBM * Usually not in use where loss zones are horizontal. Diaseal M etc) 100 bbl water 15 lb/bbl bentonite or 1. and honeycomb and caverns. cement squeeze. 3B or 3C – High-filter-loss slurry squeeze with 25 – 35 lb/bbl or coarse bridging agents Technique 5B – Downhole-mixed soft/hard plug continuously mixed in large amounts Technique 1 – Pull up and wait Technique 5B – Downhole-mixed soft/hard plug Technique 5A – Downhole-mixed soft plug Technique 7B – Downhole-mixed hard plug (sodium. walnut or cellophane.5 lb/bbl lime 50 lb/bbl Diearth. wood. walnut. silicate. Diaseal M 15 – 20 lb/bbl fine mica. silicate. BP WELL CONTROL MANUAL • Technique 3B High filter loss slurry squeeze As Technique 3A but include the following: 15 – 30 lb/bbl medium and coarse LCM • Technique 3C High filter loss slurry squeeze As Technique 3A but include the following: Reduce Diearth concentration to 10 – 25 lb/bbl Use barytes as inert filler at 300 lb/bbl Add cement at 70 lb/bbl Place in 30 bbl slugs into loss zone with 200 psi squeeze pressure. Note: • Wherever possible, slurry formulations should be tested prior to spotting to eliminate possible premature setting. When this is the case, always be aware of the thickening time and avoid leaving cement in or opposite the pipe beyond this time. Technique 4A Neat cement slurry Neat cement slurries give high compressive strength plugs. Mix Class G cement at 1.90 SG in water • Technique 4B Extended cement slurry (using bentonite) Prehydrated bentonite slurry gives a degree of fluid loss control and ‘plating effect’ to help stop lost circulation. Coupled with this, a lightweight slurry can be formulated (1.58 SG) which helps in areas of serious lost circulation. A further benefit is that reasonable compressive strength characteristics are found with slurries of this type. Add 10 lb/bbl bentonite to pre-treated fresh water (with 0.25 lb/bbl caustic and 0.25/lb/ bbl soda ash). Mix cement up to 1.58 SG. • Technique 4C Aggregated cement slurry (with sand or ground coal) Add aggregrate to the neat cement slurry at 1.90 SG up to a maximum weight of 20 – 35 lb/sack of cement in the mix. 2-25 March 1995 BP WELL CONTROL MANUAL • Technique 4D Thixotropic cements Cement of this type exhibits good flow characteristics when being pumped and a quickly developing gel strength when stationary. This thixotropic behaviour is beneficial for the following reasons: – A plug of cement displaced past the loss zone is self supporting and does not fall back under its own weight. – The cement will tend to remain next to the wellbore when squeezed into fractures due to their rapidly developing gel strength. Due to the temperature and chemical formulation sensitivity of this type of slurry, it is not recommended to use this cement without rigorous quality control and testing prior to each job. Halliburton Thixset 1 or 2 are examples of this type of cement. • Technique 5A Downhole mixed soft plug This type of lost circulation pill is designed to mix with a water base mud or formation water in the downhole environment and subsequently be squeezed into the formation. Mix 10.5 gal of diesel or base oil to 100 lb of bentonite. Granular or fibrous LCM may be added to this mix if required, ie mica at 10 ppb plus walnut at 10 ppb. This mixture must be kept away from contact with water until it is placed out of the drillpipe. To do this, a 10 bbl oil spacer is pumped ahead of a plug, followed by 10 bbl after the plug. The principle of this plug is to form a rubbery plug whenever the mixture contacts the water base mud. Formation water will assist the hydration of the bentonite. • Technique 5B Downhole mixed soft/hard plug This type of lost circulation pill is designed to mix with a water base mud or formation water in the downhole environment. It can be designed to form an initially fluid mixture of a soft or semi-hard nature depending on its composition, and can be squeezed into the formation where it will harden and develop compressive strength. The proportion of mud to the pill in the final mix downhole will determine the strength of the plug. For example, a 1:1 mix with fresh water will result in a soft plug, whereas a 1:3 (water/mix ratio) mix will result in a hard plug. In every case however, pilot tests should be carried out at surface for various mixes, prior to spotting the pill. Mix on surface 300 lb of G neat cement and 158 lb of bentonite to 1 bbl of diesel or base oil. All water should be excluded from the mix on surface. 2-26 March 1995 BP WELL CONTROL MANUAL • Technique 6 Downhole mixed soft plug Oleophilic clay and water This type of plug formulation is designed for use in an oil base mud. It works by the same principle as 5A, except that the clay disperses in water and hydrates in oil (the opposite of a bentonite squeeze). Mix on surface 280 lb of oleophilic clay to 1 bbl of water. Add lignosulphonate at 4/lb/ bbl water. An example of oleophilic clay is Baroid Geltone. The spacers ahead and behind this plug must be water based. • Technique 7A Surface mixed soft plug (polymer type) These formulations are mixed on surface, where polymers are blended with activators and extenders, to give a delayed thickening reaction. This allows enough time to place the plug in the loss zone before the chemical reaction takes place. Haliburton Temblok is an example of this type of material. This treatment is only temporary and the yield strength breaks down fairly quickly. It should be followed by a cement slurry to effect a permanent seal. • Technique 7B Downhole mixed hard plug Haliburton Flocheck can be used for this. This is a Sodium Silicate material which on contact with calcium ions forms insoluble Calcium Silicate. By pumping a CaCl 2 brine to the formation, followed by the Flocheck material, plugging of the formation occurs when the two chemicals mix in the formation matrix. Placement as follows: Pump 50 bbl 10% (by weight) CaC12 followed by 10 bbl fresh water. Then pump 35/bblof Flocheck followed by a further 10 bbl fresh water. Care must be taken to ensure that CaC1 2 does not come into contact with Flocheck on surface as it will go hard in the pits. This treatment, whilst permanent, may be reinforced by a cement slurry. 7 Drilling Blind In certain circumstances it may become necessary to drill ahead without any returns at surface, ie drilling ahead blind. This may be required if all attempts as laid out in Paragraph 6 have failed. Once the decision to drill blind has been made, the main objective will be to set casing in the first competent formation penetrated. 2-27 March 1995 BP WELL CONTROL MANUAL Although no cuttings will be obtained while drilling blind, casing seat can be located by logging and by keeping up a penetration log whilst drilling ahead. The hole has to be logged frequently, for example every 100m or whenever the penetration rate suggests a formation change. Once a competent formation has been identified, the new formation has to be penetrated by at least 20m to successfully set and cement the next casing string. Whilst drilling blind the following precautions must be taken: • Use one pump for drilling as normal with the other continuously filling the annulus with water. • Assign personnel to monitor the flowline for returns at all times. • Pick the drillstring up off bottom every 2m drilled to ensure that the hole is not packing off above the bit. • Keep one pit full of viscous mud at all times ready to pump to the hole. • If one pump requires repair, use the cement unit to fill the annulus continuously. • After drilling each single, wipe the hole over a full single and kelly length prior to drilling ahead. Wipe the hole over the length of a stand if using a topdrive. If overpull is experienced wipe the hole 3 or 4 times. Spot a viscous pill around the bit prior to making each connection. This pill should be balanced in and outside the pipe. • If, during drilling, the fluid in the annulus reaches surface, stop drilling immediately. Pick up the drillstring so that the BOPs can be closed if required. Stop the pump on the drillpipe and the annulus. Close in and observe for any pressure build up. – If there is no pressure on the annulus, start up the pump on the drillpipe and circulate bottoms up through a fully opened choke (if this is possible). The loss zone may be plugged with drill cuttings. Drill ahead if everything is normal to a predetermined depth, if the area is well known. Stop and log if the area is not well known to determine if a suitable casing seat has been found and has been sufficiently penetrated. – If there is pressure on the annulus be prepared to adopt procedures for an undergroundblowout. At all times be prepared to cement the well. If tripping is required when complete loss of returns exists then the following precautions must be taken: • Spot a viscous pill across the openhole section. • Before tripping, stop the pumps on drillpipe and annulus and observe the well for 30minutes. Keep the string moving and be prepared to close in the well if necessary . • Drop the dart into the drop-in dart sub. • Fill up the annulus continuously during the trip. • Monitor the flowline at all times. 2-28 March 1995 BP WELL CONTROL MANUAL • Stop the pumps and monitor the well whenever the bit is pulled into the previous casing shoe. • Be prepared to shut in at all times during the trip. If wireline logging is required when complete loss of returns exists then the following precautions must be taken. • When logging, the pump should be kept continuously on the hole. The only exception is when static fluid level has to be established. • Logging is best conducted using through drillpipe logging tools, with open ended drillpipe run to the casing shoe. 2-29/30 2-29 March 1995 BP WELL CONTROL MANUAL 3 WARNING SIGNS OF A KICK Paragraph Page 1 General 3-2 2 Drilling Break 3-2 3 Increased Returns Flowrate 3-2 4 Pit Gain 3-3 5 Hole not Taking Appropriate Volume During a Trip 3-4 6 Gas Cut Mud 3-4 7 Increase in Hookload 3-6 8 Change in Pump Speed or Pressure 3-6 3-1 March 1995 BP WELL CONTROL MANUAL 1 General When drilling with returns to surface, a kick cannot occur without any warning sign. This Chapter outlines and explains the signs that indicate either that a kick has occurred or that a kick may soon develop. 2 Drilling Break One of the first indications that a kick may occur is an increase in penetration rate, or a drilling break. Many factors influence the rate of penetration, but an increase in penetration rate can be caused by an increase in formation porosity, permeability or pore pressure. A change in all or one of these formation parameters may create the conditions in which a kick could occur. For this reason any drilling break should be checked for flow. Even if the flowcheck indicates no flow, the reason for each drilling break should be determined. As an example, a drilling break could be caused by drilling into an impermeable transition zone above a permeable reservoir. Because the formation is impermeable, it is unlikely that any significant flow would be noticed during a flowcheck. However, the formation may be considerably underbalanced by the mud column. If drilling continued and the reservoir was penetrated, a kick would be taken. Consideration must therefore be given to circulating bottoms up before drilling ahead after a negative flowcheck, especially in critical sections of the well. 3 Increased Returns Flowrate The first confirmation that a kick is occurring is an increase in returns flowrate while the pumps are running at constant output. However, this increase may not be detected if the influx flowrate is particularly slow. In this case a slight pit gain may be the first detectable confirmation of the kick. If low gravity formation fluids enter the wellbore during drilling, the hydrostatic pressure in the annulus will decrease rapidly as more influx enters and when the influx expands as it is circulated up the hole. As a result, rapid influx flowrates can quickly develop, even though the initial influx flowrate might have been very low. The length of formation exposed also has direct bearing on the rate of flow into the well. The greater the length of formation exposed, the larger the flowrate. It is therefore important that surface equipment be able to reliably detect a small increase in returns flowrate. 3-2 March 1995 BP WELL CONTROL MANUAL 4 Pit Gain (a) While Drilling A gain in pit volume, that was not caused by the movement of mud stocks at surface, is confirmation that a kick is occurring or has occurred. This is the most reliable indicator of a kick. Consequently, every effort must be made to ensure that pit levels are accurately monitored at all times. Very small influx volumes may not be detected at surface as they occur. This may be due to the fact that, either the initial influx was particularly small, or the influx flowrate was very slow. This could be the case if the formation has low permeability or if a more permeable formation was only very slightly underbalanced. In such cases, the influx may be detected before it is circulated to the surface if it expands significantly as it rises up the hole. In general, the greater the amount of gas that is contained in the influx, the greater the expansion of the influx will be as it rises up the hole. As a result, the greater the proportion of gas in the influx, the more likely it is that the influx will be detected as it is circulated up the hole. Consequently, a low volume influx heavy oil or brine that does not contain any appreciable quantity of gas, will be relatively difficult to detect at surface. However, if the active system is accurately monitored, pit gains of less than 10 bbl should be detected reliably, even on floating rigs. (b) During a Connection An influx may only occur during a connection due to the reduction in bottomhole pressure as the pumps are shut down and the pipe pulled off bottom. If the well flows only during a connection, it is likely that the influx flowrate will be slow initially, resulting in only a small pit gain. Therefore, early detection of flow during a connection may be difficult. However, it is important to check for flow during a connection, because if a close to balance situation is developing, it is most likely to show initially during a connection. The first signs are likely to be increasing connection gases. However, if the underbalance develops very rapidly and the bottoms up time is considerable, then it is possible that an influx may occur before the connection gases are detected at surface. In this instance, flow during a connection may be the first indication of an underbalanced situation. The detection of a small pit gain during a connection is complicated by the volume of mud in the flowline returning to the pit after the pumps have been shut down. This will cause an increase in pit level during each connection. It is important therefore to establish the volume of mud that is contained in the flowline during circulation. For instance, this volume might be 10 bbl and as such, a 10 bbl pit gain during a connection would not be significant. However, a 15/bbl gain may indicate that a 5 bbl influx has occurred. 3-3 March 1995 BP WELL CONTROL MANUAL 5 Hole not Taking Appropriate Volume During a Trip As pipe is pulled from the hole, it is essential that the appropriate volume of mud is used to keep the hole full. This is essential in order that both a full head of mud is maintained in the hole and that if an influx is swabbed into the hole, it is detected immediately. Before every trip, a trip sheet (See Page 2-4) should be filled out. This must clearly show the expected hole fill volumes as the pipe is pulled out of the hole. As the trip proceeds, actual hole fill volumes should be entered in the trip sheet alongside the expected volumes. If the hole takes less mud than expected, this should be taken as positive indication that an influx has been swabbed into the hole. A flowcheck should be carried out immediately or, if in a reservoir section, the well should immediately be shut in. A negative flowcheck at this point is not necessarily confirmation that an influx has not occurred. It is quite possible, even if an influx has been swabbed into the well, that the well will not flow if the pipe is stationary. Therefore, if at any stage in a trip the hole does not take the correct volume of mud, the pipe should be run back to bottom, using the trip tank, and bottoms up circulated. The problems associated with dealing with a kick when the pipe is off bottom can be considerable, and so every effort must be made to ensure that significant swab pressures are avoided during a trip. Swabbing is minimised by ensuring that the mud is in good condition prior to pulling out ofhole and that predetermined speeds are not exceeded at any stage in the trip (see Chapter3, Volume 2). 6 Gas Cut Mud A kick is confirmed at surface as an increase in returns flowrate and a pit gain. However, a minor influx that is not detected as a pit gain may first be identified at surface in the returned mud. Formation fluids and gas in the returned mud may therefore indicate that a low volume influx is occurring or has occurred, even though no gain has been detected. Returned mud must be monitored for contamination with formation fluids. This is done by constantly recording the flowline mud density and accurately monitoring gas levels in the returned mud. Gas cut mud does not in itself indicate that the well is kicking (gas may be entrained in the cuttings). However, it must be treated as early warning of a possible kick. Therefore the pit level should be closely monitored if significant levels of gas are detected in the mud. An essential part of interpreting the level of gas in the mud is the understanding of the conditions in which the gas entered the mud in the first place. 3-4 March 1995 Gas cutting due to this mechanism will occur even if the formation is overbalanced. is classified as follows: (a) Drilled Gas As porous formations containing gas are drilled. (c) Trip Gas Trip gas is any gas that entered the mud while the pipe was tripped and the hole appeared static. (b) Connection Gas Connection gases are detected at surface as a distinct increase above background gas. Gas due to one or a combination of the above. If the static mud column is sufficient to balance the formation pressure. connection gases indicate a condition of near balance. the trip gas is caused by swabbing and gas diffusion. when connection gases are identified. Trip gas will be detected in the mud on circulating bottoms up after a round trip. (d) Gas due to Inadequate Mud Density Surface indications of an underbalanced formation depend on the degree of underbalance. it is inevitable that a certain quantity of the gas contained in the cuttings will enter the mud. This is due to pump shut down and the swabbing action of the pipe. • Due to the pore pressure in a formation being greater than the hydrostatic pressure of the mud column. Consequently. will expand as it is circulated up the hole. The penetration of a permeable formation that is significantly underbalanced will cause an immediate pit gain. Any gas that enters the mud. Significant trip gas may indicate that a close to balance situation exists in the hole. However. • As a result of a temporary reduction in hydrostatic pressure caused by swabbing as pipe is moved in the hole.BP WELL CONTROL MANUAL Gas can enter the mud for one or more of the following reasons: • As a result of drilling a formation that contains gas even with a suitable overbalance. In all cases. consideration should be given to weighting up the mud before drilling ahead and particularly prior to a trip. drilled gas will only be evident during the time taken to circulate out the cuttings from the porous formation. as well as the formation permeability. 3-5 March 1995 . causing gas cutting at the flowline. Connection gases are caused by the temporary reduction in effective total pressure of the mud column during a connection. as the hole is circulated bottoms up after a connection. unless in solution with oil base mud and above the bubble point. Raising the mud weight will not prevent it. a change that is likely to be registered as an increase in hookload.BP WELL CONTROL MANUAL A permeable formation that is only slightly underbalanced may only cause a small flow into the well. Displacement of the drilling fluid by the influx will reduce the buoyancy of the bottomhole assembly. An increase in hookload may only be noticed after a considerable volume of influx has occurred. especially so if the influx is gas. This indication is caused as a result of the U-tube effect. However. It is not therefore a reliable method of detecting a kick at an early stage. Influx fluids will generally be lighter than the drilling fluid. even if the underbalance is relatively high. an increase in hookload may be noticed at surface. This will increase the effective weight of the drillstring. A washout in the drillstring will cause the same decrease in pump pressure and increase in pump speed. the Driller should first assume that a kick may have occurred and flowcheck the well. 3-6 March 1995 . However. This is a relatively difficult situation to detect and is also potentially dangerous. drilling such a formation may show only gas cut mud. caused by light fluids flowing into the annulus. it is only likely to become noticeable as the influx is circulated up the hole. Therefore. 8 Change in Pump Speed or Pressure Pump pressure may decrease with a corresponding increase in pump speed if an influx occurs during drilling. there may be little or no actual flow of gas into the wellbore. In the case a tight formation is underbalanced. accompanied by a small pit gain. The first evidence of this at surface is likely to be gas cut mud. 7 Increase in Hookload If an influx occurs while drilling. The initial pit gain may be so small that it is only detected as it expands as it is circulated up the hole. if these signs are noticed. 1 SHALLOW GAS PROCEDURE 4-1 4.3 DURING SHUT-IN PERIOD 4-15 March 1995 .BP WELL CONTROL MANUAL 4 ACTION ON DETECTING AN INFLUX Section Page 4.2 SHUT-IN PROCEDURES 4-9 4. 1 SHALLOW GAS PROCEDURE Paragraph Page 1 General 4-2 2 Gas encountered whilst drilling without a riser from a Floating Rig 4-3 Gas encountered whilst drilling for surface casing from a Floating Rig with a riser 4-4 Gas encountered whilst drilling for surface casing from a Bottom Supported Rig 4-6 Onshore Shallow Gas 4-7 3 4 5 4-1 March 1995 .BP WELL CONTROL MANUAL 4. It should be noted that the absence of bright spots does not rule out the possibility of the existence of shallow gas. Consequently it is strongly recommended to take the following general precautions to minimise the possibility of inducing a shallow gas flow: • Drill pilot hole • Drill riserless • Restrict ROPs • Accurately monitor the hole Shallow gas flows are often extremely prolific. the Company Representative must immediately liaise with the Senior Contractor Representative to make preparations to evacuate initially non-essential personnel from the rig. Overpressure at this depth is generally caused by inclination of the lens which has the effect of increasing the height of the lens and hence the pore pressure gradient at the top of the lens. In some areas. The new drilling location should. However . if possible. In the event of a shallow gas flow. • Improper hole fill while tripping. permeable and relatively unconsolidated. shallow gas has been associated with buried reefs or vuggy limestone which can be extremely porous and almost infinitely permeable. When encountered at shallow depths. overpressured lenses have been encountered. be located on a shallow seismic shot point. producing very high flow rates of gas and considerable quantities of rock from the formation. particularly so when a long section of sand has been exposed.BP WELL CONTROL MANUAL 1 General Offshore shallow gas accumulations are normally associated with recently laid down sand lenses that are totally enveloped by mudstones. the absence of shallow gas in one well of a series drilled from a surface location does not guarantee the absence of shallow gas in subsequent directional wells drilled from the same surface location. flat and normally pressured. Shallow gas kicks are generally caused by loss of hydrostatic head due to one or a combination of the following: • Overloading the annulus with cuttings and hence causing losses. which may indicate the presence of shallow gas. The eventuality of having to completely evacuate the rig must also be addressed (the contractor’s emergency evacuation procedures will be implemented). Further to this. • Drilled gas expanding and unloading the annulus. If a bright spot is present at the proposed drilling location it is good practice to move the rig to avoid the hazard. 4-2 March 1995 .lenses tend to be highly porous. They arecommonly thin. A well should not be drilled through a shallow seismic anomally (bright spot). • The procedure for winching the rig off location. • A float valve should always be run in the drillstring. A gas blowout in open water produces a 10 degree cone of low density water and a discharge of highly flammable gas. the following precautions or considerations should be addressed before and whilst the surface hole is open: • The rig should be moored with length of moorings remaining in the locker to allow the rig to be winched 400 ft away from the plume. This is critical for a drillship. the danger of penetrating an overpressured reservoir.BP WELL CONTROL MANUAL 2 Gas encountered whilst drilling without a riser from a Floating Rig Company policy states that surface hole will be drilled riserless unless the particular conditions as outlined in Drilling Policy and Guidelines Manual are applicable. the gas cloud would disperse slowly and would constitute a fire hazard if the gas became entrapped in a confined area. limiting the ROP and circulate at a high rate to distribute the cuttings and drilled gas. Within a plume of expanding gas.15/SG. The intensity of the blowout depends to a large extent on the water depth and current. and whilst there is unlikely to be an immediate danger to crew or vessel. might cause a drillship to keel towards the plume. Before spudding. A contingency plan must be developed. • Drill pilot hole. whilst the effect of a current would be to displace the plume away from the rig. and if constrained by its moorings. • Facilities and personnel should be continuously available at short notice to slack off the moorings closest to the plume and heave in those up current (but not down wind). however. The plume is likely to become more dispersed with greater water depth. (Typically at 1. in conjunction with the Drilling Contractor to cover the following situations: • The procedures to be adopted in the event of a shallow gas flow. a contingency plan should be prepared detailing individual responsibilities and duties.) 4-3 March 1995 . The contingency plan must be discussed in detail at the pre-spud meeting. prior to spud. thereby reducing its freeboard further. Drilling riserless ensures that the major cause of blowouts from shallow. this diminishes rapidly with water depth such that the effect on a semi-submersible at operating draft would be negligible. normally pressured gas reservoirs – namely. The severity of the hazard can only be assessed at the time. the loss of hydrostatic head – is eliminated. If practical. a floating vessel will suffer some loss of buoyancy. The eruption of the gas would tend to displace a vessel. • Sufficient mud should be kept on site to fill the hole volume twice. There remains however. Under calm conditions. the windlasses should be held on their brakes and the chain stoppers only applied after surface casing is set. • All hatches should be secured to prevent invasion of voids by inflammable gas or downflooding if the freeboard is reduced by loss of buoyancy or heel. Winch the rig to a safe position outside the gas plume. The surface diverter system ensures that there is a back-up system available in the event of a failure of the subsea system. up current but not down wind. Drop the drillstring or shear the pipe (See Section 6. the conductor is usually set in a formation that is too weak to contain the pressure of a gas kick. Immediate preparations should then be made to unlatch the pin connector or LMRP and winch off location. in conjunction with the Drilling Contractor to cover the following situations: • The procedures to be adopted in the event of a shallow gas flow.2). 4-4 March 1995 . using the subsea dump valves at the mudline and annular preventer. It is Company policy that where the situation demands that a riser is to be used when drilling for the surface casing. 3 Gas encountered whilst drilling for surface casing from a Floating Rig with a riser In relatively shallow offshore environments. As a result. A contingency plan must be developed. If the gas flow is endangering personnel or the rig: 2. If a shallow gas flow is detected: If there is no immediate danger to personnel or the rig: 1. Attempt to control the well by pumping mud/seawater at a maximum rate. the well should be diverted in order to avoid an underground blowout and the possibility of the gas broaching around the conductor shoe. 3. Industry experience has shown that current diverter systems cannot be relied upon to safely control shallow gas blowouts. • The procedure to be adopted in the event of failure of any of the major components of the BOP/riser/diverter system. shallow gas flows should be controlled at the seabed. an annular preventer and subsea dump valves are installed at the mudline. If a kick is detected in such circumstances. It can also be used to divert gas which may be in the riser above the stack. The contingency plan must be discussed in detail at the pre-spud meeting. in addition to the normal diverter system at surface. prior to spud. • The procedure for winching the rig off location.BP WELL CONTROL MANUAL • Weather conditions and current should be continuously monitored and the sea surface should be checked for evidence of gas. Before spudding. Close the annular preventer and allow the gas to vent at the seabed. If there is no immediate danger to personnel or the rig: 3. Unlatch the LMRP or pin connector and winch the rig to a safe position outside the gas plume. • A float valve should always be run in the drillstring. In the event of failure of the subsea diverter system there remains the option to divert at surface or to unlatch the LMRP or pin connector. limiting the ROP and circulating at a high rate to distribute the cuttings and drilled gas. the windlasses should be held on their brakes and the chain stoppers only applied after surface casing is set. • All hatches should be secured to prevent invasion of voids by inflammable gas or downflooding if the freeboard is reduced by loss of buoyancy or heel. 5. (Typically 1. the following procedure can be used as a guideline: 1. thereby venting the gas at the wellhead. This is critical for a drillship. Consider dropping the drillstring or shearing prior to (5) (See Section 6. however if it becomes absolutely necessary to divert at surface.2). proceed as follows: 1. • Facilities and personnel should be continuously available at short notice to slack off the moorings closest to the plume and heave in those up current (but not down wind).15/SG. If the gas flow is endangering personnel or the rig: 4. Open the subsea dump valves. in line with those listed in Paragraph 2. a contingency plan should be prepared detailing individual responsibilities and duties. • Care should be taken to monitor the hole and ensure that it remains full whilst tripping. causing losses or cuttings liberated gas. 2. Space out so that the lower kelly cock is just above the rotary table. Maintain maximum pump rate.BP WELL CONTROL MANUAL The following precautions. This is achieved by drilling a pilot hole. Attempt to control the well by pumping sea water/mud at a maximum rate. Diverting at surface is not recommended.) Should the well start to flow. 2. • Facilities should be continuously available to fill the annulus rapidly from surface in the event of sudden losses. 4-5 March 1995 . should be taken routinely whilst the surface hole is open: • The rig should be moored with length of moorings remaining in the locker to allow the rig to be winched 400 ft away from the plume. and hence the possibility of unloading the annulus. close the shaker valve and diverter element thereby diverting returns overboard. • Sufficient mud should be kept onsite to fill the hole volume twice. • Care should be taken to ensure that the annulus does not become overloaded with cuttings. 3. If practical. Open the diverter lines. 4 Gas encountered whilst drilling for surface casing from a Bottom Supported Rig Shallow gas reservoirs are potentially much more hazardous when penetrated from a jack-up or platform. In the event of a shallow gas flow. This is achieved by drilling pilot hole. thus causing losses or gas to be liberated from the cuttings to such an extent that the annulus unloads. • Facilities should be continuously available to rapidly fill the annulus from surface in the event of sudden losses. • Sufficient mud should be kept onsite to fill the hole volume twice. Consider dropping the drillstring or shearing the pipe prior to (7) (See Section 4. Because the conductor extends almost to the rig floor. should be available for immediate activation. Shut down all non-essential equipment and machinery to minimise potential sources of ignition. Deploy fire hoses beneath the rig floor . • Facilities should be available and care taken to monitor the hole and ensure that it remains full whilst tripping. 4-6 March 1995 .BP WELL CONTROL MANUAL 4. a hazardous situation is created if a restriction forms in the diverter line.3). the products of a kick are discharged directly into a hazardous zone. 5. limiting the ROP. thus inducing a sudden reduction in spudcan resistance. the diverter will immediately be closed in order to direct the flow overboard. • A means of diverting the flow away from hazardous zones. and circulating at a high rate to distribute the cuttings and drilled gas. Prepare to unlatch the pin connector or LMRP and winch to a safe position. The following precautions should be taken routinely whilst the surface hole is open: • Care should be taken to ensure the annulus does not become overloaded with cuttings. On a bottom supported rig. If the situation is deteriorating and loss of control is imminent: 6. In this event there is a real risk that the seabed becomes fluidized. The reliability of the diverter system while subject to the stress of a shallow gas flow is uncertain and so the possibility of equipment failure at this stage must be considered. Release the pin connector or LMRP and winch the rig to a safe position outside the gas plume. The subsequent pressure build up may cause gas to broach around the casing to the seabed. 7. without restricting flow or imposing backpressure on the well. • A float valve should always be run in the drillstring. the shallow zone having been charged by a faulty cement job in a previously drilled well. Maintain maximum pump rate. a means of diverting the flow away from the rig should be provided. Monitor the sea for evidence of gas breaking through outside the conductor. if water supply is known to be limited. Most flows from shallow onshore reservoirs are associated with aquifers that outcrop at higher elevations (or indeed lower elevations if air or foam drilling fluid is in use). The conductor and surface casing strings are normally set in competent formation which can permit secondary well control by normal means. Geological control is usually sufficient to predict formations accurately and. 4. Shallow onshore reservoirs are generally older. the following procedure may be used as a guideline: 1. specific contingency plans should be made to counter potential problems. Provision should also be made to ensure an adequate supply of water is available to pump to the hole at a high rate without taking returns. Onshore. close shaker valve and diverter element thereby diverting returns overboard. Shut down all non-essential equipment and machinery to minimise potential sources of ignition.BP WELL CONTROL MANUAL Should the well start to flow. when necessary. 6. 3. However. 2. Diverter procedures for an onshore well will be similar to those for a bottom supported offshore rig. (Evacuate all personnel if any evidence is detected. However. 4-7/8 4-7 March 1995 . if it is not possible to positively exclude the possibility of either a shallow gas accumulation or a weak casing shoe. but shallow gas is a rare occurrence onshore. a baryte plug may be the only practical method of halting a shallow gas flow.) 5 Onshore Shallow Gas The shallow geology of onshore locations varies widely. Deploy fire hoses beneath the rig floor. A water flow of this type is usually predictable and of limited consequence. Severe shallow flows have been encountered in the past as a result of a shallow zone becoming charged by a lower high pressure zone. most wells are spudded through a thin layer of weathered formation into a bed rock. which will tend to restrict the flow potential of a shallow kick onshore. Space out such that the lower kelly cock is just above the rotary table. Ensure that diverter lines are open. 5. more consolidated and less permeable than those offshore. Evacuate all non-essential personnel. BP WELL CONTROL MANUAL 4.3 Kick while Tripping. Fast Shut-in 4-13 4. Fast Shut-in 4-14 4-9 March 1995 . Fixed Rig.2 Kick while Drilling. Fast Shut-in 4-12 4.1 Kick while Drilling.2 SHUT-IN PROCEDURES Paragraph Page 1 General 4-10 2 Fast Shut-in 4-10 3 Shut-in Procedure 4-11 Illustrations 4. Floating Rig. the pumps stopped and the BOP closed immediately. In general. the Subsea Engineer. such as either a pit gain or an increase in returns flowrate is detected.3 should be used to make absolutely clear the shut-in procedures that will be used on each rig. In this respect. There are various methods of shutting in a well that is flowing. however copies should be distributed to other relevant personnel including the Toolpusher and.BP WELL CONTROL MANUAL 1 General It is Company policy that a well kick will be shut in and controlled at the BOP stack on hole sections below the surface casing. The smaller the volume of influx. the best method is that which ensures that the well is safely shut in and the influx volume is minimised. (Outer failsafe on a floating rig and HCR valve on a fixed rig.1 to 4. The speed with which the Drillcrew carry out these procedures is a critical factor. Speed and proficiency are achieved by regular drills.) In the event that a kick is detected. the lower will be the pressures in the wellbore and at surface throughout the kick control process. In order to implement the fast shut-in. this procedure should be written on a large notice board that will be positioned prominently on the rig floor. These forms are intended primarily for the Driller. where appropriate. (Ensure that the choke pressure can be monitored in this position. The procedures to be adopted in the event of a kick while drilling ahead from the surface casing shoe are drawn up at the discretion of the Company Representative and the Company Drilling Superintendent. In such circumstances. 2 Fast Shut-in Drilling management have issued the following guideline: The fast shut-in is the preferred method of shutting in a well. no time should be spent flowchecking the well. the choke line valve(s) are opened and the BOP closed.) • One remote operated chokeline valve closed. It is a further responsibility of the Company Representative that he ensures these drills are carried out at suitable intervals to ensure the drillcrews are proficient at implementing the shut-in procedures. 4-10 March 1995 . It is the responsibility of the Company Representative to ensure that the Contractor is made aware of the procedures that should be initiated in the event of a well kick. When a standard shut-in procedure is finalised. or suspected. the kelly (or topdrive) should be picked up. The forms illustrated in Figures 4. the equipment should be set up as follows: • The remote operated choke closed and isolated by a high pressure valve immediately upstream. if a primary indicator of a kick. the annular BOP will be used to initially shut-in the well. Fast Shut-in. mistakes are unlikely and the time taken to close in the well will be minimised.3: Kick while Tripping. On a fixed rig. if the position of the tooljoint in relation to the pipe ram is known with confidence. At all times. The advantage of this method is quite clear. the pipe rams may be used to initially shut-in the well. Fixed Rig.1: Kick while Drilling.BP WELL CONTROL MANUAL On a floating rig. Floating Rig. The following forms are examples of the information that should be provided to the Driller: Figure 4. Fast Shut-in. in order to speed up the procedure. 3 Shut-in Procedure It is the responsibility of the Company Representative and the Company Drilling Superintendent to define the shut-in procedure that will be implemented in the event of akick. namely that the operation is relatively simple in comparison with the soft shut-in. Fast Shut-in. 4-11 March 1995 .2: Kick while Drilling. Figure 4. be aware that the pressure rating of the standpipe equipment is generally less than that of the BOP stack and the choke manifold. Consequently. Figure 4. Fast Shut-in STANDING ORDERS TO DRILLER WELL NO 24 RIG ORDERS EFFECTIVE DATE RIG 20 THROUGH 121/4in HOLE SECTION 10/3/87 COMPANY REP S. CLOSE RAMLOCKS …………………………………………………………… 10.D. CHECK SPACEOUT …………………………………………………………… 6. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… WEOX02. PICK UP UNTIL ………………………… IS ………………………… ABOVE ROTARY UPPER PIPE (Space out to ensure that a tool joint is clear of ………………………… rams) 2. 8. OPEN UPPER CHOKE LINE …………………………………………………………… FAILSAFE (S) …………………………………………………………… 2.015 4-12 March 1995 .) YES IS THE WELL FLOWING? NO 1. PROCEED AS DIRECTED 2. SUDDEN CHANGE IN PROPERTIES OF RETURNED MUD 6. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 5. …………………………………………………………………………… 7.B. …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… Or if there is any other possible indication of a kick. 9. DRILLING BREAK *2. FLOWCHECK THE WELL IF NECESSARY (Do not flowcheck if 2* or 3* as above have been detected. CHECK WELL IS SHUT IN …………………………………………………………… 4. SHUT DOWN THE PUMPS 3. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1.1 Kick while Drilling.BP WELL CONTROL MANUAL Figure 4. Floating Rig. CLOSE UPPER PIPE RAMS …………………………………………………………… 7. CHANGE IN PUMP SPEED OR PRESSURE 5. 10.M. CLOSE UPPER ANNULAR …………………………………………………………… 3. INCREASED RETURNS FLOWRATE *3. TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: 1. LOWER KELLY COCK 2.5m 1. K. PIT GAIN 4. ADJUST ANNULAR CLOSING …………………………………………………………… PRESSURE …………………………………………………………… 8. HANG OFF ON UPPER PIPE RAMS …………………………………………………………… 9. Fast Shut-in STANDING ORDERS TO DRILLER WELL NO 28 RIG ORDERS EFFECTIVE DATE RIG 15 FOR WELL No 28 15/9/87 COMPANY REP J. *2. RECORD DP AND CSG PRESSURE …………………………………………………………… 5. CLOSE ANNULAR PREVENTER …………………………………………………………… 2. Fixed Rig.BP WELL CONTROL MANUAL Figure 4. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 6. PICK UP UNTIL ………………………… IS ………………………… ABOVE ROTARY 5in PIPE (Space out to ensure that a tool joint is clear of ………………………… rams) 2. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1. PROCEED AS DIRECTED 3. 9.016 4-13 March 1995 . DRILLING BREAK INCREASED RETURNS FLOWRATE PIT GAIN CHANGE IN PUMP SPEED OR PRESSURE SUDDEN CHANGE IN PROPERTIES OF RETURNED MUD …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… …………………………………………………………………………… Or if there is any other possible indication of a kick.H. 10. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… …………………………………………………………… WEOX02. J. 8.P. 7. SHUT DOWN THE PUMPS 3. FLOWCHECK THE WELL IF NECESSARY (Do not flowcheck if 2* or 3* as above have been detected.) YES IS THE WELL FLOWING? NO 1. *3. 5.2 Kick while Drilling. 6. 4. LOWER KELLY COCK 2m 1. OPEN CHOKE LINE VALVE (S) …………………………………………………………… 2. TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: 1. CHECK THAT WELL IS SHUT IN …………………………………………………………… 4.B. J. ROTATE THE PIPE …………………………………………………………… 13. SET THE SLIPS …………………………………………………………… 2.H. PROCEED AS DIRECTED 3. OPEN CHOKE LINE VALVE (S) …………………………………………………………… 5. 3.BP WELL CONTROL MANUAL Figure 4. …………………………………………………………………………… 8. LINE UP STANDPIPE MANIFOLD …………………………………………………………… 10. …………………………………………………………………………… 7. INSTALL OPEN DP SAFETY VALVE …………………………………………………………… 2. STOP TRIPPING OPERATIONS 2. NOTIFY COMPANY REPRESENTATIVE AND TOOLPUSHER 1. CHECK THAT WELL IS SHUT IN …………………………………………………………… 7. CLOSE DP SAFETY VALVE …………………………………………………………… 4. CLOSE ANNULAR PREVENTER …………………………………………………………… 6. OPEN DP SAFETY VALVE …………………………………………………………… 11. H. NOTIFY COMPANY REPRESENTATIVE …………………………………………………………… 8. …………………………………………………………………………… 6. …………………………………………………………………………… Or if there is any other possible indication of a kick. 1. Fast Shut-in STANDING ORDERS TO DRILLER WHILE TRIPPING WELL NO 28 ORDERS EFFECTIVE DATE RIG RIG 10 ON ALL TRIPS 23/7/87 COMPANY REP A. RECORD DP AND CSG PRESSURE …………………………………………………………… 12. 4.3 Kick while Tripping. 1. INSTALL KELLY …………………………………………………………… 9. IF IN OPENHOLE: ENGAGE …………………………………………………………… BUSHINGS. 2. FLOWCHECK THE WELL IF NECESSARY YES IS THE WELL FLOWING? NO 1.017 4-14 March 1995 .N. PROCEED AS DIRECTED …………………………………………………………… …………………………………………………………… WEOX02. TOOLPUSHER IF ANY OF THE FOLLOWING OCCUR: HOLE NOT TAKING CORRECT VOLUME DURING THE TRIP THE WELL IS FLOWING …………………………………………………………………………… …………………………………………………………………………… 5. 6 An Example Calculation – showing how to evaluate the type of influx fluid 4-22 An Example of the possible increase in wellbore pressure due to influx migration 4-23 4.7 4-15 March 1995 .3 DURING SHUT-IN PERIOD Paragraph Page 1 General 4-16 2 Record Pressure Data 4-16 3 Record drillpipe pressure with a Float Valve in the string 4-17 4 Trapped Pressure 4-19 5 Identify the Influx Type 4-20 6 Influx Migration 4-21 7 Control Influx Migration 4-24 Illustrations 4.4 Shut-in Pressure Build-up Curve – showing the effect of influx migration 4-17 4.5 Well Control Operations Log 4-18 4.BP WELL CONTROL MANUAL 4. the rate of build-up is relatively fast until the well begins to stabilise. 4-16 March 1995 . when a kick is taken. of the following: • The influx originated from a low permeability zone. pressure in the wellbore will stabilise quickly after the well is shut in. In general. • The influx created instability in the wellbore. • The surface lines or subsea choke line is partially packed off. Once the pressures have begun to stabilise. The kick zone EMW is determined from the drillpipe pressure during the stabilised period. It is important to record the data frequently in order that any change in the rate of build-up be clearly identified. a person must be assigned to record the drillpipe and casing pressures. or all. However. the flow will continue until shut-in pressures have built up to balance the static reservoir pressure. This section covers the procedures that may be required during the time the well is shut in prior to circulation. this will mean that the flow will stop almost immediately the BOPs are closed and that the shut-in pressure will stabilise within a few minutes. there have been many cases of surface pressures taking several hours to stabilise. It can therefore be used to determine the kick zone pressure. In most cases. There are no hard and fast rules that apply to determine the correct value for the relevant drillpipe pressure reading. In most cases. The reasons for this can be one. the inflow into the wellbore occurs for only a short time and the drawdown is relatively small. frequent and accurate pressure readings will aid the interpretation of build-up data. The drillpipe pressure reflects the difference between the kick zone pressure and the effective hydrostatic pressure of the mud column in the drillpipe. only if the well has been flowing for some time will the kick zone pressure take time to build up to a maximum after the well has been shut in. assuming that the influx has not entered the drillpipe. As a result. The pressures should be recorded initially at 1 minute intervals until the pressures have stabilised. leading to the hole sloughing and packingof f.4 shows a pressure build-up curve which shows signs of influx migration. • The influx is migrating up the hole. Usually. Figure 4. 2 Record Pressure Data As soon as the well is shut in. any further significant increase in surface pressures can be indicative of influx migration. it is often difficult to determine the drillpipe pressure that truly reflects the actual bottomhole pressure. When the surface pressures take a considerable time to stabilise. however.BP WELL CONTROL MANUAL 1 General When a flowing well is shut in by closing the BOPs. 4 Shut-in Pressure Build-up Curve – showing the effect of influx migration Figure 4.5 shows a form that can be used to record the build-up of drillpipe and casing pressure. In order to open this valve and allow the pressure to be transmitted to the surface. Line up the pump to the drillpipe. 4-17 March 1995 .018 Figure 4.BP WELL CONTROL MANUAL INITIAL PRESSURE BUILDUP STABILISED PERIOD INFLUX MIGRATION OCCURRING SURFACE PRESSURE (psi) ANNULUS PRESSURE DRILLPIPE PRESSURE TIME ELAPSED AFTER SHUT-IN WEOX02. the following procedure can be implemented: 1. 3 Record drillpipe pressure with a Float Valve in the string If a non-ported float valve is in the string and a kick is taken. This form should also be used to keep a complete record of events during the well control operation. the valve will close against the differential pressure and no pressure will be recorded at the standpipe. 15 03.03 03.13 03.00 04.06 03.00 03.09 03.02 03.BP WELL CONTROL MANUAL Figure 4.15 300 360 420 460 520 590 630 700 720 740 760 770 775 775 780 780 780 780 780 780 780 780 780 782 782 782 782 450 500 560 600 660 730 770 840 860 880 900 910 920 920 925 925 925 925 925 925 925 925 925 925 925 925 925 120 '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' '' 05.08 03.10 782 1085 1010 880 755 630 450 925 925 910 903 930 945 950 '' 120 SHEET NO 1 3/7/87 03.5 Well Control Operations Log WELL CONTROL OPERATIONS LOG WELL NO 28 FIRST READING AT TIME (hr min) RIG / RIG 9 DRILLPIPE CHOKE PIT LEVEL/ PRESSURE PRESSURE VOLUME (psi) (psi) (bbl ) 03.30 05.00 06.16 03.25 03.20 05.11 03.019 4-18 March 1995 .17 03.05 03.04 03.45 04.10 05.20 03.30 03.24 05.30 05.12 03.40 05.00 1 MINUTE UNTIL PRESSURES STABILISE DATE AND TIME INTERVAL BETWEEN READINGS REMARKS WELL SHUT IN – 10bbl GAIN INFORM COMPANY REP – PRESSURES STABILISED START MIXING KILL WEIGHT MUD @ 1.01 03.00 05.75 SG 100bbl 1.14 03.75 SG MUD MIXED IN TANK No 1 VERIFY EQUIPMENT CORRECTLY LINED UP – CO REP AND TOOLPUSHER TO RIG FLOOR START CIRCULATION – BRING PUMP UP TO 25 SPM PUMP UP TO SPEED – RETURNS THROUGH DEGASSER KILL WEIGHT MUD TO BIT WEOX02.07 03.10 03.50 06. There are three possible causes of this phenomenon: • The pumps were left running after the well was shut-in. immediately stop the pump. The casing pressure is also likely to show an indication of the valve opening. can be trapped in the well. • Pipe has been stripped into the well without bleeding the correct volume of mud. 4. Isolate the pump at the standpipe. Pressure may be trapped in the well if the surface pressure appears constant and no pressure build has been seen. Stop the pump when this change is noticed. As an example. Trapped pressure of this kind will result in surface pressures that do not reflect the actual kick zone pressure. Isolate the pump. will result in overkilling the well. An artificially high drillpipe pressure reading. 5. • The influx is migrating up the hole. Carefully monitoring both the pump and casing pressure. Bleed off the excess pressure from the casing. used to determine the kill mud weight. If the casing pressure rises at any stage. Record the increase in pump pressure and the volume of mud pumped. As outlined. in excess of that caused by the kick zone. 6. if the casing pressure rose 50 psi and this extra pressure was considered undesirable. bleed 50psi from the casing and record the shut-in drillpipe pressure as 50 psi less than the final pump pressure. this procedure involves pumping into a closed well. the pump pressure will increase slower than before. As the valve opens. The relationship between the pump pressure and the volume of mud pumped will be linear as the mud in the drillpipe is compressed.BP WELL CONTROL MANUAL 2. 4-19 March 1995 . However if the surface pressure built up at any point after the well wasshut-in. the valve will open. 4 Trapped Pressure In some circumstances it is possible that pressure. this change should be easily recognisable at slow pump rates. The utmost care must be taken in carrying out this procedure. Record the shut-in drillpipe pressure as the pump pressure recorded immediately before the float valve opened. this is confirmation that there is no trapped pressure in the well. 3. The drillpipe pressure is used to determine the kick zone pressure and hence the mud weight used to kill the well. pump to the hole at a controlled rate (very slow). and so any excessive additional pressurisation caused by pumping into the well may overpressure the openhole section. The well is pressurised at the start of the operation. If pumping is continued after the pressure equalises across the float valve. 2. An increase in casing pressure is a sure sign that additional influx has entered the well. It should be stressed that bleeding mud from a well that has kicked is an operation that must be carefully implemented. if there is no trapped pressure in the well. Allow pressure to stabilise. bleed a small volume of mud from the annulus to a suitable measuring tank.) 3. Be aware that. When the drillpipe pressure no longer decreases as mud is bled from the well. giving the false impression at surface that the bottomhole pressure is still greater than the actual kick zone pressure. record the drillpipe pressure as the shut-in drillpipe pressure. A possible consequence is that the operator may inadvertantly reduce the bottomhole pressure significantly below the kick zone pressure and cause a further influx into the wellbore. if this occurs. if no reduction in drillpipe pressure is detected after bleeding 2 – 3/bbl from the well. Therefore. This procedure is not recommended if the kick zone is suspected to have low permeability. it is potentially hazardous to increase the size of the influx. 5 Identify the Influx Type The shut-in pressures recorded on the drillpipe and the casing after a kick is taken are generally not equal. no more mud should be bled from the well. 4-20 March 1995 . If the drillpipe pressure does not drop after bleeding mud from the annulus. which is clearly a possibility if this procedure is not properly carried out. Using a manual choke. it may be prudent to use the Driller’s Method to circulate out the kick. The drillpipe pressure will continue to decrease. 4. It is unlikely that any kick fluid willenter the drillpipe. A firm recommendation is that the volumes bled from the well at this stage are kept to a minimum.BP WELL CONTROL MANUAL The following procedure can be used to check for trapped pressure: 1. continue to bleed mud from the well in 1/2 bbl increments. the drillpipe pressure and casing pressure will have fallen. If there is some doubt as to the true shut-in drillpipe pressure. Stop bleeding mud from the well. no pressure is trapped in the well. This is because the effective hydrostatic pressure of the fluid in the annulus will be reduced below that in the drillpipe. Whilst it is undesirable to overkill the well. unless influx migration is obviously occurring. because this is effectively a closed system if the kick was taken while drilling. each increment of mud bled from the well will cause a further influx into the well. even after bleeding mud from the annulus. rather than continue bleeding mud. If both the drillpipe pressure and casing pressure have decreased. no more mud should be bled off. 5. Therefore. Shut in the well. Ensure that accurate pressure gauges are fitted to the drillpipe and annulus. (1/2 barrel is a suitable amount. Bleeding even very small quantities of mud from the annulus may reduce the pressure of a tight kick zone below its final shut-in pressure. If pressure has been trapped in the well. Carefully monitor the drillpipe and casing pressure. Firstly.) 6 Influx Migration After a kick is taken. it is assumed that the influx is a discrete bubble. the pit gain during displacement. the hole may be out of gauge. It is important. together with the annular geometry and the surface pressures. The proportion of gas in the influx determines two important factors. the calculated influx gradient provides a guide to the proportion of gas in the fluid. and provision should be made for a pit gain during this period.4 > 0. With this information.2 0. condensate fluids may be formed as the gas is displaced from the hole. there is usually a tendency for the influx to migrate up the hole. using the following as aguide: Influx fluid Calculated Influx gradient (psi/ft) Gas Oil Water 0.3 – 0. This calculation is only an approximation. Thistendency is caused by the dif ference in density between the influx fluid and the mud. an estimation should be made of the maximum pressures that will be encountered during circulation. contain some gas. it is possible to estimate theinflux density . Influx migration up a closed-in well can cause excessive pressures within the wellbore if suitable control procedures are not implemented. This will not occur for a dry gas that does not contain a sufficient proportion of heavy molecules. for the following reasons.4 Figure 4. It is recommended that all kicks are assumed to contain a certain proportion of gas. whereas it is more likely to be eccentric to the hole and contaminated with mud.05 – 0.6 shows an example of how to determine the influx type. Volume 2 for hand calculation techniques. firstly.BP WELL CONTROL MANUAL The pit gain at surface provides a guide to the volume of the kick. Secondly.7 shows an example of the potential increase in bottomhole pressure caused by gas migration. Figure 4. For light oils. the effective mud weight in the annulus is not likely to be the same as in the drillpipe. a significant quantity of gas will be produced. and secondly. Prior to circulation therefore. including formation water. 4-21 March 1995 . that this calculation is carried out for the additional reason that it provides a check of the validity of the kick data. due to cuttings loading the annulus. contamination of the mud with formation fluid. Thirdly. It is useful to know the type of influx before circulation is initiated. The type of influx fluid can then be evaluated. however. Gas will come out of solution from an oil influx when the influx pressure reduces below the bubble point pressure during displacement. and possibly. (See Chapter 5. If the gas contains sufficient heavy hydrocarbon molecules at reservoir conditions. Although most formation fluids. the well bore pressures during displacement. 6 An Example Calculation – showing how to evaluate the type of influx fluid HOLE DRILLSTRING DIMENSIONS 855 PRESSURE BALANCE 2.16psi/ft – WEOX02. hydrostatic pressure of the influx = 10.163 .2808) = 0.163psi 2.7SG MUD + + MUD MUD HYDROSTATIC PRESSURE OF MUD IN THE DRILLPIPE 81/2in HOLE HYDROSTATIC PRESSURE OF MUD IN ANNULUS + 61/4in COLLARS = 20bbl INFLUX INFLUX HEIGHT OF BHA = 195m 4000m INFLUX HYDROSTATIC PRESSURE = BOTTOMHOLE PRESSURE BOTTOMHOLE PRESSURE Identify the influx fluid as follows: 1.378 SG – 0.421 = 1. Determine the bottomhole pressure 500 ANNULUS DRILLPIPE SURFACE PRESSURE SURFACE PRESSURE 1.1058bblm Height of influx = 20/0. The following formula can also be used routinely to calculate the influx density Density of the influx (SG) = MW – Pa – Pdp h x 1.7 x 1.16psi/ft Therefore the influx is mainly gas 4.020 4-22 March 1995 .7 – 855 – 500 189 x 1. Determine the bottomhole pressure Bottomhole pressure = = = = Drillpipe pressure + mud hydrostatic pressure 500 + (1.1058 = 189m 3. From pressure balance Annulus surface pressure + Hydrostatic pressure of the mud + Hydrostatic pressure of the influx = Bottomhole pressure 855 + 1.421 x 4000) 500 + 9663 10.9206 = 102psi Influx gradient = Pi/height of the influx = 102/(189 x 3.855 . Determine the hydrostatic pressure of the influx 1.421 x (4000 – 189) + Pi = 10.163psi Pi.BP WELL CONTROL MANUAL Figure 4.7 x 1.421 = 0. Calculate the height of the influx in the annulus Influx volume = Recorded pit gain = 20bbl Annular capacity at collars = 0. 45 9160psi 2.15 (12140psi) (2. migration may be completely prevented. Migration will be slowed if the viscosity of the mud is increased as a result of contamination with the influx fluid. The buoyancy force causes the influx to migrate. • The difference in density between the mud and the influx.85) WEOX02. Experiment has shown that a gas bubble will migrate up one side of the annulus as mud falls down the opposite side.7 An Example of the possible increase in wellbore pressure due to influx migration Influx migration does not always occur. • Any interaction between the mud and the influx fluid. In severe cases. the rate at which the influx rises up the hole is dependent on several variables. the more difficult it is for the mud to fall down the annulus to allow the influx to migrate. Bearing this process in mind.BP WELL CONTROL MANUAL SURFACE PRESSURE 250psi 3195psi 6180psi 0 GAS @ 6180psi 1.021 Figure 4. it is clear that the factors that predominantly affect the rate of rise of the influx will be the following: • The viscosity of the drilling fluid.4SG MUD 1500m GAS @ 6180psi 2975m GAS @ 6180psi 3000m BOTTOMHOLE PRESSURE BOTTOMHOLE EMW (SG) 6180psi 1. but when it does. The more viscous the mud. 4-23 March 1995 . it is necessary to control the well using the Volumetric Method. or there is a washout in the drillstring. then a volume of mud corresponding to a hydrostatic pressure in the annulus (at the top of the influx) of 100 psi must be bled from the well at constant choke pressure. it is not possible to monitor bottomhole pressure with the drillpipe pressure gauge. the bottomhole pressure can be monitored with the drillpipe pressure gauge. In this case. This is accomplished by bleeding suitable volumes of mud from the annulus to allow for expansion of the influx as it migrates up the hole. Thus. It is simply necessary to ensure that the drillpipe pressure stays at a suitable value above the final shut-in pressure (that value recorded before migration started) by bleeding mud from the annulus. In this event. This control procedure is greatly simplified if the drillstring is on bottom and in communication with the annulus. must be relieved by an equivalent reduction in the hydrostatic pressure of the mud in the annulus. The principle behind the control of the annulus is that an increase in annulus pressure caused by influx migration. 4-24 March 1995 . This technique ensures that the bottomhole pressure is maintained slightly above the kick zone pressure at all times. If the drillstring is off bottom. should migration occur during this period. the bit is plugged. The procedure for implementing the Volumetric Method is covered in detail in Chapter 6. the annulus pressure is the only reliable guide to subsurface pressures. In both cases however. if the annulus pressure rises 100 psi.BP WELL CONTROL MANUAL 7 Control Influx Migration There are many possible reasons that a well that has kicked may be left shut-in for extended periods. will depend both on the position of the drillstring in the hole and whether or not the drillpipe pressure can be used to monitor bottomhole pressure. Procedures for relieving bottomhole pressure. 6 5-1 March 1995 .4 Decision Analysis – No Pipe in the Hole 5-8 5.2 Decision Analysis – Pipe off Bottom (Drillpipe in the Stack) 5-4 Decision Analysis – Pipe off Bottom (Drillcollar in the Stack) 5-6 5.3 5.1 Preparations for the Well Kill 5-3 5.BP WELL CONTROL MANUAL 5 WELL KILL DECISION ANALYSIS Paragraph Page 1 General 5-2 2 Pipe on Bottom 5-2 3 Pipe off Bottom (Drillpipe in the Stack) 5-2 4 Pipe off Bottom (Drillcollar in the Stack) 5-5 5 No Pipe in the Hole 5-5 6 While Running Casing or Liner 5-7 7 Underground Blowout 5-9 Illustrations 5.5 Decision Analysis – Flow to a Fracture above a High Pressure Zone 5-10 Decision Analysis – Flow to a Fracture or Loss Zone below a High Pressure Zone 5-12 5. BP WELL CONTROL MANUAL 1 General This Chapter is intended to provide guidelines to the decision making process in the event that a kick is taken in a variety of different situations. In reality, the specific conditions prevailing at the rigsite at the time that the kick is taken will determine the best course of action to take in order to kill the well. This Chapter should therefore not be used as a guide at the moment that a kick is taken. However, it is anticipated that general familiarity with the analysis presented in this Chapter will enable rigsite personnel to be better prepared to deal with a situation in which the well has kicked. The techniques referred to in this section are covered in detail in Chapter 6, Well Kill Techniques. 2 Pipe on Bottom If a kick is taken with the pipe on bottom, the well will be shut-in immediately unless the decision has previously been made to divert. Having established that the well is safely closed in, it will be necessary to decide on the most appropriate method of killing the well. This decision is the responsibility of the Company Representative. Having decided on the most appropriate course of action, the Company Representative is responsible for ensuring that contractor personnel are made aware of the procedures that will be used to kill the well. The general procedure that is presented in Figure 5.1 represents the steps that should be taken in preparation to kill the well. These steps are applicable to any situation in which a kick is taken. 3 Pipe off Bottom (Drillpipe in the Stack) If an influx is taken during a trip it will generally be necessary to return the drillstring to bottom before the well can be killed. The surface pressure will be a major factor in determining the most suitable method of returning the pipe to bottom. It must be considered in relation to the string weight and the pressure rating of the BOPs. The first option that should be considered is stripping the pipe to bottom with the rig equipment. Annular stripping is the most satisfactory method, however ram combination stripping may have to be considered if surface pressures are approaching the pressure rating of the annular. On a floating rig, ram combination stripping is a particularly difficult operation. The limitations imposed by the rig BOP system may dictate that stripping the pipe to bottom is impractical. In this case, snubbing must be considered. Figure 5.2 represents an analysis of the decision making process in the event the well kicks with the pipe off bottom. 5-2 March 1995 BP WELL CONTROL MANUAL Figure 5.1 Preparations for the Well Kill KICK TAKEN WELL SHUT-IN MONITOR THE WELL CONTINUOUSLY PREKILL MEETING • • DECISION MADE AS TO MOST APPROPRIATE METHOD OF KILLING THE WELL DRILLING SUPERINTENDENT IN TOWN SHOULD BE MADE AWARE OF THE SITUATION ALLOCATE INDIVIDUAL RESPONSIBILITIES • ESTABLISH THE LINES OF COMMUNICATION COMPLETE PREPARATIONS • • • CHECK EQUIPMENT ENSURE PERSONNEL ARE BRIEFED VERIFY COMMUNICATIONS START UP KILL PROCEDURE • COMPANY REPRESENTATIVE CONTROLS THE OPERATION THROUGH THE CONTRACTOR TOOLPUSHER WEOX02.022 5-3 March 1995 BP WELL CONTROL MANUAL Figure 5.2 Decision Analysis – Pipe off Bottom (Drillpipe in the Stack) WELL KICKS PIPE OFF BOTTOM (Drillpipe in stack) IS IT POSSIBLE TO STAB A SAFETY VALVE? WELL IS FLOWING UP THE DRILLSTRING NO DROP THE PIPE AND SECURE THE WELL YES STAB AND CLOSE FULL OPENING SAFETY VALVE HANG OFF OPEN CHOKELINE VALVE SHEAR PIPE CLOSE ANNULAR INSTALL DP DART OR INSIDE BOP THE SEVERITY OF THE SITUATION DICTATES THAT STRIPPING WITH RIG EQUIPMENT IS IMPRACTICAL MONITOR SURFACE PRESSURE – ROTATE THE PIPE YES ATTEMPT TO REDUCE SURFACE PRESSURE – CONSIDER: • VOLUMETRIC • LUBRICATION • BULLHEADING • CIRCULATE OUT INFLUX POSSIBLE TO REDUCE SURFACE PRESSURE? NO YES CONSIDER SNUBBING SURFACE PRESSURE EXCEEDS PRESSURE RATING OF ANNULAR? NO REDUCE ANNULAR CLOSING PRESSURE ATTEMPT TO LOWER PIPE THROUGH STACK ATTEMPT TO REDUCE SURFACE PRESSURE – CONSIDER: • VOLUMETRIC • LUBRICATION • BULLHEADING • CIRCULATE OUT INFLUX YES POSSIBLE TO REDUCE SURFACE PRESSURE? NO CONSIDER FEASIBILITY OF RAM TO RAM STRIPPING CONSIDER SNUBBING NO POSSIBLE TO LOWER PIPE THROUGH ANNULAR? YES POSSIBLE TO LOWER TOOLJOINT THROUGH ANNULAR? YES IMPLEMENT ANNULAR STRIPPING NO ATTEMPT TO REDUCE SURFACE PRESSURE – CONSIDER: • VOLUMETRIC • LUBRICATION • BULLHEADING • CIRCULATE OUT INFLUX YES POSSIBLE TO REDUCE SURFACE PRESSURE ? NO CONSIDER FEASIBILITY OF ANNULAR TO RAM STRIPPING WEOX02.023 5-4 March 1995 BP WELL CONTROL MANUAL 4 Pipe off Bottom (Drillcollar in the Stack) Every effort should be made to ensure that well control problems are avoided when the BHA is across the stack. Regaining control from a situation in which the well has kicked when the BHA is across the stack can present serious complications. If the kick was swabbed in, it may be possible to bring the well under control by bleeding gas and lubricating mud into the well. It is however, undesirable to leave the collars in the stack for an extended period during a well control operation. In any event, it is likely that the pipe will have to be stripped to bottom before the well can be killed. There are considerable operational problems presented by attempting to strip the BHA through the annular; these include: • Many BOP stacks, especially on land, have only one annular BOP. The BOP element will be subject to considerable stress as the spiralled collars are stripped through it. If the element fails there is no back-up. • Stabilizers in the BHA may prevent stripping completely. Further complications that may arise in this situation are numerous, but include the following: • There is not sufficient weight of collars to strip through the annular BOP. • Well pressures force the collars out of the hole. • An internal blowout through the drillstring. The appropriate course of action required in these situations will depend to a large extent on the particular conditions and equipment at the rigsite. However Figure 5.3 is intended as a guide to dealing with such situations. 5 No Pipe in the Hole Correct tripping procedures will ensure that an influx is detected before the pipe is completely out of the hole. Should an influx remain undetected during tripping and the well is shut in with no pipe in the hole, it may not be possible to re-introduce drillpipe into the hole in order to strip to bottom. The limiting factor is the surface pressure in relation to the weight of the drillstring above the stack. A simple calculation will determine whether it will be possible to overcome the wellbore pressures with the weight of the string. There is quite clearly a limited weight that can be applied at a surface stack. If the influx is immediately below the stack, it may be possible to either kill the well by lubricating mud into the well, or to reduce the surface pressures such that it becomes possible to re-introduce pipe into the hole. 5-5 March 1995 BP WELL CONTROL MANUAL Figure 5.3 Decision Analysis – Pipe off Bottom (Drillcollar in the Stack) WELL KICKS (Drillcollar in the stack) IS IT POSSIBLE TO STAB A SAFETY VALVE? NO DROP THE PIPE AND SECURE THE WELL WELL IS FLOWING UP THE DRILLSTRING YES STAB AND CLOSE A FULL OPENING SAFETY VALVE OPEN CHOKE LINE VALVE(S) CLOSE ANNULAR YES INCREASE ANNULAR CLOSING PRESSURE IS THE ANNULAR LEAKING? NO MINOR LEAK LEAK STOPS IS THE PIPE FORCED OUT OF THE HOLE? INCREASE ANNULAR CLOSING PRESSURE YES NO NO INSTALL INSIDE BOP LEAK THREATENS RIG FLOOR AREA IS THE PIPE FORCED OUT OF THE HOLE? YES MAKE UP DRILLPIPE TO COLLARS IS IT POSSIBLE TO LOWER PIPE INTO THE HOLE? OPEN CHOKE LINE YES STRIP IN UNTIL DRILLPIPE IN THE STACK CHECK INTEGRITY OF ANNULAR PREVENTER DROP THE PIPE AND SECURE THE WELL NO ATTEMPT TO LOWER SURFACE PRESSURE CONSIDER LUBRICATING BULLHEADING STRIP IN THE HOLE YES IS IT POSSIBLE TO LOWER PIPE INTO THE HOLE? OPEN CHOKE LINE NO CONSIDER SNUBBING DROP THE PIPE AND SECURE THE WELL WEOX02.024 5-6 March 1995 BP WELL CONTROL MANUAL However, if the influx is someway down the hole, it may not be possible to reduce the surface pressure significantly. If the influx is migrating up the hole, it may be possible to kill the well by implementing the Volumetric Control Method. On fixed offshore and land rigs, the only practical method of controlling the well may be with the use of a snubbing unit. Snubbing units have been used in exceptional circumstances on floating rigs. Figure 5.4 represents a full analysis of the decision making process in the event that a kick is taken with no pipe in the hole. 6 While Running Casing or Liner Before pulling out of the hole prior to running casing, every effort will be made to ensure that the mud is conditioned and the well is under control, thereby minimising the possibility of well control problems during the casing operation. However, possible causes of well control problems while running casing include the following: • A kick that was swabbed in on the last trip of the hole. • Swabbing in a kick on a connection while running the casing. • Surge pressures while running casing leading to losses and hence inducing a kick. • When casing is run to cure a well control problem, such as after drilling with a floating mud cap or after controlling an underground blowout. Particular attention should therefore be paid to these aspects. In critical well sections, consideration should be given to installing casing rams in the BOP stack prior to running casing; this is only practical in surface stacks. Specialist shear rams are available that can shear up to 13 3/8 in. casing; these may be considered applicable in certain situations. It is impractical to detail the procedure required in the event that a kick is taken while running casing or a liner. The immediate priority however will be to close in the well, but the most suitable control technique can only be determined bearing in mind the particular conditions at the rigsite. The subsequent options available can be summarised as follows: • Cross over to drillpipe (unless current string weight is too great) and strip to bottom to kill the well. • Cross over to drillpipe, strip in until drillpipe is in the stack and kill the well at current shoe depth. • Kill the well with the casing across the stack. • Drop the casing. • Shear the casing. 5-7 March 1995 BP WELL CONTROL MANUAL Figure 5.4 Decision Analysis – No Pipe in the Hole WELL SHUT IN – NO PIPE IN THE HOLE MONITOR SURFACE PRESSURE IS THE INFLUX IMMEDIATELY BELOW THE RAMS? NO YES LUBRICATE MUD INTO THE HOLE AND BLEED GAS ALL GAS BLED FROM RAMS? NO YES IS THERE ANY PRESSURE UNDER THE RAMS? NO YES ATTEMPT TO REDUCE THE SURFACE PRESSURE BY LUBRICATING OR BULLHEADING POSSIBLE TO REDUCE SURFACE PRESSURE? NO DO SURFACE PRESSURES INDICATE THAT INTRODUCING PIPE INTO THE HOLE IS POSSIBLE? YES YES NO IMPLEMENT VOLUMETRIC CONTROL METHOD YES IS THERE EVIDENCE OF INFLUX MIGRATION? NO BULLHEAD KILL MUD INTO THE WELL PREPARE CONTINGENCY TO DEAL WITH THE FRACTURED ZONE KILL WELL NO IS SNUBBING A PRACTICAL CONSIDERATION? YES SNUB IN PIPE KILL THE WELL STRIP IN THE HOLE KILL WELL FLOWCHECK THE WELL OPEN THE RAMS WEOX02.025 5-8 March 1995 BP WELL CONTROL MANUAL The major factors that will determine the most appropriate course of action will include the following: • The length and type of casing run. • The possibility and consequences of the casing becoming stuck. • The possibility and consequences of collapsing the casing. • The feasibility of circulating out a kick by conventional means. (The relatively small annular clearance may cause excessive pressures in the annulus, or may possibly completely restrict circulation.) • The feasibility of killing the well by other means such as bullheading or by volumetric control. • The BOP stack configuration and ram types. • The likelihood of the casing being forced out of the hole by the well pressure. 7 Underground Blowout (a) Flow to a Fracture above a High Pressure Zone The majority of underground blowouts in the past have been as a result of a fracture to a weak zone up the hole as high pressure zone is penetrated. Figure 5.5 shows a decision analysis for identifying and dealing with an underground blowout of this type. If an underground blowout is suspected, on no account should attempts be made to control the well using standard techniques. If the annulus is opened, reservoir fluids will be allowed to flow up the wellbore to surface, thereby increasing surface pressures. The first action, after shutting in the well, will be to perform a positive test. The purpose of this test is to determine whether or not the hole is a closed system. A small displacement pump is lined up to the drillpipe and a small amount of fluid is pumped. If the drillpipe and casing pressure increase, there is no indication of fracture in the openhole. If the drillpipe pressure does not increase, or if any increase is not evident on the casing, then a fracture in the openhole is indicated. In order to halt an underground flow, it is necessary to pump fluid at a high rate down the drillpipe and up the annulus; thus effecting a dynamic kill. The fluid will eventually have to be at kill weight in order to balance the kick zone EMW. However, it will also have to be as thin as possible to ensure that it can be pumped at high rate without excessive surface circulating pressures. Generally the kill mud must flow at least as fast as the underground flow if it is not to be dispersed by the flow as it passes out of the bit. The kick zone EMW can at best be estimated because reliable drillpipe pressure will not be available. The mud weight required to kill the well will depend on the position of the fracture in the wellbore and the average weight of the fluid occupying the annulus between the fracture and surface. 5-9 March 1995 BP WELL CONTROL MANUAL Figure 5.5a Decision Analysis – Flow to a Fracture above a High Pressure Zone SHUT IN THE WELL MONITOR SURFACE PRESSURES REASSESS THE SITUATION NO EVIDENCE OF UNDERGROUND BLOWOUT IMPLEMENT STANDARD TECHNIQUES TO KILL THE WELL SUSPECT UNDERGROUND BLOWOUT BECAUSE: 1. DRILLPIPE ON VACUUM 2. PRESSURE BUILDUP CLEARLY INDICATES FORMATION HAS FRACTURED 3. ANNULUS PRESSURE FLUCTUATING RUN POSITIVE TEST RUN TEMPERATURE AND/OR NOISE LOG TO IDENTIFY FLOW IF NECESSARY NO UNDERGROUND BLOWOUT CONFIRMED ? YES 1. DO NOT BLEED FLUID FROM ANNULUS 2. LINE UP ONE PUMP TO THE ANNULUS. LINE UP MUD AND IF NECESSARY WATER SUCTION IF ANNULUS PRESSURE IS NOT EXCESSIVE LEAVE ANNULUS SHUT IN IF ANNULUS PRESSURE IS BUILDING, PUMP MUD AT SLOW RATE DOWN ANNULUS. IF ANNULUS CANNOT SUPPORT MUD, PUMP WATER CONTINUALLY MONITOR ANNULUS CONTINUED ON FOLLOWING PAGE WEOX02.026 5-10 March 1995 CHECK MUD IS AT KILL WEIGHT 2. PUMP LCM PILL DOWN ANNULUS UNTIL JUST ABOVE FRACTURED ZONE IMPLEMENT DYNAMIC KILL • • • 1. CEMENT BHA IN PLACE 2. PUMP LARGER PLUG PUMP KILL WEIGHT MUD AT MAXIMUM RATE KEEP PUMPING UNTIL ALL THE MUD IS USED STOP ONLY IF SURFACE PRESSURES BECOME EXCESSIVE DRILLPIPE AND ANNULUS PRESSURES INDICATE THAT UNDERGROUND FLOW HAS CEASED? TRY AGAIN YES TAKE STEPS TO SECURE WELL OPTIONS: 1. CHECK MUD IS AT KILL WEIGHT 2. BACK OFF. REDUCE DRILLSTRING INTERNAL FRICTION 4. MIX 2 x ANNULUS VOLUME OF KILL WEIGHT MUD 3. REDUCE MUD VISCOSITY 3. PUMP FRESHWATER AT MAXIMUM RATE TO SLOUGH HOLE YES IS THE PIPE STUCK ? NO OPTIONS: 1. REDUCE MUD VISCOSITY 3. REMOVE KELLY – INSTALL HP CIRCULATING LINE IMPLEMENT DYNAMIC KILL USING BARYTES PLUG • • • 1.BP WELL CONTROL MANUAL Figure 5. POOH TO PLUG FRACTURE 3. HAVING INSTALLED DART SQUEEZE HIGH FILTER LOSS CEMENT SLURRY TO PLUG WELL 2. CEMENT BHA IN PLACE 2. PUMP LARGER PLUG TRY AGAIN PUMP KILL MUD AT MAXIMUM RATE DOWN DRILLPIPE PUMP LCM PILL DOWN ANNULUS AND INTO FRACTURE KEEP PUMPING UNLESS SURFACE PRESSURE LIMITS ARE REACHED DRILLPIPE AND ANNULUS PRESSURES INDICATE THAT UNDERGROUND FLOW HAS CEASED? YES TAKE STEPS TO SECURE WELL OPTIONS: 1. POOH TO RUN CASING NO OPTIONS: 1. STRIP UP INTO CASING. SQUEEZE HIGH FILTER LOSS CEMENT SLURRY TO PLUG WELL 2. REDUCE DRILLSTRING INTERNAL FRICTION 4. STRIP UP INTO CASING.027 5-11 March 1995 . POOH TO RUN CASING NO 1. IF CIRCULATION IS POSSIBLE ON BOTTOM. POOH TO PLUG FRACTURE 3. PUMP FRESHWATER AT MAXIMUM RATE TO SLOUGH HOLE WEOX02. MIX LCM PILL (100bbl MIN FOR LARGE ANNULUS) 2.5b Decision Analysis – Flow to a Fracture above a High Pressure Zone (continued) PREPARE 2 x ANNULUS VOLUME OF KILL WEIGHT MUD (AT MIN PV AND YP – USE FRICTION REDUCER IF AVAILABLE). SUPPLY MUD AND IF NECESSARY WATER SUCTION CONTINUALLY MONITOR ANNULUS OPTIONS TO CONTROL THE FLOW: • PUMP LCM PILL • SET CEMENT PLUG ON BOTTOM • CIRCULATE THE HOLE TO LIGHT MUD.BP WELL CONTROL MANUAL Figure 5.6 Decision Analysis – Flow to a Fracture or Loss Zone below a High Pressure Zone • DRILLING AHEAD • LOSSES EXPERIENCED SHUT DOWN ROTARY OR TOP DRIVE CURE LOSSES DRILL AHEAD • CANNOT CONTROL LOSSES • WELL STARTS TO FLOW • SHUT IN WELL POSSIBLE UNDERGROUND BLOWOUT INDICATORS: • NO SURFACE PRESSURE • ANNULUS AND DRILLPIPE ON VACUUM (ANNULUS PRESSURE MAY BUILD UP) RUN POSITIVE TEST RUN NOISE AND/OR TEMPERATURE LOG IF NECESSARY UNDERGROUND BLOWOUT CONFIRMED? NO REASSESS THE SITUATION YES • DO NOT BLEED FLUID FROM ANNULUS • LINE UP ONE PUMP TO THE ANNULUS. DRILL UNDER PRESSURE WITH ROTATING HEAD NO SURFACE PRESSURE LOGS INDICATE THAT UNDERGROUND FLOW HAS CEASED ? YES TAKE STEPS TO SECURE WELL 5-12 March 1995 WEOX02.028 . If the rig pumps have been operating at maximum output there remains the options to bring more pumps to the rigsite or to reduce the frictional resistance of the drillstring by such measures as: • Removing the nozzles of the bit with a charge run on wireline. If the first attempt to control the flow is unsuccessful. to deal with an underground blowout. this rise in pressure is prevented by pumping mud down the annulus. extreme care should be taken. there are two options that should be considered for halting the flow: • Set a plug on bottom. less viscous mud ahead of the kill weight mud in order to reduce the velocity of the inflow. (b) Flow to a Fracture or Loss Zone below a High Pressure Zone The most likely cause of an underground blowout that flows down the wellbore from a high pressure zone is that a naturally fractured or cavernous formation is drilled into. As indicated in Figure 5. • Pumping a lighter. However. Subsequent options therefore include increasing the volume of the kill mud pumped and pumping at a greater rate. the most likely causes will beeither that the volume or the velocity of kill mud was insufficient.5. When the well is shut-in. The recommended procedure for mixing and spotting a baryte plug. • Perforating the BHA close to the bit. • Reduce the mud weight and drill ahead under pressure. The pump rates on the drillpipe and the annulus should be such as to ensure that the LCM pill is completely displaced into the fracture over the period of time that will be required to pump the prepared volume of kill weight mud.3) and displace it down the annulus and into the fracture as the kill weight mud is pumped down the drillpipe. Figure 5. if these measures do not bring the well under control. there remains the option to mix an LCM pill or soft plug (See Chapter 2. Section 2. it is unlikely that any pressure will be recorded on either the drillpipe or the casing. The resultant losses reduce the hydrostatic head of the drilling fluid to such an extent that a permeable zone higher up the wellbore begins to flow. the casing pressure may increase if gas migrates up the casing/drillpipe annulus. The industry has given the term ‘Baryte plug’ to the heavy weight pills required to deal with underground blowouts. If the decision is made to pull off bottom having halted an underground flow. 5-13 March 1995 .BP WELL CONTROL MANUAL The fracture may only support a column of water. is covered in Chapter 6. Having established that the flow is downwards to a loss zone. in which case it will be necessary to balance the kick zone pressure with the sum of the hydrostatic pressure of the kill weight mud from the kick zone to the fracture and the hydrostatic pressure of the water above the fracture. a further flow has been initiated by attempts to pull off bottom. having halted the underground flow.6 shows the decision analysis for identifying and dealing with an underground blowout of this type. Past experience has shown that in many cases. Section 2. 5-14 March 1995 . See Chapter 2. including a rotating head.BP WELL CONTROL MANUAL Drilling under pressure will however only be used in circumstances in which lost circulation of this type has been anticipated.3 for LCM and cement plug recipes. is available onsite. the high pressure zone has low permeability and the correct equipment. 2 Stripping 6-47 2.6 Emergency Procedure 6-93 6.BP WELL CONTROL MANUAL 6 WELL KILL TECHNIQUES Section Page 6.5 Baryte Plugs 6-84 2.3 COMPLICATIONS 6-97 March 1995 .1 Volumetric Method 6-33 2.3 Bullheading 6-67 2.2 SPECIAL TECHNIQUES 6-1 6-31 2.4 Snubbing 6-75 2.1 STANDARD TECHNIQUES 6. 1 STANDARD TECHNIQUES Paragraph Page 1 General 6-2 2 Kick Circulation Methods 6-2 3 Kick Sheet 6-3 4 Implementation of the Wait & Weight Method 6-5 5 Implementation of the Driller’s Method 6-8 6 Procedures For High Angle or Horizontal Wells 6-11 7 Floating Rig Procedure 6-14 8 Accounting for Choke Line Losses in Deep Water 6-23 Illustrations 6. gas occupies choke line 6-28 Removing Gas from a Subsea BOP Stack – Diverter is closed. the annular is opened and the gas is displaced from the stack 6-29 The Effect of Choke Line Losses – Casing pressure greater than choke line pressure 6-30 6.8 6.10 The Effect of Choke Line Losses – Casing pressure after initial circulation is less than choke line loss 6-31 6-1 Rev 1 March 1995 March 1995 .BP WELL CONTROL MANUAL 6.5 6.9 6.2 The Kill Line Monitor 6-21 6.1 An Example Completed Kick Sheet 6-14 6.4 6.7 6.6 6.3 Subsea BOP Gas prior to Removing Gas from Below the Preventers 6-24 Removing Gas from a Subsea BOP Stack – Lower pipe rams closed hang off rams opened 6-25 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to kill weight mud 6-26 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to water 6-27 Removing Gas from a Subsea BOP Stack – Gas pressure bled down. the Wait & Weight Method on both a fixed installation as well as a floating rig. and for high intensity (large under-balance) kicks. With the Wait & Weight Method.BP WELL CONTROL MANUAL 1 General This section covers the basic steps that are required to implement the Driller’s Method. or slightly greater than.5 in Vol. A full report should eventually be issued and submitted to Line Management.5).2. The Well Control operations log can be used initially for this (See Figure 4. Circulation can be started immediately if the rig mud weighting system is able to weight up the mud at a rate greater than or equal to the mud SCR.2. it is recommended that the Wait & Weight Method be used in preference to other methods. Company policy is that a contingency plan must be developed regarding the implementation of the well control methods for both Company operated rigs and rigs that are under a Company contract. So the well can be killed with one complete circulation. 2 Kick Circulation Methods (a) The Wait & Weight Method When conditions permit. This is the key to well control practice. This is illustrated in Figure 5. Chapter 5.6 in Vol. In the event of any well control incident it is important that a diary of events is kept. the mud is weighted up to the kill weight after the well is shut in. in particular for vertical and low angle wells. Therefore the advantages of the Wait & Weight Method are as follows: • The surface pressure will be lower than using other methods if the kill weight mud enters the annulus before the influx is circulated out. • The pressure exerted on the casing shoe (or the weak point in the openhole) will be lower than using other methods if the kill mud starts up the annulus before the top of the influx is displaced to the shoe (or openhole weak point). This section is intended to assist in drawing up these contingency plans. 6-2 Rev 1 March 1995 March 1995 . Further discussions on the theories behind the methods are covered in Vol. Chapter 5. All the well control techniques are designed to ensure that: Bottom hole pressure is maintained constant and equal to. the formation pressure. Then circulation is started and the kick displaced from the hole with kill weight mud. Chapter 5. This difference is most significant for influx containing gas. This is illustrated in Figure 5. These techniques use the principle that: The drillpipe pressure is used to monitor bottom hole pressure.2. • The well will be under pressure for the least time. 1a. In case a kick is taken. and the second circulation carried out to kill the well. • The earlier circulation may reduce the risks of stuck pipe and other hole problems. • Influx fluids can be displaced from the well. circulating times and the mud pump data should be recorded routinely and available at all times in the kick sheet. The procedures for completing the kick sheet are shown in Figure 6.BP WELL CONTROL MANUAL (b) The Driller’s Method In certain circumstances. Based on the kick data. These special techniques are discussed in Section 6. After a kick is taken and the well shut-in. some special techniques should be also considered. • Impending bad weather dictates that the kick must be displaced from the hole as quickly as possible.1b and 6.1d. the relevant kick data should be recorded in the kick sheet. the relevant parameters should be calculated and recorded in the kick sheet. a decision should be made regarding what method be used to kill the well. • Increasing surface pressures indicate the influx is rising rapidly in the annulus Under the above circumstances. it may not be practical to implement the Wait & Weight Method. Figures 6. In addition to the standard methods which have been described in the previous paragraphs. drillstring/annulus contents. the kick is displaced from the hole by the first circulation with the original mud. even if suitable mud weighting material is not available. The Driller’s Method requires that two complete hole circulations are carried out before the well can be killed. The advantages of the Driller’s Method over the Wait & Weight Method are: • The kick can be displaced from the hole soon after the well is shut-in. The shut-in procedure and the interpretation of the pressure data are covered in Chapter 4. In the mean time the mud is weighted up to kill weight. the Driller’s method should be considered.1c show an example kick sheet.2. 6-3 Rev 1 March 1995 March 1995 . These include: • There are insufficient stocks of weighting material at the rigsite. • The rig mud weighting system is not capable of increasing the active mud weight to kill weight as the kick is displaced. 6. • There is some considerable doubt as to the mud weight required to kill the well. If the decision is made to displace the kick from the hole by using one of the standard methods. The general well data. 3 Kick Sheet The kick sheet should be used to record all the relevant well and kick data. • It avoids the need to initiate a volumetric control during the waiting period. formation characteristics and human factors on the overall well control operation.MW1) (4.MW2) (lb/bbl) Total quantity of baryte required (lb) = Wb x Total Active Mud Volume Total active mud volume = Drillstring Vol + Annulus Vol + Surface Active Vol (lb) (bbl) The stocks of baryte at the rigsite must be at least 10% greater than the calculated quantity of baryte required. Computer software that utilises the exact technique is also available at the Drilling and Completions Branch.25 . Wb = 1490 x (MW2 . MW2 = MW1 + where (SG) Pdp = Stabilised shut-in drillpipe pressure (psi) MW1 = Original mud weight (SG) TVD = True vertical depth of kick zone (m) It is not recommended practice to weight the mud any higher than the kill weight during the well killing operation. These include the gas solubility in oil-based muds. the formation permeability and over-pressure. depending on the kill method to be used. The actual pressures will generally be lower than those predicted by the technique. or with the kill weight mud. (b) Calculate the baryte quantity required to weight up the mud This calculation is necessary in order to determine if adequate stocks of baryte are available on site. Chapter 5. The software includes the effects that the conventional approximate technique has neglected. The areas of particular importance will be the maximum pressure that will be exerted at the shoe (or openhole weak point) and the maximum surface pressure.421 Kill Mud Weight. etc. So the software can provide more realistic predictions of pressures and flows in the wellbore than the approximate techniques. After the well has been killed however. The software can be also used to investigate the impacts of operational parameters. The amount of baryte required to weight up the mud can be calculated from the following formula: Baryte required. as well as the maximum surface pressure during displacement. etc. This has been presented in Vol. the mud weight should be raised to provide suitable overbalance. An approximate technique can be used to estimate the maximum pressure at a weak point in the openhole. (c) Develop annulus pressure profile It is useful to estimate the maximum pressures that will occur during circulation. These include the kick detecting volume.BP WELL CONTROL MANUAL (a) Determine the kill weight mud Circulation may be initiated with the original weight mud.2. Sunbury. BP Exploration. the time required for the rig crew to shut-in and the mud SCR. It is not however essential to carry out these calculations prior to circulation. The weight of the mud that would exactly balance the kick zone pressure is calculated from the shut-in drillpipe pressure as follows Pdp TVD x 1. downhole temperature. 6-4 Rev 1 March March 1995 1995 . gas dispersion and slip. This. At this stage therefore thecirculating pressure can be estimated by determining the SCR pressure for the kill weight mud. particularly in the case of oil mud. followed by circulation with the kill weight mud. should be calculated in order to estimate the circulating pressure that will be required to maintain constant bottom hole pressure at the start of the circulation. the standpipe pressure must be reduced to take into account the increased hydrostatic pressure of the mud in the pipe. So several calculations are necessary prior to initiating circulation. (b) Calculate the initial circulating pressure The initial drillpipe circulating pressure. These factors are detailed in Chapter1 in ‘Drills and SCRs’. Having established the maximum possible circulation rate. 6-5 Rev 1 March 1995 March 1995 .BP WELL CONTROL MANUAL 4 Implementation of the Wait & Weight Method Prior to implementing the Wait & Weight Method. the actual circulation rate will be determined on the basis of several factors. The standpipe pressure must also compensate for the additional friction pressure in the drillpipe and across the bit as the kill weight mud displaces the original mud. These are as follows: (a) Determine the circulation rate The upper limit for the circulation rate is generally set by the maximum rate that baryte can be mixed into the mud. Pic. the relevant sections of the Kick Sheet as covered in Paragraph 3 should be completed. the static drillpipe pressure required to balance the kick zone will be zero. and associated problems of building mud weight are discussed in Chapter 1 in ‘Use of the Mud System’. The chosen SCR and the relevant pumping data should be recorded in the kick sheet. The Wait & Weight Method accomplishes the kill operation in one complete circulation. may be the rate at which viscosity can be built in the mud. It requires weight up of the mud after the well is shut in. Once the drillpipe has been completely displaced to kill weight mud. The initial circulating pressure recorded after the pump has been brought up to speedshould be the sum of the shut-in drillpipe pressure and the SCR pressure at the chosen rate: P ic = P dp + P scr where Pic Pdp Pscr = Initial circulating pressure (psi) = Stabilised shut-in drillpipe pressure (psi) = Circulating pressure at SCR with MW1 (psi) (c) Calculate the final circulating pressure As the drillpipe is displaced with kill weight mud. The following formula can be used to estimate the maximum possible circulation rate: Maximum circulation rate = Baryte delivery rate (lb/min) (bbl/min) Baryte required to weight up mud (lb/bbl) A limiting factor. a plot should be made of the required standpipe pressure (See Figure 6. Before circulation is started. • When the influx is circulated to the choke. (d) Determine the displacement times and the cumulative pump strokes At all times during circulation. See Paragraph 6.1b). (f) Procedure for the displacement of the kick 1 Bring the pump up to kill speed • Line up the pump to the drillpipe and route returns through the choke manifold to the mud gas separator. The initial circulating pressure should be plotted corresponding to zero strokes. • Open the remote operated choke at the same time as the pump is started on the hole. The two points on the graph can be joined up with a straight line to produce the standpipe pressure schedule.BP WELL CONTROL MANUAL The final circulating pressure can be estimated as follows: Pfc = P scr (at MW1) x MW2 MW1 where P fc = Final circulating pressure (psi). Consider stroking the drillstring up at this point. as well as the volume of hole that has been circulated to kill weight mud.) In practice standpipe pressure is most easily controlled by reducing the pressure in small steps. Pumping time to reach point = of interest Total strokes to reach point = of interest Volume to be displaced (bbl) (min) Pump rate (bbl/min) Volume to be displaced (bbl) (stk) Pump output per stroke (bbl/stk) (e) Plot standpipe pressure schedule To ensure that the standpipe pressure is adjusted correctly as the kill weight mud is circulated down the drillpipe. • When the top of the influx is circulated to the casing shoe or openhole weak point. the estimated circulating time and the corresponding total pump strokes to each point should be calculated. (Note: for high angle or horizontal wells. it is important to know the position of the influx in the wellbore. The final circulating pressure should be plotted corresponding to total strokes equivalent to complete displacement of the drillpipe. The key points during the circulation are as follows: • When the kill weight mud reaches the bit. 6-6 March 1995 1995 Rev 1 March . • Zero the stroke counter on the choke panel. rather than continuously. the graph is not a straight line. and hence the corrected final circulating pressure. (This expansion will not occur if the influx is water or oil. If the actual initial circulating pressure is considerably different from the calculated value. As the influx is circulated from the well and mud is circulated to the choke. This technique will be most effective at the early stages of displacement. stop the pump. 6-7 Rev 1 March 1995 . can be determined from the initial circulating pressure as follows: Pscr = Pic – Pdp The standpipe pressure schedule can therefore be corrected to take into account the adjusted circulating pressures. if the well contains a significant proportion of gas. The choke should therefore be adjusted to compensate for this.) Once the drillpipe has been displaced to kill weight mud. If the actual initial circulating pressure is equal to. choke pressure and all other relevant information shouldbe recorded during displacement using the Well Control Operations Log (SeeFigure 4. Any marginal difference between the actual and calculated initial circulating pressure is most likely to be due to the fact that the SCR pressure used to calculate the initial circulating pressure was inaccurate. • Once the pump is up to speed record the initial circulating pressure. and the choke will have to be closed down quickly. the choke pressure should be increased by approximately 70 psi. the standpipe pressure should be stepped down according to the standpipe pressure schedule.5). or reasonably close to the calculated value. (The standpipe pressure will have a natural tendency to drop as the kill weight mud is displaced down the drillpipe. The choke should therefore be opened to allow the choke pressure to drop sufficiently to re-establish the final circulating pressure on the drillpipe. The pressure on the drillpipe will increase after a lag time which can typically be 2 seconds per 300m of drillstring depth. the drillpipe pressure will tend to drop as the influx expands. the choke pressure will start to decrease due to the differences in density and viscosity between the influx and the mud. These will help to determine the down hole condition during all stages of the kill operation. the drillpipe pressure should be maintained at the final circulating pressure for the rest of the circulation. the choke pressure will begin to rise rapidly. For example. continue the displacement and adjust the standpipe pressure schedule accordingly. Pfc. If the influx contains significant quantities of gas. if the drillpipe pressure drops by 70 psi below that required. When the influx reaches the choke.BP WELL CONTROL MANUAL • Maintain the choke pressure equal to the original shut-in casing pressure as the pump is slowly brought up to speed. shut in the well and investigate the cause. The actual SCR pressure. The pit gain. the drop in choke pressure may be quite substantial. This may take 1/2 to 1 minute. As the influx is displaced up the hole. and hence maintain constant bottom hole pressure.) This effect will be especially marked if the influx contains a significant quantity of gas. 2 Circulate the influx from the well maintaining constant bottom hole pressure As the drillpipe is displaced with kill weight mud. and less so at later stages of the displacement. drillpipe pressure. The initial circulating pressure will be maintained constant throughout the first circulation since the mud weight is not changed. although the drillstring displacement volume/time is not significant in this case. However. the pump should be stopped. If this flowcheck indicates no flow. a flowcheck on the choke line return should be carried out before the rams are opened. Prior to the first circulation. 6-8 March 1995 1995 Rev 1 March . a further complete hole circulation should be carried out prior to continuing operations. the relevant sections of the Kick Sheet as covered in Paragraph 3 should be completed. and the casing and drillpipe checked for pressure. There should be no pressure on either the casing or the drillpipe. and further practicalities as outlined in Chapter 1. A suitable overbalance can be added to the mud at thisstage. the rams should be opened and a further flowcheck on the annulus carried out. Record the chosen circulating rate SCR and the corresponding pumping data in the kick sheet. the following calculations are necessary: (a) Determine the circulation rate The circulation rate for the first circulation of the Driller’s Method is not limited by the baryte mixing capacity of the rig. (b) Calculate the initial circulating pressure The initial circulating pressure at the start of the first circulation is calculated in the same manner as the Wait and Weight Method. the well shut-in. if there is still some pressure on the casing. 5 Implementation of the Driller’s Method Prior to implementing the Wait & Weight Method. circulation should be restarted to clear the contaminated mud from the annulus. In line with Company policy. The second circulation is carried out with the weighted mud to kill the well.BP WELL CONTROL MANUAL Once the hole has been circulated to kill weight mud. The kick is circulated out of the hole by the first circulation with the original mud. (c) Determine the displacement times and corresponding pump strokes These figures are calculated in exactly the same manner as the Wait and Weight Method. Once the well has been completely killed. The Driller’s method is a two complete circulation method. Limiting factors will include the additional wellbore pressures due to circulation. (d) Plot the standpipe pressure schedule The standpipe pressure is held constant throughout the first complete circulation at the initial circulating pressure. holding the standpipe pressure at the value recorded when the pump was first brought up to speed. If the actual initial circulating pressure is considerably different from the calculated value. or reasonably close to the calculated value. shut-in the well and investigate the cause. 6-9 Rev 1 March 1995 . stop the pump. Choke pressures will inevitably be higher than if the Wait and Weight Method had beenused. Prior to circulating kill weight mud into the hole.BP WELL CONTROL MANUAL The following steps can be used as a guide for the procedure for the displacement of thekick: 1 Bring the pump up to speed for the first complete circulation • Line up the pump to the drillpipe and route returns through the choke manifold to the mud gas separator. • Maintain the choke pressure equal to the original shut-in casing pressure as the pump is slowly brought up to speed. The following further calculations are then worked: (a) Determine the circulation rate for the second circulation The circulation rate is determined on the same basis as if the Wait and Weight Method had been used. • Open the remote operated choke at the same time as the pump is slowly brought up to speed. the calculations as outlined in Paragraph3 “Kick Sheet” should be carried out. the shut-in drillpipe and shut-in casing pressure should be equal. This may take 1/2 to 1 minute. Consider stroking the drillstring up at this point. this is evidence that there is still some kick fluid in the annulus. or the mud weights are out of balance. The actual SCR pressure can be determined from the initial circulating pressure as follows: Pscr = Pic − Pdp This adjusted value for the SCR pressure should be used for estimating the circulating pressures for the second complete circulation. If the actual initial circulating pressure is equal to. 2 Circulate the influx from the well maintaining constant bottom hole pressure Influx behaviour during circulation will be similar to the Wait and Weight Method requiring similar choke manipulation. Once the influx has been displaced from the hole. • Set the stroke counter on the remote choke panel to zero. These higher pressures will be reflected downhole. Any marginal difference between the actual and calculated initial circulating pressure is most likely to be due to the fact that the SCR pressure used to calculate the initial circulating pressure was inaccurate. • Once the pump is up to speed record the initial circulating pressure. continue the displacement. If the casing pressure is higher than the drillpipe pressure. causing greater stress in the openhole. ) • Zero the stroke counter on the choke panel. If this is the case. Pfc = P scr (at MW1) x where MW2 MW1 Pfc = Second circulation final circulating pressure (psi) MW1 = Original mud weight (SG) MW2 = Kill mud weight used for second circulation (SG) (d) Determine the displacement times and corresponding cumulative pump strokes These figures will be the same as for the first circulation. The initial circulating pressure is therefore calculated as follows: Pic = P dp + Pscr where Pic Pdp Pscr = Second circulation initial circulating pressure (psi) = Drillpipe pressure recorded prior to second circulation (psi) = Slow circulating rate pressure (psi) (c) Calculate the final circulating pressure As with the Wait and Weight Method. If the initial circulating pressure has changed considerably. (An alternative is to stop pumping and then restart using the procedure for the Wait and Weight Method. The following can be used as a guide for the procedure of circulating the hole to kill weight mud: 1 Bring the pump up to speed for the second complete circulation • Change pump suctions without stopping the mud pump.BP WELL CONTROL MANUAL (b) Calculate the initial circulating pressure The initial circulating pressure will be the same as for the first circulation. (e) Plot the standpipe pressure schedule The standpipe pressure schedule for the second circulation is drawn up in the same manner as for the Wait and Weight Method (Figure 6. stop the pump. continue the displacement and adjust the standpipe pressure schedule accordingly. and investigate the cause. 6-10 Rev 1 March March 1995 1995 . and begin pumping the kill weight mud. • Once the pump has been switched to the kill mud.1b). the circulating pressure must be adjusted to compensate for the kill weight mud. shut in the well. record the initial circulating pressure. The initial circulating pressure should be the same with the standpipe pressure during the first complete circulation. This is because the weighted mud will not reduce the surface and casing shoe pressures until it has passed the horizontal or high angle section. Once the well has been killed. the circulation should be switched to the kill weight mud. When the returned mud is at kill weight. Once the drillpipe has been displaced to kill weight mud. thereby ensuring constant bottom hole pressure. even if the influx is still in the annulus. a flowcheck on the choke line return should be carried out before the rams are opened. • The advantages of the Wait & Weight Method over the Driller’s Method are less important in a high angle or horizontal well. • The circulation should be started using the Driller’s Method once the well has beenshut in and the stabilised shut-in pressures are established. The well should be checked for pressure. In line with Company policy. the final drillpipe circulating pressure is held constant by manipulating the choke. the drillpipe pressure will tend to increase. By then the kick may have entered into the casing or been out of the well. If this flowcheck indicates no flow. The circulation continues until the kick is circulated out and the kill mud returns to surface. 6 Procedures For High Angle or Horizontal Wells (a) Implementation of Kick Circulation Methods The procedures for implementing one of the standard kick circulation methods are essentially the same for both the vertical and high angle or horizontal wells (as covered in the previous paragraphs). the rams should be opened and a further flowcheck on the annulus carried out. The earlier start of the circulation will reduce the risks of stuck pipe and other hole problems associated with the stagnant mud. In the mean time. As kill weight mud is circulated up the annulus. the standpipe circulating pressure should be stepped down according to the standpipe pressure schedule. the pump should be stopped and the well shut-in. there are several points which should be considered before and during a well killing operation in a high angle or horizontal well. a further complete hole circulation should be carried outprior to continuing operations. However. The choke should be adjusted to ensure that the drillpipe pressure is maintained at the final circulating pressure. • Once the mud weight has been increased to the kill weight. A suitable overbalance can be added to the mud at this stage.BP WELL CONTROL MANUAL 2 Circulate the hole to kill weight mud maintaining constant bottom hole pressure As the drillpipe is displaced with kill weight mud. the kill weight mud is prepared in the reserve mud pits. 6-11 Rev 1 March 1995 March 1995 . This will minimise the well pressures as well as the time of dealing with the kick. For example. Therefore.L1 ) ] ID 25 where: ∆P friction = Friction pressure increase due to kill weight mud. the hydrostatic pressure at the hole bottom does not change at all. Pfc . this is not the case in a high angle or horizontal well because the change in the hydrostatic pressure due to the kill mud is not linear. then: ∆P friction = β x [α 1 + (MD . This has been covered in the previous paragraphs. the surface pump pressure should be reduced linearly from the initial circulating pressure (ICP) to the final circulating pressure (FCP). However. when the front of the kill mud is going through a horizontal section of the drillpipe. This is necessary in order to calculate the friction pressure increase due to the kill weight mud. the standpipe pressures when the kill mud reaches several critical depths in the drillpipe should be calculated. the pump pressure is kept constant at FCP until the kill mud returns to surface. (psi) ii. α1 = L 1 / ID15 where: α1 L1 ID1 = Size factor for drillpipe section 1. (psi. To achieve this. end-tangent. Calculate the friction pressure increase when the kill mud reaches each of the critical depths in the drillpipe (kick-off.BP WELL CONTROL MANUAL (b) Standpipe Pressure Schedule When pumping down the kill mud through the drillpipe in a vertical well. (m/in 5) = Length of drillpipe section 1. The calculations can be performed as follows: i. Therefore. (psi) 6-12 March 1995 1995 Rev 1 March .). BHA can be treated as part of the drillpipe section.P scr α 1 + α2 β= where: β α1 α2 Pfc Pscr = = = = Drillpipe friction constant. etc. Thereafter. • If the critical depth is above/at the drillpipe section cross-over point. end-tangent. end-build. then the size factor should be calculated for each of the sections. So in this case the pump pressure should be kept constant (or increased slightly due to friction pressure increase with kill mud). in order to maintain the bottom hole pressure constant. the pressure schedule during pumping the kill mud through the drillpipe can be obtained by simply joining a straight line between ICP and FCP. end-build. These include the depths at the kick-off. (inch) If there is more than one drillpipe section (tapered string). then: ∆P friction = β x • MD ID 1 5 If the critical depth is below the drillpipe section cross-over point. Calculate the drillpipe size factor and the friction constant.in 5/m) Drillpipe size factors for section 1 and 2. (m) = ID of drillpipe section 1. (m/in5) Final circulating pressure (psi) Slow circulating pressure with original mud MW1 . the standpipe pressure schedule should be modified to take into account the effect of hole angle. etc. (m) = Vertical depth at the open hole kick zone. (psi) = Drillpipe pressure before the kill weight mud is circulated. Figures 6. Pstand = P scr + ∆Pfriction + Pstatic where: Pstand = Standpipe pressure. These calculations should be carried out if the hole has a maximum angle greater than 30de grees. So the first attempt to kill the well should be using one of the standard techniques.e. (psi) The results of the above calculations should be recorded in the Kick Sheet.1a shows an example of a completed kick sheet for a high angle well. which would increase the risk of fracturing the formation at the casing shoe or openhole weak point. A combination of the following is a possible indication that a kick has occurred in the inverted or horizontal hole section: • There is an increased mud return flowrate • There is a positive pit gain • When the well is shut in. Calculate the standpipe pressure when the kill weight mud reaches each of the criticaldepths. Figure6. 6-13 Rev 1 March 1995 March 1995 . then the free gas will be trapped there unless the mud is circulated fast enough to flush the gas out of the inverted section. (m) iii. the hole angle is greater than 90 degrees). where gas expansion causes a continuous increase in the casing pressure.0 where: Pstatic Pdp TVD TVD h TVD ) TVD h = Static drillpipe pressure.BP WELL CONTROL MANUAL MD = Measured depth at the critical depth. (c) Trapped Gas in Inverted or Horizontal Hole Section If a kick containing free gas occurs in an inverted hole section (i. It shows that the standpipe pressures required to maintain a constant bottom hole pressure are lower for a high angle well (with build-hold profile) than if the well was vertical.3). A gas kick is recognised when it is being circulated through the low angle or vertical hole section. Calculate the static drillpipe pressure when the kill weight mud reaches each of the critical depths: Pstatic = Pdp x (1.1b sho ws the standpipe pressure schedule for pumping down the kill weight mud. (psi) = Vertical depth at the critical depth. Similar scenarios also occur in washouts or undulations of a horizontal hole section. water or oil) can not be determined based on the above data (as using the method described in Section 4.1b). So if the standpipe pressure schedule for a vertical well was used (dotted straight line in Figure 6. (m) iv. the drillpipe pressure and the casing pressure are the same (under-balanced kick) or both are zeros (swabbed kick) • The casing pressure is stable (no gas migration) However the kick influx density/type (gas. excessive high well pressures would result. 6-14 March 1995 1995 Rev 1 March . which is higher than the normal range of SCR during a well control operation. The problems presented can be summarised as follows: • The frictional pressure generated by circulating through the choke line may cause excessive pressures in the wellbore or in the circulating system. The main difficulties stem from the fact that the well must be killed while circulating through a small diameter choke line. that indicates that some gas is still trapped downhole. stop the pump and shut in the well to check the pitgain.6 bbl/min. bullheading is more likely to succeed in an inverted hole section. The drillpipe pressure is still used to monitor bottomhole pressure. to take account of these problems. In an 8-1/2" hole. even in relatively shallow water. The bullheading technique is described in Section 6. Repeat the previous procedures. • Reduce the flow rate to a normal SCR and proceed using one of the standard well killing techniques. In cases where the high flow rate can not be achieved to remove the trapped gas. • After one complete circulation. 7 Floating Rig Procedure Well control on a floating rig presents special problems that are not encountered on land and fixed offshore rigs. the pump pressure at a SCR corresponding to 100~150 ft/min should be recorded in the kick sheet. To remove the trapped gas. • As the mud displaces the influx from the choke line the rapid increase in hydrostatic pressure in the annulus may cause excessive pressures in the openhole. it indicates that the kick influx is free gas which has been trapped in the inverted or horizontal hole section. consider bullheading the gas back into the formation. the mud must be circulated with an annular velocity above a critical value. • If there is still a positive pit gain. The following procedures may be attempted to remove the trapped gas from the inverted or horizontal hole section: • Start circulation with the original mud at a flow rate corresponding to an annular mud velocity of 100~150 ft/min until the entire horizontal hole section has been displaced. this corresponds to a critical flow rate of 4. well control procedures should be modified in line with those described here. • The entry of the influx into the choke line may cause an uncontrollable drop in bottomhole pressure. These problems are particularly acute in deep water.2. So prior to drilling an inverted or horizontal hole section. However. As the trapped gas should stay near the kick formation. This critical annular velocity is about 100 ft/min when the hole angle is between 90~95 degrees.BP WELL CONTROL MANUAL If the kick can not be circulated to surface using the standard techniques. Well No.5 ANNULUS CONTENTS Hole/Casing Section ID 5"DP .5 304.97 303.9 Vol (bbl): 350 Eff (%): 97 Pscr 350 590 890 SPM Stroke Vol (bbl/stk): TRAVEL TIMES (MIN / STROKES) bbi/min Pscr Surface to Bit Bit to Shoe 2.9-5/8"csg 5"DP .565 Pit Gain (bbl): Total (MT): Pscr (at MW1)= 0.44 40 Max Eqiv. Pdp= Kill Mud Weight (sg).Hole Capacity (bbl/m) 8. Mud Weight (sg): On Order (MT): 13:10 Time: TD= 4291 10900 300 Casing Burst (psi): Total Reserved Mud Vol (bbl): DRILLSTRING CONTENTS DP/DC Section ID 5" DP 5" HWDP 6-1/4" DC Capacity (bbl/m) 4.1058 Shoe to Choke Total 268 / 8055 445 / 13368 201 / 8055 334 / 13368 161 / 8055 267 / 13368 KICK DATA Time of Kick: 15:25 Shut-in DP Pres (psi).0855 0.5 Surface Equipment Vol (bbl): 6 5-1/2" 5-1/2" Max Pres (psi): 831. Rig Name: 8-1/2" 1003 50 Hole Size: MAASP (psi): Barytes on Site (MT): Rigname 27-Oct-94 Date: 9-5/8" Casing Size: Shoe Depth (m): TVD= 1535 1.0161 5180 60 60 Vol (bbl) Cumulative Volume (bbl) 301.82 1.Hole 6-1/4" DC .42 4.565 3.42 4. MW1= Barytes Required (lb/bbl): SCR (bbl/min): 750 Initial Circ Pres (psi).681 8.9 6.1a An Example of Completed Kick Sheet An Example of Completed Kick Sheet Well No. Pic= 460 81.9 100 2.565 3.1605 0.25 Length (m) 0.5 837.27 STANDPIPE PRESSURE WHEN PUMPING DOWN KILL MUD Surface: Kick Off: End Build 1: TVD (m) Vol (bbl) Strokes Pstatic (psi) Pfriction (psi) 0 350 1328 350 1000 20 77 239 905 316 160 5300 1667 309 3612 0 60 Standpipe Pressure (psi) 4 15 0 0 0 =Pdp 0 Pic= 750 670 525 Pfc= 410 DP Cross-Over: End Tangent 1: End Build/Drop 2: Bit: 6-15 March 1995 .15 Annulus Pres (psi).6 142.BP WELL CONTROL MANUAL Figure 6.275 355 600 900 119 / 3567 89 / 3567 71 / 3567 58 / 1746 44 / 1746 35 / 1746 Depth (m): TVD= 1667 TD= 5300 400 1.086 30 40 50 0.276 Section Point MD (m) Length (m) Size Factor 5300 Drillpipe Friction Constant 3.708 16.98 20 55 350 psi 410 Final Circ Pres (psi).5 8. MW2= Chosen Pump SPM: Time Started: 30 15:30 Mud Weight (sg).72 0.0583 0.0287 0.0 Total Circulating System Vol (bbl): Pump 1 Liner: Length (m) 0.1 2.276 3 2.0855 Stroke Vol (bbl/stk): Eff (%): 97 PUMP 2 bbl/min 2.275 30 40 50 Cumulative Volume (bbl) Surface Active Mud Vol (bbl): 4723 4723 Max Pres (psi): PUMP 1 SPM Length (m): 1151 Vol (bbl) 688. Pa= Stroke Vol (bbl/stk): 0.3 1501 Total Active Mud Vol (bbl): Pump 2 Liner: 4291 949 60 Choke Line ID: 3. Pfc= For High Angle or Horizontal Wells ( > 30 deg) Drillpipe Size ID 5" DP + BHA 4.1506 0. 0 239 905 3612 800 6-16 Standpipe Pressure (psi) 750 750 670 525 410 750 410 700 Kick off 650 600 If The Well Was Vertical 550 500 End Build 450 400 Bit 350 0 500 1000 1500 2000 Pump Strokes 2500 3000 3500 4000 BP WELL CONTROL MANUAL Figure 6.1b An Example of Kick Sheet March 1995 STANDPIPE PRESSURE SCHEDULE . 1c: An Example of Kick Sheet SUMMARY OF FORMULAE 1. Annular Capacity (bbl/m) = (DH 2 . When MD above/at DP cross-over point: MD Pfriction = x  ID 15 8. Drillpipe size 2 6-17 March 1995 . Initial Circulating Pressure (psi). Standpipe Pressure at Depth of Interest (psi): Pstand = P scr + Pfriction + Pstatic SYMBOLS AND UNITS D wp DH DP ID L MAASP MD MW 1 MW 2 Pdp Pfc Pic Pscr Vertical depth at openhole weak point (m) Hole diameter or casing ID (inch) Drillpipe OD (inch) Drillpipe ID (inch) Length of drillpipe with same size (m) Pstand Pstatic Pwp TVD TVD h Maxi mum allowable annulus surface pressure (psi) Measured depth at depth of interest (m) Original (unweighted) mud weight (sg) Kill mud weight (sg) Shut-in drillpipe pressure (psi) Final circulating pressure (psi) initial circulating pressure (psi) Standpipe pressure at solw circulating rate with original mud (psi) Pfriction Standpipe pressure (psi) Static (drillpipe) pressure (if well was shut in) when pumping kill mud (psi) Leak off pressure at openhole weak point (psi) True vertical depth at depth of interest (m) True vertical depth of open hole (m) Drillpipe size factor Drillpipe friction constant Friction pressure increase with kill mud (psi) Subscripts for ID. When MD below DP cross-over point: (MD .Pscr Drillpipe Friction Constant. Friction Pressure Increase When Kill Mud at MD (psi): a. 1 = L 1 / ID15 Drillpipe 2 Size Factor. Kill Mud Weight (sg). Pic = P dp + P scr 7. P fc = P scr MW 2 x  MW 1 13.MW1 ) 5.1. Pipe Internal Capacity (bbl/m) = ID 2 / 313. 2 = L 2 / ID25 Pdp 4. Final circulating Pressure (psi).8 3.25 .BP WELL CONTROL MANUAL Figure 6. Pfc .MW 2) 12. Pumping Time to Reach Depth of Interest (min): Volume to be displaced (bbl) =  Pump output (bbl/min) b. Pump Strokes to Reach Depth of Interest (stk): Volume to be displaced (bbl) =  Pump stroke volume (bbl/stk) 14. MAASP = P wp . Baryte Required (lb/bbl) = 1490 x  (4.DP 2) / 313.0 .1c An Example of Kick Sheet Figure 6. 10.L1) Pfriction = x [ 1 +  ] ID 25 9.421 x TVDh 11. Static Pressure When Kill Mud at TVD (psi): Pstatic = P dp x (1. MW2 = MW 1 +  1. L and : 1 Drillpipe size 1 2.8 Drillpipe 1 Size Factor.421 x MW 1 x D wp For High Angle or Horizontal Wells 2. =  1+2 (MW2 .TVD / TVDh ) 6. m) ] DRILLSTRING / ANNULUS CONTENTS (Routinely Recorded) These include the drillstring. bbl/stk) KICK DATA Record all the relevant kick data (time. The annulus contents include hole/casing sizes (with drillstring OD). m) • Total active mud volume [bbl] = (Total circulating system vol.421 x (Mud weight in hole. sg) − (Mud weight in hole.BP WELL CONTROL MANUAL Figure 6. psi) − 1. sg) x (Leak-off TVD. Calculate circulation times and number of pump strokes: • Surf → Bit [min] = (Total drillstring volume. sg) • Barite required [lb/bbl] = 1490 x  4.8 2 • Volume [bbl] = (Capacity. Record at least three slow circulating rates and the corresponding standpipe pressures. shut-in DP & casing pressures.8 • Annulus capacity [bbl/m] = [ (Hole size. inch)2 / 313. max mud weight. shoe depths. • Drillstring capacity [bbl/m] = (Pipe ID. bbl) CIRCULATION TIME AND PUMP STROKES (Routinely Recorded) These include the liner size. bbl) [stk] = (Total casing annular volume. casing size. mud weight. The drillstring contents include OD. hole size. casing burst pressure. bbl/stk) • Bit → Shoe [min] = (Total open hole annular volume. hole/casing ID. m) • Max mud weight (Shoe frac grad) [sg] = (Leak-off pressure. hole depths. m)] (Kill mud weight. time. pit gain). annulus contents. bbl/min) / (Pump stroke volume. capacity. All the kill parameters should be calculated. • Kill mud weight [sg] = (Mud weight in hole. bbl) [stk] = (Total drillstring volume. MAASP. lb/bbl) / 2205 • Initial circulating pres P ic [psi] = (SIDPP Pdp. capacity. bbl) • Shoe → Choke [min] = (Total casing annular volume. bbl) + (Surface active mud vol. length and volume). psi) • Final circulating pres P fc [psi] = (SCR pres P scr . psi) x (Kill mud weight. inch) − (Pipe OD.1d An Example of Kick Sheet COMPLETION OF KICK SHEET GENERAL WELL DATA (Routinely Recorded) These include well No. sg) . surface volumes and the total active mud volume. bbl/min) / (Pump stroke volume. psi) + (SCR pres P scr . date. sg) 6-18 March 1995 / (Mud weight in hole.25 − (Kill mud weight. bbl) / (Pump output. bbl/m) x (Length. volume efficiency and stroke volume. inch) 2 ] / 313.421 x (Hole TVD. rig. psi) / [ 1. ID. psi) / [ 1. barite quantities and reserved mud volume. rated pressure. bbl/stk) / (Pump output. bbl) [stk] = (Total open hole annular volume. • MAASP [psi] = (Leak-off pressure. sg) • Total quantity of barite required [MT] = (Total active mud volume. sg) + [(SIDPP Pdp. length and volume. bbl/min) / (Pump stroke volume.421 x (Leak-off TVD. bbl) x (Barite required. bbl) / (Pump output. inch) 5 . psi) STANDPIPE PRESSURE SCHEDULE Draw up the standpipe pressure schedule on the graph paper by: 1. the standpipe pressure schedule can be obtained by joining a straight line between the initial and the final circulating pressures. bbl/m) x (Measured depth MD. end-tangent. β) x (MD. m) • Static (shut-in) pressure Pstatic [psi] = (SIDPP Pdp. psi) − (SCR pres P scr . Join the marked points with straight lines. etc. α = (Drillpipe section length. psi) + (∆Pfriction . 6-19 March 1995 . After the kill mud has reached the bit depth. psi) + (Pstatic . α1 ) +  (DP2 ID. drillpipe cross-over.): • Volume [bbl] = (Drillstring capacity.BP WELL CONTROL MANUAL Figure 6.If MD (point for calculation) is above or at DP1/DP2 cross-over point: ∆P friction [psi] = (DP Friction Const. • DP size factor. m) − (Top DP1 length L 1 . psi) • DP Friction Const. the initial & final circulating pressures) and therefore the pressure schedule is a straight line before the kill mud reaches the bit. m) • Pump stroke [stk] = (Volume. etc. there should be more than two points and the pressure schedule is not be a straight line . m) ] ∆P friction [psi] = β x [ (DP1 size factor. the standpipe pressure should be maintained constant at the final circulating pressure. bbl) / (Pump stroke volume. For vertical or low angle wells. inch)5 (Calculate for each of the drillpipe IDs) (Final circ pres P fc . m) / (Top drillpipe ID. psi) x [ 1. The initial circulating pressure should be plotted corresponding to zero stroke and the final circulating pressure corresponding to the strokes for the kill mud to reach the bit. end-build.0 −  ] (Hole TVD. In this case. From the final point onward (after the kill mud has reached the bit).e.If MD is below DP1/DP2 cross-over point: [ (MD. 3. m) / (Drillpipe ID. inch) 5 • Standpipe Pressure Pstand [psi] = (SCR pres P scr . Otherwise.1d An Example of Kick Sheet (cont'd) HIGH ANGLE OR HORIZONTAL WELLS (Angle > 30 deg) No need to complete this section if the well is vertical (or angle<30 deg). =  (DP Size 1 factor α1) + (DP Size 2 factor α2) Calculate the pump stroke and the corresponding standpipe pressure when the kill mud has reached the depth at MD/TVD (the point for calculation such as kick off. bbl/stk) (TVD. the standpipe pressures should be calculated for pumping down the weighted kill mud to each of the depths at kick-off. 2. there are only two marked points (i. Choose appropriate scales for the horizontal pump stroke and the vertical standpipe pressure. draw a horizontal line. m) • Friction pressure increase (due to kill mud) ∆Pfriction : . end-build. Mark each of the calculated standpipe pressures against the corresponding pump strokes. For high angle or horizontal wells. See Figure 6. In deep water. are required to account for choke line losses. When the total strokes pumped indicates that the influx is approaching the wellhead the kill line monitor should be carefully checked for any sudden drops in pressure. In which case further calculations.BP WELL CONTROL MANUAL Choke line losses are generally not significant at slow circulating rates in shallow water and so the calculations required during the implementation of both the Driller’s Method and the Wait and Weight Method on a floating rig. A drop in pressure registered on this gauge indicates that the influx has entered the choke line. Standard procedure (as detailed in Paragraphs 4 to 6) should be modified along the following lines when using either the Wait and Weight Method or the Driller’s Method on a floatingr ig: 1 Bring the pump up to speed • • Line up the pump to circulate down the drillpipe and route returns through the choke manifold to the mud gas separator. do not account for choke line losses. • Record the pressure registered on the kill line monitor. when choke line losses can be significant. 3 Circulate the influx out of the well maintaining constant bottomhole pressure It is recommended that the influx is displaced up the choke line at a considerably reduced rate in order that the choke does not have to be adjusted at an unrealistic rate. • Open the remote operated choke at the same time as the pump is started on the hole.2 for a schematicof the kill line monitor . • Set the stroke counter on the choke panel to zero. however this drop may not always be detected. as covered in Paragraph 8. In the case of the Driller’s Method the standpipe pressure is maintained at initial circulating pressure as the kick is displaced from the hole. A considerable increase in choke pressure will generally be required as gas or lightweight influx displaces mud from the choke line. 6-20 March 1995 . Circulate the kick to the wellhead maintaining constant bottomhole pressure In the case of the Wait and Weight Method the standpipe pressure will be reduced in line with the standpipe pressure schedule. (Bear in mind that the kill line may not contain mud at this stage. it is necessary to assess the effect of choke line losses on wellbore pressures during circulation.) Once the pump is up to speed the initial circulating pressure should be checked. This may involve shutting in the well at this point and restarting the displacement at the minimum pump speed. • Hold the kill line monitor pressure constant as the pump is brought up to speed. ‘Accounting for Choke Line Losses in Deep Water’. The calculations as covered in Paragraphs 4 to 6 (which cover the normal implementation of the Wait and Weight Method and the Driller’s Method) are therefore still applicable. • 2 Line up to monitor wellhead pressure through the kill line. drilling in shallow water. 030 6-21 Rev 1 March 1995 March 1995 .2 Use of Kill Line Monitor for Wellhead Pressure on Floating Rig DRILLPIPE PRESSURE GAUGE PUMP KILL LINE MONITOR CHOKE PRESSURE GAUGE VALVE OPEN VALVE CLOSED RETURNS SEA KILL LINE (KILL LINE VALVES OPEN) CHOKE LINE SEABED KEY MUD VALVE OPEN GAS VALVE CLOSED WEOX02.BP WELL CONTROL MANUAL Figure 6. • Slowly bleed back the upper annular closing pressure.) Be prepared to deal with gas in the riser. (See Figure6. Router eturns through the degasser. Fill the hole as required. stop the pump and shut in at the choke.) • Keep pumping water across the stack and maintain the final circulating pressure. • Bleed pressure from the choke line. 4 Remove BOP gas It is quite possible that some gas will have accumulated under the closed BOP duringdisplacement of the kic k.7. across the stack and up the choke line. Line up to circulate water down the kill line and up the choke line. displace the kill and choke lines to water (maintaining the BOP gas at original pressure). the pump should be stopped and the well checked for pressure. (See Figure6. This gas must be removed from the stack before the BOP is opened. Record the kill line circulating pressure. In the case of the Driller’s Method.5.6.) • Circulate kill mud down the kill line. (See Figure 6. Take returns up the choke line.8. • Displace the riser and kill and choke lines to kill weight mud. once the returns are at kill weight. this technique is implemented as follows: • Isolate the well from the BOP stack by closing the lower pipe rams. bleed gas up choke line. In the case of the Wait and Weight Method. the well will be circulated to kill weight mud prior to step (4). • Allow the riser to U-tube.4. (See Figure 6. for which trapped gas has the potential to be a serious problem. • Slowly displace the kill line to water.) For the example stack shown in Figure 6. Open the annular. open the annular and allow riser to U-tube. (Adequate facilities should be available to deal with the returned diesel.) • Close the diverter.BP WELL CONTROL MANUAL An increase in the pressure recorded at the kill line monitor may indicate that the original mud behind the influx has started up the choke line.) • Close the subsea kill line valve(s).W hen the returns are clear water. (SeeFigure 6.) • Shut the well in. Line up the trip tank/pump to circulate the riser under the diverter. The recommended technique is to isolate the well. Diesel may be used instead of water if low mud weights have been used to kill the well. Having bled all the pressure from the choke line the gas bubble should be almost at atmospheric pressure. (This will ensure that the gas pressure is unchanged.4. As the kill line is displaced to water increase the kill line circulating pressure by an amount equal to the difference in hydrostatic pressure between the kill mud and water at the depth of the stack. displacing the gas up the choke line. 6-22 March 1995 .) (The pressure that has been trapped in the gas bubble is used to ensure that the gas bubble expands as the choke is opened to displace all the water from the choke line. In most cases this will occur only when the original mud behind the influx is passing the choke. However Case B represents a situation in which part of the choke line frictional pressure will be applied on the openhole. (See Figure 6.BP WELL CONTROL MANUAL • Open the lower pipe rams. at which time subsurface pressures are unlikely to be critically high. This is most likely to occur only in deep water.10. the choke line losses should not impose a limitation on the circulation rate. the additional pressure acting in the wellbore due to choke line friction should be estimated at a range of circulating rates. The additional pressures exerted in the wellbore due to choke line losses at pump startup can be determined as follows: For Case A: there should be no additional pressures in the wellbore due to choke line friction at pump start-up For Case B: additional wellbore pressure due to choke line friction = Pcl – Pa + Poc where: = annulus shut-in pressure (psi) = choke pressure at SCR recorded with the choke wide open (psi) = choke line frictional pressure at SCR (psi) Pa Poc Pcl 6-23 March 1995 . However.9. (See Figure 6.) In Case A the choke line friction pressure will be fully compensated for until such time during the displacement that the required choke pressure is less than the sum of choke line friction pressure and the wide open choke pressure. Section 1.) The following procedure can be used to account for choke line losses for the Wait and Weight Method (however the same principles are applicable to the Driller’s Method): 1 Assess the effect of choke line losses at pump start up In order to determine the most suitable circulation rate. 8 Accounting for Choke Line Losses in Deep Water In line with the standard procedure for floating rigs. the effect of choke line losses should be assessed in any situation in which choke line losses are considered significant. • Open the diverter and flowcheck the well.3 for the techniques for measuring choke line pressure losses.) Case B: When the shut-in casing pressure is less than the choke line friction pressure at the desired slow circulation rate. (See Chapter 1. The following two cases may be applicable at this point: Case A: When shut-in casing pressure is greater than the choke line friction pressure at the desired slow circulating rate. if Case A is applicable. an attempt will always be made to compensate for choke line losses with the use of the kill line monitor. Therefore. The choke line frictional pressure can be compensated for up to the amount equal to the difference between the shut-in annulus pressure and the wide open choke pressure. 3 Subsea BOP Stack prior to Removing Gas from Below the Preventers KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.BP WELL CONTROL MANUAL Figure 6.031 6-24 March 1995 . 4 Removing Gas from a Subsea BOP Stack – Lower pipe rams closed hang off rams opened KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.BP WELL CONTROL MANUAL Figure 6.032 6-25 March 1995 . BP WELL CONTROL MANUAL Figure 6.033 6-26 March 1995 .5 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to kill weight mud KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02. BP WELL CONTROL MANUAL Figure 6.034 6-27 March 1995 .6 Removing Gas from a Subsea BOP Stack – Kill and choke lines displaced to water KILL LINE CHOKE LINE MUD GAS UPPER ANNULAR WATER (OR DIESEL) VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02. gas occupies choke line KILL LINE CHOKE LINE MUD UPPER ANNULAR GAS WATER (OR DIESEL) VALVE OPEN VALVE CLOSED GAS PRESSURE BLEEDS DOWN TO DISPLACE WATER FROM CHOKE LINE RESULTANT GAS PRESSURE IS CLOSE TO ATMOSPHERIC LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02.035 6-28 March 1995 .BP WELL CONTROL MANUAL Figure 6.7 Removing Gas from a Subsea BOP Stack – Gas pressure bled down. BP WELL CONTROL MANUAL Figure 6.8 Removing Gas from a Subsea BOP Stack – Diverter is closed.036 6-29 March 1995 . the annular is opened and the gas is displaced from the stack KILL LINE CHOKE LINE MUD GAS UPPER ANNULAR WATER (OR DIESEL) VALVE OPEN VALVE CLOSED LOWER ANNULAR BLIND/SHEAR PIPE RAM PIPE RAM PIPE RAM PIPE RAM WEOX02. 037 6-30 March 1995 .BP WELL CONTROL MANUAL Figure 6.9 The Effect of Choke Line Losses – Casing pressure greater than choke line pressure INITIAL SHUT-IN CONDITIONS CIRCULATION STARTED AT 40SPM CHOKE PRESSURE DROPS BY CHOKE LINE PRESSURE DROP DRILLPIPE PRESSURE INCREASES BY SCR PRESSURE 800 400 800 800 1385 430 KILL LINE PRESSURE HELD CONSTANT BOTTOMHOLE PRESSURE STAYS APPROXIMATELY CONSTANT KEY MUD GAS SCRS AND CHOKE LINE LOSSES SPM 20 30 40 PSCR 400 680 985 PCL 150 250 370 MINIMUM RATE FOR PUMP WEOX02. 038 6-31 March 1995 .10 The Effect of Choke Line Losses – Casing pressure after initial circulation is less than choke line loss INITIAL SHUT-IN CONDITIONS CIRCULATION STARTED AT 30SPM CHOKE PRESSURE DROPS BY CHOKE LINE PRESSURE DROP DRILLPILE PRESSURE INCREASED BY SCR PRESSURE 400 100 400 400 780 150 KILL LINE PRESSURE HELD CONSTANT BOTTOMHOLE PRESSURE STAYS APPROXIMATELY CONSTANT INFLUX CIRCULATED OUT WITH ORIGINAL MUD WEIGHT CIRCULATION STARTED AT MINIMUM RATE.BP WELL CONTROL MANUAL Figure 6. 20SPM DRILLPIPE PRESSURE EQUALS THE SUM OF THE ORIGINAL SHUT-IN DRILLPIPE PRESSURE PLUS THE SCR PRESSURE PLUS THE CHOKE LINE LOSS PLUS THE WIDE OPEN CHOKE PRESSURE MINUS THE SHUT-IN CASING PRESSURE 100 100 100 200 CHOKE PRESSURE WITH CHOKE WIDE OPEN 600 50 UNABLE TO KEEP THE KILL LINE PRESSURE CONSTANT. EVEN WITH THE CHOKE WIDE OPEN THE KILL LINE PRESSURE INCREASES BY THE SUM OF CHOKE LINE LOSS AND WIDE OPEN CHOKE PRESSURE MINUS THE ORIGINAL SHUT-IN PRESSURE BOTTOMHOLE PRESSURE INCREASES SCRS AND CHOKE LINE LOSSES SPM 20 30 40 PSCR 400 680 985 PCL 150 250 370 MINIMUM RATE FOR PUMP KEY MUD GAS WEOX02. the displacement should be continued. For Case B. (The increase will be equivalent to Pcl + P oc – P a.) 5 Check the initial circulating pressure once the pump is up to speed If the initial circulating pressure is significantly different from the calculated value. The effect of these additional pressures must therefore be analysed at all points in the system and in particular at the openhole weak point. for each case is calculated as follows: For Case A: Final circulating pressure = Pscr X For Case B: Final circulating pressure = (Pscr where X MW2 MW1 MW2) + Pcl + Poc – P a MW1 MW2 = weight of the kill mud (SG) MW1 = weight of the original mud (SG) 4 Monitor pressure at the kill line monitor as the pump is brought up to speed For Case A. If the initial circulating pressure is equal to or reasonably close to the calculated value. The actual SCR pressure can be established from the initial circulating pressure recorded when the pump is up to speed.BP WELL CONTROL MANUAL These pressures as well as the annulus frictional pressure will act at all points in the wellbore and circulating system. Any marginal difference is likely to be due to the fact that the actual SCR pressure is different from the value used to calculate the initial circulating pressure. when kill weight mud reaches the bit. 6-32 March 1995 . Once the pump is up to speed the choke will be wide open and the pressure at the kill line monitor will have risen by the proportion of the choke line friction pressure that is not compensated for. the pressure at the kill line monitor will be constant as the pump is brought up to speed. the pump should be stopped. the pressure at the kill line monitor is held constant as the pump is brought up to speed. However at some point before the pump is up to the SCR the kill line monitor pressure will start to increase. The choke pressure will decrease by an amount equivalent to the choke line friction pressure once the pump is up to speed. For Case A: For Case B: the initial circulating pressure = Pdp + P scr + P cl + P oc – P a where: 3 the initial circulating pressure = Pdp + P scr = show circulating rate pressure (psi) = shut-in drillpipe pressure that reflects the kick zone pressure (psi) = choke line frictional pressure at SCR (psi) = annulus shut-in pressure (psi) = choke pressure recorded while circulating at SCR with the choke wide open (psi) Pscr Pdp Pcl Pa Poc Calculate the final circulating pressure The final circulating pressure. 2 Calculate the initial circulating pressure The initial circulating pressure is calculated to estimate the standpipe pressure once the pump is up to speed. the well shut in and the cause for the discrepancy determined. It should be noted that the most critical period in terms of downhole pressures is likely to occur at early stages in the displacement. In this respect the change in choke line loss compensation at latter stages in the displacement is unlikely to be a critical factor. This drop will be most significant once the original mud behind the influx is at the choke. 6 Assess the effect of choke line losses at the latter stages of kick displacement For Case A: In the latter stages of the displacement the choke pressure required to maintain constant bottomhole pressure will drop. If the required choke pressure increases to a value equal to the sum of the choke line loss and the wide open choke pressure it will be possible to compensate for the complete amount of the choke line losses. If the required choke pressure drops below the sum of the choke line loss and the wide open choke pressure.BP WELL CONTROL MANUAL For Case A. As the required choke pressure increases it will be possible to compensate for a greater proportion of the choke line losses. For Case B: As the influx expands the choke pressure required at surface will increase. it will no longer be possible to completely compensate for the choke line losses. the circulating pressure will have increased by the sum of the choke line losses and the wide open choke pressure. the final circulating pressure can be determined as follows: Pfc = Pscr X MW2 MW1 For Case B. 6-33/34 6-33 March 1995 . the actual SCR pressure can be determined as follows: P scr = Pic – P dp – P cl – P oc + P a For the Wait and Weight Method the final circulating pressure must be recalculated as follows: For Case A. the choke will be wide open at this stage and the standpipe pressure will rise above final circulating pressure. the actual SCR pressure can be determined from the initial circulating pressure as follows: P scr = Pic – P dp For Case B. The resultant increase in wellbore pressure at this stage will be given by: Increase in pressure = Pcl + P oc – P a In practice. When the hole has been circulated to kill weight mud. the final circulating pressure is determined as follows: Pfc = (Pscr X MW2)+ Pcl – P a + Poc MW1 The standpipe pressure should therefore be redrawn to take into account these adjusted figures. 1 VOLUMETRIC METHOD 6-37 2.5 BARYTE PLUGS 6-89 2.4 SNUBBING 6-79 2.2 STRIPPING 6-51 2.2 SPECIAL TECHNIQUES Subsection Page 2.3 BULLHEADING 6-71 2.BP WELL CONTROL MANUAL 6.6 EMERGENCY PROCEDURE 6-97 6-35/36 6-35 March 1995 . 1 VOLUMETRIC METHOD Paragraph Page 1 General 6-38 2 Static Volumetric Method (Drillpipe pressure used to monitor bottomhole pressure) 6-38 Static Volumetric Method (Choke pressure used to monitor bottomhole pressure) 6-40 4 Lubrication 6-46 5 Dynamic Volumetric Control 6-47 3 Illustrations 6.14 Volumetric Control Worksheet – an example for a land rig 6-44 6.13 Static Volumetric Control – illustrating the consequences of improper procedure 6-43 6.12 Static Volumetric Method – an example of control of bottomhole pressure at the choke 6-42 6.2 SPECIAL TECHNIQUES Subsection 2.15 Static Volumetric Method – choke pressure used to monitor bottomhole pressure 6-45 6.BP WELL CONTROL MANUAL 6.16 Dynamic Volumetric Method – used to remove gas from below a stack 6-49 6-37 March 1995 . There are four techniques that may be required to deal with an influx that is migrating up the hole. • If there is a washout in the drillstring that prevents displacement of the kick. 2 Static Volumetric Method (Drillpipe Pressure used to monitor bottomhole pressure) This procedure is the most simple to implement in that the drillpipe pressure is available to monitor bottomhole pressure. This situation may arise while preparations are being made to kill a well or when operations have to be suspended due to bad weather or equipment failure.BP WELL CONTROL MANUAL 1 General The Volumetric Method can be used to control the expansion of an influx that is migrating during shut-in periods. or as a means of safely venting an influx from a well in which circumstances prevent the implementation of normal well control techniques. • Lubrication: When the influx has migrated to the stack this technique is used to replace the influx with mud as the influx is bled at the choke. • Static Volumetric Control: When the drillpipe cannot be used to measure bottomhole pressure. These are as follows: • Static Volumetric Control: When the drillpipe is on or near bottom and can be used to measure bottomhole pressure. • If the pipe is a considerable distance off bottom. out of the hole or stuck off bottom. • If the pumps are inoperable. • If the pipe has been dropped. Situations in which the Volumetric Method may be applicable therefore include: • During any shut-in period after the well has kicked. This method can be used during shut-in periods prior to displacement. • If the bit is plugged. It can therefore only be used if significant migration is occurring. 6-38 March 1995 . The following Paragraphs can be used as guidelines for the implementation of the above mentioned procedures. • Dynamic Volumetric Control: This technique may be used as an alternative to the above but is most applicable as an alternative to lubrication on a floating rig. It may be necessary to implement this procedure during any time that the well is shut-in after a kick has been taken. This may occur only in the case of gas kicks. The operating margin may also typically be in the range 50 – 200 psi depending on the resultant wellbore pressures at each stage in the operation. This margin will be registered on the drillpipe as an increase in pressure over and above the final shut-in pressure. These calculations are covered in Chapter 4. The distance D (m). further increases will be due to migration.421 where P1 P2 MW T MR = = = = = (m) surface pressure at start of interval (psi) surface pressure after interval T (psi) mud weight in the hole (SG) time interval (min) migration rate (m/hr) The migration rate can therefore be estimated as follows: MR = D X 60 (m/hr) T 4 Allow drillpipe pressure to build by overbalance margin The drillpipe pressure should be allowed to build by a suitable overbalance margin. In this respect. recorded either both on the drillpipe or both on the casing. The maximum wellbore pressures can therefore be estimated along with the anticipated pit gain. it will be necessary to allow the influx to expand considerably as it migrates up the hole. taken at a known time interval apart. 3 Determine migration rate After the surface pressures have built up to values which reflect the kick zone pressure. The overbalance margin may typically be in the range 50 to 200 psi. If the influx contains a significant proportion of gas. The rate of migration can be estimated from two pressure readings. 6-39 March 1995 . a PC or programmable calculator can be used to develop the annulus pressure profile as for the Driller’s Method. migrated up the annulus of constant cross section in the time interval T (min) is given by: D= P2 – P1 MW X 1. 5 Allow drillpipe pressure to build up by operating margin The drillpipe pressure should be allowed to build by a further margin to ensure that the overbalance is maintained as mud is bled from the well.BP WELL CONTROL MANUAL The following guidelines can be used: 1 Record the shut-in drillpipe and choke pressures After the well has been shut-in the surface pressures can be used to identify the influx type. 2 Develop annulus pressure profile The annular pressures during migration of the influx will be similar to those resulting from circulation with the Driller’s Method. A manual choke should be used for this operation to ensure adequate control. Mud should then be bled from the annulus to reduce the drillpipe pressure to a value representing the final shut-in pressure plus the overbalance margin. The choke pressure is therefore used in conjunction with the volume of mud bled from the well to infer the bottomhole pressure. The principle of this procedure is that the bottomhole pressure is maintained slightly over kick zone pressure by bleeding mud from the annulus to allow the influx to expand as it migrates up the hole. When the influx has migrated to the stack. It is strongly recommended that small volumes of mud are bled off at a time to allow time for the drillpipe pressure to respond. if gas is observed at the choke.14. There will be a considerable delay time between choke and drillpipe pressure in a deep well and especially if the influx contains gas. However. 7 Continue process until influx migrates to the stack This process should be repeated until the influx migrates to the stack. out of the hole or too far off bottom to be stripped back or if the bit is plugged. 3 Static Volumetric Method (Choke pressure used to monitor bottomhole pressure) This technique may be required if the drillstring is stuck off bottom.) 8 Lubricate mud into the hole or implement the Dynamic Volumetric Method See Paragraphs 4 and 5 as follows. Use the Volumetric Control Worksheet to record all the relevant data (See Figure 6. surface pressures should no longer rise as migration will cease to occur. Arrival of the influx at the stack may be preceded by bleeding gas cut mud from the well. In these cases. 6-40 March 1995 . the kick zone will be overbalanced by the sum of these two values. the well should be shut-in and mud lubricated into the well. If gas is bled from the well the bottomhole pressure will drop and eventually cause a further influx. This may not be the case on a floating rig when some migration may occur up the choke line. Mud is bled in increments from the well as the choke pressure rises due to migration. it will not be possible to monitor the bottomhole pressure with the drillpipe during the control process. The amount of mud bled off for each increment is determined from the increase in choke pressure.BP WELL CONTROL MANUAL 6 Bleed increment of mud from the annulus to reduce drillpipe pressure After the drillpipe pressure has built by the sum of the overbalance margin and the operating margin. 1 bbl. this would cause a further influx of 8. as shown in Figure 6. It can be calculated as follows: Hydrostatic pressure per barrel = 445. Hydrostatic equivalent of mud = 445. The resultant wellbore pressures as well as the required pit gain will be similar for the two techniques. Mud weight = 1. The rate of influx migration determines the time required to bleed each increment of mud from the well. control over the bottomhole pressure is achieved.BP WELL CONTROL MANUAL For example.25 – 25) = 17. In this manner. The following guidelines can be used: 1 Record shut-in choke pressure 2 Develop annulus pressure profile 3 Determine migration rate The first three steps are carried out in the same manner as for the previous technique.12. It should be noted that this method is only applicable if the influx is migrating as the mud is bled from the well .12 illustrates this technique.4 bbl before the bottomhole pressure drops to the original kick zone pressure.) do = drillstring OD (in. a volume of mud equivalent to a hydrostatic pressure in the annulus of 100 psi is bled at the choke at constant choke pressure.5 As can be seen from Figure 6. if the choke pressure increases by 100 psi. In this example.5 bbl of mud 17. If the remaining 8. this time will continually reduce until the influx is at surface.85 SG X 5 in. It is clear that this operation will take several hours. the following conditions apply: Operating margin = 150 psi Annulus = 8 1/2 in.5 bbl of mud is bled from the well.13.5 bbl increment from the well will decrease significantly.5 psi/bbl Therefore bleed 150 = 8. If the rate of influx migration is maintained. the time required to bleed the 8. Figure 6. If the operating margin was quickly bled from the well.1 bbl were bled from the well.85 (72. the influx must migrate (1824 – 133 =) 1691m while the 8. As the influx migrates further up the hole. the original influx would expand by approximately 0. 4 Calculate hydrostatic pressure of mud per barrel The hydrostatic pressure of the mud per barrel should be calculated at the point in the annulus directly above the influx. In this example.7 X MW (d hc 2 – d o2 ) (psi/barrel) where MW = mud weight in the hole (SG) dhc = hole/casing ID (in.7 – 1.) 6-41 March 1995 . Volumetric control is similar to the Driller’s Method although the influx moves up the hole under the influence of migration. the influx must migrate 570m (approximately 2 hours) as the next increment is bled from the well. 5bbl BLED OFF WHILST HOLDING CHOKE PRESSURE CONSTANT 1000psi Pa 1000psi Pa PRESSURE IN BUBBLE NOW 5405psi PRESSURE IN BUBBLE 10.350psi T = 25 min MUD BLED AT CONSTANT CHOKE PRESSURE BHP = 10. INCREASE IN SURFACE PRESSURE FOR OVERBALANCE MARGIN 850psi Pa 650psi Pa PRESSURE IN BUBBLE 10.039 6-42 March 1995 .BP WELL CONTROL MANUAL Figure 6.200psi T = 6 hours WEOX02.000psi BHP = 10.200psi T=0 T = 15 min (assuming migration rate of 300m/hr) 3.5bbl VOLUME OF INFLUX 10bbl KEY 1824m MUD 133m GAS BHP = 10. INCREASE IN SURFACE PRESSURE FOR OPERATING MARGIN 4. 8.12 Static Volumetric Method – an example of control of bottomhole pressure at the choke 1.000psi HEIGHT OF INFLUX 66m VOLUME OF INFLUX 10bbl VOLUME OF INFLUX 10bbl DEPTH 3615m 76m BHP = Pf = 10.000psi VOLUME OF INFLUX 18. AT INITIAL SHUT-IN 2. 6 Allow choke pressure to build by operating margin The choke pressure should be allowed to continue building a further similar amount to provide an operating margin.5bbl BLED OFF INSTANTANEOUSLY.000psi T 25 min BHP DROPS BELOW 10. 8. 6-43 March 1995 . BLEED MUD FROM WELL INSTANTANEOUSLY 4a. The total margin will depend on the resultant wellbore pressures at each stage in the operation.4bbl VOLUME OF INFLUX = 10.4bbl VOLUME OF SECONDARY INFLUX = 8. WELL SHUT-IN Pa DROPS BELOW 1000psi Pa > 1000psi VOLUME OF INFLUX = 10.BP WELL CONTROL MANUAL 3a.13 Static Volumetric Control – illustrating the consequences of improper procedure 5 Allow choke pressure to build by overbalance margin The choke pressure should be allowed to build by an overbalance margin that may typically be in the range 50 – 200 psi.000psi BHP = 10. 7 Bleed increment of mud from the well at constant choke pressure A suitable volume of mud should be bled from the well to reduce the bottomhole pressure by an amount equivalent to the operating margin.1bbl BHP = 10.040 Figure 6.000psi T 25 min KEY MUD GAS WEOX02. ve underbalance .85 HYDROSTATIC PRESSURE PER BARREL OF sg MUD in 5 X sg MUD in 8.5 Bleed Mud at Choke 1150 0 -150 200 8.85 .5 117 Influx Migrating 1300 150 0 350 0 117 3:30 / 4:45 4. 1 of BP Well Control Manual min) 19:00 OPERATING MARGIN: Choke or DP Choke Monitor Pressure (psi) Change in Monitor Pressure (psi) 150 Hydrostatic of Mud Bled/ Lubricated (psi) (psi) Volume of Mud Bled/ Lubricated (bbl) Time (min) P2 0 0 100 0 200 0 100 19:25 Influx Migrating 1000 150 0 350 0 100 Bleed Mud at Choke 1000 0 -150 200 8.2311 Total Volume of Mud (bbl) 200 3:30 20 5 Rate.85 15:30 LUBRICATING MUD WEIGHT. (mpm) 850 1:35 0 Overbalance 2 Influx Migrating 1:35 / 3:15 0 Migration Rate 19:15 19:25 / 01.14 Volumetric Control Worksheet – an example for a land rig VOLUMETRIC CONTROL WORKSHEET For worksheet calculation enter information into shaded cells.25 650 1 1.5 Bleed Mud at Choke 1450 0 -150 200 8. WELL NO 26 RIG UK Units (US/UK): Rig 10 Version 1/1 1Q'95 by ODL/C.BP WELL CONTROL MANUAL Figure 6.199 6-44 March 1995 11.ve bled + ve overbalance + ve bled + ve lubricated .ve decrease . Weddle DATE AND TIME MUD WEIGHT IN THE HOLE. sg HYDROSTATIC PRESSURE PER BARREL OF 1.5 Influx Migrating 1150 150 0 350 0 108. (m) 3.5 125.5 X 20/08/95 SHEET NO ANNULUS: 17.46 psi/bbl ANNULUS: psi/bbl HYDROSTATIC PRESSURE PER BARREL OF sg MUD in HOLE: psi/bbl HYDROSTATIC PRESSURE PER BARREL OF sg MUD in HOLE: psi/bbl P1 psi Distance.5 Influx Migrating 1450 150 0 350 0 125. sg 1.ve lubricated WEOX02.5 108.743701 OVERBALANCE MARGIN: TIME ( hr 200 psi OPERATION If DP pressure can't be read see page 6-36 of Vol.:55 4:55 / 5:30 Bleed Mud at Choke 1300 0 -150 200 8.5 134 + ve increase . 13): Operating margin = 150 psi Annulus = 8 1/2 in.5 bbl of mud. This could take considerable time.5 bbl).15 Static Volumetric Method – choke pressure used to monitor bottomhole pressure 6-45 March 1995 . had been quickly bled off and assuming no migration during this period. Subsequent volumes bled from the well will require less migration distance.5 bbl of mud As can be seen from the example in Figure 6.12 the bottom of the influx has had to migrate from 133m off bottom. whilst bleeding off 8. ie for anincrease of bubble size to 27 bbl (after next bleed off). Mud weight = 1.7 – 1.5 34 42.041 Figure 6. This would result in a further influx of 8. As an example (refer to Figures 6. to 1824m off bottom. the distance from bottom will be 2395m.36/bbl before bottomhole pressure (BHP) dropped to kick zone pressure. in this case 150 psi (8.14 bbl.5 51 59.5 17 25.85 SG Hydrostatic equivalent of mud = Therefore bleed 150 17. X 5 in.5 VOLUME OF MUD BLED FROM ANNULUS (bbl) WEOX02.5 445. the bubble would have expanded by only about 0. If the operating margin.5 psi/bbl (72.12 and 6. 2200 GAS MIGRATING TO SURFACE PRESSURE BUILDUP 2050 INFLUX MIGRATING 1900 1750 MUD BLED AT CHOKE (at constant choke pressure until volume bled off corresponds to Operating Margin) CHOKE PRESSURE (psi) 1600 1450 OPERATING MARGIN 1300 1150 OPERATING MARGIN 1000 OPERATING MARGIN 850 OVERBALANCE MARGIN 650 FINAL SHUT-IN ANNULUS PRESSURE 0 8.25 – 25) = 8.85 = 17.BP WELL CONTROL MANUAL The choke pressure must be held constant as the mud is bled from the well.5 68 76. When the influx has migrated to the stack it is quite possible that the choke line will become full of gas cut mud. The following guidelines can be used to lubricate mud into a well: 1 Calculate the hydrostatic pressure per barrel of the lubricating mud This is done in the same manner as for the Volumetric Method. However lubrication is simpler to implement than the Dynamic Volumetric Method. Figure 6. For this reason alone. At this point the pump should be stopped and the well shut in. Lubrication is most suited to fixed offshore and land rigs. Use the Volumetric Control Worksheet to record all the relevant data. 6-46 March 1995 . the pump should be started slowly on the hole. It can be used to vent gas from the stack after implementing the Static Volumetric Method. This may not be the case on a floating rig when some migration may occur up the choke line. Having determined the safe upper limit for the surface pressure. it may be feasible to circulate the influx out of the hole when the influx has migrated to the bit. as well as to reduce surface pressures prior to an operation such as stripping or bullheading. Mud should be lubricated into the well until pump pressure reaches a predetermined limit. Lubrication is likely to involve a considerable margin of error when implemented on a floating rig because of the complication of monitoring the bottomhole pressure through the choke line. The well should be left static for a period while the gas migrates through the mud that has been lubricated into the well.BP WELL CONTROL MANUAL 8 Continue the process until the influx migrates to the stack This process should be repeated until the influx migrates to the stack.15 for a typical choke pressure schedule for the Static Volumetric Method. If this process has been implemented because the pipe was off bottom. When the influx has migrated to the stack surface pressures should no longer rise as migration will cease to occur.14 shows a completed example. In this situation it is impractical to attempt to maintain control of the bottomhole pressure with the choke. it may be considered for use on a floating rig. See Figure 6. 9 Lubricate mud into the hole or implement the Dynamic Volumetric Method See Paragraphs 4 and 5. 2 Slowly lubricate a measured quantity of mud into the hole Line up the pump to the kill line. 4 Lubrication This technique may be used to vent the influx from below the stack while maintaining constant bottomhole pressure. However. Returns should be lined up through the mud gas separator to the trip tank to ensure that any volume of mud bled back with the gas is recorded and accounted for. If the surface pressure increased as the mud was lubricated into the well. the final choke pressure will reflect the degree of underbalance. Experience has shown that the Dynamic Volumetric Method is the most reliable method of venting gas from a subsea stack. shut the well in and let the gas percolate through the mud. the choke pressure should eventually reduce to zero. it should only be used only as a method of safely venting an influx from below a subsea stack.BP WELL CONTROL MANUAL The exact amount of mud lubricated into the well should be closely monitored. the amount that the pressure increased should be bled back in addition. if the mud weight in the hole is insufficient. In this case. It should be possible to reliably detect changes of the order of one barrel. whilst the surface pressure and pit gain are controlled with the choke. It will then be necessary to kill the well. If the influx was swabbed into the well and the mud weight is sufficient to balance formation pressures. 4 Repeat this procedure until all the influx has been vented from the well This procedure should be repeated until all the gas has been vented from the well. This will ensure that the pressure at the stack is accurately monitored during the operation. circulation is maintained across the wellhead. 3 Bleed gas from the well Gas should be bled from the well to reduce the surface pressure by an amount equivalent to the hydrostatic pressure of the mud lubricated into the well. The principle of the procedure is identical to the Static Volumetric Control. It is likely that it will be necessary to reduce the volume of mud lubricated into the well at each stage during this procedure. the well should be isolated and the kill line circulated to mud. Having identified that the influx is at the stack. The kill line pressure is used to monitor the well. due to both the complexity of the operation and the level of stress imposed on well control equipment during circulation. 5 Dynamic Volumetric Control This technique can be used as an alternative to the Static Volumetric Method. However. if the drillpipe cannot be used to monitor bottomhole pressure. Ensure that no significant quantity of mud is bled from the well during this operation. however the implementation is considerably different. the following guidelines can be used to implement the Dynamic Volumetric Method: 1 Ensure that the kill line is full of mud If there is any possibility that the kill line contains gas. If mud appears at the choke before the surface pressure has been reduced to its desired level. It is very important that the active tank be a suitable size to resolve very small changes in level. 6-47 March 1995 . This is due to the reduction in volume of gas in the well. the pit level will drop while the choke operator adjusts the choke to maintain a constant kill line circulating pressure. If the kill line circulating pressure is held constant as mud is lubricated into the well (as gas is removed). Mud weight = 1. the kill line pressure will inevitably increase by more than the kill line pressure loss. As an example: Drop in pit level = 10 bbl Annulus = 8 1/2 in. X 5 in. the final circulating kill line pressure will be equal to the sum of the kill line pressure loss. the final circulating kill line pressure will be greater than this value.5 psi/bbl Therefore reduce kill line circulating pressure by 17. If the well has been completely killed by removing gas from the stack. the kill line pressure should be reduced to account for the greater hydrostatic pressure in the annulus.5 X 10 = 175 psi This procedure should be continued until all the influx has been vented from below the stack. See Figure 6. the bottomhole pressure will increase. This will result in mud being lubricated into the well.25 – 25) = 17. the kill line (or pump pressure) must increase by an amount equal to the kill line pressure loss.7 X 1. the choke line pressure loss and the wide open choke pressure. This will be indicated by a constant pit level.16 for an example kill line pressure schedule for this technique. 4 Reduce kill line pressure in line with drop in pit level As gas is bled from the well.85 (72. Route returns through the mud gas separator. If the well is not yet completely killed at this point.85 SG Hydrostatic equivalent of mud = 445. The kill line circulating pressure will be monitored during the operation to remove gas from the well. Therefore. as the pit level decreases. 6-48 March 1995 .BP WELL CONTROL MANUAL 2 Circulate down the kill line and up the choke line Ensure that it is possible to monitor the active pit level accurately. 3 Bring the pump up to speed As the pump is brought up to speed. However if it is not possible to compensate for the choke line pressure loss. MUD IS LUBRICATED IN ORIGINAL KILL LINE PRESSURE ONCE PUMP IS UP TO SPEED SLOPE OF LINE = HYDROSTATIC PRESSURE PER BARREL OF MUD GAIN IN PIT LEVEL ORIGINAL PIT LEVEL ONCE PUMP IS UP TO SPEED DROP IN PIT LEVEL CHANGE IN PIT LEVEL (bbl) WEOX02.BP WELL CONTROL MANUAL Figure 6.16 Dynamic Volumetric Method – used to remove gas from below a stack KILL LINE PRESSURE (psi) (PIT GAIN TO ALLOW FOR GAS EXPANSION) GAS IS REMOVED FROM THE WELL.042 6-49/50 6-49 March 1995 . 26 Equipment Rig-up for Dynamic Stripping 6-68 6-51 March 1995 .2 STRIPPING Paragraph Page 1 General 6-52 2 Monitoring Well Pressures and Fluid Volumes 6-52 3 Annular Stripping 6-56 4 Annular Stripping Procedure 6-57 5 Ram Combination Stripping 6-59 6 Ram Combination Stripping Procedure 6-61 7 Dynamic Stripping Procedure 6-67 Illustrations 6.17 A Guide to Interpretation of Surface Pressure Changes during Stripping 6-54 6.19 Surge Dampener Fitted to the Closing Line of an Annular BOP 6-57 6.22 to 6.BP WELL CONTROL MANUAL 6.21 Surface BOP Stack Suitable for Ram Combination Stripping 6-62 6.18 The Effect of the Pipe/BHA Entering the Influx 6-55 6.20 Example Stripping Worksheet – showing effect of migration and BHA entering the influx 6-60 6.2 SPECIAL TECHNIQUES Subsection 2.25 Annular to Ram Stripping 6-63 to 6-66 6. • The organisation and supervision of the drillcrew. Stripping places high levels of stress on the BOPs and the closing unit. • Controlling increases in wellbore pressure due to surge pressure. 6-52 March 1995 .BP WELL CONTROL MANUAL 1 General Stripping is a technique that can be used to move the drillstring through the BOP stack when the well is under pressure. 2 Monitoring Well Pressures and Fluid Volumes During stripping operations. (Drillpipe rubbers should be removed and any burrs smoothed out.2 in Chapter 5 for a decision analysis related to stripping operations. • Wellbore pressures in relation to the maximum allowable pressure for equipment and the formation. The equipment required for this operation is described in Chapter 1.) • The procedure to be adopted in the event that the surface pressure approaches the maximum allowable as the pipe is stripped into the influx. See Figure 5. (This information should be available at the rig site. • Wear on BOP elements and the control unit. a constant bottomhole pressure is maintained by carefully controlling the surface pressure and the volume of mud bled from or pumped into the well. and requires a particularly high level of co-ordination within the drillcrew. ’Instrumentation and Control’. • The monitoring of pressure and fluid volumes. • The level of redundancy in the BOP and the control system. • Manufacturers’ information regarding minimum closing pressures for annular preventers. • The control of influx migration. This Section is intended to aid in the drawing up of this contingency plan and as such the following are proposed as the most important considerations: • How to move the tool joint through the BOP. • The condition of the drillpipe.) • The possibility of sticking the pipe. Company policy is that a contingency plan must be developed regarding stripping procedure for both Company operated rigs and rigs that are under a Company contract. However it is recognised that there may be situations when it is impractical to bleed mud from the well at connections. When the BHA is run into the influx. Such situations include: • If the surface pressures are close to maximum allowable prior to the stripping operation. It is recommended that mud is bled from the well during each connection. the height of the influx will be considerably increased. Influx migration is indicated by a gradual increase in surface pressure even though the correct volume of mud is being bled from the well (however this may be due to the BHA entering the influx). This can cause a significant decrease in hydrostatic pressure in the annulus. requiring a greater surface pressure to maintain a constant bottomhole pressure (See Figure 6. This is in addition to the volume of mud bled from the well when introducing the pipe into the hole.17). To compensate for influx migration. This ensures that there is a clear indication at surface of the BHA entering the influx.BP WELL CONTROL MANUAL Accurate monitoring of the well is required for the following reasons: (a) To compensate for the volume of pipe introduced into the hole To avoid over pressuring the well. It is confirmed by increasing surface pressure when the pipe is stationary (See Figure 6. • If a high pressure water kick is taken. a volume of mud equal to the volume of pipe and tool joints (the volume of metal plus the capacity) introduced into the well. the required volume of mud will be very small in comparison to the volume bled off to compensate for the introduction of pipe into the hole. it is necessary to bleed mud from the well. • If the pipe has to be stripped out of the hole. (c) To allow an increase in surface pressure as the BHA enters the influx. It is therefore important to accurately monitor the total volume of mud bled from the well. In this case. It is recommended that the potential increase in surface pressure resulting from entering the influx should be estimated before stripping into the hole. there will be a tendency for the volume of metal removed from the well to be replaced by influx fluid. In these circumstances it may be necessary to implement the dynamic stripping technique.18). Influx migration is controlled by implementing the Volumetric Method. 6-53 March 1995 . (b) To compensate for influx migration. In these circumstances the effective compressibility of the fluid in the hole will be low and as such there may be a very large pressure rise as pipe is stripped into the well. must be bled off. The choke operator may continue to bleed mud from the well to maintain a constant surface pressure and inadvertantly cause further influx into the wellbore. mud should not be bled from the well while the pipe is stripped in. A potential problem arises if this condition is undetected. Normally. Where possible. 043 6-54 March 1995 .17 A Guide to Interpretation of Surface Pressure Changes during Stripping START STRIPPING IN PRESSURE INCREASES AS PIPE IS STRIPPED IN CONTINUE STRIPPING BLEED VOLUME OF MUD EQUAL TO VOLUME OF PIPE STRIPPED SURFACE PRESSURE DROPS TO ORIGINAL VALUE? NO SURFACE PRESSURE DROPS TO VALUE GREATER THAN ORIGINAL YES NO CONTINUE STRIPPING CONTINUE STRIPPING SURFACE PRESSURE INCREASES WHILE PIPE IS STATIONARY? HAS THE CORRECT VOLUME OF MUD BEEN BLED FROM THE WELL? NO YES YES INFLUX IS MIGRATING PIPE HAS ENTERED INFLUX BLEED MUD TO COMPENSATE FOR MIGRATION NO NO IS THE PIPE ON BOTTOM? YES SURFACE PRESSURE LIMIT APPROACHED? YES CIRCULATE OUT TOP OF GAS BUBBLE USING THE DRILLER'S METHOD KILL THE WELL WEOX02.BP WELL CONTROL MANUAL Figure 6. Start stripping 2.BP WELL CONTROL MANUAL Figure 6.18 The Effect of the Pipe/BHA Entering the Influx 1.044 6-55 March 1995 . BHA has entered influx • • • KEY GAS INFLUX MUD Height of influx in annulus has increased Overall hydrostatic in annulus decreases Surface pressure required to balance formation pressure increases GAS INFLUX GAS MUD MUD WEOX02. The surface pressure is the overriding factor which determines whether or not it will be possible to implement annular stripping. This may not be necessary on a surface stack if the pressure regulator can respond fast enough to maintain a constant closing pressure as a tool joint is stripped through the annular. it is also necessary to consider that the operating life of an annular element is severely reduced by increased wellbore pressure. to lubricate the influx from the well or to bullhead. it will be necessary to open the annular having closed another ram to secure the well. it will not be possible to reduce the closing pressure once the annular has been closed. some drilling contractors have installed check valves in the control lines to the BOPs. to circulate out the influx. show good performance at 800 psi wellbore pressure. if a check valve is installed in the closing line to an annular BOP. 6-56 March 1995 . To ensure that the annular is not subjected to excessive pressures as the tool joint is stripped through the element. The decision analysis presented in Chapter 5. but at 1500 psi and above the performance was severely reduced and unpredictable. The options are. • During annular stripping the only item of well control equipment that is subject to high levels of stress is the annular element. Ram combination stripping is possible on all types of rig but involves significantly more risk when implemented on a floating rig. It involves less risk than ram combination stripping for the following reasons: • Annular stripping is a relatively simple technique. on a floating rig. • The annular element can be changed out on a surface stack when pipe is in the hole by inserting a split element. However. * Tests carried out by Exxon Prod. in this case. attempts should be made to reduce the pressures in order to enable annular stripping to be used. As a word of caution. Research 1977. ‘Pipe off Bottom – Drillpipe in the Stack’ outlines the basis upon which the most suitable stripping technique is selected. • The upper annular preventer.BP WELL CONTROL MANUAL 3 Annular Stripping There are two stripping techniques. If surface pressures indicate that annular stripping is not possible.19). a surge dampener must be placed in the closing line (See Figure 6. The most appropriate technique will depend on the position of the influx in the hole. Annular and Ram combination stripping. In order to reduce the annular closing pressure. the purpose being to ensure that the BOP stays closed if the hydraulic supply is lost. • The control system is not highly stressed during the operation (as is the case during ram combination stripping). Annular stripping is considered to be the most satisfactory technique. is the only stack component that is subject to wear and this can be changed without pulling the complete BOP stack. However. Field tests* carried out on Hydril and Shaffer 5K Annulars. typically 1/2 – 1 bbl). install a Gray valve in the string.045 Figure 6. If the dart does not hold pressure allow more time for the dart to drop or consider circulating the dart into place (restrict volumes pumped to a minimum). the following procedure can be used as a guideline for the implementation of annular stripping.19 Surge Dampener Fitted to the Closing Line of an Annular BOP 4 Annular Stripping Procedure Having shut in the well. If the dart still does not hold pressure. To check that the dart is functioning properly.BP WELL CONTROL MANUAL OPENING LINE SURGE DAMPENER (precharged to 50% of required closing pressure) CLOSING LINE WEOX02. 1 Install drillpipe dart Allow the dart to fall until it seats in the dart sub. 6-57 March 1995 . bleed off pressure at the drillpipe (restrict volumes bled off to an absolute minimum. converted to SG (water = 1 SG) volume of influx (bbl) hole/casing ID (in. a high surface pressure caused by a relatively small underbalance usually indicates that the influx contains a significant quantity of gas. it will not be possible to identify the type of influx in the usual manner. However. The hydrostatic pressure equivalent of the mud in the hole is calculated as follows: Hydrostatic pressure equivalent = 445.) Allowance should also be made for the extra volume of metal in the tool joints.7 X MW (d hc2 – d o2) (psi/bbl) where MW = mud weight in the hole (SG) dhc = hole/casing ID (in.) BHA OD (in. 5 Estimate increase in surface pressure due to BHA entering the influx It is possible to estimate the maximum possible pressure increase due to the BHA entering the influx as follows: Max possible surface = 445. If the influx is migrating it will be necessary to implement volumetric control during the stripping operation.) or if the pipe is above the influx: Hydrostatic pressure equivalent = 445.7 X MW dhc 2 (psi/bbl) For more details on this technique. but a reasonable estimation can be made as follows: Displacement and capacity = do2 X 0. 4 Calculate hydrostatic pressure per barrel of mud Should migration occur. There are various tables which outline these quantities.1 ‘Volumetric Method’ in this chapter.003187 (bbl/m) where do = outer diameter of the pipe (in. 3 Determine the capacity and displacement of the drillpipe It will be necessary to bleed mud from the well to compensate for the volume of pipe introduced into the hole.) 6-58 March 1995 X 1 dhc 2 (psi) .BP WELL CONTROL MANUAL 2 Monitor surface pressures Surface pressures should be monitored after the well has been shut-in to check for influx migration. See Sub-section 2. it will be necessary to bleed from the well at constant choke pressure to allow the influx to expand. If the pipe is off bottom.7 pressure increase where MW Gi V dhc do = = = = = X (MW – G i) V X 1 – (d hc2 – d o2) mud weight in the hole (SG) influx gradient.) do = drillstring OD (in. This volume is equal to the sum of the capacity and the displacement of the pipe. 20. 8 Strip in the hole The pipe should be slowly lowered through the annular while the surface pressure is accurately monitored. 7 Reduce annular closing pressure The BOP manufacturers recommend that the closing pressure is reduced. For both ram combination techniques there is a requirement that: • There is sufficient space for the tool joint between the two stripping BOPs. 10 Strip to bottom. (See Figure 6. at the start of the operation. Mud should be bled from the well at each connection. 9 Monitor surface pressure Surface pressures and all relevant data should be recorded on the Stripping Worksheet.17 as an aid to the interpretation of changes in surface pressure.) Use Figure 6. If the influx is not migrating. Use original mud weight. Annular to ram stripping is preferable to ram to ram. A person should be posted at the Driller’s BOP Control Panel at all times to be ready to shut-in the well in the event of failure of the annular preventer. annular to ram. the overbalance margin can be applied by bleeding a volume of mud that is less than the volume of pipe introduced into the hole. and ram to ram. 6-59 March 1995 . The running speed should be reduced when a tool joint passes through the annular.BP WELL CONTROL MANUAL 6 Allow surface pressure to increase by overbalance margin An overbalance of 50 to 200 psi should be maintained throughout the stripping operation. The pipe should be filled with mud at suitable intervals. 5 Ram Combination Stripping There are two types of ram combination stripping. typically every 5 stands. Both techniques must be considered if either the tool joint cannot be lowered through the annular or the surface pressure is greater than the rated pressure of the annular and this pressure cannot be reduced to within safe limits. prior to stripping. unless surface pressure limitations dictate that this should be carried out more frequently. This reduces the wear on the annular by lubricating the element during stripping. unless surface pressures indicate that the annular cannot operate reliably. until a slight leakage occurs through the BOP. Kill the well The only sure method of killing the well will be to return the string to bottom and implement standard well kill techniques. 6 N/A 240 0 2.0 10:40 Bleed Mud at Connection 770 -120 2054 54 4.6 N/A 120 2.8 11:15 Bleed Mud at Connection 960 -120 2162 162 13.8 N/A 240 0 15.4 N/A 120 2.0 N/A 240 0 6.4 10:57 Bleed Mud at Connection 770 -120 2108 108 8.01 psi/bbl HYDROSTATIC PRESSURE PER BARREL OF 1.2 N/A 240 0 8.2 N/A 120 0 0.6 .4 N/A 120 2.0 11:20 Strip in Stand No 7 1330 250 2189 189 15.5 x 8.5 HOLE HYDROSTATIC PRESSURE PER BARREL OF TIME OPERATION 1.80 Bit 10.52 psi/bbl HYDROSTATIC PRESSURE PER BARREL OF 1.8 N/A 120 2.2 11:10 Strip in Stand No6 1080 250 2162 162 13.4 11:40 Strip in Stand No 9 1590 250 2243 243 19.8 (Assume BHA has entered flux) 11:05 Bleed Mud at Connection 830 -120 2135 135 11.197 6-60 March 1995 .2 6.6 8.6 N/A 240 0 13.8 N/A 120 2.0 10:36 Strip in Stand No 2 890 120 2054 54 4. Weddle DATE AND TIME 1.2 11:33 Bleed Mud at Connection 1340 -120 2216 216 17.2 11:28 Strip in Stand No 8 1460 250 2216 216 17.2 10:48 Bleed Mud at Connection 770 -120 2081 81 6.75 2250 STRIPPING DATA VOLUME OF MUD DISPLACED BY OVERBALANCE MARGIN 5 120 Inch Pipe Drillpipe psi 0.75 SG MUD IN 8.0 11:25 Bleed Mud at Connection 1210 -120 2189 189 15.2 10:45 Strip in Stand No 3 890 120 2081 81 6.8 N/A 240 0 4.2 17.4 N/A 240 0 11.6 N/A 120 2.2 11.75 1.2 13.ve bled M +ve +ve lubricated +ve increase overbalance M NA if bled to .ve compensate for pipe -ve decrease + ve bled -ve lubricated underbalance WEOX02.75 HOLE Change in Choke 10. WELL NO 3 RIG MUD WEIGHT IN HOLE INITIAL BIT DEPTH Rig 10 uk Version 1/1 1Q'95 by ODL/C.4 N/A 240 0 0.6 11:00 Strip in Stand No 5 950 180 2135 135 11.2 2.5 ANNULUS 26.20 Example Stripping Worksheet – showing effect of migration and BHA entering the influx STRIPPING WORKSHEET Units (US/UK) For worksheet calculation enter information in shaded cells.5 ANNULUS 16.75 SG MUD IN 6.4 11:45 Bleed Mud at Connection 1470 -120 2243 243 19.0797 bbl/m : OPERATING MARGIN 150 psi 2.2 15.2 N/A 120 2.75 SG MUD IN Choke or Dp Monitor Monitor 8.0 N/A 120 2.75 10/7/87 10:30 LUBRICATING MUD WEIGHT 2000 HOLE DEPTH SHEET NO 1 1.BP WELL CONTROL MANUAL Figure 6.4 10:53 Strip in Stand No 4 890 120 2108 108 8.15 bbl/stand (Max) VOLUMETRIC CONTROL DATA HYDROSTATIC PRESSURE PER BARREL OF SG MUD IN 5 x 8.80 Pipe Stripped Pressure Depth psi/bbl psi/bbl Hydrostatic of Mud Bled/ Over- Lubricated Volume of Total Mud Bled/ Volume Lubricated balance of Mud Pressure ( hr 10:05 min) (psi) Well Shut In-Pressures (psi) 550 ( ) ( ) bbl 2000 (psi) (psi) (bbl) (bbl) N/A Stabilized 10:20 Drillpipe Dart Installed 10:30 Strip in Stand No 1 770 120 2000 2027 27 2.2 4. the accumulators are charged to maximum operating pressure and isolated from the BOP. The procedure for ram to ram stripping will be similar. The pumps are used for operational functions. (For details of Steps 1 to 6 See ‘Annular Stripping Procedure’) 1 Install drillpipe dart 2 Monitor surface pressures 3 Determine the capacity and displacement of the drillpipe 4 Calculate hydrostatic pressure per barrel of the mud 5 Estimate the increase in surface pressure due to the BHA entering the influx 6 Check ram spaceout To confirm the distance BRT of the two preventers that will be used for stripping. • The level of stress placed on the BOP elements. (During ram combination stripping. 6 Ram Combination Stripping Procedure The following procedure can be used as a guideline for the implementation of annular to ram stripping. 6-61 March 1995 . it may be possible to modify a surface stack to suit these conditions after a kick has been taken.) • The possibility of replacing the worn BOP elements during operation. API RP 53 (issued 1984) states: “The lowermost ram should not be employed in the stripping operation. It should not be subjected to the wear and stress of the stripping operation. • There is a suitable level of redundancy in the stack to ensure the lowest BOP is not used during the stripping operation. This ram should be reserved as a means of shutting in the well if other stack components of the blowout preventer fail.” In a critical situation.BP WELL CONTROL MANUAL • There is an inlet at the stack between the two BOPs used for stripping. An example surface stack that is suitable for ram combination stripping is shown in Figure 6. • On a floating rig. the reduction in level of redundancy within the subsea BOP stack as the ram preventer is used.21. • The level of stress placed on the BOP control system. The risks involved in ram combination stripping can be assessed by considering the following points: • The high level of drillcrew co-ordination required. 21 Surface BOP Stack Suitable for Ram Combination Stripping ANNULAR BLIND RAM FLANGED ACCESS POINT TO STACK FOR USE DURING RAM COMBINATION STRIPPING PIPE RAM PIPE RAM WELLHEAD ACCESS POINT WEOX02.046 6-62 March 1995 .BP WELL CONTROL MANUAL Figure 6. 22 Annular to Ram Stripping – stop stripping in when tool joint is above the annular MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM TO PUMP CHOKE PIPE RAM PIPE RAM WEOX02.BP WELL CONTROL MANUAL Figure 6.047 6-63 March 1995 . 048 6-64 March 1995 .BP WELL CONTROL MANUAL Figure 6.23 Annular to Ram Stripping – close pipe ram – bleed ram cavity pressure MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM PRESSURE BLED OFF AT CHOKE PIPE RAM PIPE RAM WEOX02. 24 Annular to Ram Stripping – strip in until tool joint is just below annular MUD ANNULAR VALVE OPEN VALVE CLOSED BLIND RAM PIPE RAM PIPE RAM WEOX02.BP WELL CONTROL MANUAL Figure 6.049 6-65 March 1995 . BP WELL CONTROL MANUAL Figure 6.25 Annular to Ram Stripping – use rig pump or cement pump to equalize across pipe ram MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM FROM PUMP PIPE RAM PIPE RAM WEOX02.050 6-66 March 1995 . The same is true for stripping out of the hole. For this technique to be effective the pump output must be considerably greater than the rate at which the volume of pipe is introduced into the well.23). This may cause further influx to occur. Lower pipe 15 Stop when tool joint is just below annular (See Figure 6. This is achieved by circulating at a constant rate across the end of the choke line.) 11 Close pipe ram at normal regulated manifold pressure 12 Bleed ram cavity pressure Before the annular is opened it will be necessary to bleed down the pressure below it.25. A manual choke should be used and the equipment rigged up as shown in Figure 6. If the pump rate is too low.) 16 Close annular at maximum operating pressure 17 Pressurise ram cavity to equalise across ram (See Figure 6.26. and the choke pressure will fluctuate.22. 6-67 March 1995 . 8 Allow the surface pressure to increase by the overbalance margin 9 Reduce annular closing pressure and strip in 10 Stop when tool joint is above annular (See Figure 6.) Do not use wellbore pressure to equalise across the ram. (See Figure 6. The purpose of this technique is to maintain constant choke pressure as the pipe is stripped into the hole. if the pump rate is too low. 18 Reduce annular closing pressure 19 Open pipe ram 20 Continue to strip in according to the above procedure. pressure surges will be caused at the choke as the pipe is stripped in. 7 Dynamic Stripping Procedure The situations in which it may be necessary to implement Dynamic Stripping are outlined in Paragraph 2. 13 Reduce ram operating pressure 14 Open annular.24.BP WELL CONTROL MANUAL 7 Isolate the accumulator bottles at full operating pressure The accumulators should be kept as back-up in the event of pump failure. in which case the choke pressure may drop as pipe is stripped from the well. Kill the well Fill the pipe as required. BP WELL CONTROL MANUAL Figure 6.26 Equipment Rig-up for Dynamic Stripping MUD VALVE OPEN ANNULAR VALVE CLOSED BLIND RAM PIPE RAM MONITOR PRESSURE GAUGE MANUAL CHOKE PIPE RAM MUD TANK PUMP WEOX02.051 6-68 March 1995 . or drop. Use the Stripping Worksheet to record all the relevant data.BP WELL CONTROL MANUAL The main problem associated with this technique is that migration and entrance into the gas bubble may not easily be detected at surface.) 8 Ensure that the manual choke is fully closed. See Paragraph 4 ‘Annular Stripping Procedure’) 1 Install drillpipe dart 2 Monitor surface pressures 3 Determine the capacity and displacement of the drillpipe 4 Calculate hydrostatic pressure per barrel of the mud 5 Estimate the increase in surface pressure due to the BHA entering the influx 6 Allow the surface pressure to increase by the overbalance margin 7 Line up the pump to the choke line (See Figure 6. further influx may be allowed to occur. the mud tank levels should be closely monitored to ensure that the levels rise. 1-69/70 6-69 March 1995 . or out of. Kill the well Fill the pipe as required. the well. the well should be shut-in and the surface pressures verified. Influx migration should be dealt with using the Volumetric Method. The Dynamic Stripping technique can be used during either annular or ram combination stripping. If any discrepancy is noticed. 14 Strip to bottom. Open choke line valve(s) 9 Open the manual choke at the same time as the pump is brought up to speed 10 Maintain final shut-in pressure on the choke 11 Reduce annular closing pressure 12 Strip in the hole 13 Monitor surface pressures and pit level If the choke pressure increases significantly as the pipe is stripped into the hole.26. For annular stripping it is implemented along the following lines: (For details of Steps 1 to 6. It is very important to accurately record pressures and mud volumes while stripping. in direct relation to the volume of pipe that has been stripped into. To avoid this. If no allowance is made for these complications. either reduce the pipe running speed or increase the circulation rate. 3 BULLHEADING Paragraph Page 1 General 6-72 2 When to Bullhead 6-72 3 The Important Factors 6-72 4 Procedure 6-73 Illustrations 6.27 Well Shut-in after Production – tubing full of gas prior to bullheading 6-74 6.28 Example Guide to Surface Pressures during a Bullheading Operation 6-75 6.30 Well after Bullheading Operations tubing displaced to kill weight brine 6-77 6-71 March 1995 .BP WELL CONTROL MANUAL 6.29 Well during Bullheading Operations 6-76 6.2 SPECIAL TECHNIQUES Subsection 2. • When displacement of the influx by conventional methods may cause excessive surface pressures. This technique is generally used only during workover operations when there is adequate reservoir permeability. • The type of influx and the relative permeability of the formation. Bullheading is however a relatively common method of killing a well during workover operations. In most cases therefore. 3 The Important Factors Bullheading during drilling operations will be implemented when standard well control techniques are considered inappropriate. • To reduce surface pressures prior to implementing further well control operations. • The rated pressure of the well control equipment and the casing (making allowance for wear and deterioration). 6-72 March 1995 . • If the influx in suspected to contain an unacceptable level of H2 S. bullheading may be considered in the following situations: • When a very large influx has been taken. the likelihood of successfully bullheading an influx will not be known until it is attempted. • When displacement of the influx by conventional methods would result in an excessive volume of gas at surface conditions.BP WELL CONTROL MANUAL 1 General Bullheading is a technique that may be used in certain circumstances during drilling operations to pump an influx back into the formation. • When a kick is taken with the pipe off bottom and it is not considered feasible to strip back to bottom. This technique may or may not result in fracturing the formation. However. During such situations. • The position of the influx in the hole. • The consequences of fracturing a section of the openhole. • The quality of the filter cake at the permeable formation. the major factors that will determine the feasibility of bullheading include the following: • The characteristics of the openhole. it is unlikely that accurate information is available regarding the feasibility of bullheading. • When an influx is taken with no pipe in the hole. 2 When to Bullhead During operations. 06 SG 1.2808 X 3100) (psi) = 6300 psi • Maximum allowable pressure when the tubing has been displaced to brine at 1.421 (psi) = 2640 psi 6-73 March 1995 . In another situation with shallow casing set. 2 Calculate static tubing head pressure during bullheading 3 Slowly pump kill fluid down the tubing. During a workover operation a procedure for bullheading will be drawn up along the following lines: 1 Calculate surface pressures that will cause formation fracture during bullheading Calculate also the tubing burst pressures as well as casing burst (to cover the possibility of tubing failure during the operation).66 – 1.0499 bbl/m 8430 psi 3650 psi 0.BP WELL CONTROL MANUAL 4 Procedure In general bullheading procedures can only be drawn up bearing in mind the particular circumstances at the rigsite.06 SG = (1. N80 Vam Internal capacity Internal yield Shut-in tubing pressure Gas density = = = = = = 1.0499 (bbl) = 155 bbl • Maximum allowable pressure at pump start up = (1.421) – (0. Monitor pump and casing pressure during the operation As an example consider the following well (See Figure 6. For example there may be situations in which it is considered necessary to cause a fracture downhole to bullhead away an influx containing H2S. Well information: • Depth of formation/perforations at 3100 m Formation pressure Formation fracture pressure Tubing 4 1/2 in.06) X 3100 X 1.27).66 X 3100 X 1.1 psi/ft Total internal volume of tubing = 3100 X 0.1 X 3. it may be considered totally unacceptable to cause a fracture in the openhole.66 SG 0. BP WELL CONTROL MANUAL Figure 6.06SG FORMATION PRESSURE – FORMATION FRACTURE GRADIENT – 1.27 Well Shut-in after Production – tubing full of gas prior to bullheading 3650 psi 4 1/2in N80 TUBING PACKER PERFORATIONS @ 3100m – 1.052 6-74 March 1995 .66SG – KEY BRINE VALVE OPEN GAS VALVE CLOSED WEOX02. This plot can be used as a guide during the bullheading operation. Figures 6.28 Example Guide to Surface Pressures during a Bullheading Operation 6-75 March 1995 .BP WELL CONTROL MANUAL • Static tubing head pressure at initial shut-in. 10000 10000 TUBING BURST 9000 9000 SURFACE PRESSURE (psi) 8430 8000 8000 WORKING PRESSURE RANGE DURING BULLHEADING OPERATION 7000 7000 STATIC TUBING PRESSURE THAT WOULD FRACTURE FORMATION 6300 5800 6000 INCLUDING 500psi SAFETY FACTOR (if fracturing is a consideration) 5000 5000 4000 4000 3650 3000 2640 2000 2140 1000 1000 STATIC TUBING PRESSURE TO BALANCE FORMATION PRESSURE 0 0 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 155 VOLUME OF TUBING DISPLACED (bbl) WEOX02.053 Figure 6. = 3650 psi • Static tubing head pressure when tubing has been displaced to brine = 0 psi (ie the tubing should be killed) The above values can be represented graphically (as shown in Figure 6.30 show a schematic of the well at two stages of the operation.28).29 and 6. 054 6-76 March 1995 .28.BP WELL CONTROL MANUAL Figure 6. TUBING PRESSURE WITHIN ACCEPTABLE LIMITS) BULLHEAD BRINE 4 1/2in N80 TUBING PACKER PERFORATIONS KEY BRINE VALVE OPEN GAS VALVE CLOSED WEOX02.29 Well during Bullheading Operations 4000psi 60bbl OF THE TUBING DISPLACED (FROM FIG 6. BP WELL CONTROL MANUAL Figure 6.055 1-77/78 6-77 March 1995 .30 Well after Bullheading Operations – tubing displaced to kill weight brine 0psi 4 1/2in N80 TUBING PACKER GAS TRAPPED UNDER PACKER PERFORATIONS KEY BRINE VALVE OPEN GAS VALVE CLOSED WEOX02. 34 Force Diagram for Snubbing Pipe 6-85 6-79 March 1995 .2 SPECIAL TECHNIQUES Subsection 2.32 Concentric Cylinder Snubbing Unit 6-83 6.BP WELL CONTROL MANUAL 6.31 Rig Assisted Snubbing Unit 6-81 6.33 Multicylinder Snubbing Unit 6-84 6.4 SNUBBING Paragraph Page 1 General 6-80 2 Snubbing Units 6-80 3 Selection of a Snubbing Unit 6-82 Illustrations 6. 000 lb to 400. To overcome this problem. Guy lines from the work platform prevent lateral movement. 2 Snubbing Units (a) The Rig Assisted Type The rig assisted unit uses the travelling blocks to generate the snubbing force through a series of pulleys and cables. A snubbing unit can be used to introduce a range of sizes of pipe into the well. Drillpipe or tubing may provide this pressure containment. It can be used to snub tubing. Snubbing units are not commonly used on floating rigs. The weight of the snubbing unit is supported by the wellhead.31. The lowermost components of the snubbing unit are the snubbing BOPs.BP WELL CONTROL MANUAL 1 General Snubbing is a technique used to force pipe into a shut-in well when the upthrust due to well pressure makes it impossible to strip the pipe through the BOP under its own weight. when the well may be allowed to continue flowing as remedial work is carried out. (See Figure 6.) The rig assisted unit can handle larger diameter pipes such as casing up to 13 3/8 in. which are made up to the top flange of the annular preventer on the rig’s stack. Snubbing may be considered during drilling operations for well control purposes. or if the rig BOP system is not considered adequate to provide reliable pressure containment during a prolonged stripping operation. The snubbing BOPs are likely to be too tall to fit underneath the rotary table and too wide to go through it. either when it is impossible to introduce pipe into a well that is under pressure. if necessary. 6-80 March 1995 . the snubbing company can provide suitable spacer riser sections to bring the assembly above the rig floor. and have snubbing capacities of 80. This flange is often poorly maintained because it is normally made up to the bell nipple and does not generally need to form a pressure seal. In order to use a snubbing unit on a floating rig. however they have been used successfully in the past for well control operations. pressure containment must be established between the rig BOP and the unit on the rig floor. It must therefore be inspected and. Snubbing is relatively common in some areas in workover operations. These were the first snubbing units used and the few that are currently available are operated by Otis and Cudd Pressure Control. in which case small diameter tubing may be run into the well through the drillpipe or tubing. repaired before the snubbing BOPs are nippled up.000 lb. An operation of this type can only be carried out in relatively calm seas so that the rig heave does not cause excessive movement of the snubbing unit. Snubbing units can therefore be rigged up on land rigs and fixed offshore installations in a relatively straightforward manner. drillpipe and even casing in exceptional circumstances. BP WELL CONTROL MANUAL Figure 6.056 6-81 March 1995 .31 Rig Assisted Snubbing Unit TRAVELLING BLOCK BALANCE WEIGHT TRAVELLING SNUBBERS SNUB LINE STATIONARY SNUBBERS PLATFORM STRIPPING OR SNUBBING PREVENTERS PUMP INLET SAFETY PREVENTERS WELL PRESSURE WEOX02. 3 Selection of a Snubbing Unit The following are the criteria that should be used to determine the most suitable unit for a given application: • Snubbing Force This is the force that the unit must exert to push the pipe into the hole. A set of stationary snubbers grip the pipe while the travelling snubbers are being raised (by the counter balance weights) for a new bite on the pipe. There are two different types of hydraulic unit available. 6-82 March 1995 . • The multicylinder type (See Figure 6.000 lb and for pipe up to 5 1/2 in. the travelling snubbers will be removed and the pipe will be run in by conventional stripping.000 lb and for pipe up to 7 5/8 in. if required. From this position the speed of the pipe and the slips are controlled as can be the rotary table. Stationary and travelling slips are operated in sequence to grip the pipe as it is snubbed into the well. They are completely self contained and can be used either inside the derrick or when there is no rig on location. these being: • The concentric cylinder unit (See Figure 6. (b) The Hydraulic Self Contained Type Hydraulic snubbing units are the most common type available. The units are operated from the work platform which is on top of the hydraulic jack assembly. using the counter balance system.BP WELL CONTROL MANUAL The unit consists of a set of travelling snubbers which are connected to the travelling block. Once sufficient pipe has been run to reach the balance point.33) for snubbing capacity up to 150. The travelling snubbers grip the pipe and force it into the well as the blocks are raised. The snubbing force will be a maximum for the first joint of pipe and decrease gradually as the weight of the pipe in the hole increases in normal conditions. OD.32) for snubbing capacities up to 30. Another operator will co-ordinate the pipe handling. One operator will control the BOPs and equalising valves. OD. 057 6-83 March 1995 .BP WELL CONTROL MANUAL Figure 6.32 Concentric Cylinder Snubbing Unit WORKBASKET WITH CONTROLS TRAVELLING SLIPS (CLOSED) TRAVELLING SLIPS (OPEN) PISTON STATIONARY SLIPS (CLOSED) STATIONARY SLIPS (OPEN) ACCESS WINDOW STATIONARY SLIPS (OPEN) SNUBBING UNIT BLOWOUT PREVENTER STACK KEY HYDRAULIC CONTROL FLUID WELL PRESSURE PISTON EXTENDED AND TRAVELLING SLIPS CLOSED PRIOR TO FORCING PIPE INTO WELL PISTON RETRACTED AND TRAVELLING SLIPS OPEN BEFORE PISTON IS AGAIN EXTENDED WEOX02. 33 Multicylinder Snubbing Unit POWER TONGS BOP CONTROL PANEL CONTROL PANEL COUNTERBALANCE WINCH WORK PLATFORM TRAVELLING SLIPS FOUR OPERATING CYLINDERS TELESCOPING MAST STATIONARY SLIPS WINDOW – for stripper bowl or annular BOP SPOOL HANGER FLANGE PUMP INLET SNUBBING UNIT BLOWOUT PREVENTER STACK WEOX02.058 6-84 March 1995 .BP WELL CONTROL MANUAL Figure 6. 34 Force Diagram for Snubbing Pipe 6-85 March 1995 .281) – (wb X L z X 3.BP WELL CONTROL MANUAL The snubbing force is calculated as follows: – Snubbing force.34) where F s Fp Ff wa wb Ly Lz Ao = = = = = = = = required snubbing force (lb) force due to well pressure (lb) frictional force (lb) weight of pipe (lb/ft) buoyant weight of pipe (lb/ft) length of pipe above BOP to the travelling snubber (m) length of pipe in the hole (m) outside cross sectional area of pipe (in. Fs = F p + Ff – (w a – Ly X 3.2) COMPRESSION FORCE Fs POINT OF APPLICATION OF TRAVELLING SNUBBERS Fs wa Ly Ff PIPE (SNUBBING UNIT STROKE) SNUBBING BOP Ff (wa)(Ly) wb Pw Lz WELLBORE Fp Fp (wb)(Lz) Equilibrium Equation (from ∑ Forces = 0) Therefore: Fs = Fp + Ff – (wa) (Ly) – (wb) (Lz) Where Fs Fp Ff wa wb Ly Lz = required snubbing force (lb) = force due to well pressure (lb) = frictional force (lb) = weight of pipe (lb ft) = bouyant weight of pipe (lb ft) = length of pipe above BOP to the travelling snubber (m) = length of pipe in the hole (m) WEOX02.281) where Fp = Pw – Ao (See Figure 6.059 Figure 6. 2 7/8 in. Snubbing force. over and above the weight of the maximum string weight. As an example: 2 7/8 in.12 lb/ft Therefore the snubbing force is given by: Fs = Fp + Ff – (wa X Ly) – (w b X L z) Fs = (6. • Lifting Force The unit must be able to provide a reasonable overpull.460 lb – The snubbing force.492) 144 (lb/ft) wb = 3.492 X 5000) + 2000 + 5000 – (3. Drag in the hole is 2000 lb.2 ) outside cross sectional area area of pipe (in.492 in.281) (lb) = 29. Ai Ao wi wo wa wb D = = = = = = = internal cross sectional area area of pipe (in. 6-86 March 1995 .4 X 6. The wellhead pressure is 5000 psi.12 X 1000 X 3. F s = Fp + F f = (6. tubing produces a frictional force of 3000 lb at the stripping rams. In this case. friction at the BOPs is 5000 lb. The area of pipe exposed to the wellbore pressure therefore equals 6. the length of pipe in the hole (Lz) is zero.BP WELL CONTROL MANUAL – Snubbing force for the first joint of pipe.5 lb/ft is run empty to 1000 metres in 1. if there is already some pipe in the hole.5 + (O X Ai) – (1.2 SG mud.2 ) weight of fluid inside the pipe (SG) weight of fluid in annulus (SG) weight of pipe in air (lb/ft) buoyant weight of pipe (lb/ft) depth of tubing (m) wb = wa + (w i X Ai) – (wo X Ao) wb = 6.200 lb • Size of the Unit The dimensions of the unit must be checked against the internal dimensions of the derrick. Consider the following example: The well is shut in with a wellhead pressure of 5000 psi. and the length of pipe above the BOP is considered insignificant. tubing of 6.2 X 62.492 X 5000) + 3000 (lb) = 35. Fs. In this case the length of the pipe above the BOP is again considered insignificant. if the unit is to be used with a rig on location. BP WELL CONTROL MANUAL • Tubular Selection If there is already pipe in the hole. – The susceptibility of the tubing to failure due to buckling. The following points must also be considered: – The limitations imposed by the ID of the tubing on the maximum pump rate. – External flush tubing can be run through the stripper rubbers without the need for sequencing the rams. Tubing is more commonly used for snubbing for the following reasons: – The force required to snub it in is very much less. and the unit required corresponding smaller. but will be easier to control. this will determine the most suitable type of pipe to be used. – The collapse strength of the tubing. – The drillpipe must be in good condition and inspected thoroughly before running in. 6-87 1-87/88 March 1995 . Drillpipe can be used. if it starts to be forced out of the well. however the following points should be considered: – Drillpipe will require a relatively high snubbing force because of its large crosssectional area at the tool joints. – Drillpipe does not have gas-tight connections. – External upset tubing will be slower to run. – Premium connections are desirable because they are gas tight. 2 SPECIAL TECHNIQUES Subsection 2.BP WELL CONTROL MANUAL 6.5 BARYTE PLUGS Paragraph Page 1 Characteristics of Baryte Plugs 6-90 2 Deflocculation 6-92 3 Pilot Tests 6-92 4 Slurry Volume 6-92 5 Pumping and Displacement Rate 6-93 6 Preparation of a Baryte Plug 6-93 7 After Pumping a Baryte Plug 6-93 8 Baryte Plug Procedure 6-94 Illustrations 6.35 Field Mixing of Baryte Plugs 6-91 6-89 March 1995 . The recipes are identical except that one contains XC polymer to eliminate baryte settling. as well as field experience. In general. Settled baryte can appear rock-solid when pushed hard and yet move slowly out of the way of a persistent gently force. The properties of the fluid pumped should be chosen with these three factors in mind. it should be an optional feature of the slurry recipe. The ideal kill weight mud would be inexpensive and simple to mix and handle over a wide range of densities.35 was selected because it is prepared easily in both fresh and seawater and because XC solutions are shear-thinning enough to allow good pumpability while adequately suspending the baryte in the pits. and the pump rate during the kill must exceed the influx rate by sufficient margin so that the kill weight mud is not blown out of the wellbore. Three factors contribute to achieving a hydrostatic kill: the density of the fluid. Deflocculated baryte slurries fit this description except that the settling of the baryte can be a problem in surface handling and pumping. The strength of the settled baryte is another significant factor in well control. Nonetheless. Laboratory tests show clearly that even very low gas volumes (0. 6-90 March 1995 . This behaviour is actually a well understood property of deflocculated cakes.BP WELL CONTROL MANUAL 1 Characteristics of Baryte Plugs (a) Hydrostatic Kill Since baryte settling is inherently slow and since the results of settling are quite unpredictable. For large kill operations. The particular recipe in Figure 6. It would seem reasonable to use the settling recipe for small jobs or where the settling baryte might really be helpful downhole. This fact.35 shows two recipes for baryte slurries. the non-settling recipe would be preferred. A baryte plug can fail unexpectedly if a hydrostatic kill condition is not maintained. the use of a settling recipe should not be a dominant factor in designing a well control operation. it is imprudent to rely on baryte bridging when attempting to kill a well. shows that the bridging action of a baryte plug is not dependable. The density and volume of the kill weight mud must be high enough to control the formation. Some field experiences support this view. there are cases where a well has stopped flowing after being treated with a small baryte plug. Laboratory tests show that the strength of a settled baryte plug is quite variable. and the rate at which the fluid is pumped. Bentonite or some polymer other than XC could be used to suspend the baryte in a slurry. the goal in using a baryte kill slurry should be the same as with any other kill weight mud – achieving a hydrostatic kill. For this reason.01 Mcf/d at bottomhole conditions) can flow through a settling baryte plug. (c) Settling/Non-settling Since baryte settling is of little value downhole and troublesome on the surface. the volume of the fluid. (b) Bridging effect It has been suggested that a baryte plug can stop unwanted flow by a bridging effect and that achieving a hydrostatic kill is not necessary. Figure 6. the design of a baryte plug should be based on achieving a hydrostatic kill. 5 SG slurry.5 US gal oil wetting agent • Non-setting recipe 1 bbl base oil 4 lb organophilic clay 1. Add baryte to mix oil to prepare final slurry.5 SG slurry.5 US gal oil wetting agent 2.5) • Non-setting recipe 1 bbl water (fresh or sea) 15 lb lignosulphonate 1 lb XC polymer Defoamer (octanol or other) 2 lb/bbl of caustic (pH = 10.54 bbl mix water 700 lb baryte (b) For use with oil based muds 1.35 Field Mixing of Baryte Plugs (a) For use with water based muds 1. mix 0. Recipes below are for one barrel of mix water: • Setting recipe 1 bbl water (fresh or sea) 15 lb lignosulphonate 2 lb/bbl of caustic (pH = 10.BP WELL CONTROL MANUAL Figure 6. For 1 bbl of 2.54 bbl mix water 700 lb baryte 6-91 March 1995 . Recipes below are for one barrel of mix oil: • Setting recipe 1 bbl base oil 1.5 to 11.5) 2. Prepare mix oil equal to 47 percent of final volume of slurry required. Prepare mix water equal to 54 percent of final volume of slurry required. mix 0. For 1 bbl of 2. Add baryte to mix water to prepare final slurry.5 to 11. but will certainly give an indication of the settling characteristics. In general the recipes in Figure 6. The slurry volume should be 125 to 150 percent of the annular capacity necessary to give the height of plug desired. prudence suggests using the more reliable lignosulphonate rather than the somewhat unpredictable SAPP. Prepare a sample of the slurry using the recipe chosen and the ingredients at the wellsite. On the other hand. 6-92 March 1995 . Reasonable settling is 2 in.35 contain lignosulphonate. the slurry volume should be greater than the first. SAPP will not deflocculate in sea water or in the presence of some contaminants which occur in natural baryte. hematite slurries can be prepared to 3. After being stirred well. hole instability.35 do not require change except that. The non-settling recipe is strongly recommended for hematite slurries because of the relatively coarse grind of oil-field hematite.00 SG using the non-settling recipe in Figure 6. 4 Slurry Volume Slurry volumes depend upon the amount of openhole and the severity of the kick. Chemicals of either type can deflocculate a baryte slurry to improve pumpability and allow settling into a firm cake. the higher density of the substitue allows higher slurry weights than were possible with baryte. this should also be checked ahead of time. but should not be less than 40 bbl. The recipes in Figure 6. in some cases. • Use of lignosulphonate gives a slurry with low fluid loss (5cc). The settling test is not a guarantee that the baryte pill will form an effective plug under downhole conditions. If a second baryte plug is required. the sample should have the expected density and be easily pumpable. For example. perhaps. The settled cake should be hard and somewhat sticky rather than soft and slippery.35. These volumes normally range from 40 bbl to 400 bbl. Lignosulphonate is effective in sea water and tolerates both contamination and elevated temperatures. with the phosphate SAPP having the widest acceptance. or promote. Faced with this choice.BP WELL CONTROL MANUAL Baryte-plug-type slurries can be prepared with all of the baryte substitutes which are now on the market. in a mud cup after a 15 minute wait. 2 Deflocculation For years it has been standard practice to add a thinner to baryte slurries used for well control. The choice of deflocculant will influence the baryte slurry properties as follows: • Use of SAPP gives a slurry with fairly high fluid loss (50cc). possibly because it might dehydrate and plug the wellbore. it is always advisable to pilot test a baryte slurry. a low fluid loss slurry would reduce the chances of differential sticking. 3 Pilot Tests Because of variation and possible contamination of ingredients throughout the world. Replace the baryte with 870 lb hematite per final bbl of slurry. Both lignosulphonates and phosphates have been used. Use of a high fluid loss baryte slurry is advantageous. If the baryte needs to settle in the wellbore. Settling-type baryte slurries may only be stored in ribbon blenders or similar equipment which provide continuous. A baryte plug should be pumped and displaced at a rate somewhat higher than the kick rate. and the cementing unit breaks down. If there is any significant volume of mud under the baryte slurry then the baryte slurry will mix with the mud because of the large differences in density. The equipment needed on location to prepare and pump a baryte plug is a cementing unit equipped with a high pressure jet in the mixing hopper. In either case. 6-93 March 1995 . a means of delivering the dry baryte to the cementing unit. it is best to prepare the mix water first and then add baryte to the desired density. 6 Preparation of a Baryte Plug For field preparation of either a settling or non-settling baryte slurry. Hopper nozzles and feed rate should be selected to give this pressure drop. The non-settling slurry may be recirculated through the mixing hopper several times if necessary to obtain a particular weight. If the influx zone is somewhat above the bottom of the hole. Blockage of the drillstring by baryte settling will complicate the well control problem. Non-settling slurries may be stored in standardmud tanks although even these slurries may drop out a few in. the pump tie-in to the drillpipe should contain provisions for hooking up both the cementing unit pump and the rig pump so that either can be used to displace the slurry. 7 After Pumping a Baryte Plug Baryte plugs may be used in a variety of situations. This is especially true in deciding what to do after a baryte plug has been pumped.5 SG in one pass provided the mix water is fed to the hopperat 600 to 1000 psi. service companies are reluctant to recirculate settling baryte slurries through their equipment. it is not possible to give one fixedprocedure which will always work. If the kick rate is unknown. the baryte may settle in the drillpipe before the mud pump tie-in can be made or the cementing unit repaired. There will always be a need for local decisions and good judgement. and sufficent clean tankage for the mix water so that the lignosulphonate and caustic soda can be mixed in advance. It is possible to weight-up to 2.BP WELL CONTROL MANUAL 5 Pumping and Displacement Rate Baryte plugs should always be pumped with the drillpipe close to the bottom of the hole. then the baryte slurry should be pumped to bottom and then above the influx zone far enough to provide the desired hydrostatic kill height. If this is not done. The baryte slurry may be pumped into the drillpipe either through a cementing head orthrough the standpipe and kelly . thorough agitation. of baryte per day if not stirred. a reasonable rate (5 to 10 bbl/min) should be used for the first attempt although very large blowouts can ultimately require kill weight mud placement at greater than 50 bbl/min. The goal of pumping a high-density slurry is to achieve a hydrostatic kill. 8 Baryte Plug Procedure (a) Leave Pipe in Place 1 Mix and pump the slurry at the appropriate rate Monitor the slurry density with a densometer in the discharge line or a pressurised mud balance. Cement should be dump bailed on the wireline bridge plug for additional safety. Displace the slurry immediately at the same rate. 6 Pressure test the inside plug 6-94 March 1995 . 4 After it has been determined that the flow is stopped. Temperature surveys can be used in addition or if the noise log is not available. If there is doubt about the hydrostatic kill it may be better to stay on bottom to be ready to pump a larger baryte plug if needed. bullhead a cement slurry through the bit to provide a permanent seal Observe the annulus during the pumping. The survey will show a hotter than normal temperature in the zone of lost returns. Overdisplace the cement to clear the drillstring. The risk in pulling out is that the pipe may become stuck off bottom or may have to be stripped back to bottom if the baryte plug fails. It is more definitive than temperature logs. It is possible to keep the pipe free by moving it (especially in a non-settling plug) but there is no way to circulate (to avoid plugging) unless the pipe is pulled above the top of the baryte slurry. Additional cementing to obtain a squeeze pressure might be desirable. wait 6 to 10 hr for the temperatures to stabilise. Wait another 4 hr. The risk of staying on bottom is that the pipe may become stuck or plugged. the baryte plug may have been disturbed. If the underground flow has stopped. or if a sudden change in the pumping pressure occurs. If temperature surveys are used.BP WELL CONTROL MANUAL The decision after placing a baryte plug is whether to pull pipe or not. If the casing pressure begins varying appreciably. 3 Verify that underground flow has stopped A noise log may be used. If a hydrostatic kill was probably achieved then it is usually best to pull up above the slurry and try circulating mud. 5 Plug the inside of the drillstring The cement in step 4 can be underdisplaced. run a second survey. the decision whether to pull pipe depends on an assessment of the success of this kill. the temperature in the lost returns zone will have decreased. 2 Overdisplace the slurry by 5 bbl to clear the drillstring Continue to pump 1/4 bbl at 15 min intervals to keep the drillstring clear. but a wireline bridge plug set near the top of the collars is preferred. 6-95 March 1995 . – Run a free-point log. If mixing is interrupted for any reason. Consideration should be given to circulating with lighter mud because of the known lost returns zone. Cut displacement short on final stage to provide an interior plug or set wireline bridge plug. • Well will not circulate: – Squeeze cement slurry through perforation. – Circulate using drillpipe pressure method until annulus is clear. – Perforate the pipe near the indicated free point. Work the pipe while pumping and displacing. squeeze perforations with cement or set a wireline bridge plug above perforations and perforate up the hole. immediately begin displacement of the slurry using either the cement unit pumps or the rig pumps. drillpipe float is in the drillstring. 2 Displace the slurry with mud at the same rate Cut the displacement short by 2 or 3 bbl to prevent backflow from the annulus. 3 Immediately begin pulling the pipe It may be necessary to strip the pipe through the annular preventer. Low Permeability Formation) 1 Mix and pump the slurry Monitor the slurry weight with a densometer in the discharge line or a pressurised mud balance. If well will not circulate. WOC and pressure test plug. (b) Pull Out of Plug (High Pressure.BP WELL CONTROL MANUAL 7 Perforate the drillstring near the top of the baryte plug. Pressure communication between the drillpipe and annulus is one clue. overdisplace the slurry. Attempt to circulate It may be difficult to tell whether the well is circulating or flowing from charged formations. a pressure increase should have appeared on the drillpipe from annulus pressure or on the casing from hydrostatic pressure in the drillpipe when the perforation wasmade. Pull at least one stand above the calculated top of the baryte slurry. – Run free-point log. • Well will circulate: – Use drillpipe pressure method to circulate annulus clear of formation fluid. – Begin fishing operations. If a non-ported. – If returns become gas-free. if feasible. and observe annulus mud level. 5 Trip out of the hole after verifying that the well is dead If the bottom part of the hole is being abandoned. • If pressure is on the annulus. begin circulating at a slow rate. – If returns do not become essentially gas-free after circulating two or three annular volumes. the baryte plug was not effective. circulate the annulus using normal well control techniques. 6-96 March 1995 . A second plug will be necessary. If annulus will stand full. continue working the pipe. fill annulus with water and observe. – If the annulus is not full. then a cement plug should be placed on top of the baryte. Consider cutting mud weight. the baryte plug was successful and the well is dead. Continue working the pipe. begin circulating at a low rate keeping constant watch on pit levels. – If the annulus is full.BP WELL CONTROL MANUAL 4 Monitor the annulus • If no pressure is on the annulus. BP WELL CONTROL MANUAL 6.6 EMERGENCY PROCEDURE Paragraph Page 1 Use of Shear Rams 6-98 2 Dropping the Pipe 6-99 6-97 March 1995 .2 SPECIAL TECHNIQUES Subsection 2. Most shear rams are designed to shear effectively only on the body of the drillpipe. are available that are designed to shear 7 in. The use of the shear rams can be considered in the following situations: • In preference to dropping the pipe in the event of an uncontrollable blowout up the drillstring (an internal blowout). Optimum shearing characteristics are obtained when the pipe is stationary and under tension.BP WELL CONTROL MANUAL 1 Use of Shear Rams Shear rams can be used to cut drillpipe and then act as a blind ram in order to isolate the drilling rig from the well. • When there is no pipe in the hole. OD. It is clearly important however. Shearing the pipe is a technique that will be required only in exceptional circumstances. The following procedure can be used as a guideline for shearing the pipe in the case of an internal blowout: 1 Space out to ensure that there is no tool joint opposite the shear rams 2 Close the hang-off ram 3 Hang off on the rams Ensure that the pipe above the hang-off rams remains in tension. Procedures for the use of shear rams must therefore ensure that there is no tool joint opposite the ram prior to shearing. such as the Cameron Super Shear Rams. Hanging the pipe off also ensures that there is no tool joint opposite the shear rams. 4 Prepare to operate the shear rams 5 Close the shear rams at maximum accumulator pressure 6 Monitor the well. drillcollars and casing up to 13 3/8 in. the shear rams can be used as blind rams. Be aware that many subsea stacks have insufficient clearance between the top pipe rams and the shear rams to hang off on the top rams and shear the pipe. • When it becomes necessary to move a floating rig off location at short notice. Maximum operating pressure should be used to shear the pipe. that rigsite personnel are aware of the capabilities and operating parameters of the shear rams installed in the rig’s BOP stack. Specialist shear rams. Implement appropriate control procedures 6-98 March 1995 . It is therefore recommended practice that the pipe weight is partially hung off prior to shearing. The possibility of damaging the ram packings must also be considered. • If an internal blowout occurs when the drillcollars are in the stack.BP WELL CONTROL MANUAL 2 Dropping the Pipe Situations in which it will be necessary to drop the pipe will be extremely rare. Allow the string to drop 8 Close the blind/shear ram 9 Close the choke 6-99 March 1995 . Dropping the pipe is an emergency procedure and as such it is a procedure that will only be required as a last resort when the safety of the rig and personnel is threatened. Situations that may require the pipe to be dropped include: • If an internal blowout occurs on a rig that has no shear rams. Once the pipe has been dropped the well is shut-in with the blind/shear rams. • If the pipe is pushed out of the hole under the influence of wellbore pressure. • As an alternative to the use of shear rams in the event of an internal blowout when drillpipe is in the stack. It is clearly important to be sure that the pipe will clear the stack once it has been dropped (especially on a floating rig in deep water). However. re-establishing control of the well in this situation will be time consuming and costly. There are two techniques that can be used to drop the string: (a) Unlatch the elevators 1 Lower the string until the elevators are at a manageable distance from thefloor 2 Ensure that the BOP is closed at maximum operating pressure 3 Attach a tugger line to the elevators 4 Clear the floor 5 Open the choke line to bleed down surface pressure 6 Open the elevators 7 Open the BOP. • If a BOP develops a leak and there is no back-up available. BP WELL CONTROL MANUAL (b) Back off a tool joint 1 Set the slips 2 Break a tool joint. Ensure that the joint can support the weight of the string 3 Pull the slips 4 Run the joint below the rotary 5 Set the slips 6 Ensure the BOP is closed at maximum closing pressure 7 Open the choke line to reduce the surface pressure 8 Turn the rotary to the left to back off the joint 9 Open the BOP and allow the pipe to drop 10 Close the blind/shear ram 11 Close the choke Both of these techniques involve a certain amount of risk. The most suitable method in each case will depend on the particular conditions at the rigsite. 6-100 March 1995 . 39 Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx 6-114 6.36 Temperature at which Gas Hydrates will Freeze (Katz) 6-106 6.40 Annular Friction Pressure Drop 6-115 6.BP WELL CONTROL MANUAL 6.38 Height of 10 bbl Gas Influx in Annulus 6-113 6.37 Natural gas expansion – Temperature reduction curve (NATCO) 6-107 6.3 COMPLICATIONS Paragraph Page 1 Plugged Bit Nozzle 6-102 2 Plugged Choke 6-102 3 Cut Out Choke 6-102 4 Pump Failure 6-103 5 Pressure Gauge Failure 6-103 6 String Washout 6-103 7 Stuck Pipe 6-104 8 Well Control Considerations in Horizontal Wellbores 6-104 9 Hydrates 6-105 10 Surface Pressures Approach the MAASP 6-109 11 Impending Bad Weather 6-110 12 Loss of Control 6-111 13 Well Control Considerations in Slim Hole Well 6-111 Illustrations 6.41 Swab Pressure in a 1000 m Hole 6-116 6-101 March 1995 . 3 Cut Out Choke A choke is unlikely to suddenly cut out. the pump should be stopped. 6-102 March 1995 . This will result in a drop in choke pressure and a corresponding drop in bottomhole pressure. One of the reasons for displacing a kick at slow circulation rates is to avoid overpressuring the well if cuttings plug the choke. if increased drillpipe pressure does not clear the problem. the first reaction should be to check the pit volume to ensure that lost circulation is not occurring. this will cause an abrupt and continually increasing drillpipe pressure. In this event. The drillstring should be reciprocated in order to clear this problem. If the bit becomes totally plugged. circulating pressures. especially in critical hole sections. 2 Plugged Choke A plugged choke is indicated by an unexpected increase in choke pressure accompanied by an equal increase in drillpipe pressure. As a choke wears it will become necessary to gradually close it in to maintain circulating pressure. to run a circulating sub above the bit or above a core barrel. It is good practice. Therefore should a plugged bit nozzle be suspected. An increase in drillpipe pressure could also be caused by the hole packing off around the BHA. Clearly the first course of action is to open the choke in an attempt to both clear the restriction in the choke and to avoid overpressuring the well. with little or no change in choke pressure. If this action is not successful the pump should be stopped immediately. This would be likely to cause increased. If the operator finds that he has to gradually close in the choke to maintain circulating pressure. there will not be any dramatic indication that this problem is occurring. circulation rates should be minimised in critical conditions if the annulus is likely to contain a substantial volume of cuttings. though fluctuating.BP WELL CONTROL MANUAL 1 Plugged Bit Nozzle A plugged nozzle in the bit is indicated by an unexpected increase in drillpipe pressure with little or no change in the choke pressure. the well shut-in and the pump restarted to establish the increased standpipe pressure that will maintain a suitable bottomhole pressure. After switching to an alternate choke the excess pressure in the well should be bled at the choke and the displacement restarted in the usual manner. the string must be perforated as close as possible to the bit in order to re-establish circulation. The choke operator may be tempted to open the choke in an attempt to reduce the drillpipe pressure to the original circulating pressure. In this respect. Some plugging of the choke is to be expected if the annulus is loaded with cuttings. In this respect. If the washout is identified as being near the bottom of the well. The recommended procedure in the event of a drillstring washout is to stop the pump and shut the well in. or if necessary. Should this occur. the cement pump. Regardless of the depth of the washout. or preferably before this stage. and that back-up gauges are available in the event of failure of a pressure gauge during a well control operation. while the choke pressure remains unchanged. If no back-up gauge is immediately available. This may be preceded by an unexplained drop in circulating pressure. it will be necessary to re-establish the correct circulating pressure if the pump is restarted. The displacement should be continued with the second rig pump. If pump failure is suspected. 6 String Washout A washout in the drillstring may be indicated by an unexpected drop in standpipe pressure. Should gauge failure occur during a well control operation it is important that the defective gauge be replaced as quickly as possible. At. 4 Pump Failure The most obvious indicator of failure at the fluid end is likely to be erratic standpipe pressure together with irregular rotary hose movement. if the circulation is contained for prolonged periods through a washout. the flow should be switched to another choke and repairs effected to the worn choke. stop the operation and shut in the well.BP WELL CONTROL MANUAL Having established that there is no loss of circulation a worn out choke should be suspected. there will of course be the risk of parting the drillstring with continued circulation. The faulty pump should be repaired immediately. There may come a stage when it is no longer possible to maintain a suitable circulating pressure even with the choke apparently fully closed. It is advisable to periodically re-establish the circulating pressure. the pump should be stopped and the well shut-in. The most critical situation would be in the event of a washout close to the surface. Every effort must be made to ensure that the washout is not enlarged by extended circulation and drillstring manipulation. it is unlikely that it will be possible to displace the influx from the hole effectively. 5 Pressure Gauge Failure Every effort should be made to ensure that all pressure gauges are working correctly. In this case. 6-103 March 1995 . unless the influx is above the washout. it may be possible to displace the kick from the well effectively. Excessive downhole pressures may be caused if the original circulating pressure is maintained at the standpipe. as always. Efforts to free the pipe can be made once the well has been killed. 6-104 March 1995 . If the pipe is differentially stuck with the bit on bottom. however it does mean that it is not possible to check the validity of kick data. Particular attention must be paid to tripping procedures when the reservoir is exposed. to minimise the risk of sticking the pipe. a combination of working the pipe and spotting a freeing agent can be used in attempting to free the pipe. this would depend on the length of the horizontal openhole section. Downhole equivalent mud weights are calculated using the true vertical depth. the most likely cause of stuck pipe is differential sticking. Unfortunately. will be considerably greater than for a well drilled vertically through the reservoir. the likelihood of the pipe becoming stuck during a well control operation is increased if the pipe is off bottom. • It is possible that shut-in pressures in the event of a kick will be identical on both drillpipe and annulus. However. However. The possibility that the wellbore contains a large influx should therefore be addressed in such circumstances. if the well is shut-in with the pipe off bottom and the BHA in openhole. It may be possible to free the pipe by spotting a freeing agent. If the pipe is mechanically stuck. mechanical sticking may result if the hole sloughs and packs-off as a result of the contact with the influx fluids. although a large influx has been taken. 8 Well Control Considerations in Horizontal Wellbore Well control procedures in horizontal wellbores use the same basic principles as those for vertical or deviated holes. Should the pipe be differentially stuck with the bit off bottom. Due to the relatively high wellbore pressures during a well control operation. it may be possible to regain control of the well by volumetric control. The pipe should be rotated. if the influx was swabbed in. these are as follows: • The purposes of drilling a horizontal well are to improve hydrocarbon recovery and to maximise the area of reservoir exposed at the wellbore. continue the operation because it is most likely that circulation can still be carried out in order to kill the well. in the event of a kick. This is not a problem. most especially if the pipe is stuck off bottom. It must therefore be considered that influx flowrates. in order to maximise production rates. There are however several additional points to consider. the situation is complicated in that it will generally not be possible to reduce the wellbore pressure at that depth by circulation.BP WELL CONTROL MANUAL 7 Stuck Pipe The complication of stuck pipe during a well control operation can cause serious problems. The formation of hydrate plugs under these conditions can rapidly overpressure low pressure well control equipment. 6-105 March 1995 . hydrate formation could be expected. During well control operations. The formation of hydrates can be predicted using Figure 6. in a horizontal well. There have been recorded incidences of such occurrences with subsea stacks in water depths of 350m and deeper.BP WELL CONTROL MANUAL • There is a greater potential for swabbing when a large surface area of reservoir is exposed. the ‘Gray’ valve can be used. the temperature would be expected to drop to 55°F. It is quite feasible. Figure 6. This is particularly hazardous when high gas flowrates are experienced through low pressure equipment (such as the poorboy separator and gas vent line). In the event of a kick whilst tripping it may not be possible to drop or pump down the dart. liquid content and pressure and temperature. preventing opening and closing of subsea BOPs. • Plugging of surface lines at and downstream of the choke or restriction. 9 Hydrates Natural gas hydrates have the appearance of hard snow and consist of chemical compounds of light hydrocarbons and liquid water.36). gas hydrates may cause the following serious problems: • Plugging of subsea choke/kill lines. that the horizontal section is full of reservoir fluid and yet the well be dead. When back on bottom it is recommended to circulate bottoms up through the choke manifold. The major factors which determine the potential for hydrate formation are gas composition. which cause the mixing of hydrocarbon components. sealing off wellbore annuli and immobilising the drillstring. This will depend on the hole angle at the dart sub position. in which case.36. This formation process is accelerated when there are high gas velocities. It should be noted that the conditions for hydrate formation can be created at a subsea stack operating in a cold water environment. If it is not possible to install the dart into the dart sub. They are formed at temperatures above the normal freezing point of water at certain conditions of temperature and pressure (See Figure 6. As an example. if gas at 3000 psi and 90°F was choked to 1800 psi.37 can be used to predict the temperature drop associated with a pressure drop (across a choke. such as downstream of a choke and at elbows. for example). It is therefore recommended that extreme caution be paid when tripping back into such a reservoir after a round trip. Correct tripping procedure must be rigorously adhered to. pressure pulsations or other agitations. 36 Temperature at which Gas Hydrates will Freeze (Katz) The purpose of this chart is to determine the temperature below which hydrates will form. 4000 3000 1000 NE HA 900 800 ET M 700 600 500 400 AV R 6 0. 100 90 80 70 60 35 40 45 50 55 60 65 70 75 80 85 TEMPERATURE (°F) Example: With 0. hydrates may be expected at 64°F. when sufficient liquid water is present. G 300 7 0. 0 0. 8 PRESSURE FOR HYDRATE FORMATION (psia) 2000 200 9 1.BP WELL CONTROL MANUAL Figure 6. 0. WEOX02.7 specific gravity gas at 1000psia.061 6-106 March 1995 . At 200psia this would be 44°F. GAS TEMPERATURE (°F) 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 0 6 0 50 00 60 00 50 1000 00 55 00 45 00 40 00 35 00 30 2 00 15 0 0 20 MP 2000 0 50 TE D ET CO 0 ES SU R OP PRESSURE (lb/in ) 3000 2 S VE 4000 HYDRATE EXPECTANCY DEGREES FAHRENHEIT R ED R CU S Y LP GA A T TH U F EN C T 00 N 0 TA U/1 NS BT 0 50 DU 00 10 P RO R OP INITIAL TEMP RISE 150 00 70 105° .37 Natural Gas Expansion – Temperature reduction curve (NATCO) WEOX02.062 6-107 March 1995 .80° = 25° 160 NATURAL GAS EXPANSION – TEMP REDUCTION CURVE BASED ON 7 SP GR GAS (From NATCO) 5000 EXAMPLE REQUIRED: REDUCE GAS PRESSURE FROM 2400 # PSI AT 80°F TO 1500 # PSI DETERMINE INITIAL TEMPERATURE RISE NECESSARY SO THAT AFTER EXPANSION TO 1500 # PSI THE FINAL TEMPERATURE WILL BE 75°F BASE LINE 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 BP WELL CONTROL MANUAL Figure 6. consequently causing excessive downhole pressures.BP WELL CONTROL MANUAL Hydrates can be combated by one or a combination of the following: • Injecting antifreeze agents such as methanol into the gas flow. if it is suspected that the potential exists for hydrate formation. Once hydrates have formed. the MAASP is no longer a consideration and may be exceeded. it is clear that the MAASP is a consideration only when there is a full column of mud from the openhole weak point to the surface. • Reducing line pressure in order to allow the hydrates to melt. 6-108 March 1995 . It is important that adequate contingency is provided. The most appropriate place to inject methanol at surface is at the choke manifold. Surface pressures in excess of the MAASP therefore may not cause downhole failure if lighter fluids (such as a hydrocarbon influx) occupy the annulus above the openhole weak point. Consequently. from the moment that the top of an influx is displaced past and above the openhole weak point. 10 Surface Pressures Approach the MAASP The MAASP is defined as the maximum allowable annular surface pressure. The point of injection should be upstream of the choke. • Heating the gas above the temperature at which hydrate will form. a steam exchanger will usually be provided for this purpose. or slightly greater than. This is a temporary measure and not always practical. to deal with hydrates. this has the effect of dissolving liquid water deposits. assuming that MAASP is calculated from LO Test result). During gas well testing operations. Subsea water temperatures and pressures should be checked as well as the potential for hydrate formation at surface in the event of a gas kick. and thus lowering the temperature at which hydrates would be expected to form. Bearing in mind the method that is used to calculate its value (i. there are two distinct options: • Hold the choke pressure so as to maintain bottomhole pressure equal to. Experience has shown that this is the most effective and reliable method of preventing the formation of hydrates. it often takes a considerable length of time to clear the line. during a well control operation. High pressure chemical injection pumps (as manufactured by Texsteam) are suitable for this application. the kick zone pore pressure. along the above lines.e. In the event that surface pressures exceed the MAASP when the kick is still below the openhole weak point. The combination of heating and antifreeze injection is ideal. Methanol is often injected at the subsea test tree during well testing operations from a floating rig. • Reduce the choke pressure and limit it to the MAASP. • The length of time that the openhole weak point will be overpressured. On a floating rig. should this occur. • The length of time that the kick zone will be underbalanced. The consequences of underbalancing the formation as in the second option can be assessed. a critical situation is reached should it become necessary to unlatch the riser during a well control operation. bearing in mind the following factors: • The depth of the casing shoe. The appropriate course of action should therefore be selected on the basis of these factors. the following procedure can be implemented: 1 Attempt to bullhead the influx back to the formation 2 Displace the drillstring to kill weight mud 3 Close lowermost pipe rams (in addition to the hang-off rams). Shear the pipe rams 4 Prepare to unlatch. it may not be possible to offload baryte supplies or remove excess personnel in bad weather. Should weather conditions deteriorate with very little warning. • The characteristics of the openhole weak point. monitoring wellbore pressures until it becomes necessary to unlatch 6-109 March 1995 . However. in general. • Any safety factor included in the calculation of the MAASP. 11 Impending Bad Weather Bad weather is most likely to cause serious problems as regards well control on offshorerigs. • The permeability of the kick zone. This can often be assessed from the rate of pressure build after shutting in a well that has kicked. a kick zone should only be underbalanced in exceptional circumstances such as when the zone is known to have low permeability. • The quality of the cement job. • The possibility of broaching around the casing. • The degree of underbalance. • By how much the openhole weak point will be overpressured.BP WELL CONTROL MANUAL The consequences of overpressuring the openhole weak point as in the first option can be assessed. For example. In this situation it will not be possible to monitor the well and hence control the migration of the influx. bearing in mind the following factors: • The type of kick zone fluid. These failures have been attributed to faulty manufacture. should there not be adequate chemical stocks at the rigsite. lower weights on bit. Points of particular concern are. 6-110 Rev 1 March 1995 March 1995 .BP WELL CONTROL MANUAL If additional time is available. severe cold may cause operational problems. it may be necessary to implement the Driller’s Method. the same volume of formation influx will occupy a longer section of the annulus in a slim hole well than in a conventional well. Bad weather may cause problems regarding the supply of chemicals and barytes to all types of rigs. Whilst the immediate difference between a conventional well and a slim hole well is their hole sizes.5"x5" well and 523 m long in a 3. in critical situations. (a) Slim Hole Characteristics In terms of well control. However there are recorded incidents of equipment failure at pressures significantly below rated values. So a slim hole well requires significant changes in the well design.38. As shown in Fig. lack of proper maintenance. a 10 bbl influx occupies 66 m long annulus in a conventional 8. 13 Well Control Considerations in Slim Hole Well A slim hole is commonly defined as one in which 90% or more of the length of the well is drilled with drill bits less than 7" in diameter.6. consideration should be given to spotting a heavy pill or plug on bottom to either kill the well hydrostatically or provide a barrier to migration. a slim hole well has the following characteristics when compared with a conventional well: • Greater Influx Length Due to the reduced annular size in a slim hole. or corrosion. In this respect. action should be taken bearing in mind that the absolute priority is the safety of rigsite personnel. manifolds and flowlines. BOP operating fluid. A well with hole sizes smaller than those in a conventional well is also broadly considered as a slim hole well. other major characteristics of a slim hole include the practice of long sections of continuous coring and the requirements of higher drillpipe rotary speeds.5"x2. In certain areas of the world. High pressure equipment is considered particularly susceptible to failure when exposed to corrosive fluids such as H2 S. lower mud flow rates and special mud systems. However.5" slim hole well. well operation and the well control procedures. It is not possible to detail specific procedures in the event of loss of control during a well control operation. 12 Loss of Control Loss of control during a well control operation may result from excessive loading of pressure control equipment or exposed formations. This effect must be taken into account in the well control procedures. the drillpipe rotation can result in a significant increase in the annular friction pressure and the ECD.6.6. Due to the high rotational speed together with the small annular size.5"x2.40. the annular friction pressure drop can be many times higher in a slim hole well than in a conventional well.41 compares the swabbing pressure in both slim hole and conventional wells. This technique is most reliable when the influx flow is slow (low kick intensity). It can be seen that the swabbing pressure is much higher in a slim hole well than in a conventional well. The high annular friction pressure creates a high ECD during drilling ahead. • The system must be able to detect a kick whilst making a connection. a 10 bbl gas influx will reduce the bottom hole pressure by about 743 psi in a 3. The basic requirements for a slim hole kick detection system are: • The system must be able to detect a small volume of pit gain (typically 1 or 2 bbl).6.5"x5" well. as shown in Fig. or a kick influx be induced when rotation stops (whilst still maintaining circulation). the weak formation may be broken down when the drillpipe starts to rotate. • Higher Annular Friction Pressure Also due to the reduced annular size. a kick can develop more rapidly in a slim hole well than in a conventional well. Therefore the friction pressure drop can become significant during well control operations in a slim hole well whereas it is all but ignored in the case of a conventional well. As the result. Asshown in Fig. Although the basic principles in the kick detection technique remain the same for slim holes. When the influx flow is fast. • Effect of High Drillpipe Rotational Speed During a slim hole drilling operation. Therefore it is important to be able to detect a kick at a very early stage during a slim hole well operation. • The system must be able to detect the difference between the mud flow in and out of the well (typically 25 gpm). This will cause the influx flow to intensify continuously. this technique is more sensitive and reliable than the pit volume detection technique. a small volume of influx can occupy a long section of the annulus in a slim hole well and thus greatly reduce the bottom hole pressure. the drillpipe is often rotated at a much higher rate than that during a conventional drilling operation.BP WELL CONTROL MANUAL • Greater Bottom Hole Pressure Reduction As the result of the greater influx length. • Higher Swab and Surge Pressures Fig.39. Otherwise. the sensitivity of the detection system must be enhanced. 6-111 Rev 1 March 1995 March 1995 . Also the swabbing pressure increases more rapidly in a slim hole well with increasing the trip speed.5" slim hole well and only 94 psi in a conventional 8. (b) Kick Detection System As described above. the same volume of formation influx will result in a greater reduction in the bottom hole pressure in a slim hole well. So the most likely time for a kick to occur will be when the pumps are shut down to make a connection. e. well shut-in and the well kill technique for slim holes. Otherwise the slim hole well control technique must to be used. BP Exploration. • Compare the total wellbore pressure with the breakdown pressure at the weak point. This can be made in the followingsteps: • Estimate the annular friction pressure at the slow circulating rates and add this to the maximum static pressure (i. 6-112 Rev 1 March 1995 March 1995 .BP WELL CONTROL MANUAL (c) Well Kill Technique As the annular friction pressure is small in a conventional well. (d) Slim Hole Well Control Manual This section briefly summarises the key differences in well control for slim holes. Will lost circulation be likely? • If lost circulation is unlikely. the conventional well control technique can be applied. it is used as a safety factor during the well kill operation to ensure that the bottom hole pressure stays slightly above the formation pressure. kick detection. Therefore a decision that must be made when drilling a slim hole is whether the conventional well kill technique can be applied. The manual can be obtained from the Drilling and Completions Branch. So the annular friction pressure is usually ignored in the conventional well control calculations. the annular friction pressure may be so high that when used as a safety factor. A BP Slim Hole Well Control Manual is available that details the principles and procedures for kick prevention. the sum of the mud hydrostatic pressure and the surface casing pressure) at the weak point in the wellbore. In a slim hole well however. it will break down the formation at the weak point and cause lost circulation. Sunbury. 5 x 5 66 94 8.5 x 5 6 x 4.6 68.3 BP WELL CONTROL MANUAL Gas Influx Height (m) 1 0 400 6-113 Annular Size (inch) Figure 6.5 x 5 10 6 x 4.38 Height of 10 bbl Gas Influx in Annulus Figure 6.5 x 2.38a: Height of 10 bbl Gas Influx in Annulus Gas Influx 6 Volume0 0 (bbl) Rev 1 March 1995 March 1995 .2 523 m 199 m 0 66 m 8.0 cPMud: PV=15/YP=10 13.5 523 743 3.9 254.5 x 2.0 sg Mud 10 200 Friction Pressure (psi) Brine: 4.5 Height of Gas Influx (m) Reduction In BHP (osi) 1.5 Size of Annulus (inch) 3.5 x 2.5 199 283 6 x 4.5 41 128.8.8 31.5 3. 5 BP WELL CONTROL MANUAL Mud: PV=15/YP=10 31.0 SG Density Difference Between Mud and Gas) 800 254.39 Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx Rev 1 1995 March March 1995 Figure 6.5 x 5 6 x 4.6 400 743 psi 200 283 psi 0 94 psi 8.5 Size of Annulus (inch) 3.2 600 Figure 6.(1.38b: Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx .5 x 2.3 Reduction in BHP (psi) 6-114 128. swab pressures 200 Brine: 4.3 x 2.1 66.3 48.8 50.3 68.1 94.5/5 300 250 200 150 100 50 40 30 25 20 15 6/4.2 98.5 55.9 52.5 48.8 8.5 Size of Annulus (inch) 8.38c: Annular Friction Pressure Drop Rev 1 March 1995 March 1995 .4 92.8 46 46.7 128.2 3.5/2.8 64.5 44.5 x 5 6 x 4.9 41.0 cP 150 sec/std Mud: PV=15/YP=10 129 100 50 0 31.5 40.5 110 117.9 41 41.4 168 238 368 BP WELL CONTROL MANUAL 6-115 Friction Pressure Drop (psi/1000m) 254 250 Swab Pressure (psi/1000m) Height of Ga (m) (Mud Annular Velocity = 150 ft/min) 300 Figure 6.8 47.40 Annular Friction Pressure Drop Figure 6.5 55 58.2 41 13.2 147 90 90.5 45.8 46.8 92.7 42.8 3. Reduction in (psi) (Mud: 1.0" Annulus 60 0 90 60 30 Trip Speed (sec/30m std.0"x4.5 1 8 08 .0 SG. 5 / 5 6.) 0 BP WELL CONTROL MANUAL 240 Figure 6.7 128.8 92.4 168 238 368 Swab Pressure (psi/1000m) 3. PV=15 cP.38d: Swab Pressure in a 1000 m Hole . YP=10 lbf/100sqft) 300 3.5"x2.41 Swab Pressure in a 1000 m Hole March March 1995 Rev 1 1995 Figure 6.2 98.5" 120 8.5" 6-116 90 90.5 110 117.1 94.5/2.5"x5. 4 March 1995 .3 2.BP WELL CONTROL MANUAL Volume 2 – Contents Nomenclature Abbreviations 1 THE ORIGINS OF FORMATION PRESSURE Section Page 1.3 SUBNORMAL FORMATION PRESSURE 1-11 1.1 INTRODUCTION 2-1 2.2 NORMAL FORMATION PRESSURE 1-9 1.2 FORMATION PRESSURE EVALUATION DURING WELL PLANNING 2-5 FORMATION PRESSURE EVALUATION WHILST DRILLING 2-25 FORMATION PRESSURE EVALUATION AFTER DRILLING 2-69 2.5 SHALLOW GAS 1-33 2 FORMATION PRESSURE EVALUATION Section 2.4 ABNORMALLY HIGH FORMATION PRESSURE 1-17 1.1 INTRODUCTION 1-1 1. EMW 3-2 4 CIRCULATING PRESSURES AND ECD 3-4 5 CALCULATING THE CIRCULATING PRESSURE LOSSES 3-7 6 SWAB AND SURGE PRESSURES 3-10 7 SWAB AND SURGE CALCULATIONS 3-12 4 FRACTURE GRADIENT Paragraph 1 GENERAL 4-2 2 STRESSES IN THE EARTH 4-2 3 FRACTURE ORIENTATION 4-3 4 FRACTURE GRADIENT PREDICTION 4-4 5 DAINES’ METHOD OF FRACTURE GRADIENT PREDICTION 4-4 6 AN EXAMPLE PRESSURE EVALUATION LOG 4-7 7 LEAK OFF TESTS 4-9 8 LEAK OFF TEST PROCEDURE 4-10 9 INTERPRETATION OF RESULTS 4-11 March 1995 .BP WELL CONTROL MANUAL 3 PRIMARY WELL CONTROL Paragraph 1 GENERAL 3-2 2 HYDROSTATIC PRESSURE 3-2 3 EQUIVALENT MUD WEIGHT. 1 WELLHEADS 6-1 6.3 CONTROL SYSTEMS 6-43 6.4 ASSOCIATED EQUIPMENT 6-57 6.2 BLOWOUT PREVENTER EQUIPMENT 6-5 6.5 EQUIPMENT TESTING 6-67 March 1995 .BP WELL CONTROL MANUAL 5 BASICS OF WELL CONTROL Paragraph 1 GENERAL 5-4 2 DISPLACING A KICK FROM THE HOLE 5-4 3 FACTORS THAT AFFECT WELLBORE PRESSURES 5-9 4 SUBSEA CONSIDERATIONS 5-20 5 SAFETY FACTORS 5-25 6 CALCULATING ANNULUS PRESSURE PROFILES 5-29 6 WELL CONTROL EQUIPMENT Section 6. in. in.2 – – bbl/m bbl/m % – – m m m in. in. – lb – SG – psi/ft psi/m SG psi/ft m m m µsec/m March 1995 m – m/hr psi lb SG . in. in.2 – in.BP WELL CONTROL MANUAL NOMENCLATURE SYMBOL DESCRIPTION UNIT A a An b c C Cp Ca CL CR D Dshoe Dwp dbit dh dhc do di dcut dc F Fsh FPG g G Cross sectional area Constant Total nozzle area Constant Constant Annular capacity Pipe capacity Cuttings concentration Clinging constant Closing ratio Depth Shoe depth Depth of openhole weak point Bit diameter Hole diameter Hole/casing ID Pipe OD Pipe ID Average cuttings diameter Drilling exponent (corrected) Force Shale formation factor Formation Pressure Gradient Gravity acceleration Pressure gradient Gi H Hi Hp ITT K L λ MR M m MW Influx gradient Height Height of influx Height of plug Interval Transit Time Bulk modulus of elasticity Length Rotary exponent Migration rate Matrix stress Threshold bit weight Mud weight in. R m m bbl March 1995 . F.BP WELL CONTROL MANUAL SYMBOL DESCRIPTION UNIT N OPG P Rotary speed Overburden Pressure Gradient Pressure ∆P Pa ∆Pbit Pcl Pdp Pf Pfrac Pfc Pi Pic Plo Pmax S Sg Sw t Adjustment pressure Annulus pressure Bit pressure drop Choke line pressure loss Drillpipe pressure Formation pressure Fracture pressure Final circulating pressure Hydrostatic pressure of influx Initial circulating pressure Leak off pressure Maximum allowable pressure at the openhole weak point Wide open choke pressure Pore pressure Slow circulating rate pressure Plastic Viscosity Flowrate Mud flowrate Gas flowrate Reynolds number Resistivity Resistivity of water Rate of Penetration Shale factor Overburden pressure Gas saturation Water saturation Time rpm SG psi/SG (The units of subsurface pressure may be either psi or SG) psi psi psi psi psi psi/SG psi/SG psi psi psi psi/SG TR T Transport Ratio Temperature TD TVD V Total Depth True Vertical Depth Kick tolerance Poc Pp Pscr PV Q Qmud Qgas Re R Rw ROP psi/SG psi psi/SG psi cP gal/min gal/min gal/min – ohm-m ohm-m m/hr meq/100g psi Fractional Fractional seconds min – degrees C. BP WELL CONTROL MANUAL SYMBOL DESCRIPTION V Volume v vmud vp vs W w w wb wcut WOB x YP Z µ ν σ’1 σ’t Ø Ø600 β ρ ρb March 1995 UNIT bbl cc ml l Velocity m/min m/s Mud velocity m/min Average pipe running speed m/min Slip velocity m/min Weight gm kg lb Weight lb/ft lb/bbl SG Weight of pipe lb/ft Baryte required for weighting up lb/bbl Average cuttings weight SG Weight on Bit lb Offset () Yield Point lb/100ft2 Compressibility factor – Viscosity cP Poissons’s Ratio – Maximum effective principle stress psi/SG Tectonic stress psi/SG Porosity Fractional Fann reading lb/100ft2 Tectonic stress coefficient – Density SG Bulk density SG . BP WELL CONTROL MANUAL ABBREVIATIONS ASN BHA BHC BHT BGG BRT CDP CEG CG DE DIL DRG DST ECD EMW ES FDC FIT HCR ID ITT LMRP MWD OD PV RFT RMS ROP SLS TD TG UV WOB YP Amplified Short Normal Bottomhole Assembly Borehole Compensated Tool Bottomhole Temperature Background Gas Below Rotary Table Common Depth Plot Cation Exchange Capacity Connection Gas Drilling Engineer Dual Induction Laterolog Designated Resident Geologist Drillstem Test Equivalent Circulating Density Equivalent Mud Weight Electrical Survey Formation Density Compensated Tool Formation Interval Tester High Closing Ratio Internal Diameter Interval Transit Time Lower Marine Riser Package Measurement while Drilling Outside Diameter Plastic Viscosity Repeat Formation Tester Root Mean Squared Rate of Penetration Long Spacing Sonic Tool Total Depth Trip Gas Ultra Violet Weight of Bit Yield Point March 1995 . 4 ABNORMALLY HIGH FORMATION PRESSURE 1-17 1.3 SUBNORMAL FORMATION PRESSURE 1-11 1.1 INTRODUCTION 1-1 1.BP WELL CONTROL MANUAL 1 THE ORIGINS OF FORMATION PRESSURE Section Page 1.5 SHALLOW GAS 1-33 March 1995 .2 NORMAL FORMATION PRESSURE 1-9 1. 2 Composite Overburden Load for Normally Compacted Formations 1-4 Schematic Diagram of Subsurface Pressure Concepts 1-5 Types of Formation Pressure Seals 1-6 Tables 1.1 1.1 1-1 March 1995 .BP WELL CONTROL MANUAL 1.1 INTRODUCTION Paragraph Page 1 General 1-2 2 Subsurface Pressures 1-2 3 Pressure Seals 1-6 4 Pressure Gradients 1-7 Illustrations 1. length in ft.in/sq. it is neccesary to define and explain certain subsurface pressure concepts.BP WELL CONTROL MANUAL 1 General All formations penetrated whilst drilling a well exert pressures of varying magnitudes.ft/sq.ft/gal lb/sq. It has a value of 0.48 144 lb/sq.052 psi/ft per lb/gal 1-2 March 1995 .in cu.ft. 2 Subsurface Pressures (a) Hydrostatic Pressure Hydrostatic pressure is defined as the pressure due to the unit weight and vertical height of a fluid column.ft Substituting the standard conversion constants of 144 sq.ft ft X lb/cu.ft gives: C=1 X C = 0. The size and shape of the fluid column do not affect the magnitude of this pressure.052 7. density in lb/cu. Mathematically: P=rXgXD where P ρ g D = = = = (1-1) hydrostatic pressure average fluid density gravitational acceleration vertical height of fluid column Relating this to drilling operations and commonly used oilfield units gives: P = C X MW X D where P MW D C = = = = (1-2) hydrostatic pressure (psi) fluid density or mud weight (lb/gal or ppg) vertical depth (ft) conversion constant (psi/ft per lb/gal) The constant. lb/gal).052 psi/ft per lb/gal and is derived as follows: Using consistent units (pressure in lb/sq.in ft X lb/gal C = 0. These are explained in this Section.ft and 7. C. ft.ft/ft per lb/cu. C would be numerically equal to 1: C= P D X MW = 1 lb/sq. is necessary to allow the use of oilfield imperial units (psi. To gain an understanding of the origins of these pressures.ft) and rearranging equation 1-2.ft X sq.48/gal/cu. The average density of a thick sedimentary sequence is equivalent to an SG of 2.BP WELL CONTROL MANUAL So in imperial oilfield units (psi. It is the ratio of the density of afluid to the density of fresh water at a specified temperature.3.052 X MW – D (1-3) For the Company’s system of units (psi. and hence has no units. It was originally assumed that overburden pressure increases uniformly with depth.421 psi/m and is derived as follows: To express equation 1-2 in terms of SG (as in equation 1-4). Hence for fresh water: C' = C X 8.3 = 1. equation 1-2 becomes: P = 0.433 X SG X D (1-7) where D = vertical depth (ft).33 psi/ft C' = 0. has a value of 1.2808 psi/ft X ft/m C' = 1.0 psi/ft 1-3 March 1995 . the overburden pressure (S) is given by: S = 0. The constant. Hence. m): P = C' X SG X D (1-4) where SG = specific gravity of the fluid (no units) D = vertical depth (metres) C' = conversion constant (psi/m) NOTE: Specific gravity (SG) is not a unit of density.433 X X SG 2. the constant C' must be related to the density of fresh water.052 X 8. The overburden pressure gradient (OPG) is given by: OPG = S D = 0.433 X 3. ft. which is 8. C'. lb/gal).33 psi/ft/lb/gal X lb/gal C' = 0. SG.421 X SG X D (1-6) (b) Overburden Pressure Overburden pressure is the result of the combined weight of the formation matrix (rock) and the fluids (water.433 psi/ft (1-5) Expressing this in terms of metres using 3. oil and gas) in the pore space overlying the formation of interest.33 lb/gal.2808 ft/m gives: C' = 0.421 psi/m Equation 1-4 thus becomes: P = 1.433 OPG = 0. USA North Sea area 0 1 4 2 3 1 DEPTH 1000m 2 3 4 5 6 0. Texas and Louisiana.1 Composite Overburden Load for Normally Compacted Formations 1.05 OVERBURDEN GRADIENT psi/ft WEOX02. 3. USA Santa Barbara Channel.BP WELL CONTROL MANUAL Figure 1. 2.0psi/ft Gulf of Mexico.9 1. California.0 1.7 0. Constant gradient 1.8 0. 4.063 1-4 March 1995 . the overburden pressure gradient may be assumed to be close to 1 psi/ft. the overburden pressure gradient is not constant. Offshore however. Pf Matrix Stress. overburden gradients at shallow depths will be much less than 1 psi/ft due to the effect of the depth of sea water and large thickness of unconsolidated sediment. PRESSURE AL RM NO OS VE R TA B U TIC R D EN GR DEPTH DR HY O G AD R A T IEN SUBNORMAL PRESSURES (Subpressures) D IE N T ABNORMALLY HIGH PRESSURES (Surpressures) Formation Pressure.BP WELL CONTROL MANUAL However. shale) may be as high as 1. with more compact sediments.064 Figure 1.35 psi/ft. Worldwide experience indicates that the probable maximum overburden gradient in clastic rocks (fragmental sedimentary rocks ie sandstone. M Overburden Pressure. because the degree of compaction of sediments varies with depth.2 Schematic Diagram of Subsurface Pressure Concepts 1-5 March 1995 . Figure 1.1 shows average overburden gradient for various areas. Onshore. S = Pf + M WEOX02. This is the strict meaning of what is generally referred to as formation pressure.BP WELL CONTROL MANUAL (c) Pore Pressure Pore pressure is the pressure acting on the fluids contained in the pore space of the rock. Transverse Faults Salt and shale diapirs Worldwide Combination Table 1. Any departure from this situation will give rise to ‘abnormal’ formation pressures. marl.1.1 Worldwide Types of Formation Pressure Seals 1-6 March 1995 . Formation pressures less than hydrostatic are called subnormal (subpressures) and formation pressures greater than hydrostatic are termed abnormally high formation pressures (surpressures) (See Figure 1. The types of formation pressure seals are listed below in Table 1. In this ‘normal’ pressure situation. North Sea. there must be a permeability barrier which acts as a pressure seal. USA. chemical or a combination of the two. USA. The origins of a pressure seal may be physical. the matrix stress (grain-to-grain contact pressure) supports the overburden load. 3 Pressure Seals For abnormal pressures to exist. Middle East. USSR. This seal restricts or prevents the movement of pore fluids and thus separates normally pressured formations from abnormally pressured formations.2). chalk Dolomite Gulf Coast. Zechstein in North Germany. Formation pressure is related to overburden pressure as follows: S = Pf + M (1-8) where S = overburden pressure (total vertical stress) Pf = formation pressure (pore pressure) M = grain-to-grain pressure (matrix stress) All sedimentary rocks have porosity to some extent. Type of Seal Nature of Seal Examples Vertical Massive siltstones Shales Massive salts Anhydrite Gypsum Limestone. If the pore spaces of the rocks are freely connected from surface. then the formation pressure at any depth will be equal to the hydrostatic pressure exerted by the fluid occupying the pore spaces. mud weights and equivalent circulating densities (ECDs) on the same basis (See Chapter 3). it is common practice to express subsurface pressures in terms of pressure gradients. then the datum chosen for final well planning and whilst drilling is the rotary table level (since mud hydrostatic pressure starts from just below this level).433 X D (ft) (1-14) NOTE: From this point on ppg will be used instead of lb/gal as the abbreviated version of pounds per gallon. and rearranging equation 1-6 gives: PG = P D = 1. Example: For a formation pressure of 5970 psi at 3500m BRT. Or. By converting subsurface pressures to gradients relative to a fixed datum.421 X D (m) (1-13) EMW (SG) = P (psi) 0.421 X SG (1-10) where PG = pressure gradient (psi/m) at depth D (m). overburden pressures. The datum chosen is usually sea/ground level for initial planning purposes. fracture pressures. This allows direct comparison of downhole pressures to the weight (density) of the mud in use. PG = P D = 0.433 X SG (1-11) where PG = pressure gradient (psi/ft) at depth D (ft). psi/ft or psi/m. EMWs can be calculated from rearrangements of equations 1-9 to 1-11: EMW (lb/gal) = P (psi) 0.052 X D (ft) (1-12) EMW (SG) = P (psi) 1. These units can easily be converted to psi/ft or psi/m using the conversion constants derived earlier in Paragraph 2(a). Once a rig has been allocated for the well. or pressure per unit depth.BP WELL CONTROL MANUAL 4 Pressure Gradients As indicated previously in Paragraph 2(b) under ‘Overburden Pressure’. During drilling operations.052 X MW (1-9) where PG = pressure gradient (psi/ft) at depth D (ft). what is the formationpressure gradient in psi/ft? What is the equivalent mud weight in ppg and SG? 1-7 March 1995 . It should be realised that densities such as mud weights in lb/gal orSG. it is standard practice to express all pressure gradients in terms of equivalent mud weight (EMW) either in lb/gal or SG. Rearranging equation 1-3 gives: PG = P D = 0. it is possible to directly compare formation pressures. also express pressure gradients. 2808 EMW = 10.2808 pressure depth = 0.0 ppg From equation 1-13 EMW = 5970 1.052 X 3500 X 3.52 psi/ft Equivalent mud weight from equation 1-12 EMW = 5970 (ppg) 0.BP WELL CONTROL MANUAL Formation pressure gradient.20 SG 1-8 March 1995 . FPG = FPG = 5970 3500 X 3.421 X 3500 = 1. 2 1-9 March 1995 .BP WELL CONTROL MANUAL 1.2 NORMAL FORMATION PRESSURE Paragraph Page 1 General 1-10 2 Magnitude and Examples 1-10 Average Normal Formation Pressure Gradients 1-10 Tables 1. has a pressure gradient of 0. in the absence of accurate data.515 psi/ft). In formations deposited in an offshore environment. Formation Water Pressure (psi/ft) Gradient (SG) Example Area Fresh water 0. 0.02 SG. For instance. South China Sea Salt water 0.04 North Sea.2 Average Normal Formation Pressure Gradients 1-10 March 1995 . formation water with a salinity of 80. the average value of normal formation pressure gradient may not be valid for all depths. The following table gives examples of the magnitude of the normal formation pressure gradient for various areas.515 psi/ft may exist in formations adjacent to salt formations where the formation water is completely salt saturated.442 1.07 Gulf of Mexico.452 1. USA Salt water 0.19 SG.465 psi/ft is often taken to be the normal pressure gradient.BP WELL CONTROL MANUAL 1 General Normal formation pressure is equal to the hydrostatic pressure of water extending from the surface to the subsurface formation.433 psi/ft. For example.01 Salt water 0. Increasing the dissolved solids (higher salt concentration) increases the formation pressure gradient whilst an increase in the level of gases in solution will decrease the pressure gradient. Salinity varies with depth and formation type. formation water density may vary from slightly saline (1. However.02 Most sedimentary basins worldwide Salt water 0.000 ppm sodium chloride (salt) at a temperature of 25°C. 2 Magnitude and Examples The magnitude of the hydrostatic pressure gradient is affected by the concentration of dissolved solids (salts) and gases in the formation water. 0.438 1. Therefore.10 Some areas of Gulf of Mexico Table 1. USA Brackish water 0.465 1.433 1. it is possible that local normal pressure gradients as high as 0. the normal formation pressure gradient in any area will be equal to the hydrostatic pressure gradient of the water occupying the pore spaces of the subsurface formations in that area.478 1. Freshwater (zero salinity) has a pressure gradient of 0.465 psi/ft.00 Rocky Mountains and Mid-continent.44 psi/ft) to saturated saline (1. Temperature also has an effect as hydrostatic pressure gradients will decrease at higher temperatures due to fluid expansion. 0. Thus. BP WELL CONTROL MANUAL 1.5 Relationship between Piezometric Surface and Ground Level for an Aquifer System 1-13 Temperature-pressure-density diagram for Water illustrating Subnormal Pressures caused by Cooling an Isolated Fluid 1-14 Formation Foreshortening 1-15 1-11 March 1995 .3 SUBNORMAL FORMATION PRESSURE Paragraph Page 1 General 1-12 2 Causes of Subnormal Formation Pressure 1-12 3 Magnitude of Subnormal Formation Pressures 1-15 4 Summary 1-16 Illustrations 1.4 1.3 1. The piezometric surface for an aquifer system is shown in Figure 1. For example. (a) Depleted Reservoirs Producing large volumes of reservoir fluids causes a decline in pore fluid pressure unless compensated for by a strong water drive. They may have natural causes related to the stratigraphic.385psi/ft. tectonic and geochemical history of an area. A piezometric surface is dependent on the structural relief of a formation and can result in subnormal or abnormally high formation pressures. (c) Temperature Reduction A reduction in subsurface temperature will reduce the pore pressure in an isolated fluid system where the pore volumes (and thus fluid density) remains constant. After twelve years production from the field and even with pressure boosting by water injection.BP WELL CONTROL MANUAL 1 General Subnormal formation pressure is defined as any formation pressure that is less than the corresponding pore fluid hydrostatic pressure. or may be caused artificially by producing reservoir fluids. the reservoir formation pressure dropped to approximately 2750 psi.3. the original reservoir formation pressure in BP’s Forties Field was 3215psi at a depth of 2175m subsea. the water table may be deep. Subnormal formation pressures are often termed subpressures. This equates to a formation pressure gradient of 0.451psi/ft. the water table is a particular potentiometric surface. (b) Piezometric Surface A piezometric or potentiometric surface is an imaginary surface that represents the static head of ground water and is defined by the level to which the ground water will rise in a well. A subnormal formation pressure gradient is thus any gradient less than the pore fluid hydrostatic gradient. which is the normal hydrostatic gradient. 2 Causes of Subnormal Formation Pressure Subnormal formation pressures occur less frequently than abnormally high formation pressures. 1-12 March 1995 . The hydrostatic pressure gradient commences at the water table giving a subnormal pressure gradient from the surface. This gives a subnormal pressure gradient of 0. Drilling in mountainous areas may thus encounter subnormal pressure gradients due to the surface elevation being higher than the water table elevation or formation water potentiometric surface. Depleted reservoirs may thus have pore pressures less than hydrostatic. For example. In very arid areas such as the Middle East. This may cause subnormal pressures. This reduction may be due to an increase in pore volume and removal of free water from the pore space by adsorption in clay minerals as the overburden pressure decreases. Mechanisms which may create a reduction in subsurface temperature include uplift.5°C/100m).4 of this Chapter. In shales. a temperature reduction associated with a depth change would follow the path indicated (which in this example corresponds to a temperature gradient of 2. cooling must take place along a constant density path as shown.065 Figure 1. (This is the reverse of ‘Clay diagenesis’ as described in Section 1.3 Relationship between Piezometric Surface and Ground Level for an Aquifer System The temperature-pressure-density diagram for water shown in Figure 1. erosion or a combination of uplift and erosion. In an isolated fluid system (ie/completely sealed shales). Both temperature and pressure are dependent on depth. Water adsorption due to mineral transformations (eg/illite to montmorillonite) may also occur due to the decrease in temperature. uplift and overburden removal by erosion may cause a reduction in pore fluid pressure.4 illustrates this concept. For a normal fluid (non-isolated) which is allowed to expand and contract freely.BP WELL CONTROL MANUAL ABNORMALLY HIGH PRESSURES SUBNORMAL PRESSURES PIEZOMETRIC SURFACE INTAKE AREA GROUND LEVEL HYDROSTATIC HEAD AQUIFER DISCHARGE AREA RESERVOIRS WEOX02. the effects of temperature reduction will be greater as gas pressure is much more sensitive to temperature changes than water.) 1-13 March 1995 . If gas is present in the pores. (d) Decompressional Expansion Decompressional expansion is the term used to describe the combined effects of uplift and erosion. A lower pressure would result but it would still be equal to the normal hydrostatic pressure. The pressure corresponding to the lower temperature is thus subnormal. 066 1-14 March 1995 .98 1.877 = Initial conditions at depth 1 2 0.962 1 10 2.5 °C/ 100 m 9 8 PRESSURE 1000psi 7 6 PRESSURE AT DEPTH 1 1 5 PRESSURE AT DEPTH 2 FOR NORMAL FLUIDS 2 4 3 NORMAL FLUIDS ISOLATED FLUIDS 2 PRESSURE AT DEPTH 2 FOR ISOLATED FLUIDS 1 2 T2 0 50 T1 100 150 200 250 TEMPERATURE °C WEOX02.0gm/cc 11 0.933 DENSITY 0.BP WELL CONTROL MANUAL Figure 1.909 0.4 Temperature-pressure-density diagram for Water illustrating Subnormal Pressures caused by Cooling an Isolated Fluid = Conditions at depth 2 0. clays and clayey siltstones can act as semi-permeable membranes. If the flow is from a closed volume.067 Figure 1. (f) Osmosis Osmosis is the spontaneous flow of water from a more dilute to a more concentrated solution when the two are separated by a semi-permeable membrane. such as along the flanks of the Rocky Mountains. the pressure will decrease and may become subnormal. abnormally high pressures may result. then osmotic flow can occur. (e) Formation Foreshortening This is a tectonic compression mechanism. If salinity differences exist between the fluids in the sediments on either side of clay beds. such as shales. It is then possible for more competent intermediate beds. Osmosis is discussed in more detail in Section 1.5 Formation Foreshortening This pressure reduction may be sufficient to cause subnormal pressures which would be transmitted to any reservoir rocks associated with the shales. In the subsurface environment. It is suggested that during a lateral compression process acting on sedimentary beds. Likewise. as shown in Figure 1. upwarping of the upper beds and downwarping of the lower beds may occur. if the flow is into a closed volume. This mechanism is thought to occur in areas of recent tectonic activity. 1-15 March 1995 .BP WELL CONTROL MANUAL OVERPRESSURED A SUBNORMAL PRESSURE BED A P BED B P P B P OVERPRESSURED BED C C WEOX02. to have subnormal pressures due to the increase in pore volume.4 of this Chapter. The intermediate beds must expand to fill the voids left by this process.5. In terms of pressure gradients. It is probable that a number of processes have contributed to produce the subnormal pressures.385psi/ft. Subnormal gradients of 0.39 psi/ft have been quoted for areas of the Texas Panhandle (NW Texas) with one case as low as about 0. 4 Summary The various suggested causes of subnormal formation pressures can be classed as ‘artifically caused’ or ‘naturally caused’. the Forties Field reservoir is now subnormally pressured at 0. the other causes of subnormal pressure discussed have origins in the formations themselves and can be thought of as being naturally caused. Conversely.23 psi/ft thought to be the result of a low piezometric surface. subnormal formation pressures must be lower than the normal hydrostatic pressure for the location. since these subnormal pressures do not originate in the subsurface formation.188 psi/ft which was recorded in the Keyes gas field in Oklahoma. but are externally influenced. ‘Depleted reservoirs’ and ‘piezometric surface’ (where pressure regime depends on the surface location of the well) may be classed as artificial causes.BP WELL CONTROL MANUAL 3 Magnitude of Subnormal Formation Pressures By definition. It is unlikely that any one of these processes may be the sole cause of subnormal pressures in any particular area. 1-16 March 1995 .433 to 0. As previously discussed. subnormal pressures will have gradients less than normal (0. One of the lowest formation pressure gradients encountered is 0. particularly in the light of the dependency of the processes on depth and temperature.36 to 0.465 psi/ft depending on the particular area). 13 Schematic Diagram of a Mud Volcano 1-26 1.12 Abnormal Pressure Distribution around a Piercement Salt Dome 1-26 1.15 Schematic Diagram illustrating Osmotic Flow 1-30 1-17 March 1995 .7 Interlayer Water and Cations between Clay Platelets 1-20 1.11 Abnormal Formation Pressures caused by Tectonic Compressional Folding 1-24 1.4 ABNORMALLY HIGH FORMATION PRESSURE Paragraph Page 1 General 1-18 2 Causes of Abnormally High Formation Pressure 1-18 3 Magnitude of Abnormally High Formation Pressures 1-30 4 Summary 1-31 Illustrations 1.9 Water Distribution Curves for Shale Dehydration 1-23 1.8 Schematic of Reaction of Montmorillonite to Illite 1-21 1.BP WELL CONTROL MANUAL 1.14 Abnormally High Pressure due to Reservoir Structure 1-28 1.6 Typical Formation Pressures caused by Compaction Disequilibrium 1-19 1.10 Diagenetic Stages in the alteration of Montmorillonite to Illite 1-23 1. then hydrostatic pressures will be maintained. and the rate of expulsion and removal of pore fluids. overpressures and sometimes geopressures. This could occur either by an increase in the rate of sedimentation or by a reduction in the rate of fluid removal (caused by a reduction in permeability or by the deposition of a permeability barrier such as limestone). 2 Causes of Abnormally High Formation Pressure Abnormally high formation pressures are found worldwide in formations ranging in agefrom the Pleistocene age (approximately 1 million years) to the Cambrian age (500 to 600million years). Freshly deposited clays have adsorbed water layers and the solid clay particles do not have direct physical contact. The clay sediment has high porosity and is permeable in this initial state. More often. So as long as the expelled water can escape to surface or through a porous sand layer. a gradual compaction occurs and as the clay particles are pressed closer together. such that fluid removal is impeded. Abnormally high formation pressures are also termed surpressures. then an increase in pore pressure will result. (a) Depositional Causes • Compaction Disequilibrium Compaction disequilibrium is also known as ‘undercompaction’ or ‘sedimentary loading’.BP WELL CONTROL MANUAL 1 General Abnormally high formation pressure is defined as any formation pressure that is greater than the hydrostatic pressure of the water occupying the formation pore spaces. whereas compacted clay/shale has a porosity of less than 15%. It is the process whereby abnormal formation pressures are caused by a disruption in the balance between the rate of sedimentation of clays and the rate of expulsion of the pore fluids. The causes of abnormally high formation pressures are related to a combination of geological. as discussed in the following paragraphs. a balance is required between the rate of sedimentation and burial. Abnormally high formation pressure gradients are thus any formation pressure gradient higher than the pore fluid hydrostatic pressure gradient. As sedimentation proceeds. 1-18 March 1995 . geochemical and mechanical processes. Thus a vast amount of water must be removed from clay sediments during burial. they are simply called abnormal pressures. as the clays compact with burial. For this equilibrium to be maintained. pore water is expelled. The pore pressure is hydrostatic as the pore fluid is continuous with the overlying sea water. The initial porosity of clays is 60 to 90%. pore pressures will remain hydrostatic. depending on the type of clay. If the equilibrium between rate of sedimentation and rate of fluid expulsion is disrupted. They may occur at depths as shallow as only a few hundred feet or exceeding 20. physical. If the rate of sedimentation is very slow.000ft (6100m) and may be present in shale/sand sequences and/or massive evaporite-carbonate sequences. If beds of permeable sandstone that are hydraulically connected to zones of lower fluid pressure are present within an overpressured zone. This is because these pressures are produced by the excess overburden load being supported by the pore fluids. adjacent clays will dewater to the sand bed. Abnormal pressures resulting from this process will have a gradient no greater than the overburden gradient.068 Figure 1. but are caused purely by ‘leakage’ from the clays to the sand.6 Typical Formation Pressures caused by Compaction Disequilibrium 1-19 March 1995 .BP WELL CONTROL MANUAL The ‘excess’ pore fluids help support the increasing overburden load. The local pressure gradient across these clay/sand boundaries will be significantly higher than the overall pressure gradient. thereby retarding compaction further. and the Gulf of Papua.6 illustrates typical overpressures caused by compaction disequilibrium. but may not reach extrapolated pressure gradient due to leakage from the clays SAND CLAY SAND Extrapolated initial formation pressure (parallel to overburden pressure gradient) CLAY SAND Overpressured sandstone (hydrostatic gradient within sandstone) CLAY SAND PRESSURE WEOX02. Areas in which abnormal formation pressures associated with high sedimentation rates have been encountered include the North Sea. The adjacent clays will compact and decrease in permeability and porosity thus restricting further dewatering of the clay beds. Figure 1. Hydrostatic pore pressure Overburden pressure Actual formation pressure DEPTH Very high local pressure gradient adjacent to permeable zones due to low permeability of the clays CLAY Overall formation pressure parallels the overburden pressure gradient. and resulting in abnormally high pressured formations. the Gulf of Mexico. Massive rock salt deposits are commonly found in the southern North Sea with abnormally high formation pressures sometimes being encountered in formations below or within these massive salts. The fluids in the underlying formations can not escape as there is no communication to the surface and thus the formations become overpressured. Diagenetic processes include the formation of new minerals. thereby exerting pressures equal to the overburden load in all directions. Negative Charge Imbalance CLAY SHEET H H H H H H O H H H H H Na + O O O H H H O O H H O Na + Ca + + O O H Ca + + H O H O About 4 Layers of Structured Water O O Na + H 1 or 2 Layers of Adsorbed Water H H H H H H O H O O H H H H O O Ca + + H H H H H CLAY SHEET WEOX02. the redistribution and recrystallisation of the substances within the sediments.7 Interlayer Water and Cations between Clay Platelets 1-20 March 1995 .069 Figure 1. Salt is totally impermeable to fluids and behaves plastically at relatively low temperatures and pressures. and lithification (sediments turning into rocks). (b) Diagenesis Diagenesis is the alteration of sediments and their constituent minerals during burial after deposition.94 SG (0. For instance. one BP southern North Sea well required mud weights up to 1.84 psi/ft) to control a saturated salt water flow from an anhydrite formation at the boundary between the Z2 and Z3 Units of the Zechstein halite formation.BP WELL CONTROL MANUAL • Rock Salt Deposition Continuous rock salt deposition over large areas can cause abnormal pressures that may approach overburden pressure. This reaction is shown schematically in Figure 1. It involves adsorption of potassium at the interlayer and surface sites as well as the release of a small amount of silica. compaction expels most of the free pore water (non-adsorbed) and the water content of the sediment is reduced to about 30%. but poor in potassium. The environment at this initial burial stage would be alkaline. This causes the clay lattice to collapse and with the availability of potassium. O O M A O O A A W + W W W W W + W W 3 LAYER SHEET W W W W + W W Add K Substitute Al for Si and Mg K INTERLAYER SITES A Charge Satisfied O 3 LAYER SHEET A A O O A A O ILLITE Ky AL4 (Si8-y. As burial progresses and the temperature increases. principally sodium (Na +) and calcium (Ca++). After further burial. eventually all but the last layer of structured (adsorbed) water will be desorbed to the pore spaces. This water is present in the form of at least four layers of molecules adsorbed between clay platelets and up to ten layers held on the outside of the platelets. Aly) O20 (OH)4 Negatively charged plates satisfied by interlayer water and cation adsorption WEOX02. rich in calcium and magnesium (and of course sodium from salt water). This causes the adsorption of interlayer water together with various cations (positively charged ions). Aly) O20 (OH)4 = Oxygen M = Magnesium = Silicon W = Water O = Hydroxyl (OH) K = Potassium A = Aluminium + = Cation eg Ca ++.8 Schematic of Reaction of Montmorillonite to Illite 1-21 March 1995 . montmorillonite diagenesis to illite occurs. The clay platelets have a negative charge imbalance due to their structure.7.8. The interlayer water is shown schematically in Figure 1. Na+ MONTMORILLONITE (Al4-x Mgx)(Si8-y.070 Figure 1.BP WELL CONTROL MANUAL • Clay Diagenesis The major constituents of marine shales are bentonitic clays of which montmorillonite is by far the most common. Montmorillonite has a swelling (expanded) lattice structure and contains approximately 70 to 85% water at initial burial in sea floor sediments. If water escape from the clay body is restricted.84 psi/ft) was required to control a saturated salt water flow from an anhydrite section sandwiched between massive salt sections. Carbonate reservoirs are commonly overlain by evaporite sections (salt.94 SG (0. This may further reduce permeability and so assist in developing abnormal pressures. Initial dehydration may occur at temperatures as low as 6°C. (The anhydrite itself is totally impermeable and may act as a vertical permeability barrier.1/2 H2O) in which the rock volume would increase by 15 to 25%. abnormal formation pressures may result. 1-22 March 1995 . If this occurs at depth and in the presence of a permeability barrier. methane and carbon dioxide.9. At the second dehydration stage (See Figure 1. Areas in which this process has occurred include the NW coast of the USA and areas of the South China Sea region (Java.9). the silica released in the diagenetic process will precipitate in the pore spaces. Anhydrite (calcium sulphate. the water that is released expands due to a density reduction from the highly structured phase to the pore phase.2 H 2O) which liberates large amounts of water. however. Figure 1. Here. a fluid source and/or a rock volume change. Thus formations that originally contained large amounts of volcanic ash may become overpressured due to the production of gases from the volcanic ash. If such rehydration was to occur at depth in a closed system.BP WELL CONTROL MANUAL The reaction is temperature (and hence depth) dependent. There is an intermediate semi-hydrate stage (CaSO4. a mud weight of 1. Anhydrite can take on water to form gypsum. anhydrite).10 is a schematic diagram showing the stages of alteration of montmorillonite to illite. There is a 30% to 40% shrinkage in formation thickness associated with this process. anhydrite) may cause abnormal pressures by creating permeability barriers. • Diagenesis of Volcanic Ash Diagenesis of volcanic ash results in three main products: clay minerals. The process is. Thus abnormally high pressures may result. CaSO4) is formed by the dehydration of gypsum (CaSO4. • Sulphate Diagenesis Diagenesis in sulphate formations (gypsum. reversible. Water distribution curves showing the various shale dehydration stages are shown in Figure 1. Most of the interlayer water is liberated between 100°C and 250°C. etc).) This process may have been the cause of the high pressure salt water flow discussed under ‘Rock Salt Deposition’ in (a) ‘Depositional Causes’. but some of the more structured water remains to about 300°C. particularly if the rate of expulsion of free pore water from the clay body is less than the rate of water release from the clay interlayers. very high abnormal pressures could be developed. 9 Water Distribution Curves for Shale Dehydration STAGE 1 Before diagenesis (about 3000 – 6000ft. ADSORBS POTASSIUM NOTE PARTICLE COLLAPSE STAGE 3 After diagenesis and compaction (over 200°C) porosity = 10 to 20% clay is 70% illite 10% montmorillonite 20% other LOW POROSITY VERY LITTLE BOUND WATER VOLUME LOST WEOX02.072 Figure 1.071 Figure 1.10 Diagenetic Stages in the alteration of Montmorillonite to Illite 1-23 March 1995 .BP WELL CONTROL MANUAL WATER ESCAPE CURVE (SCHEMATIC) WATER CONTENT OF SHALES WATER AVAILABLE % WATER FOR MIGRATION 0 10 20 30 40 50 60 70 80 SEDIMENT SURFACE PORE WATER BURIAL DEPTH (SCHEMATIC) PORE AND INTERLAYER WATER EXPULSION 1st DEHYDRATION AND LATTICE WATER STABILITY ZONE LATTICE WATER STABILITY ZONE INTERLAYER WATER 2nd DEHYD'N STAGE INTERLAYER WATER ISOPLETH 3rd DEHYDRATION STAGE DEEP BURIAL WATER LOSS 'NO MIGRATION LEVEL' WEOX02. below 60°C) porosity = 20 to 35% clay is 70% montmorillonite 10 mixed layer 20% other MOST WATER IS BOUND WATER LOW POROSITY STAGE 2 FREE PORE WATER FROM DESORBED INTERLAYER WATER During alteration to illite (100 – 200°C) high porosity = 30 to 40% clay is 20% montmorillonite 60% illite 20% other CLAY RELEASES SILICA. However.073 Figure 1. However. then pore fluid pressures will remain normal. If conditions are such that the pore fluids can still escape. Abnormally high pressures occur initially within the hinge portion of each compressional fold in a thick clay sequence. EXTENSION EXTENSION COMPRESSION COMPRESSION COMPRESSION COMPRESSION AMOUNT OF SHORTENING POSSIBLE OVERPRESSURED ZONES WEOX02. one of the highest formation pressures reported of 1. the additional horizontal compacting force (tectonic stress) squeezes the clays laterally. Also. in a tectonic environment. The pore fluids will not be able to escape at a rate equal to the reduction in pore volume. Abnormal pressure distribution within a series of compressional folds is shown in Figure 1.00 psi/ft can be encountered.BP WELL CONTROL MANUAL (c) Tectonic Causes • Compressional Folding Tectonic compression is a compacting force that is applied horizontally in subsurface formations. In normal pressure environments.11 Abnormal Formation Pressures caused by Tectonic Compressional Folding An example of overpressures associated with steep tectonic folding is the oilfields of Southern Iran where local pressure gradients as high as 1.11. clays compact and dewater in equilibrium with increasing overburden pressures. it is more likely that the increase in stress will cause disequilibrium. 1-24 March 1995 . resulting in an increase in pore pressure.3 psi/ft was recorded in the tectonically folded Himalayan foothills in Pakistan. Uplift is not a unique cause of abnormal pressure as the process that uplifts a buried formation will also uplift the overburden. eg a sand bed. Such processes may be piercement salt domes. Formation pressures are abnormally high.9 psi/ft have been measured around mud volcanoes on Aspsheron Peninsula in Azerbaidzhan. Salt will behave plastically at elevated temperatures and pressures and due to its lower density. wherever mud volcanoes occur. this mechanism refers to the upward movement of a less dense plastic formation. will move upwards to form piercement salt domes in overlying formations. high porosity (high water content) shales behaveplastically causing the formation of shale diapirs called ‘mud volcanoes’ (See Figure 1. – Non-sealing faults may transmit fluids from a deeper permeable formation to a shallower formation. the salt may act as an impermeable seal and inhibit lateral dewatering of clays thereby further contributing to the generation of abnormal pressures. depending on the type of formation and the amount of cooling that the formation undergoes. pressure gradients of 0. For example. • Shale Diapirism As with salt diapirism.12. Additionally. there has been rapid Tertiary and/or late Cretaceous sedimentation. there must be a concurrent geological process that reduces the relief between the buried formation and the surface. then it will bepressured up by the deeper formation. (See ‘Char ged Formations’ in (d) ‘Structural Courses’). If this shallower formation is sealed. Abnormally high formation pressures associated with salt domes have been encountered worldwide. laterally against an impermeable formation such as a clay.13). 1-25 March 1995 . both onshore and offshore.) • Salt Diapirism Diapirism is the piercement of a formation by a less dense underlying formation. (See ‘Temperature Reduction’ and ‘Decompressional Expansion’ in Section 1.BP WELL CONTROL MANUAL • Faulting Faults may cause abnormally high formation pressures in the following ways: – Slippage of formations along a fault may bring a permeable formation. This upward movement disturbs the normal layering of sediments and overpressures can often occur due to the associated faulting and folding action. The typical distribution of abnormal pressure zones around a piercement salt dome is shown in Figure 1. This rapidly loads underlying shales of low shear strength causing the formation of mud volcanoes. • Uplift If a normally pressured formation is suddently uplifted.3 of this Chapter. USSR. In practice. the flow of pore fluids through the permeable zone will be inhibited and abnormally high formation pressures may result. Thus. shale diapirs. abnormally high pressures may be generated. For abnormal pressures to occur. Note that uplift and erosion may also cause subnormal formation pressures. faulting or erosion. In this case. 075 Figure 1.074 Figure 1.12 Abnormal Pressure Distribution around a Piercement Salt Dome MUD VOLCANO UPPER MIOCENE SEA LEVEL MIDDLE MIOCENE LOWER MIOCENE 0 Mile 5000ft 1 WEOX02.BP WELL CONTROL MANUAL SAND HORIZON BASIN WARD A A B C HORIZON B C D E D E SALT ABNORMAL PRESSURE WEOX02.13 Schematic Diagram of a Mud Volcano 1-26 March 1995 . 452 psi/ft. oil. the formation pressure at the oil/water contact is normal hydrostatic pressure with a gradient of 0. dipping formations and anticlines.14. such as that caused by artesian water systems. Australia. Similarly. The aquifer intake area must be high enough for the abnormal pressure to be caused by the hydrostatic head. the pressure at the top of the reservoir is 4784 psi giving an abnormal gradient of 0. Indeed one documented example in Iran quotes a pressure gradient of 0. • Reservoir Structure In sealed reservoir formations containing fluids of differing densities (ie water.BP WELL CONTROL MANUAL • Earthquakes Earthquakes may cause compression in subsurface formations which causes a sudden increase in pore fluid pressures. Abnormal formation pressures will only be generated if fluids less dense than the pore water are present. Obviously. Artesian systems require a porous and permeable aquifer sandwiched between impermeable beds.3. the pressure at the gas/oil contact is 4850 psi which gives an abnormally high formation pressure gradient of 0. gas). especially in gas/water systems with long gas columns. formation pressures which are normal for the deepest part of the zone will be transmitted to the shallower end where they will cause abnormally high pressures.462 psi/ft. A regionally high piezometric surface. For example.3. in very large structures. will result in abnormally high pressures as shown in Figure 1. Using equation 1-15. Examples of areas where abnormally high pressures are caused by artesian systems are the Artesian Basin in Florida and the Great Artesian Basin in Queensland. Examples of such formation are lenticular reservoirs. 1-27 March 1995 . such as in oil/gas reservoirs. The pressure at the top of a fluid zone is given by: P fT = PfB – [Gf X (DB where P fT P fB Gf DT DB = = = = = X D T)] (1-15) formation pressure at top of zone (psi) formation pressure at bottom of zone (psi) pressure gradient of fluid in zone (psi/ft or psi/m) vertical depth to top of zone (ft or m) vertical depth to bottom of zone (ft or m) In the example shown in Figure 1. the 1953 earthquake in California caused production in the nearby Mountain View oil field to double over a period of several weeks after the earthquake. the overpressures developed at the top of the gas column may be very high. (d) Structural Causes • Piezometric Surface This is defined in Section 1.486 psi/ft.9 psi/ft (approaching overburden gradient) at a depth of only 640 ft (195m). FPG = 4850 = 0. • Aquathermal Pressuring Referring to the temperature-pressure-density diagram for water (Figure 1.452psi/ft Pf = 11319 x 0. Formation temperature increases with depth in any geological system and if the system is essentially closed. thermodynamic effects will add to the build up of abnormal pressures.452psi/ft) At top of reservoir: Pf = 4850 – 0.BP WELL CONTROL MANUAL DEPTH CAP ROCK TOP OF GAS CAP D = 3000m (D = 9842ft) GAS (Gf = 0.462psi/ft 10500 At oil/water contact: NORMAL HYDROSTATIC PRESSURE GRADIENT OF 0. especially if gas is the medium that transmits the pressure (same mechanics as gas reservoir in ‘Reservoir Structure’. FPG = 4784 = 0. Abnormal pressures caused by recharge can be very high. . This ‘charging’ of the shallower formations may take place by fluid communication along non-sealing faults behind casing in old wells. . but over greater depth differences). 1-28 March 1995 . (e) Thermodynamic Effects Thermodynamic processes may be considered as contributing factors in most of the causes of abnormally high formation pressure already discussed. a temperature increase in an isolated fluid system must take place along a constant density path. The increase in pressure is thus very rapid and only small increases in temperature are required to produce large overpressures.988 psi/ft) have been quoted as sometimes required for drilling through shallow charged zones. may be pressured up by communication with deeper higher pressured formations. .1psi/ft) GAS/OIL CONTACT D = 3200m (D = 10500ft) OIL (Gf = 0.452 Pf = 5116psi WEOX02. 0.486psi/ft 9842 At gas/oil contact: Pf = 5116 – 0. or wells with faulty cement jobs.4).1 x (10500 – 9842) Pf = 4784psi .14 Abnormally High Pressure due to Reservoir Structure • Charged Formations Normally pressured. or low pressured porous and permeable formations at shallow depths.076 Figure 1.28SG.325psi/ft) OIL/WATER CONTACT D = 3450m (D = 11319ft) WATER (Gf = 0. and whilst drilling a sequence of permeable formations with very large differences in pore fluid pressures (causing recharge salt water flows). Mud weights as high as 19 ppg (2.325 x (11319 – 10500) Pf = 4850psi . . complex hydrocarbon molecules will break down into simpler compounds. ‘freezeback’ pressures. If the flow is into an isolated system. shales are not totally impermeable and the time taken to heat the shales during burial should be sufficient to allow most of the excess pressures developed to leak away. For a given solution.02 gm/cc NaCl in water and saturated NaClbrine. However.3.44 psi/ft have been recorded in Alaska. there is no conclusive evidence that thermal cracking is a significant cause of abnormal formation pressures. thereby contributing to the development of abnormal pressures. If salinity differences exist in the sediments above and below such beds. If contained in an isolated system. Theoretically. This action is represented schematically in Figure 1. and aquathermal pressuring is not thought to be a major cause of abnormally high formation pressures. If this thawed permafrost refreezes later in the life of the well. • Permafrost In arctic regions. then a pressure increase will occur in this system. high enough to damage the casing. may result. It is thus currently believed that osmosis is a minor cause of abnormal formation pressures. Thermal cracking of hydrocarbons will increase the volume of the hydrocarbons in the order of two to three times the original volume.15. the efficiency of clay beds as semi-permeable membranes in the sub-surface environment is unknown. • Osmosis As defined in Section 1. • Thermal Cracking At high temperatures and pressures caused by deep burial. However. Alternatively. the osmotic pressure developed across these beds may inhibit the vertical flow of water from compacting shales.66 psi/ft to as high as 1. 1-29 March 1995 . this would result in high overpressures being developed. The main effect of heating during burial is to retard compaction. Freezeback pressure gradients ranging from 0. the osmotic pressure (differential pressure across the membrane) is almost directly proportional to the concentration differential. Obviously. osmosis is the spontaneous flow of water from a more dilute to a more concentrated solution when the two are separated by a suitable semi-permeable membrane.BP WELL CONTROL MANUAL However. and for agivenconcentration dif ferential the osmotic pressure increases with temperature. this situation may be avoided by proper well planning and casing design. then osmotic flow can occur. drilling and production operations may cause extensive thawing of the permafrost. osmotic pressures of up to 4500 psi can be produced across a semi-permeable membrane with solutions of 1. Clay and clayey siltstone beds can act as semi-permeable membranes. a gradient of 1.BP WELL CONTROL MANUAL LIQUID PRESSURE DECREASES LIQUID PRESSURE INCREASES 0 0 3 1 3 2 1 2 H2O H2O H2O Na+ H2O CINa+ SALINE WATER H2O CLAY MEMBRANE FRESH WATER CI- H2O OSMOTIC H2O FLOW WEOX02. The overlying rock can be considered to be in tension. 1-30 March 1995 . local formation pressures in the range of 5870 to 7350 psi at 5250 ft (1600m) were reported. and may be as high as the overburden pressure.433 to 0. However. locally confined pore pressure gradients exceeding the overburden gradient by up to 40% are known in areas such as Pakistan. Papua New Guinea. In Iran.0 psi/ft). This equates to a formation pressure gradient of 1.04 psi/ft has been reported.15 Schematic Diagram illustrating Osmotic Flow 3 Magnitude of Abnormally High Formation Pressures As defined. In the Himalayan foothills in Pakistan.0 psi/ft are common and in Papua New Guinea. Iran. and the USSR.3 psi/ft have been encountered.4 psi/ft. These superpressures can only exist because the internal strength of the rock overlying the superpressured zone assists the overburden load in containing the pressure.465 psi/ft) and the overburden gradient (generally 1.077 Figure 1.12 to 1. Abnormally high pressure gradients will thus be between the normal hydrostatic gradient (0. In one area of Russia. formation pressure gradients of 1. gradients of 1. the magnitude of abnormally high formation pressures must be greater than the normal hydrostatic pressure for the location. permafrost and earthquakes. Clay dewatering (diagenesis) was found to have little effect.8 psi/ft being encountered.62 psi/ft (1. osmosis. and the two processes probably occur concurrently. The effects of several processes will probably combine to cause the observed abnormal pressure. This is also true of the diagenetic process. in some areas. evaporates and sandstones sandwiched between massive Zechstein salts. overpressures are often found in Permian carbonates. 1-31 1-31/32 March 1995 . Also in the southern North Sea. An expandable clay (gumbo) also occurs which is of volcanic origin and is still undergoing compaction. However conditions within clays during dewatering are very similar to these developed during undercompaction. These include uplift (as a sole mechanism). A recent report(6) has found that the most significant cause of abnormally high formation pressures in depositional basins is compaction disequilibrium.43 SG) or higher are required to keep the wellbore open because of the swelling nature of these clays. This is almost equal to the low overburden gradients in these areas. The Tertiary sediments are mainly clays and may be overpressured for much of their thickness. abnormal formation pressure gradients up to 0.BP WELL CONTROL MANUAL In the North Sea abnormal pressures occur with widely varying magnitudes in many geological formations. abnormally high formation pressures have been found in gas bearing zones of the Bunter Sandstone in the southern North Sea. In the Mesozoic clays of the Central Graben. while undercompaction is recognised as the primary mechanism. Pressure gradients of 0. 4 Summary Of all the processes that may be responsible for causing abnormally high formation pressures. Certain processes are thought to be either ineffective or uncommon as causes of abnormal pressures.52 psi/ft are common with locally occurring gradients of 0. with aquathermal pressuring contributing to a small extent. it is unlikely that any one will be the sole cause in any particular area. The consequent decrease in clay density would normally indicate an abnormal pressure zone but this is not the case. The significance of aquathermal pressuring as a cause of abnormal pressure is temperature and hence depth dependent. In the Jurassic of the Viking Graben.69psi/ft have been recorded. thermal cracking.9 psi/ft have been recorded. overpressures of 0. In Triassic sediments. With increasing depth aquathermal pressuring is thought to be a contributory factor in all cases of abnormal pressure generation. One BP well encountered a formation pressure gradient of 0. However.91 psi/ft in the Jurassic section. mud weights of the order of 0. BP WELL CONTROL MANUAL 1.5 SHALLOW GAS Paragraph Page 1 General 1-34 2 Definition 1-34 3 Origins of Shallow Gas 1-34 4 Characteristics of Shallow Gas 1-35 1-33 March 1995 . (Kerogen is a complex hydrocarbon formed from the biogenic degradation of organic matter which also gives gas as stated above. These are normally used down to a depth of about 1000m below surface or mudline. Gas influxes taken at shallow depths cannot generally be shut-in for fear that the pressures involved will fracture the formation at the previous casing shoe. Alternatively. This could result in shallow gas accumulations forming later in the life of a producing field when early wells showed no indication of shallow gas.2 of Chapter 2). 1-34 March 1995 . migration of gas from deeper petrogenic sources may be possible. For well planning purposes. or even through the natural permeability of clays at shallow depths. artificial migration paths may be produced in poorly cemented casing annuli allowing gas from petrogenic sources to accumulate in shallower formations. Thus a biogenic origin is considered likely for shallow gas accumulations in the NorthSea.) Sufficient depth of burial to produce the heat necessary for this process to operate is probably not reached in the shallow depths considered here ie down to 1000m. An example of this would be the Pleistocene section of the North Sea which contains some organic rich clays and occasional peat/lignite formations. shallow gas can be defined as any gas accumulation encountered at any depth before the first pressure containment casing string is set. 3 Origins of Shallow Gas There are two potential origins of shallow gas: (a) Biogenic Generation This is the production of gas at shallow depths of burial from the degradation of organic matter within the sediment. thereby causing an underground blowout. or flow around the casing to the seabed. (b) Petrogenic Generation This is the thermocatalytic degradation of kerogen which occurs under conditions of elevated temperature and pressure at greater depths. However. along non-sealing faults for example. 2 Definition For the purposes of drilling operations.BP WELL CONTROL MANUAL 1 General Shallow gas accumulations present a major hazard to drilling operations. This could occur naturally. possible gas bearing zones at shallow depths may be identified from shallow seismic sections (‘bright spot’ technique – See Section 2. BP WELL CONTROL MANUAL 4 Characteristics of Shallow Gas (a) Composition Shallow (biogenic) gas has the following typical composition (provided by BP/Sunbury): 99% + methane (CH 4) 0. (c) Pressures and Volumes Most shallow gas accumulations tend to be normally pressured. (b) Configuration of Shallow Gas Accumulations Shallow gas accumulations are commonly found in sand lenses which are inferred to have been deposited in a shallow marine shelf environment with tidal influence. sand patches and ridges resulting in a discontinuous and patchy distribution. It must not be assumed that because several wells have penetrated a potential shallow gas zone successfully.5% nitrogen (N2 ) less than 0. this corresponds to a bulk rock volume of 20.1% ethane (C 2H6 ) and higher hydrocarbons. then all future wells will also be free of shallow gas hazards.4). Also. In this environment.52 psi/ft).000 cubic metres.4.5% carbon dioxide (CO2 ) less than 0. In this area. overpressuring is thought to be the result of undercompaction of shales due to rapid deposition (See ‘Compaction Disequilibrium’. the classic area where overpressured shallow gas sands are encountered is the Gulf of Mexico. this corresponds to an area of only 70m in diameter. Petrogenic gas associated with the generation of oil should contain a larger proportion of ethane and higher hydrocarbons. However. Flowrates of over 100 mmscfd have been reported for shallow gas blowouts in the Gulf of Mexico. In one North Sea incident. overpressured shallow gas may result from long ‘tilted’ sand lenses. This patchy distribution of shallow gas is very important. It is difficult to estimate the volumes of gas present in shallow gas accumulations. the sands would tend to be in the form of sand waves. These sand lenses could thus be sealed by the surrounding clay sediments. Section 1. it has been estimated that 8 mmscf of gas was vented. Hydrogen sulphide (H 2S) may also be present. estimates have been made from shallow gas discharges.20 SG (0.4 of this Chapter. These high flowrates are as a result of the high porosity and permeability in shallow large grain sand deposits. 1-35 March 1995 . Section 1. However. assuming a porosity of 30%. also in Section 1. in an identical manner to that described under ’Reservoir Structure’. For a 5m thick sand. Shallow gas accumulations resulting from migration of petrogenic gas may well be overpressured (See ‘Charged Formations’. USA. The flowrate of gas in the above incident was estimated at 40 to 50 mmscfd.) One instance of overpressured shallow gas in the North Sea was reported for a well in the SE Forties area where a gas kick from a sand at about 800m subsea gave a calculated formation pressure gradient of at least 1. At a depth of about 410m subsea and 600 psi pressure. USA. Paper 5946.. 7. The Generation of Overpressures During Sedimentation and Their Effects on the Primary Migration of Petroleum. MANN. Forties Field: Shallow Gas Hazards in the Main Field Area. 2. Freeman and Company. 1975 Abnormal Pressure Technology. 1986. BPPD Aberdeen. Eng. FERTL. ‘EXLOG’. 1976. ‘GEARHART’. Importance of Abnormal Pressures to the Oil Industry. 8.M. Sunbury. 1-36 March 1995 . USA.BP WELL CONTROL MANUAL Suggestions for further reading: 1. Petrol. Elsevier Scientific Publishing Company. Gearhart Geodata Services Ltd.C. W. ‘EXXON’. Abnormal Formation Pressures. 1981.. 1985. New York. M. 1984.H. SELLEY. G.V. Exxon Company. R... W. SHEPHERD. Theory and Evaluation of Formation Pressures. Overpressure.H. Aberdeen. W. 1976. D. and CHILINGARIAN. BP Research Centre. Soc. 4. Elements of Petroleum Geology. FERTL.. Exploration Logging Inc... Report GCB/156/85.H. 5. 1985. Amsterdam. 6. Report GL/AB/1880.. 3. 3 FORMATION PRESSURE EVALUATION WHILST DRILLING 2-23 2.2 FORMATION PRESSURE EVALUATION DURING WELL PLANNING 2-5 2.1 INTRODUCTION 2-1 2.4 FORMATION PRESSURE EVALUATION AFTER DRILLING 2-65 March 1995 .BP WELL CONTROL MANUAL 2 FORMATION PRESSURE EVALUATION Section 2. 1 INTRODUCTION Paragraph Page 1 General 2-2 2 The Transition Zone 2-2 Techniques used to Predict. Detect and Evaluate Formation Pore Pressures 2-3 Table 2.BP WELL CONTROL MANUAL 2.1 2-1 March 1995 . the time available for fluid flow and pressure depletion since the overpressure developed. This Chapter is therefore mainly concerned with methods of predicting. stuck pipe. The differential pressure across a transition zone causes pore fluid flow through the transition zone. Methods for predicting and evaluating fracture pressure are covered separately in a later section of this Manual. It must be realised that the start of the transition zone marks the onset of abnormal pressures. Abnormally high pressured zones are by far the most common encountered. The following sections describe the techniques used to predict. the transition zone is the equivalent of the pressure seal discussed in Section 1. Good estimates of formation pore pressures and fracture pressures are required to optimise casing and mud weight programmes.1 of Chapter 1. in drilling operations. transition zones are normally present. and the most important. 2 The Transition Zone Formation pressure gradients are considered to be the normal hydrostatic gradient for the area until a depth is reached where various pressure indicators suggest the onset of either a subnormally or an abnormally high pressured zone. salt and anhydrite). The presence of the transition zone is very important in formation pressure evaluation. However. detecting and evaluating abnormally high formation pressures. Every effort must be made to recognise the start of this zone both in well planning and during drilling. The zone in which the formation pressure gradient changes from normal to subnormal or abnormally high gradient is known as the transition zone. and to minimise the risk of well kicks. lost circulation and other costly drilling problems. for example.1 summarises these techniques. drilling and evaluation of a well.1. detect and evaluate formation pore pressures at the various stages of drilling a well. The magnitude of the change in the trend can sometimes be used to estimate the change in the formation pressure gradient. Formation properties in this zone often show a change away from normally pressured depth related trends.BP WELL CONTROL MANUAL 1 General Knowledge of formation pore pressure is of prime importance in the planning. Since perfect seals of zero permeability rarely occur (except. In shales. Table 2. The thickness of the transition zone depends on the permeabilities within and adjacent to the overpressured formation and the age of the overpressure ie. due to the very low permeability within the zone. 2-2 March 1995 . The parameters used to monitor the trends in formation properties are listed in Table 2. the flow rate through the zone will be extremely low. shape and size Miscellaneous methods While drilling (delayed by the time required for mud return) Wireline logs Sonic (int. Detect and Evaluate Formation Pore Pressures Data Source Pressure Data/Indicators Stage of Well Offset wells Mudloggers reports Mud weights used Kick data Wireline log data Wireline formation test data Drillstem test data Planning (also used for comparisons whilst drilling) Geophysics Seismic (interval velocity) Planning Drilling parameters Drilling rate Drilling exponents Other drilling rate methods Torque Drag MWD logs While drilling Drilling mud parameters Gas levels Flowline mud weight Flowline temperature Resistivity.BP WELL CONTROL MANUAL Table 2.1 Techniques used to Predict. transit time) Resistivity log Density log Other logs After drilling Direct pressure measurements Wireline tests (RFT/FIT) Drillstem tests Well testing or completion 2-3/4 2-3 March 1995 . salinity and other mud properties Well kicks Pit levels Hole fill-up Mud flow rate While drilling (delayed by the time required for mud return) Cuttings parameters Bulk density Shale factor Volume. BP WELL CONTROL MANUAL 2.2 FORMATION PRESSURE EVALUATION DURING WELL PLANNING Paragraph Page 1 General 2-6 2 Offset Well Data 2-6 3 Seismic Data 2-8 3.1 Abnormal Pressure Evaluation from Seismic Data 2-9 3.2 Identifying Shallow Gas Hazards 4 2-20 Summary 2-21 Illustrations 2.1 Pressure/Depth Plot 2-7 2.2 Schematic Diagram illustrating Seismic Reflection System and Seismic Traces 2-9 2.3 Schematic Diagram showing Common Depth Point (CDP) Seismic Ray Paths 2-10 Schematic Plot of Offset versus Two Way Travel Time for Common Depth Point System 2-11 2.5 Example Seismic Velocity Analysis Plot 2-13 2.6 Example of Stacking Velocity Data on a Seismic Section 2-14 2.7 Seismic and Sonic ITT versus Depth Plots for Abnormally Pressured Well 2-17 2.8 Log-log Plot of Seismic Interval Transit Time 2-18 2.9 ITT Departure versus Formation Pressure Gradient 2-19 2.4 2.10 ITT Ratio versus Formation Pressure Gradient 2-20 2.11 Example of Drilling Hazard Log over Shallow Section 2-22 Table 2.2 Calculation of Depths and Interval Transit Times 2-16 2-5 March 1995 BP WELL CONTROL MANUAL 1 General At the planning stage of a well, several early decisions are made that are directly influenced by the predicted formation pore pressure profile for the well. The magnitude of the expected formation pressure influences the pressure rating of the casing and wellhead/BOP equipment to be used, and can ultimately influence drilling rig selection. Casing programme design and mud weight programmes should be tailored to the predicted formation pressures for thewell. Other related aspects of well planning that are influenced include, cement programmes, completion equipment, contingency stocks of casing, and mud chemicals/baryte stocks to be held. Thus, accurate formation pressure predictions are required in order to optimise well planning. Good well planning will, in turn, help to minimise the risk of costly problems whilst drilling. There are normally (but not always) two sources of formation pressure information for the well location being considered. The first and most widely used is offset well data. However, in areas where there are no offset wells or they are considered to be too far away to give reasonable data, then seismic data may be used to predict formation pore pressures. Seismic analysis may also be useful in validating offset well data for the location being considered. 2 Offset Well Data Pressure data from nearby wells are commonly used to predict the pore pressure profile. The data are often direct measurements which will give accurate pressures for the particular offset well location. Pressures can also be calculated or inferred from other well data available in well reports. The most commonly used sources of pressure data from offset wells are listed at the top of Table 2.1. The methods used to calculate formation pressures from other well data, such as wireline logs, are described in Sections 2.3 and 2.4. The measured and calculated/inferred formation pressures are then applied to the same formations in the well being planned. Additional information, such as the pressure gradient of the expected reservoir fluid, is also used to finally arrive at a predicted formation pressure profile for the well. This information is presented as a pressure depth plot, an example of which is shown in Figure 2.1. (Fracture pressure information is also presented in the form of formation leak off tests from offset wells.) The accuracy of the pore pressure prediction from offset well data will depend on the type of well that is to be drilled. The following two cases can be considered: • Appraisal/development wells The offset well data should usually be reliable as the offset wells will normally be fairly close to the proposed well location and usually drilled on the same structure. For development wells, the pore pressure profile should be accurately defined from data from the appraisal wells. 2-6 March 1995 BP WELL CONTROL MANUAL Figure 2.1 Pressure/Depth Plot WELL No: 3/10b-a AREA: UKCS North 0 Leak Off Test 30/4–1 Leak Off Test 30/4–2 500 Predicted Formation Pressure 3/10b-a 1500 TERTIARY TO RECENT Holocene to Eocene 1000 Palaeocene 2000 SG EQUIVALENT 3500 psi ft 3000 Upper 4500 Lower JURASSIC 2.61 1.128 2.51 1.085 2.41 1.042 2.31 0.998 2.21 0.955 2.1 0.911 4000 5000 psi ft 0.477 0.434 0.564 0.521 1.6 1.7 1.8 1.9 0.651 0.607 0.738 0.694 0.781 5500 0 Middle Lower SG EQUIVALENT 1.0 1.1 1.2 1.3 1.4 1.5 CRETACEOUS Upper DEPTH (m) 2500 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 PRESSURE (psi) WEOX02.078 2-7 March 1995 BP WELL CONTROL MANUAL • Exploration wells In well explored regions, such as certain areas of the North Sea, the offset well data should be reliable enough for a good estimate to be made of the pore pressure profile for the proposed exploration well. However, if the nearest offset wells are far away, then the pressure data should be treated with caution when applying it to the proposed well. If there are insufficient pressure data available for any one profile to be predicted, then the alternatives should be considered and the ‘worst case’ evaluated for each particular aspect of well planning. Analysis of seismic data may be required to back-up the pressure profile predicted from offset wells. In areas where there is no offset well information or they are too far away to be of any use, then seismic data analysis may be the only method available to predict the pore pressure profile (See Paragraph 3, ‘Seismic Data’). In exploration areas where there is a well established Company office, the predicted pressure profile is usually compiled by the Designated Resident Geologist (DRG) for the well. The pressure depth plot should be obtained as soon as possible and the data must be checked immediately by the Drilling Engineer responsible for planning the well. The DE must ensure that the pressure data is the best available, whilst also accepting that the accuracy of the data will vary depending on the number and proximity of nearby wells. In areas where there is no established exploration office, or where the pressure profile is required prior to compilation by the DRG, then the well planning DE will have to predict the formation pressure profile. The DRG or Area Geology Group must be consulted. The DRG or Area Geology Group will determine which offset wells are most ‘geologically similar’ to the proposed well and hence the best source of formation pressure data. Also, geological features such as faults and unconformities in the area will be identified. These may affect the way in which the pressure data are applied to the proposed well. Notes on formation pressures from offset wells are often given in the ‘Drilling Proposal’ document, together with the lithological prognosis and other pertinent data (well location, target depths, total depth etc). Petroleum Engineers should also be consulted, as they may have additional pressure information, especially regarding expected reservoir pressures. 3 Seismic Data In hydrocarbon exploration, seismic data are mainly used to identify and map prospective reservoir traps and to estimate the depths of formation tops in the lithological column. Seismic data can also be used to predict formation pressures quantitatively, or at least to give an indication of the entrance into abnormally high pressures. In new or relatively unexplored areas, seismic data are often the only information available from which pore pressure data can be derived. Seismic data can also be used to indicate the possible presence of shallow gas bearing sands. This is done using data from high resolution shallow seismic surveys which are normally used down to a maximum depth of about 1000m below surface or the mudline. 2-8 March 1995 BP WELL CONTROL MANUAL 3.1 Abnormal Pressure Evaluation from Seismic Data (a) Basic Theory A seismic wave is an acoustic wave propagated in a solid material - normally a rock. The velocity at which the wave travels depends upon the density and elasticity of the rock, and the type of fluid occupying the pore spaces of the rock. Thus the formation type, formation fluid type, and degree of compaction (ie depth) will determine the seismic velocity in an particular formation. Knowledge of seismic velocities in particular formations over a range of depths enables geophysicists to make fairly reliable formation lithology predictions from seismic data. It is also the seismic velocity of shale sequences that permits the use of seismic data for predicting the presence of overpressured formations, and to estimate the magnitude of the overpressure. Time Refl C Refl B 1 2 3 4 5 6 Up hole time Refl A 7 First breaks 8 9 10 11 12 Shot Moment Geophones Shot Point Geophones V1 A V2 Interval Velocities B Reflecting Beds V3 C WEOX02.079 Figure 2.2 Schematic Diagram illustrating Seismic Reflection System and Seismic Traces 2-9 March 1995 BP WELL CONTROL MANUAL With increasing depth and compaction, the density and elasticity of shales increases which results in increasing seismic velocity with depth. Overpressured shales are undercompacted. This results in lower density and elasticity for that depth. The seismic velocity in overpressured shales is thus lower than in normally pressured shales at similar depths. Thus we need formation interval seismic velocity data to detect and evaluate overpressured shales. These data are readily available from seismic surveys. Seismic data are acquired by creating acoustic waves, by some form of explosion (orimplosion), and measuring the time taken for the wave to travel down to subsurface reflecting beds and back to the surface. The surface point of origin of the wave is calledthe shot point and the reflected waves are detected at surface by a series of geophone (or hydrophones if offshore) placed at known distances from the shot point. The system is shown schematically in Figure 2.2, together with the seismic traces recorded by the geophones. The whole system is moved across the surface and the measurements are repeated from a new shot point. The process is continued along a pre-determined ‘seismic line’. By using the geometric relationships between the shot points and geophone positions, it is possible to identify a series of seismic traces that have approximately the same reflection point on a reflecting bed. This point is known as a common depth point (CDP), and the seismic paths associated with this point are shown in Figure 2.3. For clarity, only the first reflecting bed is shown, but obviously the deeper reflecting beds will also have corresponding CDPs vertically below, the reflections from which will appear on the series of seismic traces. The distance between the shot point and any particular geophone is termed the ‘offset’. Offset Shot Points Geophones Surface Reflecting bed A COMMON DEPTH POINT (CDP) Figure 2.3 Schematic Diagram showing Common Depth Point (CDP) Seismic Ray Paths 2-10 March 1995 BP WELL CONTROL MANUAL Figure 2.4 Schematic Plot of Offset versus Two Way Travel Time for Common Depth Point System Offset, x to Time, t A C Reflecting Beds B D E The equations of the dashed lines through the seismic reflections are of the form: x = V √ t2 - to2 where to = vertical two way reflection time to reflecting beds (ie offset, x = o) V = stacking velocity (average velocity) Thus the stacking velocity, V, is the variable defining the hyperbolae which best fit the seismic reflections. WEOX02.081 2-11 March 1995 BP WELL CONTROL MANUAL In practice, the seismic traces from the same CDP are collected together to form a ‘gather’ in which seismic traces at the various offsets are plotted against the reflection time. A simplified schematic plot of offset versus reflection time is shown in Figure 2.4. With greater offset, the path length of the wave is longer (See Figure 2.3) and the reflection time for the same reflecting bed increases. Curves can be drawn through the peaks on the seismic traces, corresponding to the same reflecting beds, as shown by the dashed lines in Figure 2.4. The geometry of the CDP seismic system is such that the equation of the curve through the seismic peaks (known as a ‘seismic event’) from a horizontal reflector should be a hyperbola. The variable defining the shape of the hyperbola is called the ‘stacking velocity’ or the ‘normal moveout velocity’. In practice, the peaks on the seismic traces do not lie exactly on a hyperbola. Velocity analyses are performed to determine the velocity value that gives a ‘best fit’ hyperbola to the data. This is done by investigating the hyperbolic function with a range of stacking velocities at increasing time increments, and comparing the result to the actual data from the seismic traces on the gather. The results from the velocity analysis are output in the form of a plot of stacking velocity versus reflection times. A typical example plot from an actual analysis is shown in Figure 2.5. The plot appears as a series of ‘contours’ defining a number of ‘peaks’. Due to the mathematical computations involved in the analysis, the peaks represent the ‘best fit’ stacking velocity values and the corresponding vertical two-way reflection times for each reflecting bed. The stacking velocities obtained are not the true average velocities from the surface to the reflecting bed. However, the stacking velocity is usually considered to approximate to the root mean square (RMS) velocity (as indicated on the horizontal axis in Figure2.5). The RMS velocity is the average velocity along the actual path of the seismic wave. In many cases, this is also considered to be equal to the vertical average velocity from the surface to the subsurface reflecting bed. Thus, the velocity-time pairs (as they are called) from the velocity analysis can be used to calculate the depths of the reflecting beds. The stacking velocities are used to compute the vertical two-way reflection times for each of the seismic traces on the seismic gather. The seismic gather can then be ‘stacked’ to form one ‘complete’ seismic trace for that particular CDP. A seismic section is then produced by displaying the stacked traces for each CDP along a seismic line. The stacking or RMS velocities are also used to calculate the interval velocities between reflecting beds, which is the property that we require to detect and evaluate abnormal pressure. (b) The Method Before attempting to predict a formation pore pressure profile from seismic data, the Drilling Engineer must discuss the seismic data and velocity analyses with the Area Geophysicist and Geologist. This will help to identify potential problems such as poor seismic data, lithology complications, errors introduced by formation dip, etc. The DE should then have a better understanding of the problems involved in predicting a pore pressure profile for the well being planned. 2-12 March 1995 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 4000 5000 6000 BP WELL CONTROL MANUAL 7000 9000 10000 12000 13000 RMS VELOCITY (ft/sec) 8000 2-13 11000 Figure 2.5 Example Seismic Velocity Analysis Plot TWO-WAY TRAVEL TIME (millisecs) WEOX02.082 March 1995 083 2-14 March 1995 .6 Example of Stacking Velocity Data on a Seismic Section SP 561 VINT 1470 1470 1527 1685 1986 2218 2368 2668 2750 2850 2851 2930 3150 1470 1635 1809 2320 2942 3098 4923 3416 3972 2866 3165 3479 LINE CB-82-41 VRMS 0 200 300 650 1150 1450 1700 1850 2050 2200 2350 3100 5000 LINE CB-82-39 SP 870 202 TIME 140 550 146 600 WEOX02.BP WELL CONTROL MANUAL Figure 2. 6 is given in milliseconds (ms). it is worth checking the stacking velocities given in the panels against the velocities obtained from the CDP velocity analyses.7. the velocities given in the panel on the seismic section will suffice.2 is shown in Figure 2.BP WELL CONTROL MANUAL The first step in the method is to obtain the stacking velocity data for a range of CDPs near to the proposed well location. This results in a plot similar to a sonic log plot but in which the data are averaged over long sections and not.V 2 (2-2) where D = depth of the reflecting bed (m) t = two-way travel time for the reflecting bed (s) V = average velocity to reflecting bed (m/s) Note that the two-way time in the panel in Figure 2. 2-15 March 1995 . for which it was calculated. The stacking velocities used for these CDPs should be given in panels displayed above the surface line on the seismic section. The depths to the reflecting beds are calculated from: D = t.5. over a few feet only.6. A plot of interval transit time (ITT) versus depth can then be constructed. This is done by simply taking the reciprocal of the interval velocity.6. This is because stacking velocities are chosen to produce a good CDP stack (‘clean’ appearance) and may not be equal to the values that would be obtained from a velocity analysis such as that in Figure 2. Note that ITT is plotted on a logarithmic scale and depth on a linear scale. Note that interval transit times are expressed in micro-seconds per metre (µsec/m) (1µsec = 10-6 sec). An example is shown in Figure 2. The final step in the calculations is to convert interval velocities. although more often than not. a term used by geophysicists. A geophysicist should be consulted to decide which stacking velocities should be used. The interval velocities are then calculated from the two-way time and stacking velocity (average velocity) using Dix’s formula: (V i12)2 = where Vi12 t1 t2 V1 V2 t 2(V 2)2 – t 1(V 1)2 t 2 – t1 = = = = = (2-1) interval velocity between reflecting beds 1 and 2 (m/s) two-way travel time for reflecting bed 1 (s) two-way travel time for reflecting bed 2 (s) average velocity to reflecting bed 1 (m/s) average velocity to reflecting bed 2 (m/s) In the example shown in Figure 2. The types of scales that are used are discussed further in (c) ‘Interpretation’. A table should be drawn up as shown in Table 2. At this point. The corresponding wireline sonic log plot is also shown for comparison. as with the wireline sonic log. This needs to be converted to seconds for use in equation (2-2) (1ms = 10 3 sec). into interval transit times which is a term more familiar to drilling engineers.2. The interval transit time is plotted as a vertical line over the depth interval. the interval velocities have already been computed using Dix’s formula. A plot of the data from Table 2. There is a certain amount of conflict surrounding the types of scale that should be used for plotting ITT data. transit time t (millisecs) Average (stacking) velocity V (m/s) D (m) Vi (m/s) ∆ti (µsec/m) 0 1470 0 1470 680 200 1470 147 1635 612 300 1527 229 1809 553 650 1685 548 2320 431 1150 1986 1142 2942 340 1450 2218 1608 3098 324 1700 2368 2013 4923 203 1850 2668 2468 3416 293 2050 2750 2819 3972 252 2200 2850 3135 2866 349 2350 2851 3350 3165 316 3100 2930 4542 3479 287 5000 3150 7875 Table 2. From the seismic ITT plot (‘stepped’ profile).7 assumes that the normal compaction trend is a straight line on semi-logarithmic scales. This method is recommended by Fertl(17).BP WELL CONTROL MANUAL Two-way time Depth Int.2 Calculation of Depths and Interval Transit Times (c) Interpretation As stated. Alternatively. the top of the abnormal pressures would probably be estimated to be at 2300m to 2500m. This is shown by the shaded section in Figure 2. The format used in Figure 2. overpressured shales have lower interval velocities. The normal shale compaction trend line on the ITT depth plot decreases with depth. 2-16 March 1995 . as it enables ITT data to be directly compared with other pressure indicators that are plotted using the same linear depth scale (composite plots). When the well was drilled the top of the abnormal pressures was found to be at about 2000m. An example plot of this format is shown in Figure 2. velocity (Dix’s formula) Int. Pennebaker(25) suggested that the normal compaction trend should be a straight line on log-log scales.7. and therefore higher interval transit times than normally pressured shales at the same depth.8. Thus an increase in interval transit time away from the normal trend line indicates the presence of abnormal pressures. 084 2-17 March 1995 .7 Seismic and Sonic ITT versus Depth Plots for Abnormally Pressured Well LITHOLOGY 500 SEISMIC DATA siltstone with mudstone 1000 SONIC LOG 1500 calcareous mudstone and siltstone Overpressure Top: Actual sandstone limestone Predicted 2500 3000 mudstone and siltstone com pac tion tren d lin e 3500 mal 4000 sandstone Nor DEPTH (metres) 2000 mudstone and siltstone 4500 100 200 300 400 500 600 800 INTERVAL TRANSIT TIME (µsec/m) WEOX02.BP WELL CONTROL MANUAL Figure 2. the difference between the observed and normal ITT values is used to estimate formation pressures from a chart such as the one shown in Figure 2.BP WELL CONTROL MANUAL NORMAL TREND DEPTH TOP OF OVERPRESSURE T. For the log-log plot. as shown in Figure 2. Thus. This can only be done using actual well data on a regional basis and with the assistance of the geologists and geophysicists. For the semi-log plot.10. this may not be possible at all.9.9). In completely unexplored areas. Pennebaker(25) presented a chart that required the ratio of observed ITT to normal ITT in order to estimate the magnitude of the abnormal pressures. Interval Transit Time WEOX02. It is most important that the correct chart is used when estimating formation pressures. the two methods of plotting ITT data require entirely separate empirically derived charts to estimate the magnitude of abnormal pressures. it is most important to obtain the correct correlation for the area that is being investigated. The chart from one method should never be used with an ITT plot from the other method. Hence. Charts relating the magnitude of formation pressures to some function of the ‘departure’ of the observed ITT values from the extrapolated normal ITT values are available for both methods. 2-18 March 1995 . It may be necessary to determine a new correlation for the area of interest. However.085 Figure 2. It should also be noted that different geological areas have vastly different correlations between ITT departure and formation pressure (See Figure 2. a major difference between the two methods arises when the plots are used to estimate the magnitude of the abnormal pressures.8 Log-log Plot of Seismic Interval Transit Time Both the semi-log and log-log plots of ITT versus depth will show approximately the same top of abnormal pressures. 1.6 S I CH UT GU PRESSURE GRADIENT psi/ft W H RT SE (FRIO. The various non-shale lithologies affect the data quite considerably and even with the actual sonic log from the well overplotted.00 0. 2-19 March 1995 .25 EQUIVALENT MUD WEIGHT SG GULF 0.9 ITT Departure versus Formation Pressure Gradient To summarise. u sec/ft shale WEOX02. seismic ITT data may be of use in determining the possible existence of overpressures at the planned well location. Referring to Figure 2. A full discussion of other problems associated with the interpretation of seismic ITTplots is given by Barr (2) and are further discussed in relation to sonic log plots in Section 2.0 0.8 RG T 2 BU FR VI AS 0.BP WELL CONTROL MANUAL Another major problem in interpreting seismic ITT plots is the placing of the normal compaction trend line. the correct position of the normal compaction trend line is still open to debate.4 of this Chapter. it may be possible to use the seismic ITT data to estimate the magnitude of formation pressures.5 1. However. VICKSBURG.00 WE 0. AND WILCOX – SOUTH TEXAS GULF COAST AREAS) NO 1.75 IO S CK EA CO NA LF H 1.7. it must not be assumed that abnormal pressures do not exist because of a lack of indications from the seismic ITT data.4 0 10 20 30 SONIC LOG DEPARTURE 40 50 abnormal t pressured – shale 60 70 80 normal t pressured .7 1. it would be most difficult to determine the exact position and gradient of the normal compaction trend line from the seismic data alone.9 2.086 Figure 2. It may then be possible to determine the position and gradient of an average normal compaction trend line for the region. One possible solution to this problem is to make numerous seismic ITT (and sonic log ITT.50 A SO 0.25 ST COA OX ILC XAS ST TE WARE DELA BASIN 2. if available) plots for the region being investigated. Depending on the degree of knowledge of compaction trends/formation pressure relationships for the area. The construction and interpretation of seismic ITT plots should always be done in conjunction with the local geophysicists and geologists. 087 Figure 2.0 1.75 0.6 PORE PRESSURE GRADIENT psi/ft 1.4 T/ 1. 2-20 March 1995 .25 1.10 ITT Ratio versus Formation Pressure Gradient 3.4 0.9 2.8 2.2 1.6 Tn Note: See warning in (c) Interpretation.00 0. the grid covering an area of only a few square kilometres around a proposed well location. The data are processed to produce detailed seismic sections usually down to a maximum depth of about 1000m.50 0. The high resolution seismic data are acquired over a survey grid with perhaps only 150m between seismic lines. WEOX02.2 Identifying Shallow Gas Hazards Detailed high resolution seismic surveys as well as conventional seismic data are used to identify potential gas bearing zones at shallow depths by using a technique known as ‘bright spot’ analysis.7 EQUIVALENT MUD DENSITY SG 1.5 1.BP WELL CONTROL MANUAL 0.25 0. bright spots do not always contain gas. A compaction model has been developed that may have an application for predicting formation pressures. An example hazard log is shown in Figure 2. It is the responsibility of the well planning DE to ensure that the pressure data used are the most accurate available.11. although there is no guarantee that this will be successful. especially if used in conjunction with seismic data. Direct pressure measurements such as those from RFTs. drillstem tests and well kicks should give more accurate data than pressures derived from well logs. Sunbury is worthy of note. It may be necessary to move the well location to avoid drilling into a possible shallow gas zone as indicated by a bright spot.BP WELL CONTROL MANUAL Gas bearing formations may produce high amplitude ‘anomalies’ on the seismic reflection traces of the seismic section. pressure data from offset wells should be used to predict the pore pressure profile for well planning. These high amplitudes (relative to the other seismic reflections) are caused by strong seismic reflections due to the velocity impedance contrast between the gas bearing formation and the overlying formations. although such a thickness of gas accumulation may be enough to cause a shallow gas blowout. or sections. the model is being validated against actual well data. and the area of the proposed well location examined in detail. However. It will not be possible to predict formation pressures for shallow gas formations from the seismic data. Seismic methods of pressure prediction should only be used in the absence of offset well data. Ideally. However. 2-21 March 1995 . Whenever possible. Also. the Drilling Engineer should liaise closely with the Geophysicists and Geologists to produce a drilling engineering hazard log over the depths covered by the shallow seismic survey. drilling personnel should always be aware that shallow gas bearing formations may be overpressured. 4 Summary The importance of reliable formation pressure data must be stressed. though this is not normally the case. the absence of bright spots does not mean that there will be no shallow gas and conversely. seismic analysis may be necessary to endorse the data from offset wells. Once the well location has been finalised. This model may be useful for pressure prediction in areas with very few or no offset wells. It must be noted that the high resolution seismic technique cannot usually detect a gas sand that is less than 2 to 3 metres thick. the Geophysicists must be responsible for analysing the shallow seismic data at the proposed well location. At present. A recent development by Geochemistry Branch at Company Research Centre. These amplitude anomalies appear visually on the seismic section as bright areas. it is wise to avoid drilling through any bright spots if possible. The lateral extent of the bright spots can be mapped on a horizontal section. Occasionally. LENSES. POSSIBLE GAS 470 18 5/8in (580m) 600 620 SAND AND SHALE 800 850 1000 FAULT BASE OF SHALLOW SURVEY 2-22 March 1995 WEOX02.11 Example of Drilling Hazard Log over Shallow Section CASING DEPTH (m) RTE 0 SEABED DRILLING HAZARD 100 200 210 230 BASE OF NEAR SURFACE SEDIMENT POSSIBLE SHALLOW GAS 350 FAULT 30in (320m) 400 SAND.088 .BP WELL CONTROL MANUAL Figure 2. 15 Schematic Diagram showing Typical response of Corrected d-exponent in Transition and Overpressured Zones 2-30 2.13 Effect of Lithology Variation on Penetration Rate 2-27 2.1 Gas Levels 3.4 Hole Characteristics 2-25 2-25 2-27 2-38 2-42 3 Drilling Mud Parameters 3.3 FORMATION PRESSURE EVALUATION WHILST DRILLING Paragraph Page 1 General 2-25 2 Drilling Parameters 2.BP WELL CONTROL MANUAL 2.4 Flowline Mud Weight 2-43 2-43 2-52 2-53 2-53 4 Cutting Parameters 2-53 5 Measurement While Drilling (MWD) Techniques 2-60 6 Mud Logging Service 2-61 7 Summary 2-64 Illustrations 2.16 Schematic Diagrams showing Various Typical d c-exponent Responses 2-31 2.3 Other Drilling Rate Methods 2.12 Example showing Increase in Penetration Rate on Entering an Abnormally High Pressure Zone 2-26 2.18 Example of Formation Pressure Determination from the d c-exponent plot using the ‘Ratio Method’ 2-34 2-23 March 1995 .3 Resistivity/Conductivity/Chlorides 3.14 Effect of Bit Condition on Penetration Rate when Drilling into an Overpressured Zone 2-28 2.2 Temperature 3.17 Schematic Diagram showing dc-exponent Response to Overcompaction caused by Ice Sheet Loading 2-33 2.1 Rate of Penetration 2.2 Drilling Exponents 2. 27 Example ‘Horner’ Temperature Plot for Estimation of True Bottomhole Temperature (BHT) 2-51 2.26 Example Flowline Temperature Plots showing Raw Data Plot.3 General Mud Logging Sensor Specifications 2-24 March 1995 2-63 . End-to-end Plot and Trend-to-trend Plot 2-50 2. Kelly Gas (Kelly Cut).32 Shale Factor/Depth Response to Overpressure caused by Compaction Disequilibrium and Clay Diagenesis 2-58 2.28 Example of Typical Response of Differential Mud Conductivity/Delta Chlorides 2-53 2.20 Example showing Formation Pressure Determination from the dc-exponent Plot using Lines Constructed from the ‘Eaton Equation’ 2-49 2.23 Example of Mud Gas Levels showing Trip Gas.BP WELL CONTROL MANUAL Illustrations 2.34 Mud Logging Unit Functions and Information Flow Diagram 2-62 Table 2.29 Schematic Shale Bulk Density/Depth Plot 2-54 2.30 Variable Density Column for Measuring Shale Bulk Density 2-55 2.19 Example showing the ‘Equivalent Depth Method’ for Formation Pressure Determination from dc-exponent Plots 2-36 2.24 Schematic Diagram showing Theoretical Geothermal Gradients and Temperature Profile through an Overpressured Zone 2-49 2. and Recycled Trip Gas 2-46 2.25 Schematic Diagram showing Expected Flowline Temperature Response on Drilling through an Overpressured Zone 2-49 2.31 Response of Shale Bulk Density/Depth Plots in Overpressures caused by Various Mechanisms 2-56 2.33 Characterisation of Shale Cavings Caused by Underbalanced Conditions and Stress Relief 2-59 2.21 Example showing the ‘Normalized Penetration Rate’ Method for Determination of Formation Pressures 2-40 2.22 Schematic Diagram showing Mud Gas Levels as an Indicator of Formation Pressures 2-45 2. rotary speed. This is due to the normal compaction increase in shales with depth. The parameters commonly used to evaluate formation pressures while drilling are listed in Table 2. It should be remembered however. together with the reduction in differential pressures across the bottom of the hole. However.1. formation properties have to be closely monitored in order to detect any changes that may indicate the transition from a normally pressured zone to an abnormally pressured zone or vice versa.1 that are associated with kicks are not discussed here. Lithological variations should always be taken into account when interpreting changes in drilling and mud parameters. Abnormally pressured zones may exhibit several of the following properties when compared to normally pressured zones at the same depths. this section concentrates on the techniques used to achieve this. • Higher porosities • Higher temperatures • Lower formation water salinity • Lower bulk densities • Lower shale resistivities • Higher interval velocities • Hydrocarbon saturations may be different (ie higher saturation) Any measureable parameter which reflects the changes in these properties may be used as a means of evaluating formation pressures. hydraulics.BP WELL CONTROL MANUAL 1 General The aim of formation pressure evaluation whilst drilling is to determine the optimum mud weight to contain any formation pore pressures encountered. the undercompaction present in transition and abnormally pressured zones. If the weight on bit. rotary speed. whilst maximising rates of penetration and minimising the hazards of lost circulation and drillstring differential sticking. result in an increase in penetration rate. It should also be noted that slower penetration rates have often been observed in the ‘cap rock’ (pressure seal) overlying transition zones. bit type and size. 2-25 March 1995 . 2 Drilling Parameters 2. As the aim of formation pressure evaluation whilst drilling is to reduce the risk of taking well kicks. that the above properties also vary with differing lithologies. drilling fluid properties and formation characteristics. then the rate of penetration (ROP) in shales will decrease uniformly with depth. mud density and hydraulics are held constant.1 Rate of Penetration Rate of penetration varies with the weight on the bit. The pressure evaluation techniques in Table 2. bit type. To achieve this. BP WELL CONTROL MANUAL The increase in ROP on drilling into a transition zone can be best seen on a plot of ROP versus depth. known as a ‘drilling break’ is shown schematically in Figure 2. remain constant.13. An increase in penetration rate away from the normal compaction trend may indicateabnormal pressures provided that the drilling and mud parameters. This is normally shown by a sharp increase in ROP as the sandstone is penetrated. This may make it very difficult to identify an increase in ROP as being one due to increased pore pressure. This effect. Drilling breaks must always be flow checked regardless of whether the current estimated pore pressure gradient is less that the mud weight. A normal compaction trend can be established in shales as shown. the transition zone may be only a few metres thick if there is a very good pressure seal. The normal compaction trend must be established over the shale sections only.12.089 Figure 2. Occasionally. ROP DEPTH NORMAL SHALE TREND LINE NEW BIT TOP OF OVERPRESSURES WEOX02.5 to 2m depth increments (depending on whether thedrilling is slow or fast) is plotted as shown in Figure 2.12 Example showing Increase in Penetration Rate on Entering an Abnormally High Pressure Zone Complications arise due to lithology changes and bit dulling. The average ROP over 0. because it may be masked by a drilling break. Sandstone usually drills much faster than shales. and lithology . A new trendline must be established for each new bitrun. 2-26 March 1995 . They may. The dull bit continues to show the normal compaction trend in the transition zone whilst the sharp bit clearly shows a gradual increase in ROP. drilling parameters are rarely held constant. however.090 Figure 2. The dull bit ROP may even show a decrease in the overpressured zone if the bit is very worn and close to being pulled. 2-27 March 1995 . Thus. A comparison of ROP curves in an overpressured section for a dull bit and a sharp bit are shown in Figure 2. 2. it is clear that a method of accounting for the effect of drilling parameters is desirable in order to make ROP a better indicator of abnormal pressures.14.13 Effect of Lithology Variation on Penetration Rate Bit dulling can also mask penetration rate changes due to pore pressure increases.BP WELL CONTROL MANUAL ROP sand shale DEPTH NORMAL SHALE COMPACTION TREND LINE WEOX02. In practice. as they are purposefully varied in order to maximise the penetration rate. provide additional information when used in conjunction with other abnormal pressure indicators. ROP curves alone tend to be of limited use in identifying overpressured zones.2 Drilling Exponents From the preceding discussion on ROP curves. The ‘d-exponent’ attempts to achieve this. 091 Figure 2.BP WELL CONTROL MANUAL SHARP BIT ROP DULL BIT ROP sand DEPTH shale TOP TRANSITION ZONE WEOX02. Bingham(4) proposed a generalised drilling rate equation to relate all the relevant drilling parameters: ROP = a WOB N B where ROP N B WOB a d = = = = = = d (2-3) penetration rate (ft/min) rotary speed (rpm) bit diameter (ft) weight on bit (lb) rock matrix strength constant (dimensionless) formation drillability exponent (dimensionless) 2-28 March 1995 .14 Effect of Bit Condition on Penetration Rate when Drilling into an Overpressured Zone (a) d-Exponent In 1965. The response of d-exponent in overpressure is shown schematically in Figure 2. normal compaction trendline.) weight on bit (lb) NOTE: The constant 106 is simply a scaling factor inserted in the equation in order to give values of d in a convenient workable range.5 to 2. The values may also be plotted up automatically to enable trends to be spotted as early as possible. Hence Rehm and McClendon (27) proposed the following correction to the d-exponent to account for mud weight variations: dc = d X FPG N ECD (2-5) where dc = corrected or modified d-exponent (dimensionless) FPGN = normal formation pressure gradient (ppg. Values should be calculated at 0. 2-29 March 1995 . in general. ECD should be used whenever possible but use of the actual mud density has been found to be acceptable. In constant lithology. However. the drillability exponent.5 to 2m intervals.0. They inserted constants to allow the use of more common oilfield units and let the matrix strength constant.0) and is a more suitable format for making formation pressure estimates from dc-exponent.15. Either system will produce an approximately linear. but made d-exponent lithology dependent: log ROP 60N d= 12WOB log 106 B where d ROP N B WOB = = = = = drillability exponent (d-exponent) (dimensionless) penetration rate (ft/hr) rotary speed (rpm) bit diameter (in. (b) Corrected d-Exponent Since the differential pressure across the bottom of the hole is affected by the mudweight also.15. ‘a’. equal 1. the semi-log co-ordinate system gives a more efficient data display (values of dc are normally in the range 0. compaction and differential pressure will decrease and will result in a decrease in d-exponent. when an overpressured zone is penetrated.BP WELL CONTROL MANUAL Jorden and Shirley (21) rewrote equation 2-3 for ‘d’. In practice. Hence d-exponent is. normally about 1. This is normally done automatically by the Mud Logger’s computer and displayed as required. SG) This correction has no theoretical basis but has been successfully used worldwide. d-exponent will increase with depth as the ROP decreases due to the increased compaction and differential pressures across the bottom of the hole. depending on penetration rate. as indicated in Figure 2. A d c-exponent plot should be commenced as soon as drilling begins. This removed the need to derive values for the matrix strength constant.0 to 3. The dc-exponent may be plotted with either semi-log or linear co-ordinate axes. related to the differential pressure at the bottom of the hole which in turn is dependent on pore pressure. SG) ECD = equivalent circulating density (ppg. then changes in the mud weight will produce unwanted changes in d-exponent. 2-30 March 1995 . This variation in d c values is mainly caused by: • Lithology As previously stated. Cuttings analysis should help to identify ‘true’ shale points for use in establishing the normal trend if the dc values show a largescatter .BP WELL CONTROL MANUAL NORMAL CONCEPTION TREND UNE DEPTH NORMAL PRESSURE TRANSITION ZONE OVERPRESSURED ZONE WEOX02. Changes inlithology will thus cause changes in the value of d c. such as silty shales. However.092 dc Figure 2. This implies that d-exponent is mainly applicable to shales. d-exponent increases with depth and compaction in constant lithology. then a slight decrease in dc values may be observed which may not affect the overall trend significantly. If the lithology change is relatively minor.15 Schematic Diagram showing Typical response of Corrected d-exponent in Transition and Overpressured Zones The ‘normal’ dc trendline should be established as soon as possible in order that transition zones to abnormal pressures can be recognised as they are being drilled. it is often difficult to precisely establish the normal dc trendline due to scatter in the dc values calculated. 16 Schematic Diagrams showing Various Typical dc-exponent Responses (a) (b) MUDSTONE SILTY MUDSTONE DEPTH CALCITIC MUDSTONE MUDSTONE NORMAL PRESSURE NORMAL PRESSURE DEPTH SOFT CLAY SAND MUDSTONE SAND MUDSTONE OVERPRESSURE OVERPRESSURE CALCITIC MUDSTONE MUDSTONE CALCITIC MUDSTONE MUDSTONE SAND MUDSTONE dc dc (c) (d) ROCK BIT 12 1/4in / 25 000 lb W/B = 2040 lb/in SMOOTHED CURVE SMOOTHED CURVE DEPTH DEPTH RAW DATA INSERT BIT 12 1/2in / 10 000 lb W/B = 1178 lb/in ROCK BIT RAW DATA dc dc (e) (f) OVERPRESSURE NEW BIT NORMAL PRESSURE DEPTH DEPTH NEW BIT NEW BIT dc FRESH BIT DULL BIT dc WEOX02.093 2-31 March 1995 .BP WELL CONTROL MANUAL Figure 2. 16 (f). The effect of drilling into an overpressured zone as the bit dulls is shown schematically in Figure 2. The increased ROP in sand sections will give sharply decreased dc values.16 (c) and (d). The new bit should give a new dc trend that continues along the previous trend provided that it is the same type of bit and none of the other parameters have varied significantly.16 (a) and (b). This also applies to formations that are susceptible to jetting. as indicated in Figure 2. such as those commonly drilled in offshore top hole sections.16(e). Therefore. Changes in hole size will also produce a trend shift in dc. The response of d c in various lithologies is shown schematically in Figure2. • Hydraulics Changes in drilling hydraulics may produce changes in dc-exponent. the normal trend must be developed through the shale sections only. such as interbedded sandstone/shale. as should the practice of shifting trends from raw data to produce smoothed curves. A new trendline should be established after drilling through an unconformity/disconformity. 2-32 March 1995 . bit dulling may totally mask or even produce an increase in dc values even though an overpressured zone has been penetrated. The different compaction histories and sedimentary conditions of the formations above and below an unconformity/disconformity may result in not only a shifted normal dc trendline. It is sometimes necessary to plot a ‘smoothed’ curve to account for trend shifts as shown schematically in Figures 2. but also a change in slope. (It may be possible to develop normal trendlines for the various other lithologies but these are of little use in overpressure evaluation and may only serve to confuse matters. Thus it can be seen that the position of normal trends should be established with great care. In extreme cases.) The important message here is that lithology variations must be taken into account when interpreting dc-exponent plots. Two further noteworthy phenomena that may cause difficulty in interpreting the plotsare: • Unconformities/Disconformities The presence of an unconformity/disconformity in the geological age of formations being drilled will often change the character of the normal trendline. A dull bit may mask the decrease in dc which would be expected if the bit was fresh. it is often impossible to establish a normal dc trend in soft. The effect of bit wear is to produce an increase in dc values towards the end of the bit run. • Bits The different drilling actions of different types of bits. can cause variations and trend shifts in dc. unconsolidated sediments. ie mill tooth or insert.BP WELL CONTROL MANUAL For major lithological variations. 5 2.0 SG DEPTH OVERCOMPACTED NORMAL COMPACTION TREND NORMALLY COMPACTED OVERPRESSURED WEOX02.3 1. The compacting influence of the ice sheet is often dissipated after the first few hundred metres and the d c-exponent then appears to decrease to a new normal trend. This is due to the increased compaction of the near surface sediments caused by the weight of a once present overlying ice sheet. 2-33 March 1995 .094 Figure 2. This may lead to a normal d c trend being developed through dc values that are too high. provided that there have been no significant changes in lithology or in any of the other relevant parameters. (c) The Calculation of Formation Pressures using dc Once the normal compaction trend has been firmly established on the dc-exponent plot.2 1. This effect is shown schematically in Figure 2. 1. This is.17.5 SG 1.17 Schematic Diagram showing dc-exponent Response to Overcompaction caused by Ice Sheet Loading • Ice Sheet Compaction Ice sheet compaction can often cause a good normal compaction trend to be established at shallow depths in top hole sections. falsely indicating an increase in pore pressure.0 G 1S 1.BP WELL CONTROL MANUAL dc – EXPONENT 0. then d c values that decrease away from this line may indicate abnormal formation pressures. of course. 32 1. SG or ppg) dcO = observed corrected d-exponent at depth of interest dcN = expected corrected d-exponent on normal trendline at depth of interest Normal shale trend line Normal formation pressure Gradient is 1.04 SG 1.66 SG dc – EXPONENT (SEMI-LOG SCALE) WEOX02. By rearranging the above equation into: dcO = d cN X FPG N FPG O (2-7) 2-34 March 1995 .80 1.18 Example of Formation Pressure Determination from the dc-exponent plot using the ‘Ratio Method’ Equation 2-6 is only valid for the semi-log dc plots as it is assumed that dc is an exponential function of depth.BP WELL CONTROL MANUAL • The ratio method The magnitude of the formation pressure can be related to the dc deviation on the semi-log plot using the ‘ratio method’: FPG O = FPGN X dcN dcO (2-6) where FPG O = actual formation pressure gradient at depth of interest (psi/ft.20 1.43 SG Maximum formation press gradient is 1. SG or ppg) FPG N = normal formation pressure gradient (psi/ft.08 SG TYPICAL TRANSITION ZONE Maximum formation press gradient is 1.08 SG SANDS DEPTH 2.44 1.56 1.095 Figure 2. An alternative method of calculating formation pressures from the dc plot is the equivalent depth method. Therefore. which controls compaction trends. The equivalent depth method attempts to relate these values to the depth at which they would be normal. Matrix stress (M) is related to pore pressure (P f) and the overburden pressure (S) as shown by equation 1-8 (See Chapter 1.) However. and the formation becomes harder to drill. it is possible to calculate a series of values of dcO . referring to the example dc plot in Figure 2. The ratio method is a very simple method of making formation pressure estimates from dc-exponent.BP WELL CONTROL MANUAL and substituting known values of FPG N and dc at various depths. The method assumes that the matrix stress (grain to grain contact pressure) is equal at all depths having the same value of dc. NOTE: Transparent overlays ready marked with equivalent formation pressure gradient lines are sometimes available for reading formation pressures directly off the dc plot. In overpressured formations the compaction and matrix stresses are less than would be normally expected at that depth. Section 1. the actual formation pressure gradient (FPG O) at the depth of interest (D O) is given by: FPGO = PfO = DO SO – M O D O DO FPGO = OPGO – MO DO where OPG O MO (2-9) = overburden pressure gradient at depth of interest (psi/ft) = matrix stress at depth of interest (psi) The overburden pressure gradient is known because it is continually estimated by the Mud Loggers and updated from wireline formation density or sonic logs. Section 1. 2-35 March 1995 .19. This equation can be rearranged to give: Pf = S – M (2-8) This equation holds at any depth. Figure 2. the value of the matrix stress at the depth of interest is unknown. As it is never certain exactly what depth and dc scales were used to construct these overlays. their use should be avoided in making formation pressure gradient estimates.1).1). • Equivalent Depth Method Due to the increase in compaction with depth. (Theoverburden gradient is required for estimating fracture pressures as well as for making pore pressure estimates. These series of values of dcO can be plotted on the semi-log dc plot as lines parallel to the normal d c trendline. the formation matrix stress also increases. However. This effect is reflected in the d c-exponent trend. it ignores the effect of the variable overburden gradient (See ‘Overburden Pressure’ in Chapter 1. but is considered not accurately defined by it. FPGO. equivalent to various values of formation pressure gradient.18 shows an example d c plot with equivalent formation pressure gradient lines drawn in. The formation pressure gradient at any desired depth can then be estimated directly from the dc plot. 19. At this equivalent depth. equation 2-8 can be solved for the matrix stress (ME) at the equivalent depth (DE): ME = SE – PfE (2-10) In terms of gradients: ME = SE = PfE = OPG E – FPG E DE DE DE ME = DE (OPGE – FPG E) (2-11) where OPGE = overburden gradient at equivalent depth (psi/ft) FPGE = formation pressure gradient at equivalent depth (psi/ft) which also equals the normal formation pressure gradient at the equivalent depth FPGNE (psi/ft) dc – EXPONENT 0.5 1.096 Figure 2. as shown in Figure 2.5 2.0 1.0 DEPTH DE NORMAL COMPACTION TREND DO WEOX02.BP WELL CONTROL MANUAL A line is then constructed vertically upwards from the value of dc at the depth of interest until it crosses the normal dc trendline at ‘the equivalent depth’ (DE). Thus.19 Example showing the ‘Equivalent Depth Method’ for Formation Pressure Determination from dc-exponent Plots 2-36 March 1995 . both the pore pressure and the overburden pressure are known. Also.20 (2-14) Combining equations (2-13) and (2-14) gives: MO = (SO – PfN) dcO d cN 1. This will be the case if high overpressures are developed at relatively shallow depths.20 (2-17) 2-37 March 1995 . This empirical equation was again developed from the basic relationship between pore pressure. as is usually the case on the semi-log dc plot. For normal pressure conditions: MN = S O – PfN (2-13) Eaton then introduced a term to relate the dc-exponent (drilling rate) response in overpressures to the reduction in matrix stress: MO = MN DcO d cN 1. lb/gal or psi/ft and depths in metres or ft.20 (2-15) Rewriting equation 2-13 for an abnormally pressured situation gives: MO = S O – PfO (2-16) Substituting equation 2-16 into equation 2-15 then gives the Eaton equation: PfO = SO – (SO – PfN) DcO d cN 1. However a major flaw in the theory occurs when the equivalent depth of a particular overpressured formation is found to be above the rig floor. then substituting equation 2-11 into equation 2-9 gives: FPGO = OPGO – D E (OPGE – FPG NE) DO where FPG O OPG O OPG E FPG NE DO DE = = = = = = (2-12) formation pressure gradient at depth of interest (psi/ft) overburden pressure gradient at depth of interest (psi/ft) overburden pressure gradient at equivalent depth (psi/ft) normal formation pressure gradient at equivalent depth (psi/ft) depth of interest (ft) equivalent depth (depth at which dc is equal to value at DO) (ft) NOTE: Equation 2-12 can be used directly with gradients in SG. and matrix stress (equation 2-8). • The Eaton Method The most accurate estimates of formation pressure from dc-exponent are considered to be obtained from the Eaton equation. the method relies on determining the intersection point of a vertical line with the normal compaction trendline.BP WELL CONTROL MANUAL Since the matrix stress at the depth of interest and equivalent depth are considered equal (equal d c values). The equivalent depth method has been successfully used to estimate formation pressures from both semi-log and linear scale d c plots. overburden pressure. It therefore becomes inaccurate when the normal compaction trendline is very steep. the relationship between ROP and the various drilling parameters is not so simple as is implied by the dc-exponent equation. OPGO. By rearranging equation 2-18 and substituting known values of FPGN. FPGN. they have not gained wide acceptance and thus tend only to be used by their originators. dcO and dcN are the same terms as explained for equations 2-6 and 2-12. Also. should always be checked. Exlog’s ‘Nx’ (normalised exponent) and ‘Nxb’. mud logging companies have developed their own drilling exponents from which they make formation pressure estimates.20 FPGO = OPGO (OPGO – FPGN) dcO d cN 1.BP WELL CONTROL MANUAL Dividing through by the depth (D). any formation pressure conclusions drawn from the dc plot.20. An example of this construction is shown schematically in Figure 2. The value of the exponent. but found that it applied equally tocorrected d-exponent. 2.4). The difficulties in achieving this have previously been discussed and highlight the fact that identification of overpressured zones should not be based on dc-exponent calculations alone. All the methods for estimating formation pressures from dc-exponent plots rely on correct placement of the normal compaction trend. As these methods are generally more complex than d-exponent methods. it is possible to plot a series of d cO lines equivalent to various values of FPG O (in a similar manner to that previously explained for the Ratio method). Other abnormal pressure indicators. gives the equation in terms of gradients: PfO = SO – SO – PfN DO DO DO DO dcO d cN 1. Eaton originally developed the equation for use in estimating formation pressures from shale resistivity plots (See Section 2. 2-38 March 1995 . In particular.20. bit tooth efficiency (bit wear) and matrix strength (lithology dependent). Suffice it to say that the methods still rely on estimating a normal compaction trend and spotting deviations from it caused by pore pressure changes and not by lithology or drilling changes. was derived from actual well data. d cN and OPG. These factors have led to the development of more refined drilling exponents in which attempts have been made to model the various drilling/formation interactions more closely. and Anadrill’s ‘A’ exponent are examples of these more refined drilling exponents. The theory of these drilling exponent methods will not be discussed in detail here as their formulae are of a proprietary nature and are not generally available. 1.3 Other Drilling Rate Methods There are a number of other drilling rate methods for estimating formation pressures that are worthy of note.20 where FPGO. Drilling factors that are not accounted for by dc-exponent are drilling hydraulics. as far as possible. These indicators must support. which are often more basic in nature than dc-exponent calculations. Formation pressure gradients can then be read directly from the dc plot. 80 1.20 1.33 1.5 SG DEPTH NORMAL TREND TOP OF OVERPRESSURE WEOX02.08 1.56 1.44 1.5 1.BP WELL CONTROL MANUAL Figure 2.0 1.097 2-39 March 1995 .20 Example showing Formation Pressure Determination from the dc-exponent Plot using Lines Constructed from the ‘Eaton Equation’ dc – EXPONENT 0.68 1. If the ECD is then considered to be fairly constant over short intervals of the hole.23m/hr 3080 6. The only variable not normalised is differential pressure across the bottom of the hole. The method uses a drilling rate equation to ‘normalise’ the effects of the variables controlling ROP. 2960 NEW BIT 1.098 Figure 2.38 ECD ALL AROUND NEW BIT ECD = 1.28 SG CIRCULATED 1.25 SG 3020 1.38 SG 1.BP WELL CONTROL MANUAL (a) Normalised Penetration Rate This method was developed in 1980 by Prentice(26) from work done originally by Vidrine and Benit(32).21 Example showing ‘Normalized Penetration Rate’ Method for Determination of Formation Pressures 2-40 March 1995 .1m/hr 1. a change in ‘normalised’ penetration rate reflects a change in formation pressure.11m/hr DEPTH (metres) NEW BIT 3050 1.25 SG 2990 ECD = 1.53m/hr 4.5 ECD ALL AROUND 12 8 4 4100 0 NORMALIZED PENETRATION RATE (m/hr) WEOX02.08 SG ECD = 1.08 SG 8.28 SG 8.37 SG CIRCULATED 1. 25 (2-20) where √σt = ‘raw’ rock strength parameter and WOB. at constant ECD. Changes in mud weight are also plotted separately. then no corrections will be necessary and ROPN will equal ROPO. B and ROP are as previously defined. √σo. N. Lithology changes are generally abrupt. ROP0. the extrapolated dulling trend ROP N and the observed ROPN at a particular depth are used to estimate the actual formation pressure at that depth.25 √σ t = WOB . The Sigmalog is then constructed by plotting √σo versus depth. Provided that the ECD and formation pressure remain constant.21. as shown in the example plot at about 9950 ft and 10. a plot of normalised penetration rate against depth is constructed. 2-41 March 1995 . Using this relationship. but no data are presented to support this claim.5 0. this then indicates either a lithology change or a change in formation pressure. Vidrine and Benit (32) developed a graphical relationship between differential pressure across the bottom of the hole and the percentage decrease in ROP caused by this overbalance. Drilling trends are fitted to each bit run. or part bit run. as shown in the example. The observed penetration rate is mathematically corrected to the normalised penetration rate by applying arbitrarily chosen normal parameters according to the equation: ROPN = ROPO where ROP W N ∆Pbit Q m λ = = = = = = = WN – m WO – m X X NN NO λ X ∆PbitN QN ∆PbitO QO (2-19) penetration rate (ft/hr or m/hr) weight on bit (lb) rotary speed (rpm) bit pressure drop (psi) mud flow rate (gpm) ‘threshold’ bit weight (weight necessary to initiate formation failure) (lb) rotary exponent and the subscripts N O = ‘normal’ values = observed values Values of λ and m are given by Prentice(26). using experimentally derived relationships to account for depth and bottomhole differential pressure (assuming a normal formation pressure gradient). the bit will dull and the ROPN will follow the dulling trend. If a deviation from the dulling trend is noted at constant ECD. Formation pressure changes show a more gradual deviation from the dulling trend. Each bit run is treated as an individual unit and is plotted up as shown in the example in Figure 2. it is a plot of a calculated rock strength parameter versus depth. If the ‘normal’ conditions are chosen so that most of a bit run can be drilled at these conditions. The method is quoted as being the most responsive of all methods used to indicate the changes in formation pressure. The method is detailed in full by Prentice(26) together with worked examples and a comprehensive discussion of the theory behind the method. The ‘raw’ rock strength is then corrected to the rock strength parameter. and easily identified.100 ft. Basically.BP WELL CONTROL MANUAL As drilling proceeds. N B . The method is based on the following drilling rate equation (developed by AGIP): 0. (b) Sigmalog This method was developed by AGIP and Geoservices(3). the relationship used to correct √σt to √σo is reworked to determine the true bottomhole differential pressure (not the assumed one). A reduced wellbore diameter caused by overpressured shales may also result in an increased torque. increased torque resulting from underbalanced conditions is virtually unseen when the pressure differential into the wellbore is less than 1 ppg (0. The Sigmalog is commonly used by Geoservices to estimate formation pressures. insufficient hole cleaning. The formation pressure can then be calculated from the differential pressure and the ECD for the mud weight in use.4 Hole Characteristics (a) Drag and Torque Drag is the excess hook load over the free hanging load required to move the drillstring up the hole. Various factors such as faults. Normal drag after drilling new hole is usually of the order of 10. dog legs. then concurrent increases in drag and hole fill (see below) should also be expected. If an increase in torque is taken to indicate underbalanced conditions. it is claimed that the Sigmalog is an excellent formation pressure evaluation tool and can be applied both in shale and non-shale lithologies. cause ‘shifts’ in the normal trend. In deviated holes however. poor bit efficiency.12 SG) equivalent pressure gradient. These include methods by Combs (10) . and the shifts of the trendlines are proportional to the shifts in the values of √σo. However. an increased volume of cuttings may come into the wellbore. In an underbalanced drilling situation. coring etc. depending on the hole and BHA geometries. This reduces the wellbore diameter and will cause an increase in drag as the bit/stabilisers are moved up through the section. Torque usually increases gradually with depth due to the increase in wall-to-wall contact between the drillstring and borehole. unconformities/disconformities. Consistent drag values much higher than this may indicate borehole instability caused by abnormal pressures. Correct shifting of the normal trendlines is thus of prime importance in calculating formation pressures from the Sigmalog. (c) Other Methods Several other methods of formation pressure evaluation from drilling rate equations have been put forward. A normal compaction trend can be established and a decrease in √σo away from the normal trend will indicate an increase in formation pressure. However all the normal trends have the same slope. Zoeller (33) . especially if the cuttings are not circulated above the drillcollars prior to picking up. Drag may be caused by bit and stabiliser balling. Despite this problem. especially if full gauge stabilisers are being used. and also by overpressure effects in shales.000 lb.000 to 20. 2. This may result in an increase in drag when picking up the drillstring to make a connection. consistently higher drag will invariably be seen.BP WELL CONTROL MANUAL In normally pressured formations. If underbalanced conditions exist then an increase in torque may be observed due to excess cuttings entering the hole. Overpressured shales often behave plastically and creep into the borehole. 2-42 March 1995 . and Bourgoyne (5). These are not discussed here but are referenced in case of interest to thereader . When this occurs. etc. √σo will increase with increasing depth and compaction. As discussed above.1 Gas Levels Hydrocarbon gases enter the mud system from various sources during the drilling of a well. However. for example when crossing a fault line into overpressured formations. sudden large increases in torque can also be caused by a locked cone on the bit. changes in gas levels can be accounted for by relating them to the actual drilling operation in progress (drilling. There is no quantitative correlation between measured gas levels and formation pressure. The gas levels from these sources are dependent upon the formation gas saturations. it removes the shale which is pushed to the bottom of the hole. 2-43 March 1995 . overpressured shales may squeeze into the wellbore and reduce its diameter. The gases in the return mud stream are extracted from the mud for analysis in the mud logging unit. However. a sudden change in formation type. Cavings caused by underbalance conditions may also enter the wellbore during a connection or a trip and cause hole fill. Also. (b) Hole Fill Hole fill after making a connection or after a trip out of the hole may indicate abnormal pressures. the mud weight and the particular drilling operation. Hole fill may also be the result of insufficient hole cleaning caused by poor mud properties. However. • Gas flowing into the wellbore due to underbalanced conditions. tripping etc) and the mud weight in use. or by not circulating all the cuttings out of the hole prior to tripping.BP WELL CONTROL MANUAL Torque can be useful in detecting large increases in pore pressures. 3 Drilling Mud Parameters 3. When drilling from a floating rig the vessel motion and varying offset from the wellhead tend to produce significant torque fluctuations that make interpretation very difficult. and by stabilisers ‘hanging up’ on hard stringers. as the bit is run in the hole to bottom after a connection or trip. increases in torque due to abnormal pressures are difficult to distinguish from the normal torque increase with depth. Tentative pore pressure estimates may then be made. Both torque and drag are not considered to be valid overpressure indicators when drilling high angle deviated holes. Then. any excessive hole fill after making a connection or a trip should be noted and other abnormal pressure indicators evaluated to determine if overpressures are actually being encountered. The main sources of gas in the mud system are: • Gas liberated from drilled cuttings. This reduction in pressure may be enough to allow a small amount of gas to be produced into the mud column. or possibly exceeding the mud weight gradient. (b) Connection Gas (CG) When circulation is stopped to make a connection. Also. connection gas may also be caused by ‘swabbing’ when picking up the drillstring to make a connection. As the pore pressure increases further. Background gas levels normally show a gradual increase as a transition zone to abnormal pressures is drilled. drilling conditions. gas may enter the mud at a rate that depends on the permeability of the formations being drilled. the longer the bottoms up time. if mud properties. entry of gas into the mud. it appears as a peak above the background gas level on the total gas trace recorded in the mud logging unit. In underbalanced drilling conditions. the effective mud weight is reduced from the ECD to the static mud weight.22. However.e. connection gas peaks begin to appear. It is possible to correlate connection and background gas levels with the mud weight to give a fairly accurate estimate of the formation pressure. due to an increase in cavings caused by the underbalanced conditions. A slight increase in the mud weight at this point then causes a sudden decrease in the background gas and the connection gas peaks disappear. If hydrocarbons are present in any porous formations drilled. the bottomhole pressure of the mud column is reduced by an amount equal to the annulus pressure loss i. i. As the pore pressure approaches the bottomhole dynamic pressure. This is known as connection gas. It is reasonable to assume at this point that the pore pressure slightly exceeds the dynamic bottomhole pressure (ECD). Shales may shown an increase in background gas levels. the background gas level also begins to increase and the connection gas peaks become higher. The high overbalance will cause the mud filtrate to ‘flush’ the gas away from the wellbore. if the mud weight in use causes a high overbalance. Hydrocarbons are often generated within shales and migrate to more porous formations such as sandstones where they may be trapped. Background gas can not be used quantitatively to estimate formation pressures since the levels depend on mud circulation rate. probably due to swabbing. However. there may be little. if any. When this gas reaches the surface. 2-44 March 1995 .e. It originates primarily from the unit volume of formation cut by the bit. then increasing background gas levels may well indicate that the formation pressure gradient is approaching. Connection gas peaks are generally short and sharp depending on the ‘bottoms up’ time. Gas in shale cuttings is released into the mud stream due to the reduction in pressure as the cuttings are circulated up the hole.BP WELL CONTROL MANUAL Gas levels are categorised as follows: (a) Background Gas (BGG) This is the total level of gas extracted from the return mud stream whilst drilling ahead. efficiency of gas extraction from the return mud stream (gas trap efficiency) and also on the gas composition. This is shown schematically in Figure 2. there will be relatively high levels of background gas in the mud stream. the wider the peak will be. and lithology remain fairly constant. indicating that a slight static overbalance has been established. and two or more gas peaks may be observed.BP WELL CONTROL MANUAL PRESSURE PROFILES MUD WEIGHT GAS LEVELS C Connection C Bottomhole Dynamic Pressure DEPTH C C Background Gas Pore Pressure Connection Gases C C Increase in BGG Level C C C C C C – Indicates connection WEOX02. this will aid in the interpretation of connection gas levels.099 Figure 2. but the effect of swabbing due to pulling the drillstring from the hole will generally be greater. Lag time calculations should locate the depths/formations causing the gas peaks. it is good practice to use connection procedures that minimise swabbing. due to pulling the drillstring out of the hole. Thus the observed trip gas may not come from the bottom of the hole but from somewhere higher in the openhole section. 2-45 March 1995 . This may result in higher than actual pore pressure estimates being made. This is because the cuttings will have been circulated from the annulus and pipe speeds will be greater. Clearly. Swabbing effects are much more difficult to quantify than simple reductions from the ECD to static mud weight. This effect may also appear for connections if there is a high degree of swabbing or the hole is underbalanced. may cause the whole of the openhole section to be underbalanced. from gas swabbed into the wellbore when the drillstring is picked up. If used consistently. especially if the connection gases observed are entirely due to swabbing.22 Schematic Diagram showing Mud Gas Levels as an Indicator of Formation Pressures One major problem with this type of interpretation is to distinguish connection gas peaks caused by effective mud weight reduction due to stopping circulating. Swabbing. (c) Trip Gas (TG) This gas is produced by the same mechanism as connection gas. A trip gas peak will be observed on circulating bottoms up after a round trip or non-drilling operation. 23 Example of Mud Gas Levels showing Trip Gas. (d) Miscellaneous Gases These are mainly ‘kelly gas’.BP WELL CONTROL MANUAL Due to the complex causes of trip gas. and Recycled Trip Gas 2-46 March 1995 . Kelly Gas (Kelly Cut). recirculated trip gas and carbide gas. GAS LEVEL TOTAL GAS 10 20 MUD WEIGHT 30 40 50 60 70 60 70 60 70 RECYCLED TRIP GAS 20 30 40 50 TIME 10 KELLY CUT TRIP GAS 10 20 30 40 50 CIRCULATION STARTED WEOX02. The early onset of trip gas after circulation is resumed may indicate that much of the openhole is slightly underbalanced. it may only be used qualitatively in estimating formation pressures. Other abnormal pressure indicators must be consulted to confirm this.100 Figure 2. 24. Although indicating the presence of hydrocarbon gases. Recirculated trip gas (or any other recirculated gas) behaves in a similar way to kelly gas. This enhances any gas diffusion effects from formations to the borehole and may result in enrichment of the aerated mud with the hydrocarbon gases. A gas peak will thus be recorded when this mud is circulated back to the surface. Kelly gas due to connections is rarely seen as the kelly is usually kept full of mud during connections by closing the lower kelly cock. Again. Carbide gas is used to check the calculated total circulation time and is caused by the Mud Loggers putting calcium carbide down the drillpipe at a connection. Also. 2-47 March 1995 . the caprock immediately above a pressure transition zone often shows a reduced geothermal gradient due to increased compaction (higher thermal conductivity) and a lower than normal temperature at the top of the transition zone. In some cases. very ‘dry’ holes are drilled which may be overpressured. This may often be reflected by an increase in the temperature of the return mud in the flowline. the flowline temperature may even fall (negative gradient) and be then followed by a large increase as the overpressured zone is penetrated.2 Temperature Due to the radial flow of heat from the earth’s core to the surface. The geothermal gradient is the rate at which the temperature increases with depth and is usually assumed to be constant for any given area. and should be anticipated by the Mud Loggers from knowledge of the mud system total circulation time. it is very difficult to use gas levels as a reliable formation pressure indicator. kelly gas is of no value for formation pressure evaluation. The air is pumped into the borehole as a slug of mud aerated with compressed air. These formations will thus have a higher geothermal gradient across them. then formations with a higher water content (higher porosity) will have a lower thermal conductivity. 3.23. The carbide reacts with the water in the mud to produce acetylene. as shown schematically in the plot of flowline temperature versus depth in Figure 2. Occasionally.23) but should be easily distinguishable from other gas peaks by experienced Mud Loggers. The top of an overpressured shale should therefore be marked by a sharp increase in geothermal gradient. a hydrocarbon gas that is detected as a large sharp gas peak when circulated round to surface. However.25. Overpressured shales usually have a higher water content than normal and will thus have higher than normal geothermal gradients across them. this may be reflected in the flowline mud temperature by a reduced flowline temperature gradient. but show very low background gas levels. Kelly gas after a trip is sometimes observed (as shown in Figure 2. Since water has a thermal conductivity of about one-third to one-sixth that of most formation matrix materials. This phenomenon can be explained by considering the thermal conductivity of the formations. This effect is shown schematically in Figure 2. It must be noted that evaluation of formation pressures from gas levels relies entirely on hydrocarbon gases being present to some extent in the well being drilled. it has been found that the temperature gradient across abnormally pressured formations is generally higher than that found across normally pressured formations in the same area. An example is shown in Figure 2. The circulation time can then be used to back calculate the openhole volume and thus to check for hole enlargement. In these wells. the subsurface temperature increases with increasing depth.BP WELL CONTROL MANUAL Kelly gas (also known as ‘kelly cut’) is caused by air being circulated around the system from a partly empty drillstring or kelly after a trip or connection. However. Surface effects can be minimised by measuring the temperature of the mud in both the flowline and the suction pit (mud temperature into the hole). as shown in the left hand curve in Figure 2. may cause large fluctuations in flowline temperatures). It may. 2-48 March 1995 . there are many other factors that affect the flowline temperature and make the interpretation of flowline temperature plots very difficult.26. the temperature trends (flowline and differential) are still found to be obscured by discontinuities at bit trips. • Volume of the mud system. and then plotting lagged differential temperature. especially offshore. Various methods are used to improve the interpretation of temperature-depth plots. but care is required to ensure that this technique does not smooth out obvious gradient changes within an individual segment.BP WELL CONTROL MANUAL The example in Figure 2. Such factors include: • Circulation rate. Since overpressure indications are based on temperature gradient changes rather than on the magnitude of the flowline temperature. such as those encountered in desert regions. The flowline temperature very clearly reflects the changes in formation temperature and there are no other influences on the mud temperature. • Time elapsed since the last trip (the mud in the hole heats up during a trip). disregarding the absolute temperatures. of course. each depth segment on the temperature-depth plot can be investigated separately for gradient changes. wiper trips and other periods with no circulation. The three techniques for plotting flowline temperature are shown in Figure 2. to produce a ‘smoothed curve’. • Lithology effects (sandstones and limestones generally have higher thermal conductivities than shales). mud chemicals or weighting material.26. however. A sharp increase in differential pressures may then indicate entry into a pressure transition zone. end to end plotting of the individual segment trendlines may be of value. an idealised case. • Ambient temperature (diurnal temperature changes. be helpful to plot the segments end to end. These discontinuities split the temperature depth plot into a series of unconnected depth segments. • Rate of penetration. In practice. Also. • Surface treatments such as adding water. • Cooling effect of the sea around long marine risers.25 is. 24 Schematic Diagram showing Theoretical Geothermal Gradients and Temperature Profile through an Overpressured Zone TOP OF OVERPRESSURED ZONE WEOX02.25 Schematic Diagram showing Expected Flowline Temperature Response on Drilling through an Overpressured Zone 2-49 March 1995 .102 FLOWLINE TEMPERATURE Figure 2.BP WELL CONTROL MANUAL GEOTHERMAL GRADIENT DEPTH GEOTEMPERATURE OVERPRESSURE WEOX02.101 DEPTH Figure 2. assuming that the maximum temperature is at the bottom of the hole.26 Example Flowline Temperature Plots showing Raw Data Plot. End-to-end Plot and Trend-to-trend Plot Due to the many factors affecting the flowline mud temperature. However.103 Figure 2. This is normally done during wireline logging runs as most logging tools contain a maximum recording thermometer.BP WELL CONTROL MANUAL NEW BITS NB NB DEPTH NB NB NB NB NB NOTE TEMPERATURE REDUCTION GRADIENT NB NB NB NB TOP OF OVERPRESSURE NB RAW DATA END-TO-END PLOT FLOWLINE TEMPERATURE TREND-TO-TREND PLOT WEOX02. it is very difficult to interpret temperature-depth plots to evaluate formation pressures. Downhole formation temperatures are required. Mud temperatures recorded from consecutive logging runs are used to predict the actual bottomhole formation temperature. it is only possible to measure the downhole mud temperature. 2-50 March 1995 . At least. changes in the gradient of the plots may suggest that an overpressured zone has been penetrated. (a) Bottomhole Formation Temperature (BHT) The actual formation geothermal gradient can not be estimated from surface mud temperature measurements. though it may well be useful to support other pressure indicators. It is unlikely that flowline temperature will be the primary indication of abnormal pressures. A modified Horner expression is used to model the temperature increase with time. By extrapolating 2-51 March 1995 .3 0.260 0. the mud temperature begins to rise and gradually approaches the formation temperature.BP WELL CONTROL MANUAL T tL LOG tc + tL tL 241 257 262 4.1 0.50 0.00 9.4 0. It is estimated that about four days are required for the mud temperature to reach equilibrium with the formation temperature.2 0.104 Figure 2.25 7. When circulation stops.178 0. the formations in the lower section of the hole are cooled by the mud in circulation. T (°F) TRUE BHT IS 288°F 280 270 260 250 240 230 0 0.133 300 290 RECORDED TEMPERATURE.27 Example ‘Horner’ Temperature Plot for Estimation of True Bottomhole Temperature (BHT) When drilling.5 LOG tc + tL tL WEOX02. known as ‘delta-chlorides’. the response of differential mud conductivity is similar to that of mud gas levels showing influx peaks at connections or a gradual increase due to underbalanced conditions. 3. but may confirm any flowline temperature trends that were noticed earlier. extrapolating the plot to intercept the temperature axis gives the estimated actual formation temperature. a warning of underbalanced conditions may be given. as shown in Figure 2. The system is best suited to situations where there is a large difference between pore water and mud salinity. pore water influxes from more permeable formations may be seen as changes in mud conductivity or delta-cholrides. Hence. This is shown schematically in Figure 2. Unfortunately the actual formation temperature can only be estimated at logging points. This is due to the volume of pore water released being minute compared to the volume of mud. At ‘infinite time’ after circulation was stopped (i. An increase in the differential chlorides. an attempt can be made to monitor this formation property by measuring the mud conductivity (conductivity is simply the inverse of resistivity). as shown in Figure2.log where T Tf c tC tL tC + t L tL (2-21) = measured temperature (°F or °C) (from each wireline logging run) = actual formation temperature (°F or °C) = constant = circulation time at TD = time since circulation stopped A plot of T versus log ((tC + tL)/tL) should thus give a straight line.BP WELL CONTROL MANUAL the temperature increases to infinite time.27. and may well result in a mirror image plot to that shown in Figure 2. Hence.27. Hence.28. may then indicate abnormal pressures. A large salinity contrast between mud filtrate and formation fluids is required. This could be the case with saturated salt and potassium chloride (KCl) mud systems. However. Obviously. It is doubtful whether an increase in mud conductivity due to the release of pore water from drilled cuttings would be measurable. tL = infinity). In these situations.e. the value of log (t C +t L)/tL) equals zero. unless of course. When using water base muds. Due to their higher pore water content. they are generally of little use in pressure evaluation while drilling. Increases in the geothermal gradient may indicate the presence of abnormal pressures. The mud conductivity at the flowline and suction pit can be measured and a conversion made to chlorides. it is possible to estimate the formation temperature. Thus. the method is of little use in saline mud systems.28. overpressured shales generally have lower resistivities than normally pressured shales at the same depths. The Horner temperature expression is: T = Tf – c. These gradients are thus average gradients over significant depth intervals and they can only be established after each hole section has been drilled. 2-52 March 1995 . only three or four formation temperatures can be estimated from which geothermal gradients can be established. Thus.3 Resistivity/Conductivity/Chlorides The resistivity of a formation depends on the porosity and the dissolved salts concentration in the formation pore water. The geothermal gradients between the logging run end points can then be calculated. the mud filtrate salinity is much greater than the formation water salinity. mud conductivity as an abnormal pressure indicator has many limitations. then a normal compaction trendline can be established. an underbalanced situation due to abnormal pressures may be indicated by a slight reduction in the flowline mud weight. 2-53 March 1995 .BP WELL CONTROL MANUAL ZERO LOSS GAIN MUD CONDUCTIVITY DEPTH MUD CHLORIDE INFLUX AT CONNECTION CONTINUOUS INFLUX INCREASE MUD DENSITY MUD CONDUCTIVITY MUD CHLORIDE WEOX02. A schematic shale bulk density plot is shown in Figure 2. Overpressured shales are generally undercompacted and thus have higher porosities and lower bulk densities than would be expected. Some influxes are not always picked up by an increase in return mud flow or by an increase in mud pit level. If shale bulk density is plotted against depth as drilling progresses. A decrease in shale bulk density away from the normal compaction trendline may then indicate the presence of an overpressured zone.29.4 Flowline Mud Weight Continuous recording of the flowline mud weight will show mud density changes due to gas cutting or formation influxes.105 Figure 2.28 Example of Typical Response of Differential Mud Conductivity/Delta Chlorides 3. especially if the influx occurs gradually due to a very low permeability formation. 4 Cuttings Parameters (a) Shale Bulk Density The bulk density of normally compacted shales increases with depth. Thus. BP WELL CONTROL MANUAL The magnitude of abnormal pressures can be calculated from shale bulk density plots using the equivalent depth method (as described previously for d-exponent plots). DEPTH NORMAL SHALE TREND LINE TOP OF OVERPRESSURES 2.4 2.5 SHALE DENSITY (gm/cc) 2.6 WEOX02.106 Figure 2.29 Schematic Shale Bulk Density/Depth Plot Alternatively empirical curves, relating observed bulk density deviation from the normal trend to formation pressure gradient, can be used. However, such curves are area dependent, so can only be used if the appropriate area curve is available. Hence it will usually be necessary to use the equivalent depth method if formation pressure magnitudes are required from shale bulk density plots. 2-54 March 1995 BP WELL CONTROL MANUAL The most common methods of measuring shale bulk density at the rigsite are: • Mud Balance Shale cuttings are added to the mud balance cup until the balance reads 1.0 SG (8.33ppg) with the cap on. The cup is then topped up with fresh water and re-weighed (W). The shale bulk density is then given by: Bulk density (SG) = • 1 2–W (2-22) Density Column A graduated column of fluid is prepared from a mixture of two fluids of different densities such that the density of the mixture varies with column height. The column is calibrated using beads of known density which settle at different heights in the column. Selected shale cuttings are then dropped into the column and the height at which they settle is converted to shale density using the calibration curve. The method is illustrated in Figure 2.30. 250 200 SG 2.2 150 2.3 Shale 2.65 100 Shale Density 2.48 FLUID LEVEL cc 2.38 50 0 2.2 2.3 2.4 2.5 2.6 2.7 2.8 DENSITY (gm/cc or SG) WEOX02.107 Figure 2.30 Variable Density Column for Measuring Shale Bulk Density The mud balance method has the advantage of being fast and simple and uses a good quantity of cuttings to obtain a good average bulk density. The density column, however, requires selection of individual cuttings and multiple determinations to obtain an average density value. The mud balance method is probably the more representative method. 2-55 March 1995 BP WELL CONTROL MANUAL Use of shale bulk densities for the detection and evaluation of formation pressures frequently has the following limitations: • Presence of shale gas in the cuttings decreases the bulk density values determined. • Cavings from higher up the hole may be part of the sample. • The reliability of the data depends on the consistency and care taken by personnel, when carrying out the density determinations. • Formation age boundaries and unconformities may cause shifts in the normal compaction trendline. It may be necessary to determine individual normal compaction trends for each geological age unit. • Variations in the lithology, such as high carbonate content, silty/sandy shales etc, may cause significant variations in the bulk density determinations. Only good clean shales should be plotted. The presence of high density minerals, such as pyrite, will increase bulk density values and may mask the onset of abnormal pressures. • Density measurements on cuttings from water base muds are usually low due to the absorption of water by the cuttings. Less reactive muds, such as oil base muds and highly inhibited water base muds, will give more accurate cuttings densities. SHALE DENSITY DEPTH NORMAL PRESSURE OVERPRESSURE COMPACTION DISEQUILIBRIUM CLAY DIAGENESIS AQUATHERMAL PRESSURING TECTONIC PRESSURING WEOX02.108 Figure 2.31 Response of Shale Bulk Density/Depth Plots in Overpressures caused by Various Mechanisms 2-56 March 1995 BP WELL CONTROL MANUAL • The response of shale bulk density values in abnormal pressured zones will vary with the type of mechanism that caused the overpressure. This is illustrated by the idealised plots shown in Figure 2.31. However, as most overpressures in shales are caused by compaction disequilibrium and aquathermal pressuring, the most common response will be a decrease in shale bulk density at the top of an overpressured zone. (See Chapter 1 Section 1.4 for explanations of the various causes of abnormal formation pressures.) Despite the above limitations, shale bulk density plots can be a very valuable indicator of abnormal pressures. They should be constructed during the drilling of all exploration and appraisal wells, and are most useful when long shale sections are encountered. (b) Shale Factor Shale factor is a measure of the cation exchange capacity (CEC) of shales. The CEC of a shale is dependent on the montmorillonite content. This in turn depends on the degree to which montmorillonite conversion to illite has progressed in the shale since montmorillonite has a much higher CEC than illite (See ‘Clay Diagenesis’, in Chapter1 Section 1.4). The CEC is expressed in milli equivalents per 100 grams of sample (meq/100gm), and is termed the shale factor. The shale factor of a sample of shale cuttings is determined using the methylene blue test. Basically, a suspension of powdered sample (in water) is titrated against a solution of methylene blue dye of known concentration. The end point of the titration is when the sample suspension water first turns blue. The shale factor is then calculated from: shale = 100 factor sample wt (meq/100gm) (gm) X titrant vol (ml) X titrant normality (2-23) Pure montmorillonite clays have a high shale factor of about 100 meq/100gm. This is due to the presence of many loosely bound cations (Na+ , Ca++) between the clay platelets. However, pure illite clays, due to their tightly bound cation (K+ ) between clay patelets, have low shale factors of 10 to 40 meq/100gm. Thus, shale factor can be used to identify the montmorillonite/illite content of shale samples. For abnormal pressure evaluation, however, the use of shale factor is limited as it is dependent on the various mechanisms that may cause overpressures. Generally, shale factor decreases with depth as montmorillonite is converted to illite. Inoverpressured intervals caused by compaction disequilibrium (see Chapter 1 Section1.4 ) clay dewatering has been restricted, which in turn restricts montmorillonite diagenesis to illite. Thus a larger proportion of montmorillonite will be present in the overpressured zone, resulting in an increase in shale factor. This is shown schematically in Figure 2.32(a). However, overpressures caused by clay diagenesis (montmorillonite dehydration) will show a decrease in shale factor on entering the overpressured zone. The proportion of montmorillonite has been reduced by conversion to illite, with the release of large amounts of water. This causes increased pore pressure if water escape is restricted. This shale factor response is shown schematically in Figure 2.32 (b). 2-57 March 1995 BP WELL CONTROL MANUAL Since compaction disequilibrium is thought to be the major contributing mechanism to overpressure development in shales, the shale factor response of Figure 2.32 (a) will probably be the most dominant. However, the contribution of other overpressure mechanisms will complicate the interpretation of shale factor plots. This often results in shale factor being of little use in the detection of abnormal pressures. DEPTH SHALE FACTOR DEPTH SHALE FACTOR MONTMORILLONITE CONTENT INCREASE MONTMORILLONITE CONTENT DECREASE OVER PRESSURES (a) COMPACTION DISEQUILIBRIUM OVERPRESSURES (b) CLAY DIAGENESIS WEOX02.109 Figure 2.32 Shale Factor/Depth Response to Overpressure caused by Compaction Disequilibrium and Clay Diagenesis (c) Cuttings Character The presence of cavings in drilled cuttings samples is an indication that the borehole wall is unstable. Cavings are much larger than normal drilled cuttings and are readily seen at the shale shakers. They are thought to be produced by two different mechanisms which result in cavings of different shapes and sizes, these two mechanisms are: • Underbalanced drilling • Borehole stress relief In underbalanced drilling conditions, the pore pressure in the formation adjacent to the borehole is greater than the pressure in the borehole. In impermeable formations, such as shales, the pressure differential due to an underbalance may be high enough to exceed the tensile strength of the shales. The shale will thus fail in tension and form cavings which fall into the borehole. These cavings are usually long, splintery, concave and delicate, as illustrated in Figure 2.33 (a). 2-58 March 1995 BP WELL CONTROL MANUAL The natural stresses that are present in the earth’s crust vary regionally and with depth, lithology etc. Drilling a hole through formations will relieve some of these stresses depending on the hole angle and direction in relation to the principal formation stresses. The result may be that the formation stress at the borehole wall is greater than the stress (pressure) due to the mud column. The borehole wall may then fail either in compression from vertical stresses or in tension due to horizontal stresses, or a combination of both. Cavings produced in this manner tend to be blocky and rectangular in shape, as shown in Figure 2.33 (b). Thus, the presence of cavings in cuttings samples will not necessarily mean that the hole is underbalanced. However, other overpressure indicators should always be examined in detail to confirm whether abnormal pressures are being encountered. Even if it can not be confirmed that the hole is underbalanced, it may still be necessary to increase the mud weight to regain hole stability, and avoid the problems caused by excessive amounts of cuttings/cavings being present in the hole. FRONT SIDE MAY BE STRIATED FRONT SIDE SCALE 0.5in to 1.5in TYPICALLY CRACKED DELICATE SPIKY SHAPE BLOCKY RECTANGULAR SHAPES PLAN PLAN CONCAVE SURFACE (a) Typical shale caving produced by underbalanced conditions (b) Typical shale caving produced by stress relief WEOX02.110 Figure 2.33 Characterisation of Shale Cavings Caused by Underbalanced Conditions and Stress Relief (d) Other Methods Several other methods of formation pressure evaluation based on measurements on shale cuttings have been developed. These include shale cuttings resistivity, filtration rate of shale cuttings slurry, filtrate (shale water) colour index, shale cuttings moisture index, redox and pH potential of cuttings slurry and slurry filtrate. These methods are fairly complex and time consuming and thus have not gained wide acceptance as rigsite techniques. A more detailed discussion of these techniques is given by Fertl(17). 2-59 March 1995 BP WELL CONTROL MANUAL 5 Measurement While Drilling (MWD) Techniques Measurement While Drilling (MWD) tools are now able to provide continuous downhole drilling parameter data and electric log data whilst drilling is in progress. The use of MWD data in formation pressure evaluation follows the same principles as previously discussed for surface measured drilling parameters, as outlined for wireline log data in Section 2.4 of this Chapter. The advantage of MWD data is that actual downhole drilling parameters (weight-on-bit, torque) are measured and the formation log data are obtained very shortly after the formation has been drilled. Thus, formation log data and conventional ‘whilst drilling’ techniques can be combined to evaluate formation pressures as drilling progresses. The downhole drilling parameters of most relevance are: • Weight-on-bit The actual downhole weight-on-bit (WOB) is usually less than recorded at surface due to the drag in the hole. Using the actual downhole WOB will give more accurate values for d-exponent or the drilling rate method that is being used as a formation pressure indicator. • Downhole Torque Variations in torque at the bit may be used to indicate bit wear. This in turn may be used to account for bit wear in more complex drilling rate methods for estimating formation pressures. • Downhole Temperature The difference between downhole annulus temperature and flowline temperatures will give an indication of the amount of heat transferred from the formation to the mud. A similar effect to that described in ‘Differential Temperature’ on Page 2-50, should be observed on drilling into an overpressured zone. The MWD formation logs presently available for formation pressure evaluation are gamma ray, resistivity and most recently, porosity. The gamma ray log is used to identify lithology. Shales show a high level of radioactivity, whereas sands and evaporites (except for complex salts) show a low level. Hence the gamma ray log can be used to pick clean shale sections for overpressure determination by any of the shale related parameters previously discussed. In particular, the gamma ray log can be used in conjunction with the MWD resistivity log to plot shale resistivities whilst drilling. The theory and method of formation pressure evaluation from shale resistivities is discussed further under ‘Wireline Logs’ in Section 2.4 of this Chapter. The gamma ray log itself has been used as a formation pressure indicator. A normal depth related compaction trend was established with departures from this trend indicating the magnitude of overpressures. However, it would appear that this method may only be valid for US Gulf Coast shales. More recently, an MWD porosity log has become available. Thus shale porosities may be measured whilst drilling and a normal compaction trend established. Again, overpressured shales will show an increase in porosity away from the decreasing normal trend. The MWD gamma ray log will also be required to pick clean shales, from which the porosity values can be plotted. 2-60 March 1995 BP WELL CONTROL MANUAL The combination of MWD logging techniques and downhole/surface measured drilling parameter techniques should enhance the ability to detect and evaluate formation pressures whilst drilling is in progress. Developing MWD technology is continually assessed by Drilling Division, and reports periodically issued. 6 Mud Logging Service The function of the wellsite mud logging service is twofold: • Sampling and description of drilled cuttings, and hydrocarbons detection and evaluation. • Monitoring and interpretation of drilling data for drilling optimisation and formation pressure evaluation. These functions, and their relation to information flow through a typical mud logging unit,are illustrated in Figure 2.34. The level to which the latter function is required depends on thetype of well being drilled. Usually exploration and appraisal wells require mud loggingservices capable of a higher level of formation pressure evaluation than for development wells. (a) Pressure Evaluation Service In most mud logging services, there is a Pressure Evaluation Geologist or Engineer permanently on duty in the mud logging unit. It is this individual’s responsibility to closely monitor all the available formation pressure indicators and to communicate this information to the Company supervisory personnel at the rigsite. He should also make formation pressure estimates based on all the available pressure indicators (and discussions with Company personnel), and be able to support these estimates with sound reasoning. The Pressure Evaluation Geologist/Engineer holds a very responsible position amongst the various rigsite personnel and should have many years experience in rigsite mud logging work. It is important that a good level of communication is established and maintained with the person(s) concerned in order that reliable formation pressure estimates are obtained and their implications speedily acted upon. (b) Composite Logs As part of the pressure evaluation service, the Pressure Evaluation Geologist/Engineer will prepare ‘composite logs’ showing well depth versus various selected overpressureindicators. These logs are potentially most useful as they show graphically the response of the various overpressure indicators to differing lithologies and formationpressure regimes. It is most important that these logs are kept up to date to enable up-to-the-minute pressure estimates to be made based on the information given by the logs. 2-61 March 1995 BP WELL CONTROL MANUAL Figure 2.34 Mud Logging Unit Functions and Information Flow Diagram KELLY POSITION DEPTH GAS FROM MUDSTREAM PENETRATION RATE CARBON DIOXIDE H2S PUMP RATE MICRO GAS MUD FLOW HYDROCARBONS TOTAL GAS UV BOX CHROMATOGRAPH COMPUTATION DISPLAY DATA STORAGE MUD pH/PHS REMOTE DATA DISPLAY MUD RESISTIVITY EVALUATION MUD WEIGHT FORMATION CUTTINGS MUD TEMPERATURE PIT LEVEL/PVT DENSITY GEOCHEMICAL ANALYSIS DRILLING PARAMETERS KELLY HEIGHT HOOK LOAD BIT REVOLUTIONS DRILL RATE WEIGHT ON BIT ROTARY SPEED TORQUE TOTAL DEPTH STANDPIPE PRESSURE CASING PRESSURE CEC MUD PRESS FORMATION LOG MISC ENGINEERING DATA PRESSURE LOG WIRELINE LOG DATA GEOCHEMICAL LOG BASIC ADDITIONAL REMOTE DATA TRANSMISSION WEOX02.111 2-62 March 1995 General sensor specifications are however given in Table 2. Parameter to be Measured Required Accuracy Preferred Sensor Type +/. It is not the intention of this manual to discuss the equipment used by the individual mud logging service companies. The current specifications against which the mud logging units/services should be evaluated. Once the required levels of mud logging and pressure evaluation services have been defined. and there are numerous differrent types of sensors available for measuring the various drilling parameters.01 SG 10 psi 10 psi 20 gpm 50 gpm 20 gpm 1 SPM 1°C 5 bbl 0.3 10 cm 10 cm 200 lb 1 rpm 5 amp 0. Different methods are also employed to relay the measured data to the mud logging unit.5 bbl General Mud Logging Sensor Specifications (d) Mud Logging Unit Suitability The suitability of a mud logging unit for a Company drilling operation depends essentially on the level of pressure evaluation service required.1ppm +/.These specifications cover the basic mud logging service (sampling. data storage and personnel requirements. which in turn depends on the type of well that is to be drilled. cuttings description etc). software. The basic geological sampling and mud logging service should not vary significantly with the well type. are contained in BP report DTG/D/4/86 (24). drilling data service (including pressure evaluation and drilling optimisation).BP WELL CONTROL MANUAL (c) Mud Logging Equipment The equipment contained within a modern mud logging unit is very complex.0. for trip monitoring Pressure transducer (strain gauge) Proximity switch Hall effect current sensor Gamma ray Strain gauge Strain gauge Non-intrusive flow meter Paddle type flow meter Non-intrusive flow meter Proximity switches Platinum resistance Ultrasonics Ultrasonics Mud Logging Service Total gas Hydrogen sulphide Constituent gases Drilling Data Service Depth Kelly position Hookload Rotary speed Rotary torque Mud weight Standpipe pressure Choke pressure Flow rate in Flow rate out Flow rate out Pump rate Mud temperatures Pit volumes Trip tank volume Table 2.5% Flame ionisation Solid state semi-conductor instrument Flame ionisation +/+/+/+/+/+/+/+/+/+/+/+/+/+/+/- Heave and tide compensation independent of kelly. then the suitability of individual mud logging units can be evaluated.0.1% +/.3. reporting. 2-63 March 1995 . as most of our drilling occurs in sedimentary basins containing such sections. However. then the techniques discussed are of direct relevance to our drilling operations. Occasionally. 2-64 March 1995 . Also.BP WELL CONTROL MANUAL 7 Summary The majority of the ‘whilst drilling’ formation pressure indicators discussed are only applicable to massive shale sections interbedded with sandstone/siltstones. It is stressed that all formation pressure indicators must be carefully examined to confirm the possible abnormal pressures that may be implied by a particular overpressure indicator. The most reliable abnormal pressure indicators in shales are probably d-exponent (or other drilling rate method) in combination with gas levels and cuttings character (cavings). the possibility of lithological changes should always be borne in mind when sharp changes in abnormal pressure indicators are observed. one indicator may be particularly effective in showing the onset of abnormal pressures. but this will probably not be apparent until drilling has progressed well into the overpressured zone. 44 Example of a Typical Drillstem Test String (for high pressure gas well) showing Position of Gauges 2-81 2.4 FORMATION PRESSURE EVALUATION AFTER DRILLING Paragraph Page 1 General 2-66 2 Formation Pressures from Wireline Logs 2.2 Drillstem Test Data 2-77 2-77 2-82 4 Summary 2-84 Illustrations 2.39 Empirical Correlations for Estimation of Formation Pressures from Shale Resistivity Ratio 2-74 2.1 RFT/FIT Data 3.38 Shale Resistivity/Depth Plot illustrating the Problems Associated with Formation Pressure Interpretation 2-73 2.40 Log-derived Shale Bulk Density Plot on Semi-logarithmic Scales 2-76 2.36 Schematic diagram showing Shale Sonic Interval Travel Time Response in Overpressures 2-68 2.BP WELL CONTROL MANUAL 2.41 Schematic diagram showing the RFT Pre-test and Sampling Principle 2-78 2.35 Schematic diagram showing the Operating Principle of the Sonic (BHC) Logging Tool 2-67 2.42 Diagram showing the Operation of the RFT Sample Probe 2-79 2.45 Example of a Typical Pressure Chart from a Mechanical Gauge placed below the Tester Valve in the DST String 2-83 2-65 March 1995 .3 Density Log 2.43 Example of an RFT Analogue Pressure Recording 2-79 2.2 Resistivity Log 2.4 Other Logs 2-66 2-66 2-70 2-75 2-77 3 Direct Pressure Measurements 3.1 Sonic Log 2.37 Schematic Shale Resistivity/Depth Plot showing Response in Overpressures 2-71 2. A discussion of the problems associated with the interpretation of ITT depth plots. formation pressures are directly measured in the ‘shut-in’ (pressure build-up) periods during drillstem testing (DST) of potential reservoir formations. Formation pressures calculated from wireline logs are estimates only. These are log-log plots (as suggested by Pennebaker(25)). Some of these logs can be used to estimate formation pressures to confirm (or otherwise) the estimates made whilst the hole sections were being drilled. Departures from this line towards higher shale ITT values indicates abnormal pressures.BP WELL CONTROL MANUAL 1 General After each intermediate and reservoir hole section has been drilled.2 of this Chapter. as suggested above. the formations are electrically logged to evaluate their physical characteristics and hydrocarbon potential. overpressured shales show a higher sonic ITT than normally pressured shales at the same depth. a plot of sonic ITT in shales versus depth on semi-logarithmic axes should show a straight line compaction trend in normally pressured shales.2 of this Chapter. The principle of operation of the sonic tool (borehole compensated (BHC) tool) is shown in Figure 2. The average time difference is then recorded to compensate for borehole geometry and tool tilt. ∆t. • Normal Trend Line It is sometimes very difficult to confidently establish the position of the normal shalecompaction trend line. Also. The normal compaction trend and sonic log departure in overpressures are shown in the schematic sonic log plot in Figure 2.1 Sonic Log The sonic logging tool measures the time. Thus. The main problem areas are: • Scales Two types of formats have been proposed for plotting ITT-depth data. This is known as the interval transit time (ITT) and is the reciprocal of formation interval velocity. required for a compressional sonic wave to travel through one foot (or metre) of formation. 2 Formation Pressures from Wireline Logs 2. As discussed in Section 2. The time difference between sonic arrivals at each pair of receivers is measured. Sonic pulses from two transmitters travel through the formation. is given in relation to seismic ITT data in Section 2.36. and semi-log plots. and are picked up by two pairs of receivers.35. The semi-log format is recommended as the linear depth scale enables direct comparison of sonic ITT data with other overpressure indicator plots. The depth interval over which the sonic log data are obtained in normally pressured upper hole sections is often too small to reliably establish the normal compaction trend. 2-66 March 1995 . This is because logs are normally only obtained from below surface casing. Direct formation pressure measurements are normally taken in the reservoir hole section(s) using a wireline repeat formation test (RFT) tool. Hence. may exhibit higher ITT values (higher porosity) than would be recorded if the shales were non-reactive. These higher ITT values may falsely indicate the presence of abnormal formation pressures. • The BHC sonic tool has a ‘depth of investigation’ of only a few inches into the borehole wall. the sonic log data from this deeper reading tool should be used in preference to those from the BHC sonic tool. Care should be taken to ensure that the normal compaction trend line is established through ITT values in good clean shale sections only. 2-67 March 1995 . A deeper reading ‘long spacing sonic’ (SLS) tool is sometimes run.112 Figure 2. These may then be used to determine the position and gradient of an average regional normal compaction trend line.35 Schematic diagram showing the Operating Principle of the Sonic (BHC) Logging Tool Different lithologies frequently have vastly different sonic ITTs. When available. It may be necessary to make sonic log plots from several wells (if data are available) in the area of interest. reactive shales that absorb water from the drilling mud.BP WELL CONTROL MANUAL T UPPER TRANSMITTER R1 R2 t1 PAIRED RECEIVERS R1 + R3/R2 + R4 t = t2 – t1 R3 t2 MUD CAKE R4 T LOWER TRANSMITTER WEOX02. BP WELL CONTROL MANUAL Figure 2.36 Schematic diagram showing Shale Sonic Interval Travel Time Response in Overpressures DEPTH NORMAL COMPACTION TREND LINE TOP OF OVERPRESSURES SHALE INTERVAL TRAVEL TIME.113 2-68 March 1995 . t WEOX02. These empirical correlations are area dependent. These data should be available in the form of an overburden gradient-depth plot in the Mud Logger’s report for the well.9. then the depths and magnitudes of suspected abnormal pressures may be calculated. The advantages and disadvantages of this method are discussed in Section 2. This was developed for use in conjunction with log-log seismic ITT plots and is probably only valid for the US Gulf Coast. It is necessary to obtain overburden pressure gradient data for the well being investigated in order to use the equivalent depth method. ppg or psi/ft and depths in metres or feet. 2-69 March 1995 .BP WELL CONTROL MANUAL • Unconformities/disconformities may produce a marked sudden shift in sonic ITT values and may require a second separate normal compaction trend line to be established.3 of this Chapter. the equivalent depth method may be used. in Section 2. Once the position of the normal compaction trend lines has been firmly established on the semi-log sonic ITT-depth plot. However. A full discussion of the method is given in connection with d c-exponent plots. as shown by the examples in Figure 2. The empirical correlations are quick and easy to use as formation pressure gradients are read directly from the charts. so their use is limited to areas for which correlations are available. Several methods are available for estimating the magnitude of abnormal pressures from sonic log plots: (a) Empirical Correlations Charts relating the magnitude of formation pressures to the difference between the observed shale ITT value and the extrapolated normal ITT value are available. Note that the correlation developed by Pennebaker (25) (Figure 2. the correlations are area dependent.3 of thisChapter . (b) Equivalent Depth Method When no empirical correlation is available.10) should not be used with semi-log ITT plots. Equation 2-12 is also used for formation pressure calculations from sonic ITT plots: FPGO = OPGO – DE (OPGE – FPGNE) DO where FPG O OPG O OPG E FPG NE DO DE (2-12) = formation pressure gradient at depth of interest (psi/ft) = overburden pressure gradient at depth of interest (psi/ft) = overburden pressure gradient at equivalent depth (psi/ft) = normal formation pressure gradient at equivalent depth (psi/ft) = depth of interest (ft) = equivalent depth (depth at which sonic ITT is equal to value at DO) (ft) NOTE: Equation 2-12 can be used directly with gradients in SG. 2.2 Resistivity Log The resistivity of shales depends on the following factors: • Porosity • Salinity of pore water • Temperature Temperature varies approximately linearly with depth and hence formation resistivities can be corrected for temperature. Despite the problems outlined earlier. This will lead to individual normal compaction trends being developed for each area investigated. it will be necessary to use either the equivalent depth method or the Eaton equation (or both). if a correlation is not available for the area of interest. Under normal compaction (i. Also. The use of an empirical correlation provides the quickest method of estimating the magnitude of abnormal pressures from sonic ITT plots. any departure from this normal trend towards lower shale resistivities may indicate an increase in porosity and hence overpressures. which was developed for dc-exponent plots: FPGO = OPGO – (OPGO – FPGN) ∆t N ∆t O 3. the derivation of which is exactly analogous to equation 2-18. 3.e. FPG N = normal formation pressure gradient (psi/ft) ∆t N = extrapolated normal trend sonic ITT at depth of interest (µsec/ft) ∆t O = observed sonic ITT at depth of interest (µsec/ft) The value of the ITT ratio exponent.0 (2-24) where FPGO and OPGO are as defined above and. the salinity of the pore water should not vary significantly with depth.BP WELL CONTROL MANUAL (c) Eaton Equation The following equation was presented by Eaton(12) for calculation of formation pressures from sonic ITT plots. depending on the area under investigation. it is considered that the use of sonic ITT data provides the most reliable method of formation pressure evaluation from well logs. in normal pressure environments). was derived from actual well data. shale resistivity increases with depth since porosity decreases. A plot of shale resistivity versus depth will thus show an increasing trend with depth.0. Porosity is thus the major factor controlling shale resistivity. The shape and slope of the normal trend line will vary with the age and type of shales present. Shale resistivity (Rsh) is plotted on a log scale versus depth on a linear scale. It is unlikely that any two areas will have identical normal compaction trends. The normal compaction trend line may be a curve or may approximate to a straight line over certain depth intervals. In clean shale sections. However. These latter methods require overburden pressure gradient data which should be readily available in Mud Loggers’ reports for the well(s) under investigation.37. A schematic shale resistivity-depth plot is shown in Figure 2. 2-70 March 1995 . 0 1. Rsh (ohm-m) WEOX02.8 1.0 SHALE RESISTIVITY.37 Schematic Shale Resistivity/Depth Plot showing Response in Overpressures DEPTH NORMAL COMPACTION TREND LINE CAP ROCK TOP OF OVERPRESSURE 0.BP WELL CONTROL MANUAL Figure 2.114 2-71 March 1995 .4 0.0 3.5 2.6 0. Also. shales at depths less than 1000m below surface or the mudline. there are several methods available: (a) Empirical Correlations At depths where the observed shale resistivity values (Rsh(O)) diverge from the normal trend value (Rsh(N) ). 2-72 March 1995 . Again. usually contain formation water fresher than sea water. mud filtrate invasion in permeable zones) do not affect the resistivity values recorded. a variety of resistivity logging tools are run. from which shale resistivity plots may be made. This results in high resistivity values that may indicate lower-than-actual formation pressures. • Changes in formation water salinity may give false pressure indications. it is possible to estimate the magnitude of any abnormal formation pressures indicated by the shale resistivity plot. so it will not work in oil base muds.38. The tools are designed for various depths of investigation from shallow to very deep. the ratio of normal to observed shale resistivity (Rsh(O)/R sh(N)) is calculated. Use the deepest reading resistivity curve available to plot true shale resistivities. As can be seen from this chart. The corresponding formation pressure gradient is then read from a chart such as the one shown in Figure 2. The deep reading tools record the true resistivity of virgin formation and thus near borehole effects (shale hydration. • It may be very difficult to firmly establish the shape and position of the normal compaction trend line from the resistivity plot for just one well. The problems associated with interpreting shale resistivity plots are illustrated in Figure2. The dual laterolog tool requires a conductive mud. shales in the proximity of large salt masses (e. The deep reading logs that should be used for resistivity plots are the ILd curve from the dual induction laterolog (DIL) tool and the LLd curve from the dual laterolog (DLL) tool.BP WELL CONTROL MANUAL Originally. It may be necessary to consult a geologist in order to pick good clean shales from the well logs. Possible problems that may be encountered with shale resistivity plots are: • Only shale resistivities in thick clean shales must be plotted. shale resistivities were plotted from the amplified short normal (ASN) curve of the now absolute ES (electrical survey) logging suite.39. An average regional trend may have to be established from the resistivity plots of many wells in the area of interest.g. salt domes) have very low resistivities due to increased pore water salinity. Once the normal compaction trend has been firmly established. This may indicate higher-than-actual formation pressures. The dual induction laterolog will work in oil base or water base muds and tends to be the resistivity log that is normally run. the correlations are area-dependent and the appropriate chart is required for the particular area under investigation. Today. Unconformities/disconformities and variations in geological age may show sudden changes in shale resistivities which will affect the position of the normal trend line. For example. Again.BP WELL CONTROL MANUAL Fresh water shales Normal pressure environment Region 'A' limey shales DEPTH ne o Err s tr ou Pressure top d en nd l tre rma No Abnormally high pressure environment Region 'B' Lithology.1 0. equation 2-12 is valid for use with shale resistivity plots: FPGO = OPGO – DE (OPGE – FPGNE) DO (2-12) where DE = equivalent depth (depth at which shale resistivity is equal to the value at the depth of interest.0 Rsh (ohm-m) WEOX02. OPGE. and FPGNE are as previously defined in connection with dc-exponent plots and sonic ITT plots. DO. OPG O. DO) (ft) and FPG O.0 5. As explained previously.115 Figure 2. 2-73 March 1995 .3 ) and sonic log plots (earlier this Section).5 1. change 0. overburden gradient data must be obtained (from Mud Loggers’ report) in order to use this method. not pressure.38 Shale Resistivity/Depth Plot illustrating the Problems Associated with Formation Pressure Interpretation (b) Equivalent Depth Method This method is identical to that previously discussed for dc-exponent plots (Section2. 1970 Equivalent mud weight.00 0. 1972 (Range) 2. the value of the shale resistivity ratio exponent.25 1. was derived from actual well data.5 Reservoir FPG.20 R sh(O) where FPGO. Wyo (Timko.4 0. Overburden pressure gradients for the well are also required (from Mud Loggers’ well report) in order to use equation 2-25. 2-74 March 1995 .25 0. 1972) 1.116 Figure 2.75 0.20.BP WELL CONTROL MANUAL 0. 1972) 2.7 HottmanJohnson.6 North Sea (limited data) (Timko. OPGO and FPGN are as defined for equation 2-24 (sonic log plots). SG E Riverton area.0 10 15 20 30 Normal R(sh)/observed R(sh) 40 50 WEOX02. 1.50 0. and Rsh(N) = extrapolated normal trend shale resistivity at depth of interest (ohm-m) Rsh(O) = observed shale resistivity at depth of interest (ohm-m) Again.9 Eaton. developed for dc-exponent plots): FPG O = OPGO – (OPG O – FPGN) Rsh(N) 1.8 East Cameron Timko-Fertl.39 Empirical Correlations for Estimation of Formation Pressures from Shale Resistivity Ratio (c) Eaton equation Equation 2-25 was proposed by Eaton (12) for calculating formation pressures fromshale resistivity plots (derivation analogous to equation 2-18. 1965 South China Sea (Limited data) Timko. 1972 1. psi/ft 1. F sh increasing with depth. The method is subject to inaccuracies. 2. Formation water salinity variations cause erratic tool responses which make it virtually impossible to construct a normal compaction trend. they have been found to be of limited use in the North Sea. All the pressure evaluation methods using resistivity logs were developed for the US Gulf Coast and would appear to work quite well for this region. Values of Rsh are then obtained from thick.BP WELL CONTROL MANUAL (d) Formation Factor Method This method was proposed by Foster and Whalen. Departure from the normal trend towards decreasing Fsh values then indicates abnormal pressures. R w. Other methods rely on the assumption that formation water resistivity remains relatively constant with depth. the method involves computing a formation water resistivity (Rw) depth profile from the SP (spontaneous potential) curve in clean. The method is detailed in full by Foster and Whalen(18) and Fertl(17). The skid has a plough shaped leading edge to cut through any mud cake present on the borehall wall. The gamma rays collide with electrons in the formation which cause the gamma rays to scatter. The major drawback with this method is the calculation of R w values from the SP curve.3 Density Log The formation density logging tool consists of a radioactive source which bombards the formations with medium-energy gamma rays. The magnitude of any abnormal pressures can then be calculated using the equivalent depth method (as discussed in (b) above).(18) and is based on the equation: Fsh = Rsh Rw (2-26) where F sh = shale formation factor (dimensionless) Rsh = shale resistivity (ohm-m) Rw = formation water resistivity (ohm-m) Basically. shale free water sands. However. The advantage of this method is that it takes into account changes in formation water resistivity. A plot of Fsh versus depth on semi-log scales (linear depth scale) then shows a straight line trend in normally pressured formations. The dual detectors of the FDC tool automatically compensate for mud cake effects. is difficult and is very time consuming. The degree of scattering is directly related to the electron density and therefore the bulk density of the formation. 2-75 March 1995 . Any mud cake that is not removed will effect the tool reading. the gamma ray source and two detectors are mounted on a skid that is pushed against the borehole wall by an eccentering arm. In the FDC (formation density compensated) logging tool. The scattered gamma rays that return to the borehole are picked up by detectors in the logging tool. Values of Fsh at depths corresponding to the Rsh values are then calculated from equation 2-26. clean shales from whichever resistivity log is available (ILd or LLd curve). The corrected bulk density (Pb) and the correction made (∆ρ) are recorded on the FDC log. 4 2.3 2.5 2.2 2.0 2.BP WELL CONTROL MANUAL Figure 2.117 2-76 March 1995 .7 SHALE BULK DENSITY (gm/cc) WEOX02.40 Log-derived Shale Bulk Density Plot on Semi-logarithmic Scales DEPTH NORMAL COMPACTION TREND LINE CAP ROCK TOP OF OVERPRESSURES 2.1 2. This enables a series of pressure readings to be taken and permits the Logging Engineer to ‘pre-test’. pressure measurement whilst taking a sample.41. After the normal compaction trend line has been established. 3 Direct Pressure Measurements 3. The RFT was developed from the formation interval tester (FIT) which is only able to take one. the thermal neutron decay time log (TDT). the FIT is able to take a pressure measurement/sample in cased hole by using a shaped charge to perforate the casing. or ‘probe’ the formation for permeable zones before attempting to take a fluid sample or a pressure recording. then a decrease in shale bulk density from the normal compaction trend line will indicate abnormal pressures. Since the bulk density of shales is inversely proportional to porosity. the equivalent depth method (See ‘Sonic’ and ‘Resistivity Logs’) may be used to estimate the magnitude of formation pressures.4 Other Logs Other wireline logs that have been used to evaluate formation pressures include the spontaneous potential (SP) log. 2-77 March 1995 . and also downhole gravity and nuclear magnetic resonance (NMR) logs. The densities from non-washed-out pure shale sections should be plotted. the tool can be ‘set’ any number of times. After it has been run in the hole. it has been found that unless borehole conditions are ideal (uniform gauge hole). the formation density log will not be as accurate or reliable for pressure evaluation as other techniques based on sonic or resistivity logs. the neutron porosity log (CNL). The use of shale bulk density trends from the formation density log should be a fairly reliable overpressure indicator. less accurate. and an increase in shale porosity indicates abnormal pressures. Also. 2. A schematic diagram of the RFT pre-test and sampling principle is shown in Figure 2. However. has been discussed by Zoeller(34). the use of an MWD gamma ray log for formation pressure evaluation of US Gulf Coast shales.40.BP WELL CONTROL MANUAL A plot of shale bulk density versus depth on either linear or semi-log scales will show a straight line normal compaction trend. These techniques are discussed further by Fertl(17).1 RFT/FIT Data The repeat formation tester (RFT) is an electric wireline tool designed to measure formation pressures and to obtain fluid samples from permeable formations. However. The semi-log type plot is shown schematically in Figure 2. The probe is then forced into the formation and opened by retracting the filter probe piston.43. a packer moves out on one side and back-up pistons move out on the opposite side. 2-78 March 1995 . each sampling a small volume (10cc) of the formation fluid at different rates (assuming that the formation is permeable).BP WELL CONTROL MANUAL FILTER PROBE PACKER FLOWLINE PRESSURE GAUGE EQUALIZING VALVE (TO MUD COLUMN) CHAMBER No 1 CHAMBER No 2 PRETEST CHAMBER SEAL VALVE (TO LOWER SAMPLE CHAMBER) SEAL VALVE (TO UPPER SAMPLE CHAMBER) WEOX02. An analogue pressure recording from a typical pre-test is shown in Figure 2. This forces the packer against the borehole wall and holds the body of the tool away from the wall to reduce the chances of differential sticking.42.118 Figure 2. The pressure is continuously recorded at surface in both analogue and digital form. This operation is shown in Figure 2. A strain gauge pressure transducer monitors the pressure during the pre-test. A filter in the flowline probe prevents sand entry into the tool and the piston cleans the filter when the tool is retracted. The two pre-test chambers are then operated sequentially.41 Schematic diagram showing the RFT Pre-test and Sampling Principle When the tool is set. 43 Example of an RFT Analogue Pressure Recording 2-79 March 1995 . t WEOX02. t PRESSURE.BP WELL CONTROL MANUAL MUD CAKE PACKER UNCONSOLIDATED SAND PROBE PISTON FLOWLINE FILTER PROBE CLOSED DURING INITIAL SET PROBE OPEN AND SAMPLING WEOX02.120 Figure 2.42 Diagram showing the Operation of the RFT Sample Probe FLOWRATE. P t=0 t1 t2 HYDROSTATIC PRESSURE FORMATION PRESSURE P1 P2 TIME. Q q2 SHUT-IN q1 TIME.119 Figure 2. After about 15 seconds. The pressure then drops again as the first 10cc pre-test piston starts to retract (at time tO). The two values should be within a few psi of each other. • The formation pressure. The pressure then builds up towards a final pressure. in deep high pressure wells. Thus. The formation pressure is used to verify estimates made whilst drilling the well and to construct a reservoir pressure profile. such as permeability.5 times faster than the first piston. 2-80 March 1995 . This will yield data on the pressure gradients and nature of the reservoir fluids. the RFT provides accurate data on formation pressures. When the piston stops retracting. • The pressure transient induced by the withdrawal of a small sample of formation fluid (2 x 10cc). there is a slight pressure rise because the packer continues to compress the mud cake until the tool is fully set.BP WELL CONTROL MANUAL The initial pressure (See Figure 2. The probe piston then retracts giving a drop in pressure due to the flowline volume expansion and communication with the formation. formation pressure data can only be obtained from permeable formations such as reservoir sandstones. The pressure thus drops further until the second pre-test chamber is full (at time t2 ). the probe and packer are retracted and the mud hydrostatic pressure is again measured. These formations may or may not be at the same pressure as adjacent shales. the pressure rises slightly due to the compression of the mud cake by the packer. The pressure/flowrate/time data from the pre-test sample withdrawal can be used to calculate reservoir characteristics. the RFT provides three distinct pieces of pressure data: • The mud column hydrostatic pressure (two readings). Hence. Accurate knowledge of formation pressures in such wells allows fine mud weight adjustments to be made to minimise the risk of swab/surge pressure problems. The two mud hydrostatic pressure readings are compared to verify the stability of the tool’s recording system. Finally. When the tool is set. RFTs are normally run at the request of the Geologists/Petroleum Engineers to seek information on potential reservoir formations. the RFT is being increasingly run to obtain accurate formation pressures before potentially troublesome drilling operations (such as coring) are commenced. the first pre-test chamber is full (at time t1) and the second piston begins moving at a rate 2. However.43) before the tool is set is the hydrostatic pressure of the mud column. However. which is usually that of the original formation pressure(30). 44 Example of a Typical Drillstem Test String (for a high pressure gas well) showing Position of Gauges DESCRIPTION Flowhead Tubing Lubricator Valve Tubing 5in PIPE RAMS 5in Slick Joint Tubing 5in Slick Joint MUD LINE Tubing Downhole Safety Valve (surface controlled) Tubing Annulus pressure operated Downhole Shut-in Tool (including tubing reverse-out facilities) Tubing Nipple Tubing (2 joints) Crossover Pressure Gauge Carrier + 2 Gauges Drill Collar (1 joint) Pressure Gauge Carrier + 2 Gauges Drill Collar (1 joint) Pressure Gauge Carrier + 2 Gauges No-Go Shoulder of Seal Assembly Permanent Packer Millout Extension Seal Assembly Seal Bore Extension Liner WEOX02.BP WELL CONTROL MANUAL Figure 2.121 2-81 March 1995 . A-B: The gauge is run in the hole with the test string and records increasing hydrostatic pressure. various pressure gauges are run in the hole with the test string. C: The packer is set. These are run in conjunction with clocks and recorders. permeability. squeezing the sump below the packer and causing an increase in pressure. and include: • Mechanical gauges – normally bourdon tube (BT) type pressure gauges with mechanical clocks and recorders.45 are as follows: A: Atmospheric pressure at surface. D-E: The tester valve is opened and the gauge is suddenly subjected to the reduced hydrostatic pressure of the water cushion alone. The pressures recorded during the test are used to calculate reservoir characteristics such as formation pressure.44 (for a gas well test). 2-82 March 1995 . Various types of pressure gauges are available. Data are recorded on various types of electronic memories and read from the gauge on surface after the test by a special reader. The SRO gauges are always placed above the tester valve (above the packer) as they are connected to surface equipment by a cable. skin damage and productivity index. • Electronic gauges – strain gauge.BP WELL CONTROL MANUAL 3. Note that a linear plot of the pressures recorded by an electronic gauge should have the same general form.2 Drillstem Test Data Whenever drillstem tests are carried out on potential reservoir formations. • Electronic surface read out (SRO) gauges – strain gauge or quartz crystal type pressure gauges linked by cable to the surface where downhole pressures are continuously monitored and recorded. The significant events during the test (marked by capital letters) on Figure 2. • Placed in a ‘bundle carrier ’ or ‘gauge carrier’ in various positions in the string. quartz crystal or bourdon tube type pressure gauges with electronic clocks. The purpose of these pressure gauges is to record the downhole pressure during the sequence of flow and shut-in periods that comprise the drillstem test (DST). the gauge records the hydrostatic pressure of the mud column. The mechanical and electronic gauges can be run in various ways/positions in the test string: • Set in a wireline nipple (hence retrievable during or after a test). A typical DST string is shown in Figure 2.45. This illustrates the various positions of the pressure gauges in the DSTstring. • Hung off in the tailpipe (below the packer) using a DST hanging kit. The early ‘steps’ effect is the result of pauses to pump the water cushion into the test string. A typical valid pressure chart from a mechanical gauge placed below the tester valve is shown in Figure 2. After a DST has been successfully completed. without the baseline. the test string is pulled and the pressure gauges are retrieved for the pressure charts to be read. B: At test interval depth. L-M: The packer is unset at the end of the second build up period and the pressure gauge again reads the pressure of the annulus mud column.45 Example of a Typical Pressure Chart from a Mechanical Gauge placed below the Tester Valve in the DST String E-F: The influx of reservoir fluid into the test string adds to the pressure of the partial water cushion. K-L: The reservoir pressure starts to build up again as it returns to equilibrium. F-G: The reservoir pressure slowly builds up. 2-83 March 1995 .122 Figure 2. G-H: The tester valve is now opened again and the reservoir is exposed to hydrostatic pressure of the fluids in the test string. I-J: As the reservoir fluid replaces the water cushion in the test string. After 30 minutes. no more build up is seen. H-I: The reservoir flows again and the gauge pressure increases until the water cushion reaches the surface. the gauge pressure decreases until all the water cushion has been unloaded (J). N-O: The test string is pulled out of the hole and the gauge pressures reduces. The gauge now gives an estimate of the virgin reservoir pressure (G).BP WELL CONTROL MANUAL C D B N M G PRESSURE L I E F H J K A TIME O BASE LINE WEOX02. F: The tester valve is shut after an initial 5 to 10 minute short flow period. J-K: The pressure continues to fall due to wellbore effects before steadying out as the flow into the wellbore becomes radial. K: The tester valve is closed at the end of the second flow period. O: Finally. the gauge is back on surface and reads atmospheric pressure. “BP”. 6. D. BARR. data from drillstem tests can give accurate estimates of formation pressures. BPPD Aberdeen.Ltd. with assumptions made as to the pressures in any adjacent permeable sections. 1983. 1986. the pressure data can only be obtained from permeable reservoir formations that are considered to have sufficient hydrocarbon potential to warrant the expense of a drillstem test... M. N. formation temperature.G.. Report DTG/L/1/1986.. Pet.. 3. 43(9): 76?78. 9. These methods are clearly not applicable to impermeable shale sections (where the majority of overpressures are developed). 2-84 March 1995 . 1976. and GERARD. 2. R. 4. “BP”. Massachusetts. 4 Summary The most accurate estimates of formation pressures are obtained from wireline RFT measurements and drillstem test pressure data. A Guide to Testing Operations. The recognition of a normal shale compaction trend line is of vital importance whenestimating formation pressures from log-derived shale properties. 5 1965. Resident Geologists Manual. Boston. 5. “BP”. BP Research Centre. Eng. 1976.. BINGHAM. the sonic log is usually the best log for quantitative pressure evaluation as it isrelatively unaf fected by changes in hole size.. 2nd Edition. M. 8. BOURGOYNE. June 1985. BPPD London. A Graphic Approach to Overpressure Detection While Drilling. January 1986. An Appraisal of Seismic Reflection Techniques for the Recognition and Prediction of Abnormal Formation Pressures. Sept. USA.. Conversely.T. Of the various logs available. International Human Resources Development Corporation. 1971. COCHRANE. 2 1964?Apr. the New Seismic Interpreter – Videotape Manual. and HARDMAN. ANSTEY. BP Exploration Co. However. Shallow Gas Hazards in Drilling Operations.A. these direct measurements are only possible in permeable formations such as sandstones and limestones. Report PEB/55/83. However.BP WELL CONTROL MANUAL Analysis of the pressure build up data from the shut-in periods can then give accurate estimates of the reservoir formation pressure. P. 1965. Ltd. London. Thus. London. Operations Support Division. Logging Operations Branch. A Wellsite Guide to Logging Operations.F. estimates of formation pressures from wireline logs are restricted to shalesections. and formation watersalinity . 1985.V. Sunbury. A New Approach to Interpreting Rock Drillability. Oct. BELLOTTI.E. Oil and Gas Journal. As with RFT pressure data. World Oil. the reservoir pressure calculated from DST data may or may not be the same as the pressures in adjacent shales. Nov. Section 2 References 1. BP Exploration Co. A. 1976. 7. 1985. 1985. 1986. An example of this analysis is given in the BP Guide to Testing Operations. P. Instantaneous Log Indicates Porosity and Pore Pressure. C.. R. 20: 68?86.. 1981. 2-85 March 1995 . SPEPaper5544. 21. 1972. SPE Paper2165. 17: 717-723. BP Research Centre. Field Geologist’s Training Guide. EATON. Elsevier Scientific Publishing Company. Journal of Petroleum Technology. “EXLOG”.. New York. An Engineering Interpretation of Seismic Data. 30.E. 1968.. Prentice and Records Enterprises. Sunbury. 1966. JORDEN. 1986. USA. J. DIX. 27. 24. W. 1985... 19. Technical Specification for Drilling Mud Logging Service. ROESLER. R. ReportDTG/D/4/86. 1980. R. USA.J.. “EXLOG”. 25. 1968. USA. RFT – Essentials of Pressure Test Interpretation.. 1979. Louisiana. 12... Aberdeen. Mud Logging: Principles and Interpretations. Lafayette.R. C. IADC/SPE Paper 14801. 11. Report GCB/156/85.K. 18. 1986. MINTON. SPE Paper2162. SPE/IADC Paper 16057.M.. 1975. Abnormal Pressure Technology. and PASKE. 29. R. 1966. D. C. Measurement of Formation Pressure from Drilling Data. Schlumberger Ltd. USA. and BURGESS. “EXXON”. W. J. amd WHALEN.. 1986.. LESSO. “SCHLUMBERGER”. H.. FERTL.. and JOHNSON. BPPD Aberdeen. and SHIRLEY. E. FOSTER. Inc. T. SPE Paper 3601. 1975. Exploration Logging Inc.A. G.C. The Equation of Geopressure Prediction from Well Logs. “SCHLUMBERGER”..S. W.H. Overpressure. 1955. Log Interpretation Volume 1 – Principles.H.. W. 26.C. 23. USA.. BARNETT. Pore Pressure and Porosity from MWD Measurements.. Exxon Company. 16. Abnormal Formation Pressures. Estimation of Formation Pressures from Electrical Surveys – Offshore Louisiana. “EXLOG”. Application of Drilling Performance Data to Overpressure Detection. and McCLENDON. REHM. Schlumberger Ltd. 22. W. PENNEBAKER.. “GEARHART”. 1965.. SPE Paper 1200. The Generation of Overpressures During Sedimentation and theirEf fects on the Primary Migration of Petroleum. Amsterdam. B.BP WELL CONTROL MANUAL 10. 20. Estimation of Formation Pressures from Log-derived Shale Properties..D.. Theory and Evaluation of Formation Pressures. 15.B. Geophysics. 18: 1387-1394. 1981. COMBS. 1976. 13. C. Journal of Petroleum Technology..E. MANN.F.A. 1980..M. Gearhart Geodata Services Ltd. O. 14. Formation Pressures from Normalized Penetration Rate Plots. Exploration Logging Inc. HOTTMAN.M. 1971..G. USA. 17. Seismic Velocities from Surface Measurements. Theory and Applications of an MWD Neutron Porosity Sensor.. PRENTICE. 1986. Exploration Logging Inc. 28. Prediction of Pore Pressure from Penetration Rate. A. E.J.BP WELL CONTROL MANUAL 31. 1987. SPEPaper12166. W. 1967.. Report DTG/L3. Field Verification of the Effect of Differential Pressure on Drilling Rate. W. Pore Pressure Detection from the MWD Gamma Ray. 33. 1983.A. and BENIT.. ZOELLER. SINGH. D. J. 32. 2-86 March 1995 .J.. 34. VIDRINE. SPE Paper 3066. 1970. ZOELLER. A Review of Measurement-While-Drilling Systems.. The Drilling Porosity Log “DPL”. SPE Paper 1859. BPPD London.. 2 The Effect of Flowline Elevation – shown in relation to calculation of formation pressure 3-5 Example Calculation of the Equivalent Circulating Density (ECD) 3-6 3.BP WELL CONTROL MANUAL 3 PRIMARY WELL CONTROL Paragraph Page 1 General 3-2 2 Hydrostatic Pressure 3-2 3 Equivalent Mud Weight.5 Theoretical Variation in Swab/Surge Pressure – when tripping pipe at constant speed 3-11 Pressure Surges associated with Lowering Pipe into a Borehole 3-12 3-1 March 1995 .3 3. EMW 3-2 4 Circulating Pressures and ECD 3-4 5 Calculating the Circulating Pressure Losses 3-7 6 Swab and Surge Pressures 3-10 7 Swab and Surge Calculations 3-12 Illustrations 3.1 Hydrostatic Pressure 3-3 3.4 3. • Tripping pipe. The hydrostatic pressure of the mud column acts as a result of the height of fluid between the flowline and the point of interest in the wellbore. Primary well control is exercised between two distinct limits.BP WELL CONTROL MANUAL 1 General Primary well control is maintained by controlling formation pore pressures with the hydrostatic pressure of the drilling fluid. EMW can therefore be used to describe a formation pressure as well as a pressure applied by a column of mud. The EMW must therefore be referenced to the flowline. in theory. these being the maximum formation pore pressure gradient and the minimum fracture pressure gradient in a section of openhole. by the density. and without confusion. and vertical height of the fluid above a point of interest.1 shows a sample calculation. • Circulation. be related to the density of a mud column. EMW The most convenient method of describing downhole pressure is in terms of an equivalent mud weight (EMW). Easy to use formulae are presented to predict the effects of these factors.421 Figure 3. EMW is used in order that downhole pressure can easily. The effect of the following is considered: • Flowline elevation. The density of the drilling fluid and the height of the fluid column are related to the hydrostatic pressure as follows: Hydrostatic pressure (psi) = MW (SG) X D (m) X 1. 3 Equivalent Mud Weight. 2 Hydrostatic Pressure The hydrostatic pressure of a column of drilling fluid is determined. 3-2 March 1995 . This Chapter is intended to outline the various factors that can influence the actual pressure exerted by the drilling fluid in the wellbore during routine drilling operations. 123 3-3 March 1995 .1 Hydrostatic Pressure B A VERTICAL DEPTH = 1000m MEASURED DEPTH = 1200m MUD @ 1.421 = 1.BP WELL CONTROL MANUAL Figure 3.5 x 1000 x 1.421 = 2130 psi WEOX02.5 SG The hydrostatic pressure at total depth in well A and well B = Density of the (SG) x vertical depth (m) x 1. However. the applied pressure at a given point in the well is equal to the hydrostatic pressure exerted by the head of fluid above that point. 4 Circulating Pressures and ECD When the well is static.3. when the well is being circulated. The EMW will be greater than 1. • The mud weight. (The presence of cuttings and drilled solids in the mud will have the effect of increasing the effective mud weight and changing the mud rheology. Figure 3. if the pumps are started. • The rheology of the mud. however the most fundamental factors are: • The hole depth.BP WELL CONTROL MANUAL It is important therefore that the effect of flowline elevation be considered when describing formation pressures in terms of an equivalent mud weight. depending on whether the well is offshore or on land. As shown. or the surface elevation. • The OD of the drillstring. The increase in EMW is due to the frictional pressure resulting from the flow of the mud up the annulus. the EMW at every point in the well will no longer be equal to the weight of the mud.5 SG fluid. Consider the example of a land well in Figure 3. There are many factors that can affect the ECD in a particular well.) It is clearly important to be able to estimate circulating pressure losses in order to be able to predict both the pump pressure and downhole ECD at specified circulating rates. referenced to the flowline. This is because formation pressures are originally referred to sea-level.2 shows an example of the calculation of the EMW of a normally pressured formation referenced to the flowline of a semi-submersible drilling rig. At each point in the well the EMW is increased by a factor reflecting the total frictional pressure above that point. The next paragraph details the formulae that can be used to estimate circulating pressurelosses.5 SG at every point in the wellbore. the EMW at any point in the hole.5 SG. • The quantity of cuttings in the annulus. 3-4 March 1995 . • The circulation rate. is 1. the downhole pressures are described as equivalent circulating density or ECD. Therefore if the hole is full to the flowline of 1. • The size of the hole. 95 SG WEOX02.421 x 300 = 439psi Normal pore pressure gradient = 1.421 x 325 = 0.03 x 1.2 The Effect of Flowline Elevation – shown in relation to calculation of formation pressure 1 NORMALLY PRESSURED SHOWING SAND @ 300m BELOW SEA LEVEL 2 SAND EQUIVALENT MUD WEIGHT REFERENCED TO THE FLOWLINE OF A SEMISUBMERSIBLE DRILLING RIG FLOWLINE ELEVATION SEA LEVEL 25m 100m SEA BED 200m Formation pressure at 325m BRT = 1. in EMW = 439 = 1.03 SG Formation pressure at this point referenced to the flowline.124 3-5 March 1995 .BP WELL CONTROL MANUAL Figure 3. 3 Example Calculation of the Equivalent Circulating Density (ECD) A HOLE STATIC B HOLE BEING CIRCULATED PUMP 1.421 = 1.421) + 250 = 5579psi ECD at TD = 5577 2500 x 1.5 SG Total pressure at TD = (1.5 x 2000 x 1.57 SG Hydrostatic pressure EMW = 1.5 x 2500 x 1.54 SG Pressure drop = 150psi Hydrostatic pressure EMW = 1.5 SG MUD IN THE HOLE 2000m Pressure drop = 100psi 500m Total pressure at shoe = (1.BP WELL CONTROL MANUAL Figure 3.421 = 1.5 SG WEOX02.421) + 100 = 4363psi ECD at shoe = 4363 2000 x 1.125 3-6 March 1995 . it is recommended for field use when the BP Hydraulics Programme is not available. Calculate PV and YP.47 X Q d i2 (m/min) 3. It is recognised that. the Bingham model may overestimate the friction pressure of a mud that exhibits low gel strength. Calculate the mud velocity.8 X MW µ X v X d i2 The critical Reynolds number is assumed to be 2000 for Bingham fluids. µ = 8361. If Re is greater than 2000. Power Law and Modified Power Law Models.5 X P X d i2 (centipoise) LXv 5.5 X d i2 + L X YP 68. (a) For use inside the pipe: 1.6 X d i (psi) 4. P= L X PV X v 8361. the flow is assumed to be laminar and the pressure loss is calculatedusing the formula in step 3. The cause of this discrepancy is considered to be primarily the variation in rheological characteristics of the oil mud under the influence of downhole conditions. Calculate the Reynolds number. v = 7. The following procedure can be used to approximate circulating pressure losses using the Bingham Model. Calculate the effective viscosity. Calculate the pressure loss for the pipe section. assuming laminar flow. Re = 422.BP WELL CONTROL MANUAL 5 Calculating the Circulating Pressure Losses There are various models that attempt to describe the rheology of drilling fluids. PV = Ø600 – Ø300 and YP = Ø300 – PV 2. Very large discrepancies have been recorded between predicted and actual circulating pressures when using the Modified Power Law to model the behaviour of oil base drilling fluids. The most widely used are the Bingham. at low velocity. If Re isless than 2000. as a result. The best results have been obtained using the Modified Power Law to model the behaviour of water base drilling fluids. the flow is assumed to be nonlaminar and the pressure loss must be re-calculated using the formulae in steps 6 and 7: 3-7 March 1995 . The Bingham Model is considerably easier to use than the Modified Power Law and. Calculate the pressure loss for the section of the annulus in non laminar flow. P= f X L X MW X v 2 315.47 X Q dhc 2 – d o2 (m/min) 2. P= f X L X MW X v 2 315. f = 0.32 (dhc – d o)2 60. Calculate the Fanning friction factor.25 7. (ie the velocity above which the flow will be non laminar) vc = 7. Calculate the Fanning friction factor. Calculate the pressure loss for the section of annulus assuming laminarflow .32 X P X (dhc – d o)2 LXv (centipoise) 4.079 Re 0.8 X MW X µ v X (dhc – d o) The critical Reynolds number is assumed to be 3000 for Bingham fluids. Calculate the mud velocity. the flow is assumed to be non laminar and the pressure loss must be re-calculated using the formulae in steps 5 and 6: 5. If Re is less than 3000.BP WELL CONTROL MANUAL 6.079 Re 0. If Re is greater than 3000.8 X d i (psi) 8. P= L X PV X v + L X YP 5574.25 6. Re = 422.96 (dhc – do ) (psi) 3. f= 0. Calculate the Reynolds number. µ= 5574. Calculate the critical velocity.79 MW X di X YP X 1 MW X di2 ) )2 ] (m/min) (b) For use in the annulus: 1. Calculate the pressure loss for the pipe section in non laminar flow.76 X PV + [7. Calculate the effective viscosity.76 X (PV2 + (102. the flow in this section of the annulus is assumed to be laminar and the pressure loss is calculated using the formula in step 2.8 X (dhc – d o) (psi) 3-8 March 1995 . v = 7. ∆Pbit = where v vn Q di dhc do L PV YP MW µ Ø600 Ø300 An P ∆Pbit vn2 X MW (psi) 12. Calculate the bit pressure loss.BP WELL CONTROL MANUAL 7. • The pressure drop through the bit is accurately modelled by the formula presented.23 (m/sec) 2. The annulus pressure losses may also be estimated when circulating by subtracting the calculated pressure drop in the drillstring and the bit from the actual standpipe pressure (accounting also for surface pressure losses).2) section pressure loss (psi) bit pressure loss (psi) These formulae can be used to estimate the pressure drop in each section of pipe and annulus. The ECD at the bottom of the hole can be estimated from the total annulus pressure loss. 3-9 March 1995 .46 X MW MW X (dhc – do) X 1 YP X (dhc – do)2))2 ] (m/min) (c) To calculate the pressure drop across the bit: 1.63 X (PV2 + (51.) ID of hole/casing (in. Calculate the critical velocity. (The velocity above which the flow will be non laminar) vc = 11. Calculate the nozzle velocity.63 X PV + [11. • The effect of loading the annulus with cuttings is measured directly. The standpipe circulating pressure can be estimated from the sum of the pressure losses across the bit and in all sections of the pipe and the annulus. This technique is likely to yield a more accurate estimate of the annulus pressure losses for the following reasons: • The inside measurements of the drillstring are more accurate than the openhole internal diameter. vn = Q An X 10.) OD of pipe (in.) length of section of pipe/annulus (m) plastic viscosity (centipiose) yield point (lb/100ft2) mud weight (SG) effective viscosity (centipiose) Fann viscometer reading at 600 rpm (lb/100ft2) Fann viscometer reading at 300 rpm (lb/100ft2) total nozzle area (in.49 = = = = = = = = = = = = = = = = mud velocity (m/min) nozzle velocity (m/min) pump output (gal/min) ID of pipe (in. 3-10 March 1995 . 6 Swab and Surge Pressures Swab and surge pressures are caused by the movement of pipe in and out of the wellbore. have shown that steady state models are not adequate to model the behaviour of the mud while the pipe is tripped.4 and 3. Therefore. or the pipe has stopped and the reflected pressure waves have diminished. • Inertial forces of the mud when the speed of the pipe is changed. The transient model assumes that a pressure wave is propogated at the instant that the pipe begins to move. a small error in the calculated pressure drop will cause a relatively large error in the estimate of the annulus pressure loss. • The gel strength of the mud.5. • Breaking the mud gel. • The acceleration or deceleration of the pipe. • The position of the low clearance pipe in the hole in relation to the point of interest. • The viscosity of the mud. Therefore the factors that determine the magnitude of swab and surge pressures are assumed to be: • The annular clearance. Traditionally swab and surge pressures have been calculated using a steady state model that is based on the assumption that swab and surge pressures are caused by three effects: • Viscous drag of the mud as the pipe is moved. • The length of low clearance pipe in the hole. the pressure at a point in the well oscillates. the wave then travels down the well at the speed of sound and is reflected back up the hole. On the basis of these assumptions. rather than a steady state phenomenon. It has been shown that swab and surge pressures are best modelled as a transient. Recent studies however. typical variations in wellbore pressure due to swab and surge pressures whilst tripping pipe are shown in Figures 3. As a result of this effect. • The speed of the pipe.BP WELL CONTROL MANUAL The main disadvantage of this technique stems from the fact that the majority of the pressure loss in the system is in the drillstring and across the bit. The oscillations will continue until either the pipe reaches a steady speed. BP WELL CONTROL MANUAL Figure 3.4 Theoretical Variation in Swab/Surge Pressure – when tripping pipe at constant speed 1 RUNNING IN THE HOLE 2 PULLING OUT OF THE HOLE 1 Increase due to BHA 4 Reduction due to removal of BHA from the hole MAX SURGE PRESSURE WHEN BIT IS AT POINT OF INTEREST A 3 Decrease as BHA passes point A 4 Constant stage pressure due to drillpipe in the casing SURGE PRESSURE AT A 3 Reduction due to removal of drillpipe from the hole BIT DEPTH A BIT DEPTH 2 Increase due to drillpipe MAX SWAB PRESSURE WHEN BIT IS AT POINT OF INTEREST 2 Influence of BHA 1 Constant swab pressure due to drillpipe in the casing SWAB PRESSURE AT A WEOX02.126 3-11 March 1995 . 3-12 March 1995 . The swab/surge pressures predicted by this model are subject to inaccuracy.127 Figure 3. • The temperature profile in the wellbore. • The change in rheological properties of the mud with pressure and temperature. • The elasticity of the wellbore.BP WELL CONTROL MANUAL D A Negative Surge – Pipe Lifted from Slips B Positive Pressure to Break Mud Gel C Minimum Pipe Velocity D Maximum Pipe Velocity E Negative Surge – Sudden Pipe Stoppage PRESSURE B 0 C E A TIME WEOX02. • The elasticity of the pipe. especially in deep wells when the transient response of the mud is most significant. The software used by mud logging companies currently uses a steady state model. 7 Swab and Surge Calculations The swab/surge software that is able to model the transient response of the mud to pipe movement has been developed by Sunbury.5 Pressure Surges associated with Lowering Pipe into a Borehole The latest swab/surge software models the behaviour of the mud as a transient phenomenon and also accounts for the following factors: • The compressibility of the mud. Therefore: EMW at point of interest = MW ± sumP (SG) D X 1. The following procedure should be used to calculate swab/surge pressure for either open or closed pipe: 1. 3-13 March 1995 .421 where sumP = total swab/surge pressure (psi) D = vertical depth to point of interest (m) Preston Moore’s method can be used to approximate swab/surge pressures due to the movement of a drillstring that contains a bit with nozzles. as it is generally assumed that it will predict low values of swab/surge pressures. For closed pipe: v = CL + For open pipe: v = CL + do 2 2 dhc – do 2 X do 2 – di 2 2 dhc – do 2 – di 2 vp X vp where v = velocity of the mud (m/min) CL = clinging constant vp = average running speed of the pipe (m/min) The clinging constant. X the average velocity (as 3. may be used in the field to approximate swab/surge pressures. Determine the maximum mud velocity. Estimate the velocity of the mud for a given pipe running speed. Determine the swab/surge pressures due to the pipe movement. 2. K. The maximum mud velocity is generally taken to be 1. The swab/surge pressure resulting from the pipe movement can be estimated by substituting the maximum annular mud velocity as calculated in (2) into the formulae for annular pressure loss (Bingham or Power Law).45 in the absence of detailed formula that are used to predict this quantity. as such. is assumed to equal 0.BP WELL CONTROL MANUAL The formulae used for the steady state model are relatively easy to use and. The upper limit for swab/surge pressures for a drillstring with a bit and nozzles will be represented by the value calculated for closed pipe. The range of values for the resultant swab/surge pressure that are predicted by this technique should be treated with some caution.5 calculated in (1)). The swab/surge pressure is added to the hydrostatic pressure of the mud if the pipe is being run into the hole and subtracted if the pipe is being pulled. BP WELL CONTROL MANUAL The procedure for calculating swab/surge pressures for a drillstring that contains a bit and nozzles is as follows: 1. or the sum of (2) and (3). 9. Calculate the total annular swab/surge pressure. use the formulae for internal pressure loss (Bingham or Power Law). Using the formulae: vn = Q An X 10. Use the following formulae: v(drillcollar) = v(drillpipe) X Adp Adc where Adp = cross-sectional area of drillpipe annulus (in. the velocity of the mud inside the pipe equals the velocity outside.49 (m/sec) (psi) where in this case the mud flowrate. Use the formulae as shown for the previous technique. Q. This is equal to the sum of the swab/surge pressures at the drillpipe and the collars. Calculate the swab/surge pressure generated by the drillpipe due to the pipe movement. Calculate the swab/surge pressure generated inside the drillcollar. Calculate the velocity of the mud around the drillpipe for open pipe.2) Adc = cross-sectional area of drillcollar annulus (in. Using Preston Moore’s assumption that the fluid level outside the pipe equals the level inside the pipe. Calculate the swab/surge pressure generated inside the drillpipe. Calculate the swab/surge pressure generated at the bit. Assuming that the mud velocity outside the pipe equals that inside the pipe. 7. Calculate the velocity of the mud around the collars. is equal to the mud flowrate through the collars.2 ) 4. 2. Assuming that the mud velocity outside the drillcollar equals that inside the collar.23 ∆P bit = vn2 X MW 12. 5. use the formulae for internal pressure loss (Bingham or Power Law). 6. Use the formulae for annular pressure loss (Bingham or Power Law) and v(drillcollar) as calculated in (3). The swab/surge pressure can be calculated by substituting the annular mud velocity in the formulae for annular pressure loss (Bingham or Power Law). 3. Calculate the swab/surge pressure inside the drillstring. 8. 3-14 March 1995 . Calculate the swab/surge pressure generated at the collars due to pipemovement. The resultant swab/surge pressure is added to the hydrostatic pressure of the mud if the pipe is being run into the hole and subtracted if the pipe is being pulled. It is assumed that the actual swab/surge pressure will be between the values calculated in (5) and (10). This is equal to the sum of the swab/surge pressures inside the drillstring.BP WELL CONTROL MANUAL 10.421 (SG) where sum P = total swab/surge pressure (psi) D = vertical depth to point of interest (m) 3-15/16 3-15 March 1995 . Estimate the actual swab/surge pressure due to the pipe movement. Therefore: EMW at the point of interest = MW ± D sumP X 1. Calculate the total internal swab/surge pressure due to the pipe movement. plus the bit swab/surge pressure as calculated in (9). (6) plus (8). 11. 4 A Typical Fracture Test 4-12 4-1 March 1995 .BP WELL CONTROL MANUAL 4 FRACTURE GRADIENT Paragraph Page 1 General 4-2 2 Stresses in the Earth 4-2 3 Fracture Orientation 4-3 4 Fracture Gradient Prediction 4-4 5 Daines’ Method of Fracture Gradient Prediction 4-4 6 An Example Pressure Evaluation Log 4-7 7 Leak Off Tests 4-9 8 Leak Off Test Procedure 4-10 9 Interpretation of Results 4-11 Illustrations 4.3 An Example Pressure Evaluation Log 4.1 Principal Stress Orientation 4-3 4.2 Poisson’s Ratio for Different Lithologies 4-5 4. 2 Stresses in the Earth At any point below the earth’s surface. This will lead to loss of mud from the hole and the possibility of the loss of primary control. • The intermediate stress.1 shows the effect of tectonic forces on the principal stresses. A small tectonic force ensures that the two principal stresses in the horizontal plane are no longer equal. In most cases. the horizontal stress may be greater than the vertical stress. even in a tectonically relaxed area.BP WELL CONTROL MANUAL 1 General The absolute upper limit of primary well control is the point at which the wellbore pressure equals the fracture pressure of the exposed formation. it is appropriate to explain the origins of the stresses that occur naturally below the surface of the earth. Figure 4. This is defined as the overburden pressure. This has the effect of creating an actual intermediate stress. As the well is drilled. At this point a fracture is initiated and the wellbore can no longer be considered to be a closed system. The leak off pressure is converted to an equivalent mud weight which determines the upper limit of primary control for the next hole section. Leak Off Tests are carried out to assess the mud holding capability of the openhole. be vertical and the stresses in the horizontal plane will be equal. However the test should be repeated when weaker zones are drilled into. the maximum stress will be vertical. At the well planning stage. In a tectonically relaxed area the maximum stress will. due to the pressure of the overlying rock and pore fluid. the resultant stress in the rock can be resolved into three principal stresses that act at right angles to each other. the fracture gradient can be estimated from offset well data. Before covering the techniques that are used to predict fracture gradient. Ifthis information is not available then Daines’ Method can be used to predict the fracture gradient. It is Company policy that these tests be carried out to leak off point. At shallow depths however. LO tests are generally carried out once in each openhole section after drilling out of the shoe. it is useful for the Drilling Engineer to be able to predict and measure fracture pressures. 4-2 March 1995 . It is not practical to conduct a leak off test at every change in formation and consequently it is useful to be able to predict the fracture gradient of new formations without conducting further leak off tests. • The minimum stress. In order to drill a well safely therefore. which in most cases will represent a pressure that is less than the actual fracture initiation pressure. these being: • The maximum stress. in most cases. This may be the case. Consequently induced fractures will be vertical in areas where tectonic forces are negligible.1 Principal Stress Orientation In an area where tectonic stresses are particularly high. it is possible that the maximum principal stress acts horizontally. 3 Fracture Orientation A fracture will be created if wellbore pressures exceed the minimum principal stress at any point in the openhole. in most cases. for example.BP WELL CONTROL MANUAL σ'1 = maximum principal stress σ'2 = intermediate principal stress σ'3 = minimum principal stress σ'3 σ'1 σ'1 σ'2 σ'2 σ'3 σ'3 1 – Tectonically relaxed area – σ'1 is vertical – σ'2 = σ'3 – induced fractures will be vertical σ'2 2 – under the influence of a small tectonic stress – σ'1 is vertical – σ'2 = σ3 an actual intermediate stress is created σ'1 3 – in an area that is significantly affected by tectonic stress – σ'1 is horizontal – induced fractures will be horizontal WEOX02. it is necessary for the applied pressure to lift the weight of the overburden for horizontal fractures to be formed. be greater than pressures due to tectonic forces. in a mountainous region where the formations may be severely folded.1). (See Figure 4. and horizontal if the minimum principal stress is vertical. In effect. which will be at right angles to the direction of the minimum principal stress. 4-3 March 1995 . This is unlikely to occur at depth when overburden pressure will. However horizontal fractures may be formed in areas where tectonic forces are significant. However. The fracture will propogate along the path of minimum resistance. this is unlikely to occur at great depths where the overburden pressure is generally the predominant factor. except possibly at very shallow depths.128 Figure 4. Fractures will therefore be vertical when the minimum principal stress is horizontal. The following procedure can be used after the first LO Test (assuming the maximum effective stress to be vertical and due to the overburden): 1. When such information is available. Geoservices and Gearhart. This is done using the following formula: σt = Pfrac – σ'l where σt = Pfrac = σ'1 = µ = Pf = µ – Pf l–µ tectonic stress (psi) fracture pressure (psi) maximum effective principle stress (psi) Poisson’s ratio for the rock formation pore pressure (psi) and σ'1 = S – Pf where S = overburden pressure (psi) 4-4 March 1995 . Daines’ Method can be used to predict fracture pressures in all types of formation types. The coefficients that are used to calculate the fracture pressures are specific to each lithology. but are applicable worldwide. in areas where the subsurface stress regime is relatively unknown. Eaton’s Method relies on the availability of accurate locally calculated stress coefficients to predict fracture pressures. such as in the Gulf Coast.2. by Ben Eaton whose technique is currently used by Anadrill. As a result. Calculate the magnitude of the tectonic stress. with the use of the values for Poisson’s ratio as shown in Figure 4. it is possible to predict the fracture pressure in subsequent formations with reasonable accuracy. 5 Daines’ Method of Fracture Gradient Prediction Having conducted the first LO test in a competent formation. once the first LO test has been carried out. this method has been shown to be very accurate. Hubbert and Willis were the first to derive a method. Daines’ Method is particularly useful in wildcat areas. in 1982. This technique has proved particularly accurate in wildcat wells in the North Sea. However. The magnitude of the tectonic stress is calculated at the depth of the first LO test. Eaton’s Method is most applicable to predicting fracture pressures in areas where a great deal of data relating to subsurface stress regimes is already available. it is not possible to use Eaton’s Method with any degree of accuracy.BP WELL CONTROL MANUAL 4 Fracture Gradient Prediction Many different techniques can be used to estimate fracture gradients. Eaton’s Method was refined by Daines. but they were followed. because the result of the first LO test carried out in a competent formation is used to measure the subsurface stress regime directly. amongst others. whose technique has since been used by Exlog. medium medium.31 0. very wet 0.01 Calcereous (<50% CaC03) dolomitic siliceous silty (<70% silt) sandy (<70% sand) kerogenaceous 0.24 fine.17 0.12 0. cemented fine very fine medium poorly sorted. clayey fossiliferous 0. reprint Series SPE Dallas (1963).BP WELL CONTROL MANUAL Figure 4.27 0.20 Dolomite 0.07 0.” Drilling.08 Slate 0.03 0.06 0.14 0.20 0.24 0.13 Tuff: Glass 0.21 Greywacke: coarse fine medium 0.23 0. calcarenitic porous stylolitic fossiliferous bedded fossils shaley 0.28 0.09 0.17 0.05 0.04 0.50 Clay 0.28 0.10 0.13 From Weurker H.17 coarse coarse.12 0.G: “Annotated Tables of Strength and Elastic Properties of Rocks. 4-5 March 1995 .17 Conglomerate 0.2 Poisson’s Ratio for Different Lithologies Clay.25 Limestone: Sandstone: Shale: Siltstone 0. 2. or from the bulk density values determined from the cuttings. Using Figure 4. Having calculated the above figures at the first LO test. 4.BP WELL CONTROL MANUAL The overburden pressure is determined from density logs. Calculate the tectonic stress at the point of interest. Calculate the tectonic stress coefficient.2 to determine a value for the Poisson’s ratio for the rock. The tectonic stress coefficient can be calculated as follows: β = σt / σ'1 where β = tectonic stress coefficient This value is used to predict the magnitude of the tectonic stress throughout the nexthole section until the next LO test can be used to recalculate the figure. The magnitude of the tectonic stress is calculated from the maximum principal stress and the tectonic stress coefficient as follows: σ t = σ'1 X β 5. the fracture pressure can be calculated from the following formula: Pfrac = σt + σ'l µ + Pf l–µ (psi) where P frac = fracture pressure at the point of interest (psi) This procedure can be repeated as the well is drilled in order to map the trend in fracture gradient with depth. The magnitude of the maximum principal stress is calculated from the pore pressure and the overburden pressure as follows: σ'1 = S – Pf where S = overburden pressure (psi) Pf = pore pressure (psi) The overburden pressure can be calculated from density logs. Calculate the maximum principal stress at the point of interest. if the rock strata are horizontal and the basin structure does not change significantly with depth. the fracture pressure can be calculated as drilling proceeds in the following manner: 3. Calculate the fracture pressure at the point of interest. or from bulk densities determined from the cuttings. 4-6 March 1995 . It is however generally the case that σ'1 remains directly proportional to σt throughout the well. 00) + (1. Fromthe log.93 SG An interesting case would be to estimate the fracture gradient of a sand at these conditions and at this depth.79 – 1.4 (1. the formation is mudstone. casing shoe. as shown in the following calculation using Daines’ formula: Pfrac = σt + σ'l µ + Pf l–µ (SG) at 600m BRT the fracture pressure is calculated: Pfrac = 0. casing point to the 18 5/8 in.32 SG The possible variation in fracture gradients at these depths is therefore quite significant. This is the first point at which the clays are assumed to be adequately compacted so as to predict a reasonable figure for the tectonic stress coefficient as follows: σt = Pfrac – σ'l µ – Pf l–µ (SG) 4-7 March 1995 . The tectonic stress coefficient is calculated from the result of the LO test carried out at the 18 5/8 in. Such clays possess negligible shear strength and.01 P frac = 1. As a result.01 for a typical shallow marine sand. as a result. the fracture gradient is reduced to a value that is less than the overburden gradient.BP WELL CONTROL MANUAL 6 An Example Pressure Evaluation Log Figure 4.79 – 1. The calculated fracture gradient at shallow depths should therefore be greater than the overburden. This is a typical feature of young unconsolidated clays which can behave as a liquid and as such have relatively high Poisson’s ratio of the order of 0.00) + (1. the fracture gradient is calculated as follows: Pfrac = 0.44 P frac = 1. the fracture pressure appears to be greater than overburden pressure from the seabed to approximately 1450m.4 (1.79 – 1.00) 0. but substituting a Poisson’s ratio of 0.44 + 1.0 l – 0.79 – 1. the formation may only be fractured by actually lifting the overburden. After 1450m. Using the same formula.3 (contained in wallet) shows an example Pressure Evaluation Log produced by Exlog for a well drilled in the North Sea. This means that vertical fractures may be formed at pressures lower than the overburden pressure.0 l – 0.01 + 1. casing point. From the 30 in.5. the clays have sufficiently dewatered due to compaction to support a horizontal stress.00) 0. 39 + 0. causing a reduction in the calculated fracture gradient to 1. The fracture pressure in the sand remains constant at 2. section to a calculated maximum of 2. At 3220m.39 (1. which is slightly higher than the predicted figure.53) 0.28 + 1. At 3120m.88 SG at 3100m. At 2880m.06 is used to calculate the fracture gradient in the sandstone section after 4429m.21 SG fracture gradient. A Poisson’s ratio of 0. However.24 – 1.2 – 1. the actual fracture gradient of the mudstone increases with depth and in line with the pore pressure.39 SG Therefore: Pfrac = 0.22 SG.28 Pfrac = 2.13 SG.28 is used.BP WELL CONTROL MANUAL from the result of the LO test: σt = 1. A Poisson’s ratio of 0. Therefore at 3400m. casing point. the formation changes to a sandstone interbedded with siltstone.16 SG until the formation becomes interbedded with mudstone.165 SG therefore the tectonic stress coefficient is given by: β= σt σ'1 = 0.25 = 0.95 – 1. the fracture gradient increases in line with the overburden gradient.165 = 0. This figure is therefore taken to be the minimum fracture gradient in the 8 1/2 in.205 SG at 4429m.8 – (1. the formation changes to limestone.06 SG.99 = 0.2 = 0. the fracture gradient is calculated as follows using Daines’ formula: Pfrac = σt + σ'l µ + Pf l–µ (SG) where σ'1 = S – Pp = 2. 4-8 March 1995 . From the 18 5/8 in. the pore pressure gradient begins to decrease. the calculated fracture pressure increases to 2. Mud was lost to the sandstone stringers at the base of the limestone (4200m) at an ECD of 2.99 SG σ t = 0. The underlying mudstone has a calculated fracture gradient of 2.22 SG. The LO test at this point confirms a 2.53 l – 0. for which a Poisson’s ratio of 0.99 0.06 is chosen for these loose fine grained sands which results in a reduction in the calculated value of the fracture gradient to approximately 1. The fracture pressure then increases with depth and pore pressure throughout the 12 1/4 in.23 SG at the 9 5/8 in.95 – 1. shoe shows a fracture gradient of 2.25 l – 0. at which point.53) and this value of – is used to calculate the tectonic stress in subsequent rock strata. to 2. hole. shoe to 2880m.72 SG.39 – 0.03 SG The LO test at the 13 3/8 in. these additional stresses are released and consequently the pressure required to reopen the fracture may be less than that originally required.” The following guidelines are offered: “Leak off tests should be performed after drilling 3 to 5m of new hole below any casingshoe. • To test the effectiveness of a cement job.’’ Company policy is therefore to restrict applied pressures to a maximum represented by the LO point. there may be no clear leak off before a fracture occurs. however. Company policy is that: “Leak off tests or competency tests will be performed prior to drilling each new hole section (except for conductors). it is not certain that an induced fracture will heal completely to withstand the pressure that originally caused it to fracture. When drilling through sands. the ability of the hole to contain a kick. however. • (On a development well) where the pressure may be limited to that required to drill safely the next section of hole (competency test). If a fracture is created. at any point below the casing shoe. A brittle formation may be permanently weakened by an induced fracture and consequently it is not recommended to conduct LO tests in such formations. and thus. Field evidence. such as limestone. Leak off tests should not be conducted in brittle formations (eg fractured limestone). consideration should be given to carrying out a further LO test to ascertain the new rock strength. As a result. in many cases. Leak off tests should be taken to leak off unless: • The pressure exceeds that to which the casing was tested. or permeable rock. The reason for this is that. that particularly brittle rocks. It is accepted. will show very little inelastic behaviour prior to fracture. suggests that in most cases induced fractures will heal completely. However it is difficult to predict the circumstances in which fractures will not heal completely and hence permanently weaken the formation. It has been suggested that the drilling process locks additional stresses into the rock around the wellbore. thereby increasing the pressure required to cause a fracture. 4-9 March 1995 .BP WELL CONTROL MANUAL 7 Leak Off Tests The purposes of carrying out a leak off test are: • To establish the upper limit of primary control for a section of openhole. The mud logging company will provide an estimate of the fracture pressure at current depth. An estimate of the volume of fluid required to pressurise the hole can be determined from the bulk modulus of elasticity of the fluid that is in the hole. BP H3HF Base Oil = 160. 2.BP WELL CONTROL MANUAL 8 Leak Off Test Procedure The following general procedure is recommended for conducting LO tests: 1. 4. Pull up into the casing. NOTE: This may be lower than 2. or to interpret any anomalies observed during the test. Ensure that suitable pressure gauges are available. Drill out of the shoe and 3 to 5 m of new hole. Line up the pump to the annulus and displace all lines to the well to mud. Plot a graph of pressure versus mud pumped to establish linearity prior to the LO test. The following figures can beused: K.000 – 335. 7.31 SG or 1 psi/ft. Test the casing prior to drilling out of the shoe. as is common in deep water offshore. It may not be necessary to conduct a leak off test in a development well when pore and fracture pressures are well defined. Assess the upper limit for the test. in which case. 6. 4-10 March 1995 . This figure may be used as an upper limit for the test.000 psi K. 5. Determine the estimated fracture pressure.000 – 260. The gauges should be of a suitable range and have been recently calibrated with a Dead Weight Tester. water = 290. Close the BOP. a limit test will suffice. 8. Circulate and condition the mud. 9. The absolute upper limit for all types of test will be the overburden gradient at current depth. ∆V = ∆P X V K when ∆V V ∆P K = = = = volume required to pressurise hole (bbl) volume to be pressurised (bbl) required increase in pressure (psi) bulk modulus of elasticity (psi) The bulk modulus of elasticity of a drilling fluid is determined by the characteristics ofthe base fluid as well as the solids content of the fluid. 3.000 psi The bulk modulus of actual drilling fluids will be greater than these figures by an amount related to solids content. the fracture would propogate into the formation at a pressure slightly lower than point 4. the pressure in the wellbore at the exposed formation is equal to the sum of the pore pressure and the minimum horizontal effective stress. and accurately record the volume of mud pumped. any cracks that exist at the wellbore and in the vertical plane will be in a state of equilibrium. the applied pressure exactly counteracting the naturally occurring compressive forces. the formation is deforming plastically. From points 2 to 4. NOTE: It is Company policy that the test is stopped at leak off point. 9 Interpretation of Results Figure 4. Record the final pump pressure and calculate LO EMW. in that for the same increment of applied stress (pressure). At point 3. From points 1 to 2. In other words.BP WELL CONTROL MANUAL 10. 11. as is shown on the diagram. the pump would normally be stopped and the pressure bled down in line with Company policy. a greater level of strain (volume) is produced. which represents the leak off point (because it is the first noted deviation from the linear relationship).5 bbl/min. The difference between the pressure at point 2 and the pressure at point 4 represents the pressure required to initiate the fracture. At point 2. If the pump was stopped at point 4. Bleed back mud from the well and compare with the volume pumped. If the pump was kept running after point 4. if it is significantly less.3 to 0. Stop the pump when any deviation from linearity is noticed between pump pressure and volume pumped. 4-11 March 1995 . 12. Monitor the pressure build up. If the pump was left running. the returned volume should be equal to the volume pumped into the hole. the exposed rock is deforming elastically as the relationship between pressure and volume pumped is linear. the fracture would not propogate further into the formation and the pressure will drop to point 5. Run the pump at a constant 0. If the pressure is then bled down. the pressure would eventually build to fracture pressure as shown. Plot pressure versus volume of mud pumped. then the fracture may be still be open. The pressure at point 5 should be equal to the pressure at point 2.4 shows the result of a typical fracture test carried out in a consolidated low permeability formation in a tectonically relaxed area. or the fracture propogation pressure. 130 Figure 4. psi 2 LEAK OFF PRESSURE (the pump would normally be stopped at this point) PRESSURE BLED DOWN 1 1 1 2 bbl PUMPED 2 3 4 TIME. MINUTES 3 WEOX02.4 A Typical Fracture Test 4-12 March 1995 .BP WELL CONTROL MANUAL FRACTURE PRESSURE (pump stopped) 4 5 3 GAUGE PRESSURE. 3 Shoe Pressure – during the first circulation of the Driller’s Method 5-6 5.8 5.1 Choke and Standpipe Pressure – during the first circulation of the Driller’s Method 5-5 5.7 Choke Pressure – during the Driller’s Method for various influx volumes 5-9 Choke Pressure – during the Wait and Weight Method for various influx volumes 5-9 Shoe Pressure – during the Driller’s Method for various influx volumes 5-11 5.BP WELL CONTROL MANUAL 5 BASICS OF WELL CONTROL Paragraph Page 1 General 5-3 2 Displacing a Kick from the Hole 5-3 3 Factors that Affect Wellbore Pressures 5-8 4 Subsea Considerations 5-19 5 Safety Factors 5-24 6 Calculating Annulus Pressure Profiles 5-27 Illustrations 5.2 Pit Gain – during the first circulation of the Driller’s Method 5-5 5.4 Choke and Standpipe Pressure – during the second circulation of the Driller’s Method 5-6 Choke and Standpipe Pressure – during the Wait and Weight Method 5-7 5.6 Shoe Pressure – during the Wait and Weight Method 5-8 5.5 5.11 Choke Pressure – during the Wait and Weight Method and the Driller’s Method for two different influx volumes 5-12 5.10 Shoe Pressure – during the Wait and Weight Method for various influx volumes 5-11 5.9 5.12 Choke Pressure – during displacement of a gas kick using the Driller’s Method for various kick intensities 5-12 5.13 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities 5-13 5-1 March 1995 . 28 Choke Pressure – during displacement of a gas kick with overbalanced mud 5-26 5.18 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2500m 5-16 5.30 Annulus Pressure Worksheet 5-31 5.20 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1500m 5-17 5.24 Choke Pressure for various Water Depths – during displacement of a gas kick 5-21 5.27 Annulus Pressure Loss for various Well Configurations 5-25 5.29 Shoe Pressure – during displacement of a gas kick with overbalanced mud 5-26 5.23 Comparison of Choke Pressures – during displacement of a gas kick on a fixed rig and a floating rig 5-20 5.14 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities 5-13 5.31 Graph of Pseudo-critical Temperature and Pressure for Hydrocarbons 5-33 5.16 A Comparison of Shoe Pressures – during displacement of a 20 barrel gas kick for various shoe depths 5-15 5.22 Choke Pressure – during displacement of a water kick using the Wait and Weight Method 5-19 5.32 Compressibility Factors for Natural Gas 5-34 5-2 March 1995 .21 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1000m 5-17 5.19 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2000m 5-16 5. ID) 5-24 5.17 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 3000m 5-15 5.25 Determination of the Required Rate of Choke Manipulation for a Deep Water Subsea Well 5-22 5.BP WELL CONTROL MANUAL 5.15 A Comparison of the Shoe Pressure – during displacement using the Driller’s and Wait and Weight Method for two gas kicks of different intensities 5-14 5.26 Estimated Choke Line Losses (psi) for Various Choke Line Lengths (3in. Both these methods ensure that the bottomhole pressure is maintained constant and equal to. The procedures used to implement these techniques on either a floating or a fixed rig are detailed in Volume 1. Once the well has been shut-in. the well can be killed using either the Wait and Weight Method or the Driller’s Method. it is important to understand the surface and downhole pressures that are caused by displacing a kick from the hole using either the Driller’s Method or the Wait and Weight Method. and to explain the most important factors that affect the magnitude of these pressures. 5-3 March 1995 . Once the drillpipe has been displaced to kill weight mud. the circulating pressure is held constant. the kick zone pressure. The Wait and Weight is the preferred method. During the second circulation. The original mud weight is used to displace the kick from the hole and then the mud is weighted to kill weight for the second circulation. The pressure at each point in the annulus will vary significantly as the kick is displaced from the hole. In order to fully understand the implementation of these methods. The pressure plots contained in this chapter are generated on the basis that the bottomhole pressure is constant and exactly equal to the kick zone pressure. however the plots can demonstrate the influence of the major factors that affect the wellbore pressures during circulation. and secondly for the reduction in underbalance as the drillpipe is displaced. the drillpipe circulating pressure is adjusted to account firstly for the increased circulating pressure due to the heavy mud. During the first circulation. The actual pressures seen when a kick is taken may be different from those predicted by the programme. This chapter is intended to cover the variations in surface and subsurface pressures during these methods. 2 Displacing a Kick from the Hole (a) Driller’s Method The Driller’s Method requires that two complete hole circulations are carried out before the well is killed. All the pressure plots shown in this chapter are developed by computer programme.BP WELL CONTROL MANUAL 1 General When a kick is taken with the pipe on bottom. the major factors that determine the pressure at any point in the annulus during displacement of the kick are the height of the influx in the annulus and the relative position of the influx in the annulus. the drillpipe circulating pressure is held constant at a value equal to the shut-in drillpipe pressure plus the circulating pressure loss in the system at the slow circulating rate. or slightly greater than. The pressures are determined by simulating the displacement of a gas kick from a well with the model of a discrete bubble of gas. 3 shows the pressure at the casing shoe as the kick is displaced from the hole. Once the influx has been circulated past the shoe. the choke size will have to be increased so that the correct final circulating pressure is maintained.BP WELL CONTROL MANUAL Figure 5. or the volume of the kick. From point D to point E. In practice. the maximum shoe pressure might have been when the influx was circulated to the shoe. At point D. the top of the influx has arrived at the casing shoe and from point R to point S the influx is circulated past the casing shoe. the choke pressure required to maintain the final circulating pressure will be zero. From point A to point B. the choke will be wide open at this point and it may not be possible to keep the standpipe pressure down to the final circulating pressure. From point Q to point R. the standpipe pressure must be reduced as the drillpipe is displaced to kill weight mud. if the shoe was shallower. the gas arrives at the choke. At point R. the shoe pressure was at maximum when the well was shut-in. the pressure at the shoe will remain constant as the influx is circulated to the choke. the gas is passing the choke. In other words. Figure 5. Figure 5. At point C. very little choke manipulation will be required at this stage because the standpipe pressure will drop automatically as the kill weight mud is pumped down the drillpipe. the gas has expanded to occupy its original height in the annulus when opposite the BHA. as long as the choke is correctly manipulated. the choke operator will have to close in on the choke to ensure that the choke pressure does not drop significantly as the low density gas passes across the choke. From point P to point Q. the pressure drops as the influx is displaced past the BHA.3 that. Point A represents the shut-in casing pressure. From point B to point D. the choke operator will have to open the choke to reduce the choke pressure to maintain the correct standpipe pressure. The choke operator will open the choke to maintain the appropriate standpipe pressure. the influx did not expand to its original height in the annulus before it arrived at the choke.2 shows the pit gain. In practice therefore. the casing pressure drops as the influx is displaced past the BHA.1 shows the choke pressure during the displacement of a kick with the Driller’s Method for a surface BOP. the gas has been displaced from the well and the choke pressure will stabilise at a value determined by the degree of underbalance.4 shows the standpipe and choke pressure during the second circulation during which the well is circulated to kill weight mud. Figure 5. However. The choke pressure required to balance the kick zone pressure reduces as the gas passes the choke because the column of gas in the annulus is continually decreasing in height. This drop is caused by a reduction in height of the influx as the influx is displaced from the BHA annulus to the drillpipe annulus. Having established the initial circulating pressure. 5-4 March 1995 . the influx is expanding as it is circulated up the hole and hence the choke pressure required to balance the kick zone pressure is increasing. the pressure increases as the influx expands as it is circulated up to the casing shoe. The choke operator will therefore close in on the choke to maintain the correct standpipe pressure. Once the kill weight mud starts up the annulus. Once the hole has been displaced to kill weight mud. At point E. It can be seen from Figure 5. as it is displaced to the choke. in this case. 132 Figure 5.7SG 1.7SG 1.2 Pit Gain – during the first circulation of the Driller’s Method 5-5 March 1995 .131 Figure 5.1 Choke and Standpipe Pressure – during the first circulation of the Driller’s Method WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 2000 1800 SURFACE PRESSURE (psi) 1600 D 1400 1200 STANDPIPE PRESSURE A 1000 B SCR1 800 C E 600 CHOKE PRESSURE 400 P DRILLPIPE 200 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.83SG 0 200 BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 100 90 PIT GAIN (bbl) 80 70 60 50 40 30 20 10 0 400 600 VOL MUD PUMPED (bbl) 800 WEOX02. 7SG 1.4 Choke and Standpipe Pressure – during the second circulation of the Driller’s Method 5-6 March 1995 WEOX02.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.3 Shoe Pressure – during the first circulation of the Driller’s Method WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.133 Figure 5.83SG 6 1/4in/180m 5in DP DRILLER'S BHA: PIPE: TECH: 2000 1800 SURFACE PRESSURE (psi) 1600 1400 1200 1000 SCR1 800 600 STANDPIPE PRESSURE 400 P DRILLPIPE CHOKE PRESSURE SCR2 200 0 0 DRILLPIPE VOLUME 200 400 ANNULUS VOLUME 600 800 VOL MUD PUMPED (bbl) Figure 5.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 6000 P 5800 R Q 5600 S 5400 5200 5000 4800 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.134 .7SG 1. the kill weight mud arrives at the choke. the kick is displaced from the hole with kill weight mud. As can be seen. at point E. Between point T and point U. the choke pressure during both techniques is the same until the kill weight mud starts up the annulus at point B. Between point P and point Q.5 shows the choke and standpipe pressure during displacement of the influx with kill weight mud. Figure 5. 5-7 March 1995 . when the kill weight mud arrives at the shoe. the pressure at the shoe decreases. Between points D and E.5 Choke and Standpipe Pressure – during the Wait and Weight Method Figure 5. At point S. The influx expands as it is circulated to the shoe at point R.135 Figure 5.) From this point onwards. and secondly that the well is under pressure for a significantly shorter period. The pressure at point U is equal to the kick zone equivalent mud weight. The choke pressure during the Driller’s Method is included for comparison. and thus represents the minimum pressure that the shoe will see once the well has been killed.BP WELL CONTROL MANUAL (b) Wait and Weight Method During the Wait and Weight Method.6 illustrates the pressure at the casing shoe for both the Wait and Weight Method and in comparison with the Driller’s Method. the kill weight mud starts up the annulus and hence reduces the choke pressure below that for the Driller’s Method. the volume of original mud behind the influx is displaced from the well until. the pressure at every point in the annulus will be lower than if the Driller’s Method had been used. the shoe pressure decreases as the influx is displaced past the BHA.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20bbl GAS 2000 1800 SURFACE PRESSURE (psi) 1600 1400 C 1200 A 1000 SCR1 800 B CHOKE PRESSURE (DRILLER'S METHOD) 600 400 P DRILLPIPE D SCR2 200 0 0 DRILLPIPE VOLUME 200 400 STANDPIPE PRESSURE (W + W METHOD) CHOKE PRESSURE (W + W METHOD) E 600 800 VOL MUD PUMPED (bbl) WEOX02.7SG 1. (This is because the bottomhole pressure is kept equal and constant for both methods. the original weight mud is displaced past the shoe until point U. The most significant advantages of the Wait and Weight Method in relation to the Driller’s Method are: firstly that wellbore pressures during displacement of the kick are generally lower than for the Driller’s Method. after which. WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1. Figures 5. 5-8 March 1995 .136 Figure 5. the wellbore pressures will be lower the smaller the influx volume. however. Figure 5. the maximum shoe pressure is unaffected by the technique used to kill the well. The greater the volume of influx.7 and 5. the shoe will be under pressure significantly longer if the Driller’s Method is used.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 6000 P 5800 R S Q 5600 DRILLER'S METHOD 5400 T 5200 WAIT AND WEIGHT METHOD U 5000 4800 0 DRILLPIPE VOLUME 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.8 shows the choke pressure as the same influx volumes are displaced from the well using the Wait and Weight Method.8 quite clearly show that.7SG 1. WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7 shows the choke pressure as various influx volumes are displaced from the well using the Driller’s Method. the greater will be the wellbore pressures during circulation.6 Shoe Pressure – during the Wait and Weight Method 3 Factors that Affect Wellbore Pressures (a) Influx Size The most fundamental factor that affects the wellbore pressures during circulation.BP WELL CONTROL MANUAL In this case therefore. regardless of the technique used to kill the well. is the volume of the influx. Figure 5. 30.7 Choke Pressure – during the Driller’s Method for various influx volumes WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20. 30.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20. 40.137 Figure 5. 50bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 50bbl 40bbl 1200 30bbl 1000 20bbl 800 600 400 200 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.8 Choke Pressure – during the Wait and Weight Method for various influx volumes 5-9 March 1995 .138 Figure 5. 40. 50bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 50bbl 40bbl 1200 30bbl 1000 20bbl 800 600 400 200 0 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.7SG 1. 13 shows the displacement of the same kicks. The maximum shoe pressure is not necessarily affected by the technique used to displace the kick (in most cases the maximum shoe pressure will be at initial shut-in and as such is not dependent on the technique used to kill the well). However in a long openhole section it is possible that the maximum shoe pressure may occur as the influx is displaced to the shoe. Close attention to the indicators of increasing pore pressure will ensure that kicks of high intensity are avoided. it is therefore particularly important that shut-in procedures are implemented as quickly as possible. Figure 5. the Wait and Weight Method does not reduce the maximum pressure that the shoe experiences during displacement. using the Wait and Weight Method. Figure 5. (b) Kick Intensity The intensity of a kick is a measure of the degree of underbalance recorded after the kick has been shut-in. Figure 5. given that kill weight mud will start up the annulus before the kick arrives at the choke. In this instance. Figure 5.9 shows the shoe pressures as various influx volumes are displaced from the well using the Driller’s Method.14 shows a comparison of the two techniques for a low intensity kick.15 shows a comparison of the shoe pressures during displacement of the same two kicks. Influx volume is therefore a variable that has significant influence on wellbore pressure during the displacement of a kick. if kill weight mud is to have an effect on the maximum pressure at the shoe. It can therefore be seen that the Wait and Weight Method is more effective in reducing choke pressures for kicks of relatively high intensity. but in the case of the high intensity kick. the hole configuration must be such that the kill weight mud starts up the annulus before the kick is displaced past the shoe. Figure 5. In this case. the shoe pressure is significantly reduced once the kill weight mud starts up the annulus.12 shows the choke pressure during the displacement of a range of high and low intensity kicks by the Driller’s Method. However.10 shows the shoe pressures as the same influx volumes are displaced using the Wait and Weight Method. Figure 5. This can be determined from the drillpipe pressure. (c) Hole Configuration The maximum surface pressure during displacement of a kick will always be lower if the Wait and Weight Method is used.14 shows clearly that it is especially important to use the Wait and Weight Method for kicks of relatively high intensity. Figure 5.BP WELL CONTROL MANUAL Figure 5. even if there is some doubt as to whether the well is flowing. The intensity of the kick will be a major factor in determining the wellbore pressures during displacement of the kick. 5-10 March 1995 .11 shows a comparison of choke pressure during the Wait and Weight Method against the Driller’s Method for influx volumes of 20 bbl and 50 bbl. it is the only variable that the rig crew have some control over for a given kick situation. as well as a high intensity kick. 40.7SG 1. 50bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 50bbl 40bbl 6000 30bbl 5800 20bbl 5600 5400 5200 5000 4800 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02. 30.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1. 30.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20.10 Shoe Pressure – during the Wait and Weight Method for various influx volumes 5-11 March 1995 . 40.139 Figure 5.7SG 1.9 Shoe Pressure – during the Driller’s Method for various influx volumes WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.140 Figure 5. 50bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 50bbl 40bbl 6000 30bbl 5800 20bbl 5600 5400 5200 5000 4800 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02. 83SG 600 1.7SG 1. 50bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 50bbl 1200 1000 20bbl 800 DRILLER'S METHOD 600 400 WAIT AND WEIGHT METHOD 200 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.91SG 1000 1.87.142 Figure 5.11 Choke Pressure – during the Wait and Weight Method and the Driller’s Method for two different influx volumes WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.79.75.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.87SG 800 1.141 Figure 5.12 Choke Pressure – during displacement of a gas kick using the Driller’s Method for various kick intensities 5-12 March 1995 .79SG 400 1. 1.83. 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20. 1. 1.91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 1200 1.75SG 200 0 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02. 7SG 1.83SG 800 1.13 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1. 1.143 Figure 5.75SG 400 200 0 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.91SG 1400 1200 1000 800 600 DRILLER'S METHOD 1.87SG 1000 1.14 Choke Pressure – during displacement of a gas kick using the Wait and Weight Method for various kick intensities 5-13 March 1995 .91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP W+W 20bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1400 1.75SG 400 200 WAIT AND WEIGHT METHOD 0 0 200 400 600 VOL MUD PUMPED (bbl) 800 WEOX02.83.87.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.144 Figure 5. 1. 1.75. 1.79SG 600 1.79.91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 2000 1800 CHOKE PRESSURE (psi) 1600 1.75. 1.9SG 1200 1.7SG 1. 75SG 5400 DRILLER'S METHOD 5200 5000 WAIT AND WEIGHT METHOD 4800 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02. the maximum pressure at the shoe is clearly at initial shut-in.16 shows the pressure variations at 1000m. the more marked the difference between wellbore pressures during the Wait and Weight Method and the Driller’s Method.91SG DRILLER'S METHOD 6000 5800 5600 WAIT AND WEIGHT METHOD 1. However.15 A Comparison of the Shoe Pressure – during displacement using the Driller’s and Wait and Weight Method for two gas kicks of different intensities Once the kill weight mud starts up the annulus.145 Figure 5. As can be seen from Figure 5.16. for various lengths of openhole. shoe pressures will be lower than if the Driller’s Method is used. if the shoe was at 1000m. using both the Driller’s and the Wait and Weight Methods.75. 2000m and 3000m. A 20 barrel kick is taken at 3500m and is then displaced from the hole. However.7SG 1. 1. Figures 5. the higher the kick intensity.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1. if the shoe had been at 3000m. This situation is brought about when the influx expands to occupy a greater height in the annulus than it did at initial shut-in before it is displaced to the shoe. Figure 5. Figure 5. for a given kick intensity the significance of the difference between the two techniques is also influenced by the depth of the shoe. the shoe pressure is actually greater than at initial shut-in when the influx is displaced to the shoe. The shallower the shoe.17 to 5. 5-14 March 1995 . This generally requires a considerable length of openhole.21 compare the shoe pressures during displacement of a gas kick for a range of shoe depths. As discussed in (b). the more significant is the effect of the kill weight mud on pressure reduction at the shoe.16 shows a comparison of the shoe pressures for the same kick. The hole configuration therefore can influence the pressures seen at the shoe during displacement.91SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 6600 6400 SHOE PRESSURE (psi) 6200 1. 17 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 3000m 5-15 March 1995 .147 Figure 5.16 A Comparison of Shoe Pressures – during displacement of a 20 barrel gas kick for various shoe depths WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 3000m 1.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: 3500m 1000m. 2000m.146 Figure 5.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP DRILLER'S 20bbl GAS +100 CHANGE IN SHOE PRESSURE (psi) INITIAL (SHUT IN PRESSURE) 0 -100 SHOE AT 3000m -200 SHOE AT 2000m SHOE AT 1000m -300 -400 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.7SG KICK ZONE EMW: 1.7SG 1. 3000m MW1: 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 8300 SHOE PRESSURE (psi) 8200 Q P 8100 8000 R 7900 DRILLER'S METHOD S WAIT AND WEIGHT METHOD 7800 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02. 149 Figure 5.7SG 1.7SG 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 7100 SHOE PRESSURE (psi) 7000 6900 6800 DRILLER'S METHOD 6700 6600 WAIT AND WEIGHT METHOD 6500 6400 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 5900 SHOE PRESSURE (psi) 5800 5700 5600 DRILLER'S METHOD 5500 R 5400 5300 WAIT AND WEIGHT METHOD 5200 5100 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.148 Figure 5.18 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2500m WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2500m 1.19 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 2000m 5-16 March 1995 . 83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 3500 3400 P SHOE PRESSURE (psi) 3300 3200 DRILLER'S METHOD 3100 3000 2900 2800 WAIT AND WEIGHT METHOD 2700 2600 2500 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 1500m 1.21 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1000m 5-17 March 1995 .7SG 1.150 Figure 5.7SG 1.20 A Comparison of Shoe Pressures – during displacement of a gas kick shoe at 1500m WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 1000m 1.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP BOTH 20bbl GAS 4700 4600 P SHOE PRESSURE (psi) 4500 4400 DRILLER'S METHOD 4300 4200 4100 4000 WAIT AND WEIGHT METHOD 3900 3800 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.151 Figure 5. 19 shows the shoe pressure profile for the shoe at 2000m. the shoe pressure almost reaches its original shut-in value.17 shows the shoe pressure for a 20 barrel kick taken at 3500m for the shoe at 3000m. Figures 5. A similar pressure profile is shown to that in Figure 5.1 to 5. (d) Influx Type All the pressure profiles in Figures 5.21 shows the shoe pressure profile for the shoe at 1000m. however in this case the influx expands more before it arrives at the shoe due to the greater length of openhole. In the case of the Driller’s Method. the top of the influx arrives at the shoe and from point Q to point R the pressure at the shoe drops as the influx is displaced past it. The shoe pressure is reduced by the kill weight mud from this point on. unless the water contains a significant quantity of gas. As can be seen from the pressure profile. in the case of the Wait and Weight Method. the kill weight mud starts up the annulus. before the influx arrives at the shoe. Water is essentially incompressible andconsequently will not expand appreciably as it is displaced up the well. The reduction in shoe pressure due to the kill weight mud is most significant when there is a long section of openhole (as is seen in Figures 5. At point Q. However a water kick may cause special problems as a result of hole deterioration as it is displaced from the hole. This will mean that the wellbore pressures will not be significantly affected by the displacement of the influx. Figure 5. In the case of the Wait and Weight Method however. In this case.21).17. in the case of the Wait and Weight Method. from point P to point Q the pressure increases as the influx expands as it is displaced up towards the shoe. the pressure decreases as the influx is displaced past the BHA. Figure 5. Figure 5. the shoe pressure now increases past the shut-in value as the influx is circulated to the shoe. the kill weight mud starts up the annulus at point P. the kill weight mud starts up the annulus at point P.20 shows the shoe pressure profile for the shoe at 1500m. However. even when the shoe is relatively shallow.17 to 5. In the case of the Driller’s Method. Figure 5. From point R to point S. the kill weight mud starts up the annulus at point R.21 show that the Wait and Weight Method has only a small influence on the maximum shoe pressure for wells of this type.BP WELL CONTROL MANUAL Figure 5. and this has the effect of reducing the maximum pressure that the shoe experiences. when the tail of the influx is passing the shoe. the pressure at the shoe is further reduced at point S when.21 represent the displacement of gas kicks. 5-18 March 1995 . However.17 to 5. the expansion of the gas as it is displaced from the well significantly affects the resultant wellbore pressures. the pressure at the shoe remains constant as the original mud occupies the annulus from the bottom of the hole to the shoe.18 shows the shoe pressure for the shoe at 2500m. A water kick will behave in a different manner. The most important point however is that the time that the shoe is subject to high pressure is substantially reduced when the Wait and Weight Method is used. From initial shut-in to point P. therefore.152 Figure 5. to very light oils that have very high gas oil ratios. The fundamental difference between well control procedures on a fixed and a floating rig originate from the necessity of having to circulate through this choke line. 500 CHOKE PRESSURE (psi) 400 300 P Q 200 R 100 S T 0 0 200 400 VOL MUD PUMPED (bbl) 600 800 WEOX02. 4 Subsea Considerations If a kick is taken from a floating rig. From point S to point T. the influx passes the choke with a corresponding drop in choke pressures. From point R to point S. From point P to point Q. the choke pressure drops as the kill weight mud starts up the annulus. the kill weight mud arrives at surface. the choke pressure remains relatively constant as the drillpipe is displaced to kill weight mud. ranging from viscous black oil that contains very little gas.22 Choke Pressure – during displacement of a water kick using the Wait and Weight Method An oil kick is likely to behave in a similar manner to the gas kick when displaced from the well. 5-19 March 1995 . At point T. the choke pressure drops as the original mud behind the influx passes the choke. This is in marked contrast to the gas kick where the expansion of the kick at this stage tends to increase the choke pressure. the influx will be displaced to the surface through a small diamater choke line that is attached to the drilling riser. From point Q to point R. Most oil will contain gas at reservoir conditions which will come out of solution and expand as it is displaced up the hole. The term ‘oil’ covers a large variety of fluids.22 shows a typical choke pressure profile for a salt water kick displaced from the hole by the Wait and Weight Method.BP WELL CONTROL MANUAL Figure 5. the majority of oil kicks will behave similarly to a gas kick. Essentially. FIXED RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW.153 Figure 5. The influence of the choke line is apparent in that the maximum choke pressure is increased from 1200 psi to approximately 2600 psi. MW2: 3500m 2000m 1. This is due to the fact that the height of the influx is considerably increased as it is displaced from the annulus to the choke line.7SG 1.83SG CHOKELINE: BHA: PIPE: TECH: INFLUX: 1000m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS 2800 2400 FLOATING RIG CHOKE PRESSURE (psi) 2000 1600 1200 FIXED RIG 800 400 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02. Figure 5.23 shows a comparison between the choke pressure during displacement of a gas kick from a well drilled in 1000m of water and a similar well drilled from a fixed rig. MW2: 3500m 2000m 1.7SG 1.23 Comparison of Choke Pressures – during displacement of a gas kick on a fixed rig and a floating rig 5-20 March 1995 .83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS FLOATING RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW.BP WELL CONTROL MANUAL The potential problems caused by circulating through the choke line can be summarised asfollows: (a) Choke pressures will be significantly higher than for an equivalent well drilled from a fixed rig. 500m.BP WELL CONTROL MANUAL Figure 5.1 = = = = 256 psi/min 192 psi/min 64 psi/min 6. It can be seen that the choke pressure is not.7SG 1.7SG 1. MW2: 3500m 2000m 1. This can be converted to a rate of choke manipulation for various displacement rates as follows: At 4 bbl/min At 3 bbl/min At 1 bbl/min At 0.25 the increase in choke pressure required as the influx is displaced up the choke line is equivalent to 64 psi/bbl. 100m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS 2800 1000m WATER 2400 CHOKE PRESSURE (psi) 2000 500m WATER 1600 100m WATER 1200 800 FIXED RIG 400 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02.83SG CHOKELINE: BHA: PIPE: TECH: INFLUX: 1000m.154 Figure 5. As can be seen from Figure 5.24 shows the choke pressures during displacement of the same 20 bbl influx for a variety of water depths.24 Choke Pressure for various Water Depths – during displacement of a gas kick (b) The rate of increase of choke pressure required as the gas enters the choke line may be unrealistically high at normal displacement rates.83SG BHA: PIPE: TECH: INFLUX: 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS FLOATING RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW. significantly affected by a water depth of 100m. in this case. FIXED RIG: WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW. MW2: 3500m 2000m 1.4 psi/min 5-21 March 1995 .1 bbl/min = = = = 64 64 64 64 x x x x 4 3 1 0. the drillpipe pressure will only register the drop in bottomhole pressure after the lag time. As gas invades the choke line: p = bbl/pumped 1800 28 = 64psi/bbl 2000 28 = 71psi/bbl As the mud behind the gas enters the choke line p = bbl/pumped WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: 3500m 2000m 1. which can be substantial in deep wells.7SG 1. the most satisfactory rate of displacement would be of the order of 1 bbl/min.BP WELL CONTROL MANUAL It can therefore be seen that normal displacement rates have the potential to require an unrealistic rate of manipulation of the choke. 5-22 March 1995 .155 Figure 5.25 Determination of the Required Rate of Choke Manipulation for a Deep Water Subsea Well It should be noted however that these calculations are based on the assumption that the gas influx enters the choke line as a discrete bubble without mixing with the mud ahead of it. A further problem exists in that when the gas enters the choke line. In this case.83SG CHOKELINE: BHA: PIPE: TECH: INFLUX: 1000m/3in ID 6 1/4in/180m 5in DP WAIT AND WEIGHT 20bbl GAS 2800 CHOKE PRESSURE (psi) 2400 2000 1800psi 1600 2000psi 1200 800 400 0 0 200 400 600 800 VOL MUD PUMPED (bbl) WEOX02. This may not always be the case. however the figures quoted above certainly indicate that the normal kick displacement rates have the potential to cause such complications. when added to the wellbore pressures resulting from the displacement of a kick. the lag time will not be so problematical because the required rate of choke manipulation is generally lower. (such as 1 bbl/min) choke line losses are generally insignificant. the required rate of choke manipulation as the mud behind the influx enters the choke line may be unrealistically high at normal slow circulating rates. 5-23 March 1995 .26 shows a table of estimated choke line losses for various choke line lengths. however. When very slow displacement rates are used.25 shows that the choke pressure would theoretically have to be reduced at 71psi/bbl which corresponds to the following rates for various displacement rates: At 4 bbl/min At 3 bbl/min At 1 bbl/min At 0. it may be of a magnitude such as to cause formation breakdown. This lag time. Choke line frictional pressure may be significant. Figure 5.BP WELL CONTROL MANUAL On a fixed rig.1 = = = = 284 psi/min 213 psi/min 71 psi/min 7. In other words. The lag time between the choke and the drillpipe pressure gauges is generally considered to be of the order of 2 seconds per 300m of drillstring length. It can be seen therefore that there may be a lag time of approximately 20 seconds in deep wells. (c) The rate of decrease of choke pressure required as the mud behind the gas reaches the base of the choke line may be unrealistically high. will be significantly affected by the type and size of the influx in the hole. but can be significant in waters of 500m or greater. In this case. There are special techniques that can be used to eliminate the effect of choke line losses during displacement of a kick. In a similar manner. leading to the possibility of fracturing the exposed formation. even in deep water.1 bbl/min = = = = 71 71 71 71 x x x x 4 3 1 0. Choke line losses are generally insignificant in relatively shallow waters. In certain circumstances. the bottomhole pressure may have dropped 130 psi before the drillpipe pressure gauge registers this drop. the bottomhole pressure will drop only very slightly before the drillpipe pressures registers that drop and the choke operator closes in the choke (to increase the choke pressure and hence the bottomhole pressure). (d) The frictional pressure as a result of circulating through the choke line may be significant at slow circulating rates. If the required rate of choke manipulation is 420 psi/min as the influx is displaced up the choke line. is described in Chapter 6 of Volume 1. One such technique. Figure 5. namely the use of the kill line monitor.1 psi/min This is clear indication that normal displacement rates are unsuitable when displacing a gas influx through a long choke line. the potential problem is that the well may be overpressured. Clearly this is an additional reason for displacing the influx through the choke line at a rate that is substantially slower than normal slow circulation rates. Figure 5. ID) 5 Safety Factors During well control operations.1 1000 m 120 200 220 245 500 m 90 100 110 125 100 m 17 19 22 25 1. This will provide a margin of error for the choke operation that will prevent a second influx occurring.7 1. In general. and consequently the use of these techniques ensures that the bottomhole pressure is maintained at the kick zone pressure plus the annulus frictional pressure.9 2. it is clearly necessary to maintain the bottomhole pressure slightly greater than the kick zone pressure.7 1. every effort should be made to ensure that no additional pressures are applied to the openhole at early stages in the displacement of the kick when downhole pressures will generally be at a maximum.5 1. 5-24 March 1995 .5 1. excessive additional pressure may needlessly overpressure the wellbore and possibly cause the formation to fracture.26 Estimated Choke Line Losses (psi) for Various Choke Line Lengths (3 in.9 2.1 1000 m 260 295 325 360 500 m 130 145 165 180 100 m 26 30 33 36 CHOKE LINE LENGTH (m) 4 bbl/min MUD WEIGHT (SG) CHOKE LINE LENGTH (m) Figure 5. the annulus back pressure will always provide a safety margin over and above the kick zone pressure.27 shows a series of estimations of annulus frictional pressures for various well configurations. However. The following are possible causes of additional pressures during the displacement of a kick: (a) Annulus Frictional Pressure During displacement of a kick.BP WELL CONTROL MANUAL 3 bbl/min MUD WEIGHT (SG) 1. Standard well control techniques do not take annulus frictional pressure into account. The use of heavier than kill weight mud is not recommended.157 Figure 5.27 Annulus Pressure Loss for various Well Configurations It can be seen from these figures that the annulus frictional pressure may vary considerably from well to well in a kick situation. when standard techniques are used to displace a kick. in comparison to the Wait and Weight Method.7 SG to 2.3 SG to 1. (b) Heavier than Kill Weight Mud The use of heavier than kill weight mud will result in higher wellbore pressures than if kill weight mud is used. Figure 5. The significance of the annulus friction pressure must be assessed before a kick is displaced.5 SG mud = 150 to 180psi 2.1 SG mud = 190 to 240psi WEOX02.BP WELL CONTROL MANUAL 13 3/8in @ 1500m 12 1/4in hole 180m of 8in collars TD 1800m 7in @ 3200m Annulus pressure loss at 3 to 4bbl/min for mud weight range 1.28 shows the choke pressure during displacement of a kick for various mud weights.1 SG = 100 to 125psi 7in @ 4200m 200m 4 3/4in collars 6in hole TD 4500m Annulus pressure loss at 3 to 4bbl/min for 1.29 shows the equivalent shoe pressures. Figure 5. The maximum additional pressure will be applied when the heavier than kill weight mud arrives at the bit. 5-25 March 1995 .7 SG = 20 to 25psi 9 5/8in @ 3200m 9 5/8in shoe @ 3500m 8 1/2in hole 270m of 6 1/2in collars TD 4000m 3 1/2in drillpipe Annulus pressure loss at 3 to 4bbl/min for mud weight range 1. This is because additional choke pressure must be applied to account for the fact that the drillpipe and annulus will be out of balance as the hole is circulated to heavier than kill weight mud. 83SG MUD (WAIT AND WEIGHT) 4200 4000 3800 0 200 400 600 800 VOL MUD PUMPED (bbl) Figure 5. 1. 1. 1.87.83.9SG MUD 1.159 .9SG 6 1/4in/180m 5in DP OVERBALANCED MUD INFLUX: 20bbl GAS BHA: PIPE: TECH: 1600 1400 CHOKE PRESSURE (psi) 1.85SG 600 1.83SG 1.87SG 1.28 Choke Pressure – during displacement of a gas kick with overbalanced mud WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: MW2: 3500m 2000m 1.83SG 1.158 Figure 5.BP WELL CONTROL MANUAL WELL DEPTH: SHOE DEPTH: MW1: KICK ZONE EMW: MW1: 3500m 2000m 1.7SG 1.29 Shoe Pressure – during displacement of a gas kick with overbalanced mud 5-26 March 1995 WEOX02. 1.87SG MUD 4400 1.83. 1.85.9SG 1200 1000 800 1.83SG MUD (WAIT AND WEIGHT) 400 200 0 0 400 200 600 800 VOL MUD PUMPED (bbl) WEOX02.87.9SG 6 1/4in/180m 5in DP OVERBALANCED MUD INFLUX: 20bbl GAS BHA: PIPE: TECH: SHOE PRESSURE (psi) 5000 4800 4600 1.7SG 1.85SG MUD 1. 1.85. The annulus pressure worksheet shown in Figure 5. It is however useful to have a simple method of handcalculating both the maximum pressures that may be experienced at the openhole weak point. The techniques for using these sheets are described on the reverse side of this sheet. it may be applied only at a late stage in the displacement. The advantage of using additional choke pressure to create a safety margin is that it can be controlled during displacement. Additional choke pressure should never be applied to the well at an early stage in the displacement when downhole pressures will generally be maximum. At the rigsite.30b. it is not essential to have made all these calculations prior to displacing a kick from the hole. kill weight mud has started up the annulus and consequently pressures on the openhole are at a minimum. before the kick is displaced from the hole. 5-27 March 1995 . From the examples in Figures 5.30a provides a means of determining these pressures.32 should be used in conjunction with the annulus pressure worksheet. at the bottom of the well and at the standpipe will increase by 100 psi. and at surface. Additional choke pressure should therefore only be considered if the annulus frictional pressure is known to be insignificant. The choke pressure can therefore be used to apply a safety margin to the kick zone during displacement of the influx.28 and 5. care should be taken to avoid applying several safety factors while displacing the kick. The software used applies Boyle’s Law to the original influx at the bottom of the hole and then calculates the pressures in the wellbore and at surface in order that bottomhole pressure is maintained constant and exactly equal to the kick zone pressure. For example.31 and 5. The benefit of using this worksheet is that it can help in developing an understanding of the pressures involved during the displacement of a kick.BP WELL CONTROL MANUAL Heavier than kill weight mud is often considered in order to either add a small overbalance after the kick has been displaced from well or to kill an underground blowout. in Figure 5. 6 Calculating Annulus Pressure Profiles The annulus pressure profiles shown in this Chapter have been developed by computer. Figures 5. The benefit of the computer is that it can process a great deal of calculations in a relatively short time.29 it can be seen that even a relatively small overbalance will increase the wellbore pressures during kick displacement. Therefore if the choke pressure is increased by 100 psi. However. Overbalance should be added to the mud after the well has been killed. when the influx is in the casing. (c) Additional Choke Pressure An increase in choke pressure will exert an additional pressure throughout the circulating system. the pressure at the casing shoe. It is not the simplest and quickest method. use D = depth of openhole weak point. The hydrostatic pressure of the influx is assumed to remain constant during displacement. if a computer is not available for this purpose: (a) Wait and Weight Method Use: 2 PD = S + K X 1. To determine the pressure at the openhole weak point when the top of the influx is at the openhole weak point. D original influx pressure (psi) original influx temperature (°R) original influx compressibility factor original inlfux volume (bbl) kill mud weight (SG) original mud weight (SG) annular capacity immediately below the influx (bbl/m) well total depth (m) height of original mud below influx (m) hydrostatic pressure influx (psi) kick zone pressure (psi) Therefore to determine the choke pressure at gas to surface.421 (MW2 – MW1) + Pi – Pf (psi) and: K= PO X VO X Z D ZO X TO X TD or: K = PO X and D PD TD ZD PO TO ZO VO MW2 MW1 C TD H1 Pi Pf VO (if temperature and compressibility effects are ignored) = = = = = = = = = = = = = = = depth to the top of the influx (m) pressure at the top of the influx (psi) influx temperature for influx at depth.421 – H1 X 1.421 X MW2 4 C 1 2 –S 2 (psi) where: S = (TD – D) MW2 X 1. D (°R) influx compressiblity factor for influx at depth. use D = O.BP WELL CONTROL MANUAL The formulae that are presented as follows are recommended for use at the rigsite for quick estimations of annulus pressures during the displacement of a kick. However it may be adjusted for substantial changes in annular capacity using the following formula: Pi1 = P i2 X C2 C1 where Pi1 Pi2 C1 C2 = = = = hydrostatic pressure of influx at original conditions (psi) hydrostatic pressure of influx at point of interest (psi) original annular capacity (bbl/m) annular capacity at point of interest (bbl/m) 5-28 March 1995 . it is necessary to include into the formula the effect of the choke line.BP WELL CONTROL MANUAL (b) Driller’s Method This formula can be used both for the Driller’s Method and for the Wait and Weight Method when kill weight mud has not yet been circulated to the bit.421 + Pi – Pf (psi) (c) For a Subsea Well In order to calculate the choke pressure with gas to surface for a subsea well.421 4 C 1 2 –S 2 (psi) where: S = (TD – D) MW1 X 1. The formulae presented as follows are used only to calculate choke pressure at gas to surface: Use for the Weight and Wait Method: 2 Pchoke = S + K X MW2 X 1.421 + Pi – Pf (psi) C and Pchoke Dwhd Vcl C = = = = choke pressure at gas to surface (psi) wellhead depth below rotary table (m) internal volume of choke line (bbl) annular capacity immediately below the influx (bbl/m) 5-29 March 1995 . The formulae presented in (a) and (c) are equally applicable for calculating the pressure at the top of the influx before it is circulated to the subsea wellhead. Use: 2 P = S + K X MW1 X 1.421 + Pi – Pf (psi) Use for the Driller’s Method: 2 Pchoke = S + K X MW1 X 1.421 4 C 1 2 –S 2 (psi) where: S = (TD – Dwhd +V cl ) MW1 X 1.421 X MW1 + (TD – H1 – Dwhd + V cl ) MW2 C X 1.421 C 4 1 2 –S 2 (psi) where: S = H1 X 1. 7 SG Annular capacity below the influx. MW1 = 1. Theory and Application by Peter Mills. ID Capacity of the drillstring = (3370 X 0.) 5-30 March 1995 . Reidel Publishing Company. drillpipe. ID Choke line:1000m/3 in. (For derivation of these formulae ref: Blowout Prevention.1604 If the Weight and Wait Method is used: S = H1 X 1.BP WELL CONTROL MANUAL (d) A completed example Estimate the maximum choke pressure during displacement of a gas kick taken on a floating rig for the following conditions: Volume of influx.5 ) 1.421 X 1.83 X 1. OD/ 2 3/4 in. D. VO = 20 bbl gas Kill mud weight. Drillstring: 5 in.83 0. H1 = 201 = 1253m 0.68 in.421 0.421 + Pi – Pf C = (1253 X 1. 1984.1604 bbl/m Well total depth.0239) = 201 bbl Height of this volume in the annulus. BHA 180m/ 6 1/4 in. TD = 3500m Hole/Casing ID = 8. as such. C = 0.421 + 59 + 9101 = -2310 psi Substituting into: 2 Pchoke = S + K X MW2 X 1.7) + (3500 – 1253 – 1000 + 28.83 SG Original mud weight. the actual maximum pressure would be expected to be lower than this value.1604 X (psi) 1.05827) + (180 X 0.1604 (psi) 1 2 – -2310 2 (psi) = 3225 psi Therefore the maximum anticipated pressure during displacement is 3225 psi. MW2 = 1.421 X MW1+ (TD – H1 – D whd +V cl ) MW2 X 1.421 C 4 2 Pchoke = -2310 + 20 4 X 1 2 –S 2 9101 X 1. It would however be anticipated that this figure represents the maximum possible pressure at surface and. ID X OD length. ft bbl/ft Volume bbl Casing Shoe Depth: Annulus. in.ft Annulus. in. ft bbl/ft Volume bbl Kick Zone Pressure: TVD. in. ft bbl/ft Volume bbl Influx Height = ft Temp Grad: °F/ft Total Annulus Volume bbl Influx Hydrostatic = psi Kill Mud Height of Hydro Pressure Below Influx Below Original Mud Pressure (psi) Mud Below Influx ( ) of Mud Below Influx ( psig ) Influx Hydrostatic (psi) Influx Mid-point Pressure (psia) °F °R (7) (8) (9) (10) (11) (12) (13) Vol (bbl) Height ( ) Pressure (psi) Vol (bbl) Height ( ) (1) (2) (3) (4) (5) (6) Original Mud Influx Temp Hydro- above influx Influx Size Req'd Back Pressure (psi) Pressure at the Shoe (psi) (20) (21) Factor Vol (bbl) Height ( ) Height ( ) Pressure (psi) static of Annulus Fluids (psi) (14) (15) (16) (17) (18) (19) ft ft Z 5-31 ft ft ft WEOX02. Rig Name: bbl Date: Kick Zone Depth: TVD. ID X OD length. Weddle ANNULUS PRESSURE WORKSHEET March 1995 . in.30a Version 1/1 1Q'95 by ODL/C.ft = psi Original Mud Weight: ppg ppg Shut in Drill Pipe Pressure: Annulus.196 BP WELL CONTROL MANUAL Original Mud Volume of Mud Pumped (bbl) Annulus Pressure Worksheet Drillstring Internal Volume Well No: Figure 5. ft bbl/ft Volume bbl Casing Pressure: = psi Mud Weight to Displace Kick: ppg Annulus. ID X OD length. ft bbl/ft Volume bbl Pit Gain = bbl Surface Temp: °F Annulus. ID X OD length. in.Units (US/UK): For worksheet calculation enter information into shaded cells. ID X OD length. At this point and subsequently this volume will remain constant at the drillpipe internal volume. Volume 2) using the calculated values of pseudo reduced pressure and temperature.7 unless logging unit has detected presence of CO2 or H 2S or unusually heavy hydrocarbon components). (10) Gas hydrostatic pressure In a constant annulus size it is assumed that the gas hydrostatic pressure remains constant as the influx expands. The pressure at the shoe is determined by either: • Subtracting the hydrostatic pressure of the annulus fluids from the bottomhole to the shoe from the bottomholepressure • Adding the hydrostatic pressure of the fluids from the shoe to the surface to the required back pressure (20) This procedure will be repeated until the influx is positioned at the appropriate point in the well. can be determined from Figure 5. The pseudo reduced values are then calculated as follows: P pseudo reduced = P absolute (psia) P pseudo critical and T pseudo reduced = (14) T(°R) T pseudo critical Z factor The compressibility factor. For the first approximations it is a good idea to neglect the effect of temperature and compressibility in order to speed the calculation. in the annulus. The worksheet can be used as follows for the Wait and Weight method: (if the Drillers method is used (5). (15-16) Influx volume and height The expanded volume of the influx can be calculated using Gas law relationships as follows: V2 = T2 X Z2 X P1 X V1 P2 X T1 V T P Z = = = = Influx volume (bbl) Influx temperature (°R) Influx pressure (psia) Compressibility factor The influx height is determined as follows: Influx height = Influx volume Annular capacity (19) Total hydrostatic pressure of annulus fluids (20) Required back pressure (21) Pressure at the shoe This equal to (9) + (10) + (18). Use Figure 5. (9) Pressure of mud below the gas Equal to (4) + (7). 5-32 March 1995 . The gas hydrostatic must however be corrected for substantial changes in annular dimensions using the following relationship: Gas hydrostatic (2) = Gas hydrostatic (1) X (11) Annular capacity (2) Annular capacity (1) Gas mid point pressure This is equal to the kick zone pressure minus the total hydrostatic pressure of the mud below the influx and half of the gas hydrostatic pressure. (5-7) Kill mud below original mud This volume is zero until the internal volume of the drillstring has been displaced.32 (BP Well Control Manual.30b Annulus Pressure Worksheet The worksheet provided can be used to estimate annulus pressures during the displacement of a kick.31 (BP Well Control Manual. For example if the first calculation shows that the top of the influx is above the shoe (assuming that the point of interest is when the top of the influx arrives at the shoe). (12-13) The gas temperature This is estimated from the surface pressure and the temperature gradient in the well unless more detailed information is available. Once the kill mud starts into the annulus. (8) Metres of mud below gas The total height of mud below the influx. This is the difference between the kick zone pressure and the total hydrostatic pressure of the fluid in the annulus (19).BP WELL CONTROL MANUAL Figure 5. Volume 2) to determine the pseudo critical temperature and pressure of the gas (assume gravity is 0. The temperature in °F can be converted to °R by adding 460. Z. the calculation should be reworked for a smaller volume of mud pumped. (2-4) Original mud below gas This volume is equal to the volume of kill weight mud pumped until the drillpipe is displaced. Convert this volume to height and hydrostatic pressure equivalent. (6) and (7) are left out of the calculation) (1) Barrels (bbl) of kill weight mud Estimate the volume of kill mud pumped for the gas to arrive at the point of interest. its height and hydrostatic pressure should be calculated. 5 0.6 0.8 0.2 Gas Gravity (air = 1) WEOX02.31 Graph of Pseudo-critical Temperature and Pressure for Hydrocarbons 700 Miscellaneou Pseudo Critical Pressure psia s gases Cond 650 ensat e well fluids 600 550 500 es Pseudo Critical Temperature °R as o ne lla 450 e isc g us M ell ew sat ds flui den Con 400 350 300 0.9 1 1.BP WELL CONTROL MANUAL Figure 5.162 5-33 March 1995 .1 1.7 0. 3 0.2 1.7 1.15 1.0 2.4 1.0 2.8 1.5 1.7 2.25 3.2 1.9 1 1.1 PSEUDO REDUCED TEMPERATURE 1.9 0.0 2.6 1.4 1.5 .4 0.6 2. 0.163 5-34 March 1995 .0 0.1 2.2 0.1 1.05 3.8 1.0 1.8 2.8 1.2 1.1 2.7 1.35 2 1.5 1.8 1. 1. 1941 1.7 1.6 3 1.9 0.6 1.9 1.6 0.3 0.45 1.4 2.5 1.4 COMPRESSIBILITY FACTOR Z COMPRESSIBILITY FACTOR Z 1.9 1.2 2.4 2.0 1.3 1.25 4 1.BP WELL CONTROL MANUAL Figure 5.1 1.2 1.6 January 1.32 Compressibility Factors for Natural Gas PSEUDO REDUCED PRESSURE 0 1 2 3 4 5 6 7 8 1.3 2. 05 1.1 1.0 1.0 1.6 1. 1 1.9 7 8 9 10 11 12 13 14 15 PSEUDO REDUCED PRESSURE WEOX02.6 3.05 1. 1.0 1.95 1.4 1.8 2.7 1.0 1.5 1.2 1 1. 1.4 2.3 0. 05 0. • A choke system that can maintain a variable back pressure on a well whilst it is circulated.BP WELL CONTROL MANUAL 6 WELL CONTROL EQUIPMENT Section Page 6. the casing string and the BOP stack. • BOPs securely anchored to the wellhead and capable of closing off the annulus against openhole or any tool that is run into the hole. • A kill system which gives flexibility to pump to the hole via the annulus or drillstring. The basic requirements for effective BOP equipment include: • A properly designed and cemented casing string that can contain pressures encountered whilst drilling.5 EQUIPMENT TESTING 6-64 Blowout preventers and associated equipment provide the means of controlling a well after primary control has been lost.3 CONTROL SYSTEMS 6-43 6. • A properly designed and installed wellhead assembly that can support.2 BLOWOUT PREVENTER EQUIPMENT 6-5 6. • A control system to operate the BOPs which features adequate redundancy and acceptable closing times. • Instrumentation that allows control of the well killing operation. and seal between.1 WELLHEADS 6-1 6.4 ASSOCIATED EQUIPMENT 6-55 6. March 1995 . BP WELL CONTROL MANUAL 6.1 WELLHEADS Paragraph Page 1 Surface Wellheads 6-2 2 Subsea Wellheads 6-2 6-1 March 1995 . casing hangers/pack-offs and a guide base. Subsequent casing hangers land off on the previous seal assembly. platform and jack-up rigs. or hub to suit a clamp. it can be similar in concept to a subsea wellhead. with the weight of the casing transferred to the cement. top and bottom. (b) Slip and Seal Assembly The weight of the casing string is transferred onto the preceding spool via casing slips. casing in the case of a 2 stack system. The starting head is anchored to the surface string of casing. Additional support may be provided by the conductor. consists of one or two wellhead housings. As an alternative to the conventional stack of spools. the void between the slip and seal assembly. to retain. 6-2 March 1995 . in which the conventional stack of spools is replaced by wellhead housing in which successive casing slips/hangers are stacked. or mud line hanger. and sometimes to energise the pack-off. which is weight or jack screw energised. or onto the conductor and surface casing in the case of a single stack system.BP WELL CONTROL MANUAL 1 Surface Wellheads A conventional wellhead for use on land. several manufacturers offer a more compact system. often inlaid with stainless steel. • A bowl to accommodate the next casing string slips. Often the side-arm is threaded to accept a plug to facilitate valve removal. and seals the annulus between casing and spool. • A set of seals. • Studded or flanged side-arms below the bowl.which provide communication to the casing annulus. • Lock down screws are provided in the top flange of most spools. to pack off around the preceding casing stub.e. The wellhead housings are normally made up onto the conductor and 13 3/8 in. The major components of the surface wellhead are as follows: (a) Spools Conventional wellhead spools generally incorporate the following features: • API standard flanges. sometimes energised with plastic packing. The assembly incorporates a packer. to suit an API gasket. and the ring gasket). It is positioned just above the seabed. Such a system greatly simplifies and speeds wellhead installation. The flange face has a machined groove. • Ports are provided to allow the pressure testing of the flange seals (i. They perform four functions: • Support of casing strings by means of an internal upset on which the first casing hanger lands. comprises a series of spools and is based on a starting head. the upper spool seals. and also to retain the bore protector. 2 Subsea Wellheads A subsea wellhead as used on floating rigs. in the base of the spool. For deep water guidelineless operations. housings to 5000 or 10. It acts as an anchor for the guidelines. The following are the major items of equipment associated with the subsea wellhead: (a) Casing Hangers Casing hangers are screwed on to the top of the casing string. The connector retains a metal gasket that is weight and pressure energised. 16 3/4 in. the standard square four posted guide base is replaced by a funnel. The connector should have the same pressure rating as the stack. • Support of the stack which lands on the hub and latches onto a profile on the outside of the hub. 18 3/4 in. to seal between the wellhead and connector. (c) Stack Connector The BOP stack is connected to the wellhead by means of a hydraulically actuated connector which clamps on to a profile on the outside of the hub. In most systems. 6-3/4 6-3 March 1995 . and a guide for locating the stack connector precisely over the wellhead. and are landed in the wellhead on a retrievable handling string. the energised packer is locked into a recess in the housing. Commonly 21 1/4 in. or petal shaped guide box. wellhead housing. housings are rated to 2000 or 5000 psi.BP WELL CONTROL MANUAL • Pressure isolation of the casing annulus from the wellbore by providing a polished bore on which the seal assembly packs off. (d) Permanent Guide Base A permanent guide base is locked onto and run with the 30 in. (b) Seal Assembly The seal assembly provides a means of isolating the casing annulus by sealing between the hanger and the wellhead housing. the packer is energised with weight or by right hand torque. Generally. although some deep water designs are set hydraulically.000 psi. by provision of a polished stainless steel inlaid profile for a gasket in the hub bore. housings to 10. and 13 5/8 in. • Pressure containment between the wellhead housing and the BOP.000 psi or 15.000 psi. 3 Hydril Annular Preventer Type GK 6-10 6.13 10M/15M Surface BOP Stack 6-26 6.4 Hydril Annular Preventer Type GL 6-11 6. Ring Gaskets.2 Hydril Annular Preventer Type MSP 6-9 6.9 Ram Preventer Opening and Closing Ratios 6-18 6.11 Availability and Bore of Blowout Preventers by Major Manufacturers 6-22 6. Flange Bolts and Nuts 6-34 6-5 March 1995 .10 Approved BOPs for Company Operations 6-21 6.5 Shaffer Annular Preventer 6-12 6.7 Packing Unit Selection (from Hydril) 6-14 6.14 Four Inlet/Outlet 10M/15M Subsea BOP Stack 6-27 6.15 Three Inlet/Outlet 10M/15M Subsea BOP Stack 6-28 6.1 Annular Preventer Sealing Elements 6-8 6.6 Cameron Annular Preventer Type D 6-13 6.8 Secondary Rod Seal – Cameron Type U 6-17 6.12 5M Surface BOP Stack 6-25 6.16 Specifications for BOP Flanges.2 BLOWOUT PREVENTER EQUIPMENT Paragraph Page 6-7 1 Annular Preventers 2 Ram Type Preventers 6-15 3 BOP Stack Size and Pressure Rating 6-20 4 Stack Configurations 6-23 5 Choke and Kill Lines 6-29 6 Choke and Standpipe Manifolds 6-36 7 Diverters 6-39 Illustrations 6.BP WELL CONTROL MANUAL 6. 19 Standpipe Manifold 6-39 6.BP WELL CONTROL MANUAL 6.20 Subsea Diverter Stack 6-40 6-6 March 1995 . 10M/15M 6-38 6.18 Choke Manifold.17 Hydril Drilling Spool Data 6-35 6. on occasions. when coupled with wellbore pressure sealing effects. should be run cautiously through BOPs to minimise element damage. retract fully. Elements of annular preventers do not. it is not recommended as such gross deformation of the elastomer causes cracking and accelerated wear.7. This information should be available at the rigsite. GK. The pipe should be moved slowly. (See Figure 6. neoprene) used in the packingelement should be the most suitable for a particular wellhead environment.6) together with a summary of major operating features.1. cause high internal stresses in the element and reduce element life. • When stripping. • Cap seals should be replaced when changing elements. Extrusion of the element into the wellbore is effected by upwards movement of a hydraulically actuated piston. • Drilling tools. The majority of annular preventers currently in use are manufactured by Hydril (Types MSP. Seals should be replaced and all sealing surfaces inspected. 6-7 March 1995 . Preventers should be stripped and inspected annually. hydraulic closing pressures should conform to the manufacturer’s recommendations for pressure testing and operational use of the preventers. • Although most models and sizes of annular preventer will seal an openhole in an emergency operation. Shaffer (Spherical) and Cameron (Type D). The element is designed to seal around any shape or size of pipe and to close on openhole. • Cavities should be flushed out and the element inspected following each well. The following are the most important aspects of the operation of annular preventers: • To obtain maximum sealing element life. • The type of elastomer (natural rubber. Excessive closing pressures. See Figure 6. with pressure on the wellhead. synthetic rubber. these are illustrated below (See Figures 6.) An important function of annular preventers is to facilitate the stripping of the drillpipe in or out of the well. • Closing pressures should be regulated to the pressures specified by the manufacturers. Surge vessels on the closing ports will help to smooth-out surge pressures as tool joints pass through the element. The manufacturers also provide information regarding recommended closing pressures during stripping operations.BP WELL CONTROL MANUAL 1 Annular Preventers Annular preventers have a doughnut shaped elastic element with bonded steel internal reinforcing. especially rock bits. Closing pressures higher than this will increase element wear. the closing pressure should be regulated to the minimum required for a slight weeping of mud past the element. which controls closing pressure.2 to 6. Undue wear of the element is avoided by the use of pilot-operated hydraulic regulator. GL. GX). particularly as tool joints pass through the element. 164 6-8 March 1995 .1 Annular Preventer Sealing Elements SPHERICAL SEALING ELEMENT (SHAFFER) CUTAWAY DRAWING SHOWING HOW RUBBER IS MOULDED AROUND STEEL SEGMENTS (HYDRIL) (CAMERON) OPEN CLOSED ON PIPE CLOSED ON PIPE WEOX02.BP WELL CONTROL MANUAL Figure 6. An annular preventer should never be operated without some closing hydraulic pressure applied. Good stripping capability of the packing unit since (fatigue) wear occurs on the outside of the packing unit. In some circumstances and depending on the preventer size. 5. Automatically returns to the open position when closing pressure is released. Figure 6. the packing unit may suddenly open with only a small surge or reduction in well pressure. Also.2 Hydril Annular Preventer Type MSP WEOX02. 3. Primary usage is in diverter systems. 4.BP WELL CONTROL MANUAL PACKING UNIT PISTON OPENING CHAMBER CLOSING CHAMBER Operating Features: 1. the well pressure can maintain closure without any closing hydraulic pressure being applied. 6-9 March 1995 . Sealing assistance is gained from the well pressure. the pressure seal may be lost around the body of the drillpipe after a tool joint passes through the element during stripping operations. 2.165 • Most annular preventers are designed to use wellbore pressure to assist in maintaining closure. The reason is that with only well pressure maintaining closure. Will close on open hole and hold 2000psi (but not recommended). Has provision to measure piston travel to gauge element wear. WEOX02. 2. Will close on open hole (but not recommended). Sealing assistance is gained from the well pressure. Available with a bolted top. Requires high closing pressures when used in subsea installations. 5.3 Hydril Annular Preventer Type GK PISTON TRAVEL INDICATOR HOLE PACKING UNIT PISTON OPENING PORT CHAMBER CLOSING CHAMBER Operating Features: 1.166 6-10 March 1995 .BP WELL CONTROL MANUAL Figure 6. 3. 4. 2. 6. Minimise closing/opening fluid volumes. 4. Primarily designed for subsea operations. Operate as a secondary closing chamber. Will close on open hole (but not recommended). c. 3. Bolted cover for easier element charge.4 Hydril Annular Preventer Type GL PACKING UNIT OPENING CHAMBER PISTON PRIMARY CLOSING CHAMBER SECONDARY CHAMBER Operating Features: 1. WEOX02. Some sealing assistance is gained from well pressure. Has a secondary chamber which can be connected four ways to achieve different effects: a. 5. and d.BP WELL CONTROL MANUAL Figure 6. Reduce closing pressure. Has provision to measure piston travel to gauge element wear. Automatically compensate (counterbalance) for marine riser hydrostatic pressure effects in deep water. b.167 6-11 March 1995 . Will close on open hole (but not recommended). 4.BP WELL CONTROL MANUAL PACKING UNIT UPPER ADAPTER HEAD OPENING CHAMBER PISTON CLOSING CHAMBER Operating Features: 1. the cover of the preventer can be unbolted and the packing element lifted out with a hoist line. New packing elements for Hydril and Shaffer annular preventers can be split in the field and installed in reverse order. Cameron has recently developed a packing element for their Type D annular preventer which can be split in the field. This reqires a bypass arrangement around the 1500 psi annular regulator on 3000 psi closing units. WEOX02. Some sealing assistance is gained from the well pressure. Hydril’s and Shaffer’s annular preventers are claimed to provide positive closure with 1500 psi closing unit pressure when the rubber elements are new. Requires higher closing pressure in subsea applications. 6-12 March 1995 . 5. Important to check seals in upper adapter head when changing an element and replace if necessary. After the pipe rams are closed and locked below the annular preventer and the hydraulic and well pressure bled off. • If the annular packing element wears out during stripping or well killing operations. 6. 3.5 Shaffer Annular Preventer • Cameron’s Type D annular preventer requires 3000 psi hydraulic closing pressure for positive closure with no pipe in the preventer.168 Figure 6. With the element above the preventer. Currently the most common annular preventer for subsea use. the damaged unit can be split and removed from the pipe. No provision for measuring piston travel. 2. the element can be changed without pulling the pipe. BP WELL CONTROL MANUAL • A 1 in. Most sizes use less closing fluid than Shaffer and Hydril annular preventers. PACKING UNIT OPENING CHAMBER PISTON CLOSING CHAMBER Operating Features: 1.6 Cameron Annular Preventer Type D 6-13 March 1995 .169 Figure 6. 5. Requires 3000psi closing pressure to close an openhole. These valves must be in the open position at all times except when testing hydraulic lines and hydraulic chamber seals. These valves can be used to verify seal leaks between the opening and closing chambers of an annular preventer. 4. Overall height is less than Hydril and Shaffer annular preventers. Quick-release top latch for easy element change. 6. WEOX02. Two piece packing unit. 3. valve can be installed on both the opening and closing lines next to the annular preventer. Operational problems have been experienced with this preventer. 2. The manufacturers’ recommendations for the required adjustment pressure are summarised below: • For Hydril GK and MSP.421) (psi) adjustment pressure (psi) mud weight in the riser (SG) sea water density (SG) water depth (m) annular closing ratio and CR = Closing chamber area Closing chamber area – Opening chamber area For example CR for Hydril 13 5/8 in. New or repaired units obtained from other service companies should not be used since the preventer manufacturers cannot be held responsible for malfunction of their equipment unless their elements are installed. the water depth.421 X D) – ρw ( CR X D X 1. 2M MSP = 4.56 CR for Hydril 21 1/4 in.7 Packing Unit Selection (from Hydril) • Only packing elements which are supplied by the manufacturer of the annular preventer should be used. 5M GK = 2. and the water density as follows: ∆P = (MW where ∆P MW ρw D CR = = = = = X 1.BP WELL CONTROL MANUAL IDENTIFICATION PACKING UNIT TYPE Colour Code OPERATING TEMP RANGE DRILLING FLUID COMPATIBILITY NATURAL RUBBER Black NR -30°F – 225°F Waterbase fluid NITRILE RUBBER Red Band NBR -20°F – 190°F Oil base/oil additive fluid NEOPRENE RUBBER Green Band CR -30°F – 170°F Oil base fluid Figure 6. 6-14 March 1995 . Closing pressures must be adjusted when annular preventers are operated subsea. the adjustment pressure is related to the mud weight.74 and so: Subsea closing pressure = Surface closing pressure + Adjustment pressure • For Hydril GL operated subsea (with the secondary chamber connected to the openingline): Adjustment pressure as for Hydril GK in subsea operation. to hang-off on) and at least one set of blind/shear rams installed. One set of variable rams will provide back-up for two different pipe rams. annular preventers suffice for closing on casing. However. 6-15 March 1995 . Variable bore pipe rams are also available for most ram preventers. (i.335)D For the 18 3/4 in.g. which is dependent on relative tool joint size and ram range. 5M: ∆P = (0. Some variable rams have a limited hang-off capacity.e. it is not considered necessary to install casing rams under normal circumstances. (b) Variable Pipe Rams Variable pipe rams are available for some models.339MW – 0. 3 1/2 in.318)D 2 Ram Type Preventers Ram type BOPs have two hydraulically actuated horizontally opposed rams which are either designed to seal off an openhole or an annulus against a pipe of specific diameter.335MW – 0. There are several different types of ram preventer. • For the NL Shaffer annular operated subsea. e.BP WELL CONTROL MANUAL • For Hydril GL operated subsea (with the secondary chamber connected to the closingline): Adjustment pressure = K X Adjustment pressure (as determined for Hydril GK) where K = • Closing chamber area Closing chamber area – Secondary chamber area For Hydril GL operated subsea (with secondary chamber in hydraulic communication with the riser): No adjustment required. On subsea stacks. as outlined below: (a) Pipe Rams Standard pipe rams are designed to centralise and pack-off around one specific size of drillpipe or casing. and 5 in. 5M: ∆P = (0. or 5 in. and 7 in. The working pressure of ram preventers should be at least equal to the maximum anticipated surface pressures. At least one preventer should be fitted with rams to suit each size of drillpipe in the hole. unless conditions are exceptional. tests carried out by Exxon indicated that the required adjustment to the closing pressure is given by the following: For the 16 3/4 in. plus a margin for pumping to the well. pipe rams should be designed to support the string weight. brought about by the steel plates. The majority of ram-type preventers in present day use are manufactured by Cameron (Types U and T). which involves hanging off on floating rigs. – 4 1/2 in. Blind/shear rams should be specified when ordering a preventer. Although the detailed design of products from the three manufacturers varies. Shearing of drillpipe should be carried out with the pipe stationary. 1/2 in. Sometimes this involves special hardening of the bearing area. in. Some models of blind/shear ram are unsuitable for sour service. in. and should be used where appropriate. • Ram Locking Devices Hydraulically operated ram preventers are provided with locking-screw stem extensions and large diameter hand wheels similar to the operating screws of manually closed preventers. if practical. is opposite the rams. – 2 7/8 in. As the rams arebrought together . it may be necessary to increase operating pressure above 1500 psi to shear. the front face of the ram sealing element will wear. – 2 7/8 in. not a tool joint. these steel plates meet before the preventer is fully closed.000 lb) can be furnished for floating operations. – 3 1/2 in. in. 5/8 in. On some preventers. which might render the ram unsuitable for sour service. and in tension. in. as some preventers require oversized cylinders or other special features. The main purpose of the locking screws is to manually lock the rams in the 6-16 March 1995 . (e) Offset Rams Offset rams and dual offset rams are available for dual completions. – 2 7/8 in. 11 in. in. in. If the rams are used for stripping pipe.BP WELL CONTROL MANUAL Cameron offer the following sizes of variable bore rams: BOP Bore Pipe Size Range 11 in. 13 5/8 13 5/8 16 3/4 16 3/4 18 3/4 18 3/4 5 5 7 5 7 5 7 5 in. in. in. NL Shaffer (Types LWS and SL) and Hydril (Types V and X). in. in – 2 7/8 in. thereby effecting a seal. (c) Hanging Rams Pipe rams with enhanced load-bearing capabilities (usually rated to 600. will ensure that rubber from the packing element moves forwards to replace that which is worn away. – 3 1/2 in. (d) Blind/Shear Rams These are designed to cut drillpipe and then seal as blind rams. The self-feeding action. Care should be taken to ensure that the pipe body. most models share the following basic features: • Self Feeding Action of Elastomer The front elements of ram seals have steel plates bonded to the rubber. – 3 1/2 in. in. Furthermovement of the ram bodies causes extrusion of the rubber element. The pipe stub is accommodated in a recess. In an emergency. This plastic seal is used only during emergency situations.171 Figure 6. During the initial pressure testing of a BOP stack. removing the check valve and digging out the plastic packing. An optional hydraulic lock mechanism (Cameron’s Wedge Lock. The primary rod seal must always be repaired when the emergency is over. should be equipped with secondary piston rod seals. The hydraulic ram lock was developed for subsea BOP stacks and can be used on land rigs in place of the manually operated locking screws. The hydraulic lock holds the rams closed until unlocking pressure is applied even though the primary control pressure is released. The secondary seal can be removed by unscrewing the energising plug. If the locking screws are used to close the rams. see Figure 6. the screws can be used to close the rams if the hydraulic system fails. 6-17 March 1995 .8 Secondary Rod Seal – Cameron Type U • Secondary Shaft Seals All ram preventers with rated working pressure 5000 psi or higher. the hydraulic closing unit valve handle should be turned to the closed position. The secondary seal is plastic which is stored in a cavity until it is activated by forcing it around the ram rod. the secondary seals on each ram preventer should be removed to assure that the main rod seals are tested.8. the primary rod seal may leak under excessive pressure during well control operations. This will eliminate the possibility of hydraulic oil being trapped on the opening side of the actuating pistons. The secondary seal is designed for static conditions and movement of the rod causes rapid wear of both the seal and rod.BP WELL CONTROL MANUAL closed position after they are shut hydraulically. Due to routine wear. in case the primary rod seals fail. Shaffer’s Poslock and Hydril’s MPL) can be used in place of locking screws to lock the rams in the closed position. BACK-UP RINGS (IN 10000 AND 15000psi WP PREVENTERS ONLY) PLASTIC INJECTION SCREW CHECK VALVE ENERGISING RING HYCAR LIP SEAL RETAINER RING AND LOCKING RING PLASTIC PACKING RING 'O' RING VENT TO ATMOSPHERE OPERATING CYLINDER PREVENTER BODY PREVENTER BONNET WEOX02. 000 5. 6-18 March 1995 .2 10.0 7. These are the ratios between the well pressures and the operating pressures needed to open or close the rams.3 6.4 5.0 2.6 2.3 5. Opening ratios of two-to-one are common.54 7.56 5.000 1.11 Figure 6.5 2.9 7.11 2.0 7. 11 in. 1.6 18 3/4 in.6 7.1 3.63 7.3 7.0 26 3/4 in.3 7.9 Shaffer ‘SL’ Open Hydril Ram Open Close 7.000 3.2 7.74 16 3/4 in.9 5.3 2.1 7.000 15.8 7.000 3.62 2.6 2.11 7.5 1.0 7.5 2.29 2.98 1.68 7.3 2.1 4.000 10.2 0.000 5.8 6.000 10.11 2.03 2.24 13 5/8 in.000 2. as shown in Figure 6.3 5. 2.5 2.8 3.23 5.000 15. 3.11 7.000 5.14 5.9 6.3 1.000 15.2 5.000 Close 2. 2.6 7.3 6.98 0.3 7.06 5.41 10.000 2.000 3.BP WELL CONTROL MANUAL SIZE WP (psi) Cameron U Open 7 1/16 in.3 6.8 6.9 6.000 3.000 10.54 5.11 1.9. 10.000 5.0 2.8 6.1 2.83 1. Closing ratios are generally in the range of six-to-one to nine-to-one.3 2.00 3.00 4.11 2.000 15.5 1.54 7.000 5.000 2.3 2.3 5.7 6.000 2.0 8.3 9.5 2.85 1.0 7.6 7.6 7.3 2.4 8.000 10.000 5.0 6.000 3.4 3.9 Ram Preventer Opening and Closing Ratios • Closing Ratios Ram-type preventers have specially designed opening and closing ratios.3 2.37 Close 5.9 2.000 1. This means that a preventer having a closing ratio of six-to-one would require 500 psi closing pressure to close the preventer when the wellbore pressure is 3000 psi.8 2.3 2.000 10.6 2.4 9.000 10.2 7.2 7.15 10.6 3.27 21 1/4 in.8 7.6 5.2 10.1 7. 9 in. Opening ratios are much lower because the wellbore pressure acts behind the ram to oppose opening.6 2.7 1.11 10.4 3.6 4.9 6. 3.000 3. they should be tested at 200/300psi prior to the rated working pressure test. a ram preventer should be closed immediately to minimise additional well flow. – Bonnet seals should be handled carefully. This would induce excessive extrusion of the elastomer and can cause cracking or bonding failures. Numerous costly incidents have resulted from accidentally closing the blind rams and flattening or cutting 6-19 March 1995 . – Bonnet seals should be tested after installation. Due regard should be paid to the type of lubricant used. and be stored at controlled temperatures in darkness. In instances where mechanical problems prevent rapid closure of the annular preventer. Usually. especially in the larger sizes. • Ram preventers will close faster than annular preventers. pressures greater than 3000 psi may be required to open some ram preventers. The seals are generally of fibrous/rubber construction and require careful handling and installation. • Wellbore pressure helps close ram preventers. Manufacturers’ recommendations should be observed meticulously. • Bonnet Seals Bonnet (or door) seals are exposed to wellbore pressures and fluids. inspected (particularly all sealing surfaces) and seals replaced annually. They should be discarded after storage for one year. • The main closing unit control handle for operating blind or blind/shear rams should always be protected against accidental closure with pipe in the hole. eg make-up torque is reduced by approximately 50% if a molybdenum disulphide lubricant. – Bonnet seals should be replaced each time bonnets are opened. They are designed to hold pressure from the lower side and will not seal properly if installed upside down. bonnet seals are critical to the integrity of the BOP system.BP WELL CONTROL MANUAL It should also be noted that. particularly on installation. – Bonnet bolts should be made up to manufacturers’ recommended torques. Field experience has proven that ram preventers are more likely to leak with a lowwellbore pressure than a high pressure. is used. – Bonnet faces. ram preventers require only one-third or less of the hydraulic fluid volume to close compared to an annular. The following are the most important aspects of the care and maintenance of ram preventers: • Pipe rams should not be closed on openhole or on mis-matched pipe. which can be extremely high with some compression-type seals. ram preventers are not designed to be pressure tested from the top side and this can damage the preventer. Since they can be subjected to high pressures and temperatures without being backed-up by another seal. • Ram recesses should be washed out and the ram element inspected following each well. ram preventers should close with 300 psi or less hydraulic pressure without wellbore pressure. preventer faces and seal grooves should be clean and dry before seal installation and make-up. rather than an API5A lubricant. For this reason. for high wellbore pressures. the preventer should be checked first for debris in the ram cavity and then inspected for piston rod misalignment or other mechanical problems. If high closing pressure is required during test operations. • When in good operating condition. Preventers should be stripped. Also. 3 BOP Stack Size and Pressure Rating The following stacks are available: • Single stack systems Bore 21 1/4 in.150 in. Variable bore rams can be used to seal on the body and end sections of aluminium drillpipe. but it is necessary to use two preventers which have sufficient distance between rams to isolate a tool joint box. ram blocks must be slightly modified to seal and not damage the main tube section of aluminium pipe.688 in. The upper and lower rams of a double ram preventer are too close together for this purpose. it prevents closing the preventer from a remote station. Standard rams will not seal on the tapered end sections.BP WELL CONTROL MANUAL the drillpipe during well control or drilling operations.. • When aluminium drillpipe is used. Shear rams are not recommended for land rig operations. In addition. on both the box and pin ends from 5. regular 5 in. 5 in. steel pipe. For example. 10M or 15M Figure 6. Thus. 5 in. A flip-up cover without locking device should be used. OD up to 5. special consideration must be given to ram size selection.10 shows a summary of approved BOPs. 16 3/4 in. to 46 in. If the handle is locked in the open position. 2M or 5M 5M. 11 in. 13 5/8 in. 6-20 March 1995 . aluminium drillpipe has an outside body diameter of 5.11 shows the availability and bore of BOPs from the major manufacturers. Excessive hydraulic pressure should not be applied on the rams when stripping pipe under pressure because it tends to wear the resilient material of the ram. • Ram preventers can be used to strip drillpipe in or out of the hole under pressure. • Working Pressure 10M (virtually obsolete) 10M or 15M 5M or 10M Multiple stack systems Bore Working Pressure 21 1/4 in. OD. versus a 5. The drilling spool provides this space in a five preventer stack.000 in. aluminium pipe has a tapered transition zone for a length of 41 in. Figure 6.150 in. 10M or 15M 5M. 18 3/4 in. The lowest ram in the BOP stack should never be used for stripping since it is always considered the master valve. body diameter for 5 in. Figure 6. GL. depending on the extent of exposure and H2S content. however. Natural rubber (black) – Water base muds 2. Synthetic rubber (red) – All muds 3.BP WELL CONTROL MANUAL OFFSHORE DIVERTER SYSTEMS Hughes Offshore Hughes Offshore Type KFDS (Floating) Type KFDJ (Platform) Hydril C Type FSP (Floating and Platform) (with Flow Selector) ANNULAR PREVENTERS ACCEPTABLE RUBBERS* Cameron – Type D Nitrile – Water and Oil Muds Hydril – MSP. The performance of these products can vary significantly. Natural rubber (black) – Water base muds 2. GS. GX The following types of Hydril rubbers are available: 1. Nitrile (blue) – Oil and water base muds RAM PREVENTERS ACCEPTABLE RUBBERS* Cameron – Type QRC Cameron – Type U Super Wear – Water and oil muds Super Wear – Water and oil muds Hydril – Type Ram Nitrile – Water and oil muds Shaffer – Type LWP Shaffer – Type LWS Shaffer – Type SL The following types of Shaffer rubbers are available: 1.10 Approved BOPs for Company Operations 6-21 March 1995 . GKS. Neoprene rubber (green) – Low temperature service and oil muds Shaffer – Spherical The following types of Shaffer rubbers are available: 1. Natural rubber (black) – Water base muds 2. GK. H 2S exposure reduces the service life of rubber products. ** Shaffer Type 70 ram blocks are not acceptable because of metallurgical and rubber packer failures. Nitrile (blue) – Oil and water base muds Koomey – Type PL PB * All BOP manufacturers specify their rubber elements and rams as H2S resistant. – – – – – 11 in. – 11 in. – 21 1/4 in. 11 in. – 21 1/4 in.000 7 1/16 in. 7 1/16 in. BP WELL CONTROL MANUAL 6-22 Figure 6. 13 5/8 in. – – – 9 in. 18 3/4 in. 9 in. 21 1/4 in. – 11 in. 21 1/4 in. 13 5/8 in. 16 3/4 in.000 3. – 13 5/8 in. 13 5/8 in. – – – – – 11 in. 7 1/16 in. 7 1/16 in. – – – – – 30 1.000 3.000 15. 13 5/8 in. – – – – 13 5/8 in. 9 in. 16 3/4 in. 7 1/16 in. – – – – 13 5/8 in. – – – 11 in. – – 7 1/16 in.000 – 11 in. 16 3/4 in.000 15. – 21 1/4 in. – – – – – 11 in. 26 3/4 in. 11 in. 11 in. 7 1/16 in. 5. 2. 7 1/16 in. 11 in. 20 3/4 in. 9 in. 18 3/4 in.000 3. 9 in.000 15. – – – – 9 in. 21 1/4 in. 7 1/16 in. – – – 18 3/4 in. 13 5/8 in. – – – – – – – – – 11 in. 2. 21 1/4 in. 11 in. 18 3/4 in. 13 5/8 in.000 10. 7 1/16 in. 18 3/4 in. 18 3/4 in. 11 in. – – – 18 3/4 in. 500 – – – – – – 29 1/2 in. 11 in. 9 in. 13 5/8 in.000 10. – – 11 in. 7 1/16 in. 7 1/16 in. – – – – – 18 3/4 in.000 13 5/8 in. 7 1/16 in. – – – – 18 3/4 in. 7 1/16 in. 7 1/16 in. 18 3/4 in. 11 in. – – – – – – – – 21 1/4 in. 11 in. 11 in. – – – 16 3/4 in. 26 3/4 in.000 – 18 3/4 in. 21 1/4 in. 13 5/8 in. 11 in. – – – – – 21 1/4 in.000 – – – – – – 30 in. 21 1/4 in. 16 3/4 in. 7 1/16 in. – – – – – 18 3/4 in.000 – 16 3/4 in. 13 5/8 in.000 10. – – – – 16 3/4 in.000 15. 11 in. 7 1/16 in. 16 3/4 in.000 – 26 3/4 in. – – – – – – – – – – – – – – – – – – – – – – 29 1/2 in. 21 1/4 in. 9 in. 11 in. 20 3/4 in. – – 16 3/4 in. 9 in. 7 1/16 in. – – – – 13 5/8 in. 13 5/8 in. 21 1/4 in. 20 3/4 in. 13 5/8 in. 16 3/4 in. 11 in. 13 5/8 in.Cameron U Cameron QRC Cameron D Hydril GK Hydril GL Hydril GX Hydril HSP Hydril Ram Shaffer LWS Shaffer SL Shaffer Spherical Koomey 3. 21 1/4 in. 7 1/16 in. 7 1/16 in. 13 5/8 in. 7 1/16 in. 16 3/4 in. 18 3/4 in. – – – – – – – – – – – – 16 3/4 in. 21 1/4 in. – – – 18 3/4 in. 2. 7 1/16 in. 3.000 – – – – – 9 in. – – – – – – – – – – – – 7 1/16 in. 20 3/4 in. – – – – 18 3/4 in. 7 1/16 in. 11 in. 16 3/4 in.000 3. 11 in. 11 in. – 7 1/16 in. 16 3/4 in. 7 1/16 in.11 Availability and Bore of Blowout Preventers by Major Manufacturers March 1995 Blowout Preventer Nominal Size . 11 in. 13 5/8 in. 13 5/8 in. – – – – – – 9 in. 13 5/8 in.000 21 1/4 in. – – – – – 21 1/4 in. 11 in.000 5. – – – – – – – – 9 in. 16 3/4 in. 18 3/4 in. – 11 in. 11 in. 13 5/8 in. – – – – – – 9 in. 11 in. 11 in. – – – – – Working Pressure 7 1/16 in. 13 5/8 in. – 16 3/4 in. – – – – – – 16 3/4 in. – 13 5/8 in.000 5. – – 13 5/8 in. – 7 1/16 in. – 11 in. 13 5/8 in. 9 in. 11 in. 13 5/8 in. 13 5/8 in.000 5. 7 1/16 in.000 10.000 10. 13 5/8 in. 9 in. – – – 13 5/8 in. 11 in. 13 5/8 in. 7 1/16 in.000 5. – – – 21 1/4 in.000 5. 13 5/8 in. 16 3/4 in.000 3. 13 5/8 in. 2.000 5. – – – – 7 1/16 in. 2.000 10. – – – – – 21 1/4 in. 11 in. 7 1/16 in.000 10. 15 show examples of acceptable stacks for various applications. It is acceptable to use annular preventers rated at 5000 psi less than the rams for certain 10M and 15M applications. before pulling the BHA through the stack. Figures 6. (a) 5M Surface BOP Stack (Figure 6. • Facility for stripping pipe through annular preventer. conducted on the BOP (or valve) body at the time of manufacture to a pressure 50% greater than the working pressure.12 to 6. the pipe rams are closed and the blind rams changed to pipe. In service. The rams should be changed out on the trip out of the hole prior to running casing. 4 Stack Configurations Company policy regarding minimum stack configurations for all categories of land and offshore operations is detailed in the Drilling Policy and Guidelines Manual. The particular details of each well will however dictate the most suitable stack for each application.BP WELL CONTROL MANUAL The test pressure rating of BOP equipment is a one off test. • No facility for ram combination stripping is available on this stack.12) The following points should be considered regarding this stack: • Two ram preventers and one annular preventer in line with Company policy. when changing ram elements and in the event of failure of rams above). • Lowermost ram not used for stripping operations and only used when no other ram available for this purpose (i. • If surface pressures exceed the pressure rating of the annular preventer. The upper pipe rams are closed. the lower pipe opened and the kick circulated out through the choke line. The bonnet seals are tested against the test plug and the annular prior to running casing. • If casing rams are required they should be positioned in the top ram preventer cavity. • Pipe can be stripped through annular preventer and between annular and upper piperam. • Ram preventer combination stripping is possible if blind rams are replaced with pipe rams. if suitable space is available between top two ram type preventers. (b) 10M/15M Surface BOP Stack (Figure 6. working pressure ratings should not be exceeded.e. • Annular access below the lowermost ram is possible through wellhead outlet. • Annular access below the lowermost ram possible through wellhead outlet. • A line must be rigged up to the flange between the top two ram preventers to facilitate ram combination stripping.13) The following points should be considered regarding this stack: • Three ram preventers and one annular preventer in line with Company policy. 6-23 March 1995 . • In the event of failure of pipe ram no. • In the event of failure of the choke line downstream of the failsafes. The concept for use of this ram is similar to that of the master valve on a production tree. • The lower kill line is used as the kill line monitor (See Standard Techniques. • Lowermost rams not used for stripping operations and only used when no other ram available for this purpose. before pulling the BHA through the stack. immediately below pipe ram no. • Variable bore rams can be fitted in the ram preventers below the blind/shear rams. • BOP gas can be removed from this stack using the technique described in Chapter6 of Volume 1.) It is important to have the facility to shear the pipe quickly and reliably during a well control operation. • For normal kill procedure drillstring is hung off on pipe ram no. 2. The rams should be changed out on the trip out of the hole prior to running casing. • There should be adequate space between the blind shear and pipe ram no. Chapter6.14) The following points should be considered regarding this stack: • Four ram preventers. (c) Four Inlet/Outlet 10M/15M Subsea BOP Stack (Figure 6. • If casing rams are required they should be positioned in the upper pipe ram preventer cavity. Volume 1). (If this line fails during the displacement of a kick there is no back-up available. • Lowermost ram only used when no other ram available is for this purpose. • The fact that there is an inlet/outlet. two annular preventers in line with Company policy for minimum requirements for high pressure subsea BOP stacks. is minimised. The hang off capability of these rams should be checked against maximum anticipated string weights.BP WELL CONTROL MANUAL • Well can be circulated either under the annular preventer or under the upper pipe rams. after a well control operation. especially so on a dynamically positioned vessel.) 6-24 March 1995 . The bonnet seals are tested against the test plug and the annular prior to running casing. In line with Company policy it should not be used for extended periods of circulation. 2. • The upper (primary) annular preventer can be recovered with lower riser package for element replacement. the well can be shut-in on and hung off on pipe ram no. means that the possibility of trapped gas. that can be used as a choke line. the well can be circulated through the kill line. • The lower choke line is used primarily for pressure testing and monitoring the well. • Four inlet/outlets provided in order to maximise flexibility of the stack. 2 and 3. 2 to shear on pipe body when the pipe is hung off on pipe ram no. or the upper choke line upstream of the failsafes. taking returns up the lower kill line as the riser is U-tubed. (This may not be possible if the top two ram type preventers are a double. 3 and returns taken up the lower kill line. 2 and well circulated through upper choke line. • The choke line between the drilling spool and choke manifold should not contain any bend or turn in the pipe body. WEOX02. the contractor will furnish and maintain all components shown except the 'A' section and items 1 and 2. Flanged gate valves – 2in minimum ID – same working pressure as 'A' section. 2. Top of annular preventer must be equipped with API flange ring gasket.12 5M Surface BOP Stack FLOWLINE FILL UP LINE 8 ANNULAR BOP BLIND RAMS 5 KILL LINE CHOKE LINE CHOKE MANIFOLD 4 3 7 6 PIPE RAMS SECTION A 1 CASING SPOOL 1 2 1. Any bend or turn required should be made with a running tee with a blind flange or welded bullplug.175 6-25 March 1995 . 3. which will be furnished by the Company.BP WELL CONTROL MANUAL Figure 6. All connections should be flanged or welded. Welds should be stress relieved. holes filled in with screw type plugs. Flanged gate valve – 2in minimum ID – same working pressure as BOP stack. Tee with tapped bullplug. 7. All fabrications requiring welding must be done by a certified welder. or flanged spring-loaded type check valve – 2in minimum ID – same working pressure as BOP stack. and pressure gauge. 6. needle valve. 5. NOTES: • Unless specified otherwise in the Bid Letter and/or Contract. As 3. All flange studs must be in place or 8. The outside valve is the working valve during drilling operation. Flanged hydraulically controlled gate valve – 3in minimum ID – same working pressure as BOP stack. 4. Drilling spool – two flanged side outlets – 3in choke and 2in kill line minimum IDs. Flanged gate valve – 3in minimum ID – same working pressure as BOP stack. This valve is removed and reused after completion. Flanged hydraulically controlled gate valve – 3in minimum ID – same working pressure as BOP stack.13 10M/15M Surface BOP Stack 9 FLOWLINE FILL UP LINE 8 ANNULAR BOP BLIND RAM OUTLET FLANGE (USED ONLY FOR RAM COMBINATION STRIPPING) UPPER PIPE RAM 5 KILL LINE 4 DRILLING SPOOL 4 CHOKE LINE 7 6 CHOKE MANIFOLD LOWER PIPE RAM 3 3 1 1 SECTION B 2 SECTION A 2 1.176 6-26 March 1995 . • The choke line between the drilling spool and choke manifold should not contain any bend or turn in the pipe body. The ID of the bell nipple must be less than the minimum ID of the BOP stack. 3. Welds should be stress relieved. Tee with tapped bullplug. 2. Top of annular preventer must be equipped with API flange ring gasket. 9. The outside valve is the working valve during drilling operation. 4. Drilling spool – two flanged side outlets – 3in choke and 2in kill line minimum IDs. All fabrications requiring welding must be done by a certified welder. Flanged gate valve – 3in minimum ID – same working pressure as BOP stack. All connections should be flanged or welded. Flanged gate valve – 2in minimum ID – same working pressure as 'B' section. which will be furnished by the Company. 6. 8. needle valve. NOTES: • Unless specified otherwise in the Bid Letter and/or Contract. the contractor will furnish and maintain all components shown except the 'A' and 'B' sections and items 1 and 2. Any bend or turn required should be made with a running tee with a blind flange or welded bullplug. WEOX02. This valve is removed and reused after completion. Flanged gate valve – 2in minimum ID – same working pressure as BOP stack. 5. and pressure gauge. 7. Flanged gate valves – 2in minimum ID – same working pressure as 'A' section.BP WELL CONTROL MANUAL Figure 6. All flange studs must be in place or holes filled in with screw type plugs. 177 6-27 March 1995 .BP WELL CONTROL MANUAL Figure 6.14 Four Inlet/Outlet 10/15M Subsea BOP Stack KILL LINE CHOKE LINE UPPER ANNULAR BOP RISER CONNECTOR LOWER ANNULAR BOP BLIND/SHEAR RAMS PIPE RAM No 2 PIPE RAM No 3 PIPE RAM No 4 WELLHEAD CONNECTOR WEOX02. 178 6-28 March 1995 .15 Three Inlet/Outlet 10/15M Subsea BOP Stack KILL LINE CHOKE LINE UPPER ANNULAR BOP RISER CONNECTOR LOWER ANNULAR BOP BLIND/SHEAR RAMS PIPE RAM No 2 PIPE RAM No 3 PIPE RAM No 4 WELLHEAD CONNECTOR WEOX02.BP WELL CONTROL MANUAL Figure 6. The majority of the comments relating to the 4 inlet/outlet stack are applicable in this case with the obvious exception that there is no line entering the stack below the lowermost ram. Disadvantages: • Reliance is placed on the annular preventers when running casing. • Unless variable or suitable sized pipe rams are installed initially. The lowermost ram is not used for stripping operations. the drillstring should be hung off on pipe ram during well control operations.15 shows an acceptable configuration of a 3 inlet/outlet high pressure subsea stack. Ram combination stripping is however considered impractical from a floating rig. can be regularly checked. (a) Surface BOP Stacks The location of kill and choke outlets on a BOP stack will be influenced primarily by the number of rams used and their sizes. and that the cost of conversion to a 4 inlet/outlet configuration may be prohibitive. 2 and shear on the pipe body generally means that it is not possible to use a double preventer for these two rams. In particular. including choke and kill lines. it is essential that equipment specifications should suit a particular well. (d) Three Inlet/Outlet 10M/15M Subsea Stack It is recommended that 4 inlets/outlets are provided for high pressure subsea stacks in order to provide a high level of flexibility/redundancy within the stack. the choke and kill lines should never be rated to a lower working pressure than the stack. No inlet/outlet is provided below the lowermost ram because it is considered that the benefit of such a line is insignificant compared to the reduction in the flexibility of the stack that this would entail. satisfy Company policy and local legislation. It is recommended that ultrasonic testing equipment is held on each rig in order that the wall thickness of pipework. 6-29 March 1995 . Figure 6. the stack must be pulled and redressed before using tapered strings. • The requirement to have the facility to hang off on pipe ram no.BP WELL CONTROL MANUAL • Annular and ram combination stripping is possible with this stack. Annular preventers are not to be considered an adequate substitute for pipe rams when using tapered strings. especially for short term contracts. 5 Choke and Kill Lines The variations in contractor furnished equipment and the requirements of individual areas are such that specification of a standard layout is not feasible. 2. However. This is undesirable and reduces the flexibility of the stack. • If it is not possible to shear on the pipe body when the drillstring is hung off on pipe ram no. However it is recognised that many subsea stacks incorporate only 3 inlets/outlets. Company policy is that check valves are not mandatory on the kill line. Choke and kill lines are generally fabricated in line with the following specifications: • All connections should be flanged. at least 100 ft from the well. a check valve has been installed outboard of the stack valves on the kill line. Supports should be fitted as required. although minimal use is acceptable on kill lines. • Lines. Screwed fittings.. Each wellhead spool should have dual valve isolation on one side and valve removal plugs (VRP) should be installed on the non-active side. The remote kill line should be rated at the pressure rating of the BOP stack and should terminate at a similarly rated flanged valve. Now many rigs. The purpose of this line is to enable a pump truck to be tied into the well in an emergency situation. • Remote Kill Line On a land rig. • All subsea choke and kill line valves are fail safe and hydraulically actuated. • Subsea choke and kill lines are much longer. During normal operations. a remote kill line can be tied in to the kill line so that it may be used whichever preventer is closed. • Check Valves Traditionally. All welding should be conducted by certified welders to approved weld procedures and all welds should be suitably non destructively tested and pressure tested prior to use. • Choke lines should be well braced. but these should not be welded to the choke line. clamped or welded. • Wellhead Outlets It is recommended that wellhead spool outlets are not used for a choke and kill line tie-ins. particularly the primary choke line should be installed with the minimum number of bends. (but this might restrict operational flexibility should it be required to substitute for a washed out choke line). 6-30 March 1995 . Depending on water depth. pressure losses in the lines might be significant. the choke line. the kill line may be as small as 2 in. the inner (manual) choke and kill line valves should be open and the outer (HCR) valves closed. unions and chicksans should not be used on the choke lines. (b) Subsea BOP Stacks Subsea choke and kill lines differ from surface systems in that: • Subsea choke and kill lines require flexible connections at the ball/flex joint. In such a hook-up. the choke line must have a minimum ID of 3 in. targeted tees. Swept bends are undesirable. or replace. line size and mud properties. or block tees should be used. • All welding should be carried out under shop conditions with machine cut weld preparations. particularly jack-ups. check valves are omitted. Where bends are required. and at the telescopic joint. to withstand severe vibration.BP WELL CONTROL MANUAL • Choke and Kill Outlets To comply with Company policy. have the facility to use the kill line to augment. The valve must be rated WOGM which means that it is serviceable for water. Generally BOP stacks for exploration wells should have 4 ram. (c) Hydraulically Operated Valves A remotely operated valve is installed on the choke line adjacent to the BOP stack to rapidly shut off hazardous flow in the event of downstream equipment failure. Swept bends are not desirable. • Targeted tees should be used for all 90 degree bends. On some rigs. Valves should be installedas close to the BOP outlets as possible. chicksans and unions should not be used. the dump valve should be treated with caution. not to drilling spools or the wellhead. Another advantage for remote operation is that this valve is usually located at an elevated working level in the substructure which makes hand operation difficult and unsafe. • Lines should be installed with the minimum number of bends. so that they will not part when full working pressure is applied simultaneously to both lines. • Choke and kill connections at the lower riser disconnect should be rigidly supported by the framework. The hydraulic actuator must be designed for 3000 psi maximum working pressure. The following points should be noted regarding the major choke and kill line components: • All valves should be failsafe. Side-arms and valves should be well protected by the framework around the stack. • The choke and kill lines across the telescopic joint should be able to accommodate the maximum designed travel of the joint. Specifically designed hydraulically controlled gate valves (HCV) are extensively utilised for this service. Often dump valves are considered to be unnecessary and are omitted on most rigs. The 3000 and 1500 psi design 6-31 March 1995 . or inadvertent opening. This valve may be used to dump cement returns. targeted tees or block tees should be used. • Both the choke and kill line should be tied into the choke manifold to allow one to replace or augment the other. • Choke lines should be anchored to withstand vibration. Two valves are required per outlet. a hydraulically actuated cement dump valve is provided on the kill line. but these should not be welded to the choke line. Where bends are required. • The choke and kill line across the ball/flex joint should be flexible and not restrict movement of the joint up to its maximum designed deflection. gas or mud flow. however. • All surface connections should be flanged. oil. Supports should be fitted as required. the actuator should fully open the valve with 1500 psi control pressure for maximum design conditions. clamped or welded. However. and 2 annular preventers.BP WELL CONTROL MANUAL Choke and kill lines are tied into BOP outlets. Misuse. It can also be used to flood the riser if it becomes evacuated and in danger of collapsing. • Riser couplings and the LMRP stab plates should be designed to withstand induced loadings when full working pressure is applied simultaneously to both lines. thereby avoiding long circulation times up the riser in deep water. and preferably in line with the outlets. Screwed fittings. This provides some flexibility in case a ram or element fails during a well killing operation. could cause considerable loss of hydrostatic head in the well. This valve has the same basic design and operational features as a Cameron QRC preventer. Other reputable valve manufacturers’ equipment may be acceptable for choke line service. The choke line valve must be operable from both the main and remote closing units. long slip fit seats to minimise wear in the valve body. Cameron’s type F hydraulically operated gate valve is probable the most widely used and is available with rated working pressures from 3000 psi to 15. • NL Shaffer Valve The operating characteristics of the NL Shaffer Model CB. however. • Rockwell Valve The Rockwell (McEvoy) valve has unique features of a split gate. the hand operated gate valves used for the choke manifold and kill line are usually the same type as the HCV. the valve requires a single hydraulic line for opening. The pressure-assist feature limits the long sea chest valve to a maximum 2400m water depth for failsafe spring closure. Cameron introduced the HCR (High Closing Ratio) as the first remotely controlled valve for choke line service. Rockwell and Vetco. WKM. Two of the more important parameters used in evaluating these valves for floating drilling operations are their susceptibility to forming hydraulic blocks when used in tandem and the water depth sensitivity of their operators.000 psi. On most rigs. Cameron Iron Works and NL Shaffer supply the majority of remotely operated choke line valves since they are initally ordered as a component of the BOP stack. NL Shaffer’s choke line valve is the type DB which is rated for 5000.BP WELL CONTROL MANUAL pressures are required for compatible operations with standard BOP closing units. a pressure-assist hydraulic line is required for normal closure. The Model CB valve with the short sea chest and a pressure-balancing tail rod will failsafe closed at rated working pressure regardless of water depth. Generally.000 psi and higher working pressure BOP required additional valve development. The latter is important because when used subsea.000 and 15. closing mechanism. prior well control reliability and experience should be verified. (d) Subsea Failsafe Valves These valves are made by a number of companies including Cameron. bi-directional sealing valve is governed by the selection of either a short or long sea chest. Because the HCR is limited to 5000 psi working pressure. The seal is always on the downtream side of the gate. and a sealant that is injected to complete the seal. however. Currently. The HCR valve has been used so extensively throughout the industry that most oil field personnel refer to any make of remotely controlled valve as the HCR. smaller in diameter than the stem. When equipped with a long sea chest. 6-32 March 1995 . these are gate valves closed with a spring operated. hydrostatic head alone may be sufficient to hold the valves open (in the absence of closing pressure) if a means is not available to balance the hydrostatic forces acting on the operator and stem. hydraulically operated valves are available with stem and handle for manual operation (to close but not open) in case of hydraulic system failure. NL Shaffer. As an optional feature. 10. the advent of 10. and closure is obtained by spring action plus limited line pressure-assist.000 psi working pressures. sometimes pressure assisted. Although numerous companies manufacture HCVs. Line pressure assists the spring closing action because the pressure balancing tail rod is 1/4 in. Model EDU. the body volume decreases when the valve opens. The tensile rating of the bolts used in these connections must be sufficient to withstand the maximum load which may be imposed. 1972. Cameron rates the Type A and the AF valves for service in water depths to 300m. Bolted flanges or studs are the most common type of connection used. 6-33 March 1995 . flow paths within the body allow redistribution of the small volume change resulting from valve stem movement. Basically. It has no balancing stem. (e) BOP Stack Connections There are three types of connections available for blowout preventer units: flanged. therefore. through-conduit gate valve. but now a modified version. the manufacturer limits the valve to water depths of 900m to ensure failsafe closure. the valve was marginally failsafe in 440m of water. All valves were originally designed with a dog attached to the gate to rotate the seats a fraction of a turn when the valve was opened. The torque applied to the nuts and bolts must meet API recommended values to maintain the pressure seal. Since the valve lacks a balancing stem. A metal-to-metal seat is provided between the moving sealing member (gate) and the stationary seats. The problem of body lock is solved in the same way as fluid lock when the valves are in tandem. is available that is independent of water depth. studded or clamped. WKM claims that the body cavity is so large compared with this change that pressure locking is no problem. • Vetco Type VS Valve The Vetco Type VS subsea gate valve is a full-bore. The Type DF valve is rated by Cameron for service to a water depth of 1800m.BP WELL CONTROL MANUAL Prior to a modification made in June. and 3) the type DF valve is bi-directional with a balancing stem ported to the sea and a vertical fluid passageway on the outer surface of the gate to prevent pressure locking. which reportedly would provide uniform seat wear. Cameron now recommends removal of the dog since its action can induce stresses which may cause the seat to fracture if settled baryte and/or drilled solids prevent seat rotation. 2) The Type AF valve has bi-directional sealing capability with a ported outlet in the lower body cavity to prevent liquid locking. • Cameron Valves Cameron has three subsea valve designs: 1) the Type A valve has a solid gate for uni-directional sealing. • WKM Valve (Model M with D-2-C Operator) This valve will fail safe closed in 570m water depth. If used. Ring Gaskets. Flange Bolts and Nuts March 1995 All blowout preventers.4B of API 6A.000 psi wp Installations API Type 6BX with Type BX Groove MAXIMUM BOLT ** STRENGTH MINIMUM NUT STRENGTH API Type RX ASTM Grade B-7 ASTM Grade 2-H API Type RX or API Type BX w Type 6BX Flange ASTM Grade B-7 ASME Grade 2-H API Type BX ASTM Grade B-7 ASTM Grade 2-H * Acceptable material for flange ring gaskets as per API Spec 6A. drilling spools.RATING OF BOP STACK APPROVED FLANGES 5000 psi wp Installations API Type 6B with Type R Flat Bottom Groove or API Type 6BX w/Type BX Groove 10. ASTM A-193 Gr B M a maximum Rockwell hardness of 22 may be acceptable.16 Specifications for BOP Flanges. flanges should be derated per Table 1. ‘Wellhead Equipment’. adapter flanges will be furnished with the specific API ring joint flange equipment listed below: . Sweet Oil – Low Carbon Steel Sour Oil or Gas – Type 316 stainless steel preferred but Type 304 stainless steel acceptable except for high risk H2S wells. ** In some H2S applications. BP WELL CONTROL MANUAL API Type 6B with Type R Flat Bottom Groove 6-34 2000 psi wp and 3000 psi wp Installations APPROVED * RING GASKETS Figure 6. 000 Flange 11 in. 10.00 13.000 Hub 13 5/8 in.52 22. 10.000 Flange 20 3/4 in.12 25.000 Flange 9 in.38 27. 10.000 Flange 3 1/16 in. 10. 10.52 21. 7 1/16 in.38 22.000 Flange 3 1/16 in. 15.000 Flange 3 1/16 in. 13 5/8 in. 11 in.44 15.000 Hub 3 1/16 in.12 25.000 Flange 13 5/8 in. 10. 5.00 15.12 22. 7 1/16 in. 2.000 Hub 7 1/16 in.000 Flange 11 in.38 22. 3. 11 in. 5.75 21.000 Hub 4 1/16 in.000 Flange 4 1/16 in. 13 5/8 in. 20 3/4 in. 5.000 Hub 13 5/8 in. 3. 11 in. 3.25 16.000 Hub 11 in.25 15.38 19. 10.000 Flange 7 1/16 in. 3.000 Flange 21 1/4 in. 7 1/16 in.000 Flange 3 1/16 in.12 29. 1. 500 Flange 12 in. 10. 7 1/16 in.000 Flange 3 1/16 in.75 21.000 Hub 13 5/8 in.50 15.00 19.50 13.12 27. 3.50 16.00 15. 5. 5.25 19.000 Flange 11 in. 3. 3. 11 in.000 Flange 3 1/16 in.000 Hub 11 in. *30 in. 3. 9 in. 5. 10.88 22. 5. 5. 3.52 6-35 March 1995 .000 Flange 7 1/16 in.000 Flange 3 1/16 in. 3.62 18.38 22. 13 5/8 in.000 Flange 9 in. 21 1/4 in.000 Flange 3 1/16 in. 5.000 Hub 21 1/4 in.000 Hub 21 1/4 in. 5.000 Flange 3 1/16 in.75 27. 10. 21 1/4 in.000 Flange 4 1/16 in.000 Flange 11 in.000 Flange 13 5/8 in. 9 in.38 23.000 Flange 2 1/16 in.88 20.000 Flange 3 1/16 in.12 27.000 Hub 4 1/16 in.000 Flange 510 525 510 500 525 1025 1075 1400 700 725 710 725 950 975 1065 1290 2190 2215 1285 1310 1710 1055 1080 1755 1780 1050 1075 3325 3355 1925 1950 2590 2615 2540 2565 1850 1800 1850 1850 1825 2380 2320 2500 2450 16. 11 in.12 18. 11 in.17 Hydril Drilling Spool Data B A WEOX02.000 Flange 4 1/16 in.25 13.75 19.38 25.000 Hub 4 1/16 in. 13 5/8 in. 5.75 19.000 Flange 3 1/16 in.) 7 1/16 in. 10. 13 5/8 in.000 Flange 21 1/4 in.52 22.38 31.52 27.75 21. 3. 15.38 23.00 20.000 Flange 3 1/16 in. 2. 21 1/4 in. 10. 9 in.50 16. 5.25 17. 11 in. 2.75 27. 10.62 22. 1.25 17.000 Flange 13 5/8 in. 11 in. 20 3/4 in.000 Flange 4 1/16 in. 3.38 22. 20 3/4 in. 5. 10. 7 1/16 in.18 15. 5. 3.38 22. *30 in.75 21. 5.000 Flange 3 1/16 in. 5. 13 5/8 in.000 Flange 9 in. 2. 3.000 Flange 3 1/16 in. 20 3/4 in.000 Flange 3 1/16 in.000 Hub 4 1/16 in.000 Flange 3 1/16 in.000 Flange 11 in.000 Flange 30 in. 3. 5.25 25. 1.12 21.12 23. 9 in. 500 Flange 29 1/2 in.) (B) SPOOL CENTRE LINE TO FLANGE OR HUB FACE (in.000 Flange 3 1/16 in.000 Flange 4 1/16 in.000 Flange 13 5/8 in. 5.00 19.000 Flange 7 1/16 in.50 16.12 25.000 Flange 7 1/16 in.000 Flange 7 1/16 in.000 Flange 13 5/8 in. 21 1/4 in.000 Flange 20 3/4 in.00 27.62 18.000 Flange 21 1/4 in. 10.000 Flange 13 5/8 in.12 27. *29 1/2 in. 5.000 Hub 3 1/16 in. 5.12 18.000 Flange 13 5/8 in.000 Hub 20 3/4 in.000 Flange 12 in. 5.12 18.75 27. 500 Flange 7 1/16 in. 15. 5.000 Flange 11 in. 10. 21 1/4 in.18 16. 7 1/16 in. 11 in. 13 5/8 in.000 Flange 7 1/16 in. 5. 10.38 23.62 23.000 Flange 4 1/16 in. 3. 13 5/8 in. 5.75 21.000 Flange 11 in.000 Flange 20 3/4 in. 5.000 Flange 9 in. 5. 2.00 40. 5. 3. 3.000 Hub 7 1/16 in. *29 1/2 in. 13 5/8 in.180 BORE CONNECTIONS SIDE OUTLETS WEIGHT (lb) (approx) (A) HEIGHT (in. 5.75 40. 5.000 Flange 3 1/16 in.000 Flange 7 1/16 in.000 Hub 4 1/16 in.50 17. 10.75 27.000 Flange 3 1/16 in.12 18.00 19. 5.75 31.BP WELL CONTROL MANUAL Figure 6. 5. 2.75 25.38 23. 7 1/16 in. 10.000 Flange 3 1/16 in.25 18.000 Flange 3 1/16 in. 500 Flange 30 in. 5. 13 5/8 in.25 13.62 18. 5. 7 1/16 in.50 19.000 Flange 3 1/16 in. 10.52 22.62 18.50 13.000 Flange 4 1/16 in.000 Hub 29 1/2 in. 15.50 17.000 Flange 4 1/16 in.38 18.88 20.000 Flange 4 1/16 in.88 20. API Type RX and Type BX ring-joint gaskets are pressure-energised seals but are not interchangeable. two remotely adjustable chokes. The system offers complete redundancy.000 psi range. This problem has been greatly reduced by the manufacturer furnishing recommended bolt torque make-up values and the avialability of power torque wrenches on the rigs. rubber or other resilient materials are not acceptable. API Standard 6A. 6-36 March 1995 . The spool provides space between ram preventers to facilitate stripping operations and localises possible erosion during well control operations in the less expensive spool rather than the preventer body. provides specifications for flanged wellhead fittings. Drilling spools should be designed and fabricated inaccordance with API 6A. Bolts must always be the right size – not larger and not smaller than required for the specific bolt holes. lower rated valves are acceptable downstream. It is important that the ring groove in the flange be clean and dry prior to flanging up. When a clamp connected BOP stack is used. 6 Choke and Standpipe Manifolds (a) Choke Manifold A typical choke manifold layout is shown in Figure 6. ‘Wellhead Equipment’.17 shows dimensional data for Hydril’s drillingspools.BP WELL CONTROL MANUAL API high-pressure connections are pressure sealed by means of ring-joint gaskets made of soft iron. because the wrench movement is downward instead of horizontal. the kill or secondary choke line and from the kill pump.16 lists specifications for BOP flanges. All flanges in the stack and side-outlets should be fitted with new ring-joint gaskets each time they are assembled. especially in cramped quarters. Rings that have been coated with Teflon. ring gaskets and bolts. two manually adjustable chokes. a straight choke bypass. (except of the buffer tank) since flow can be directed via an alternative route whilst a section is repaired. API Type 6BX flanges are available for the 5000 psi to 30. Figure 6. API Type 6B flanges are available in the following pressure ratings: 2000 psi to 5000 psi range. Cameron Iron Works clamp connections are installed on most major manufacturers’ hub and clamp preventers. Figure 6. low-carbon steel or stainless steel. recommended torque requirements should be obtained from the manufacturer and all bolts should be made up to the required torque with power wrenches. Most wellhead manufacturers can fabricate drilling spools to any dimensions required although lead time is usually several weeks. a buffer chamber and outlets to the pits. It features inlets for the primary choke line. (f) Drilling Spools Drilling spools are recommended for choke and kill line outlets on all BOP stackarrangements (subsea BOP stacks and low pressure surface stacks are excluded).18. Hub and clamp connectors are principally used on subsea BOP stacks to reduce the weight and height. ‘Specifications for Wellhead Equipment’. Each choke can be isolated by two valves on the high pressure side. When clamp connectors were first used there were numerous problems with the clamp loosening during drilling operations and creating a hazard in well control situations. The bolts are designed for easier make-up. direct or via the poorboy degasser. Valves upstream of the chokes should be rated to the working pressure of the BOPs. This manifold. A recording chart for standby pressure and choke manifold pressure. (b) Standpipe Manifold A typical arrangement of standpipe manifold showing connections to the choke manifold is illustrated in Figure 6. should not be used. or circulating head. permits one mud pump to be lined up on the annulus. All connections should be flanged. An inlet to facilitate the tying-in of a specialised choke manifold during formation testing is also provided. or clamped. 6-37 March 1995 . as previously mentioned. It is recognised that the majority of choke manifolds installed on drilling rigs comprise a buffer tank into which all the lines downstream of the chokes are tied. and should have read-outs for standpipe manifold pressure. but the isolation valve should be the same pressure rating as the BOP stack. one of which must be remotely adjustable. for example. mandatory in some areas. an additional outlet from the buffer chamber is provided. valves on the choke line and manifold should be left open up to the valve immediately upstream of the remotely operated choke that will be used in the event of a kick. to facilitate control of severe lost circulation. The control panel for the chokes should be near the Driller’s station. On wells where there is a possibility of encountering hydrogen sulphide. The remote adjustable choke(s) should be left closed. Consideration should therefore be given to installing split buffer tanks and separate flare lines or. Under normal drilling conditions. (through kill line perhaps via the choke manifold) and the second to kelly. This chart can be used when testing BOPs. the manifold is in effect rendered useless. It must be possible to record choke pressure when the well is shut-in with the choke manifold lined up in this manner. it is acceptable to use 5000 psi standpipe manifolds. or when handling kicks. Field welding is not acceptable.000 and 15. where fitted. Company policy specifies that choke manifolds should incorporate at least two variable chokes on offshore rigs. The outer choke (HCR or failsafe) valve on the BOP stack should be closed during drilling. so that hydrocarbons can be directed via a production separator to a flare. may also be considered. as should connecting pipework. Field personnel should be aware that this design compromise seriously reduces the flexibility/redundancy of the manifold.19. a bypass line upstream of the buffer tank. all equipment and material should be suitable for sour service.BP WELL CONTROL MANUAL A bypass line to the poorboy degasser is provided in order to be able to deal with returns in the event of failure of the buffer tank. For 10. welded. On some manifolds. choke manifold pressure and pump stroke counters. If the buffer tank cuts out. The MAASP function.000 psi BOP systems. The valves downstream should be open to the poorboy degasser and mud tanks. A pressure gauge reading standpipe pressure should be located at the choke manifold if manual chokes are used during a well kill operation. 18 Choke Manifold. 4. 3. 10M/15M BYPASS TO POORBOY DEGASSER OR TRIP TANK TO POORBOY DEGASSER TO MUD PITS 2 4 2 3 PRIMARY CHOKE LINE BOP STACK KILL OR SECONDARY CHOKE LINE 1 1 1 1 2 CHOKE BYPASS LINE 1 2 1 3 RESERVE PIT (DERRICK FLARE OFFSHORE RIGS) BUFFER CHAMBER FROM KILL PUMP TO GAUGE 2 4 MANUAL CHOKE LINE 1.BP WELL CONTROL MANUAL Figure 6. 10000psi gate valves. 2.181 6-38 March 1995 . FROM DST CHOKE MANIFOLD DST LINE 2 BURNING LINE (PRODUCTION GAS SEPARATOR OFFSHORE RIGS) WEOX02. 5000psi gate valves. Remote controlled chokes. Manually adjusted chokes. minimum on offshore rigs) and as straight as practical. consisting of an annular preventer and vent lines. will be diverted. There should be no restriction to the bore. erosion and the risk of plugging by well debris. A surface diverter system. but instead. allows the flow to be directed to a safe area.g.19 Standpipe Manifold 7 Diverters If a kick is taken when conductor is set in incompetent formation. the well will not be shut-in. the lines should be flushed through to ensure that they remain unobstructed. To prevent the well being inadvertently shut in. The lines should be sufficiently braced to absorb severe shock loadings. 2.182 Figure 6. away from the rig and personnel. the control panels should be clearly marked that the well is not to be closed in. MUD PUMP WEOX02. sections likely to suffer erosion e. 5000psi gate valves. so that no valves are necessary. bends. Gate valve to suit pressure rating of standpipe manifold.BP WELL CONTROL MANUAL SECONDARY STANDPIPE PRIMARY STANDPIPE ISOLATION VALVE SAME RATING AS CHOKE MANIFOLD TO REMOTE PRESSURE GAUGE 1 1 2 2 1 1 AUXILIARY TIE-IN POINT TO HOLE/FILL LINE OR TRIP TANK 1 TO CHOKE MANIFOLD OR PRESSURE GAUGE MUD PUMP 1. but that the diverter is to be actuated. any valves in the lines should be full opening ball valves. If the BOP stack is installed. should be reinforced. An acceptable alternative is to elevate the vent line above the flowline. Periodically. any valves in the vent line should be designed to automatically open when the diverter is closed. 6-39 March 1995 . so as to minimise back pressure. Vent lines should be as large (12 in. BP WELL CONTROL MANUAL Figure 6.20 Subsea Diverter Stack 21in HST RISER COUPLING PIN MUD BOOST LINE CONNECTION 211/4in – 2000 MSP ANNU-FLEX FLEX JOINT ANNULAR BOP 21in HYDRAULIC CONNECTOR 211/4in – 2000 SHEAR RAM OUTLET NOZZLE(S) 211/4in – 2000 FSS SPOOL BLIND FLANGE C/K VALVE 30in LATCH WEOX02.183 6-40 March 1995 . In order to move the rig off location the blind/shear rams can be closed and the connector released. Company policy states that subsea wells should be drilled riserless until a pressure containment string is set. the dump valves will be opened and the annular closed. Various stacks have been custom made for diverting subsea in areas of high incidence of shallow gas. • LMRP with annular preventer. In the event of a shallow gas flow the dump valves will be opened and the annular closed to divert subsea. 6-41/42 6-41 March 1995 .BP WELL CONTROL MANUAL The working pressures of the diverter and vent lines is not of prime importance (particularly on floating rigs where the slip joint packing may be the limiting factor). 500 psi is a typical rating. If however it becomes necessary to drill for surface casing with a riser.). This will be a relatively inexpensive stack that will in most cases be made up mainly from existing rig equipment. The most likely stack up that will be used to divert subsea will comprise the following: • Pin connector with subsea dump valves (minimum ID 10 in.20. An example is shown in Figure 6. Company policy states that the well will be diverted subsea in the event of a shallow gas flow. This is to avoid allowing shallow gas flow to the rig. the diverter stack comprising: • Flex joint • Annular preventer • Hydraulic connector • Blind/shear ram • Spool piece with two outlets with dump valves • Choke/kill line • Hydraulic connector In the event of a shallow gas flow. In order to move the rig the LMRP can be disconnected and the well allowed to flow at the seabed. BP WELL CONTROL MANUAL 6.3 CONTROL SYSTEMS Paragraph Page 1 General 6-44 2 Power Source 6-44 3 Control Manifolds 6-46 4 Accumulators 6-47 Illustrations 6.23 Ram Preventers – fluid required to operate 6-50 6.21 Subsea Stack Function Schematic 6-45 6.22 Annular Preventers – fluid required to operate 6-48 6.24 Compressibility Factor – Nitrogen 6-51 6-43 March 1995 . and where possible. located at the main control manifold. (c) Battery Packs Where electric panels are used. in emergencies. For 3000 psi accumulator systems. 6-44 March 1995 . Water depth considerations will also influence the design of subsea BOP control systems. Diesel driven pumps may be substituted for land rig applications. For 3000 psi accumulator systems. size and pressure rating of BOPs. The essential elements of a control system are: • Power Source(s) • Control Manifolds • Accumulators • Connecting Pipework/Hose Bundle and Wiring Detailed specifications for a particular application will be governed by the number. 2 Power Source (a) Primary Power Source The primary power source should be an electrically driven pump (or pumps) located at the main control manifold. where possible. An example arrangement for subsea BOP systems is shown in Figure 6. (b) Secondary Power Source The secondary power source should be an air power pump system. 150 ft from the well axis. This should be located. also to close an annular preventer (without accumulator assistance) in less than 2 minutes. a battery pack is required. rapidly. conveniently. A standby diesel driven air compressor piped to the pumps should be provided at a location away from the primary rig power source.BP WELL CONTROL MANUAL 1 General The Control System provides the means to individually close and open each BOP and valve. repeatedly and at the correct operating pressure. and for electro-hydraulic systems. primary rig power may not be available. The equipment should be designed to operate when. 150 ft from the well axis.21. the pump(s) should incorporate a pressure switch set to cut in and out at 2750 psi and 3000 psi respectively. the pump(s) should incorporate a pressure switch set to cut in and out at 2800 psi and 3000 psi respectively. The electric pump output should be twice that of the secondary air pumps. The combined electric and air pumps should be sufficient to charge the accumulator system from pre-charge to operating pressure in less than 15 minutes. BP WELL CONTROL MANUAL DRILLER’S PANEL DRILLER’S PANEL MINI PANEL OPEN BLOCK CLOSE RIG POWER 120V ac ACCUMULATORS DRILLER’S PANEL MINI PANEL OPEN BLOCK CLOSE ACCUMULATORS RIG POWER 120V ac RESERVOIR MINI PANEL OPEN BLOCK CLOSE RIG POWER 120V ac ACCUMULATORS RESERVOIR RESERVOIR SOLENOIDS RIG AIR COMPRESSOR 3000psi PUMP RIG AIR COMPRESSOR 3000psi PUMP KR KR YOUR RIG RIG AIR COMPRESSOR 3000psi PUMP POD SELECTOR AIR VALVE YOUR RIG KR YOUR RIG PILOT REGULATOR POD MOUNTED REGULATOR POD SELECTOR SPM VALVE KR KR KR REDUNDANT POD REDUNDANT POD REDUNDANT POD MALE POD CONNECTOR FEMALE POD CONNECTORS POD LATCH SHUTTLE VALVE RAM PREVENTER CLOSING LINE BOP RAM PREVENTER OPENING LINE WELLHEAD RAMS CLOSED BLOCK POSITION (RAMS CLOSED.184 Figure 6. NO PRESSURE) 3000psi Accumulator Fluid Pressure 125psi Rig Air Pressure Vent/or No Pressure RAMS OPENED Regulated KR Fluid Pressure WEOX02.21 Subsea Stack Function Schematic 6-45 March 1995 . • Pressure gauges for accumulator. air-hydraulic or electro-hydraulic. regulated manifold and annular pressures and flowmeter. • A relief valve for the hydraulic and electric pumps. manifold and annular pressures. An additional function is required on subsea stacks to transfer command between hose bundles or pods. wellhead disconnect). The accumulators and charge pumps are usually located with this manifold. • Read-outs for the accumulator pressure. • A schematic of the BOP arrangement showing kill and choke line outlets. • A valve to bypass the manifold regulator. Required features include: • A regulator to reduce accumulator pressure to manifold (operating) pressure for the ram preventers and valves. extension arms and wheels should be provided for ram type BOPs. 6-46 March 1995 . • A flowmeter to indicate the volume of fluid used in operating a function (essential on subsea stacks. • Air supply pressure read-out. for all functions. and air lines. (a) Central (Main Control) Manifold This manifold should be located away from the rig floor area and in an accessible location. A locking device should not be used. • Tie-in points for accumulators.BP WELL CONTROL MANUAL (d) Manual Closing of BOPs For surface BOP installations. or switches. It should be air or electric operated. • Control handles. remote panels. • A vent line for bleeding off accumulator fluid to the storage tank. Required features include: • Controls for each BOP stack function and to adjust the manifold regulators. and having ram sizes marked. 3 Control Manifolds The BOP control systems should ideally be equipped with 3 control manifolds or panels. (b) Driller’s Control Panel The panel should be located on the rig floor within easy access of the Driller’s station. desirable on surface stacks). A hinged cover should be placed over critical functions (shear/blind rams. It may be all hydraulic. Explosion-proofing is required for electric panels. • A regulator to reduce accumulator pressure to the variable operating pressure for annular preventers. charge pumps. air pressure. wellhead disconnect. • A schematic of the BOP arrangement showing kill and choke line outlets and having ram sizes marked. The optimum bladder inflation. without pump assistance. • Visual and/or audible warning devices for low accumulator pressure. to ensure acceptable response times. eg shear rams. for critical functions. is governed by the minimum acceptable pressure remaining in the accumulators after operation of the preventers. at least two accumulators should be isolated from the main bank to provide pilot line pressure. Accumulator bottles should be used as surge dampeners on annular preventers for stripping operations on both surface and subsea BOP stacks. The purpose of the accumulators is to provide a store of hydraulic energy and a high rate supply of hydraulic fluid to the BOP functions. • Where applicable. controls for diverter functions. • Covers. or interlocks. (a) Accumulator/Precharge Operating pressure of accumulators is generally 3000 psi. About 1200 psi is required to hold some annular preventers closed. or fluid levels. The accumulators should be located near the main control manifold location. or precharge pressure. For subsea installations. 4 Accumulators The hydraulic fluid required to operate the BOP functions is stored in accumulators. • Visual and/or audible warning devices for low accumulator pressure. it is normally located in the Toolpusher’s office. Required features include: • Controls for each BOP stack function. It should be air or electric operated. air pressure or fluid levels.BP WELL CONTROL MANUAL • Covers. for critical functions. For offshore rigs. Also. The response time of the BOP functions is therefore independent of the output of the pumps. A precharge of 1000 psi will retain a small liquid reserve in the accumulator when pressure in the system falls to 1200 psi. (b) Sizing of Accumulators Company policy for surface stacks specifies that the total accumulator volume should be 1 1/2 times that required to close one pipe ram and one annular preventer and open one hydraulically activated choke and still retain accumulator pressure equal to 200 psi above pre-charge pressure. 6-47 March 1995 . (c) Remote Manifold (or Panel) This panel should be located a safe distance from the well axis. pressurised against a nitrogen inflated bladder. or interlocks. additional accumulators should be mounted on the BOP stack. 000 2.000 3.000 5.000 10.8 7.6 28.4 9.8 19.000 2.22 Annular Preventer – fluid required to operate 6-48 March 1995 Spherical Balancing .4 44.000 5.5 14.8 5.000 10.4 6.2 3.000 5.9 33.7 5.000 3.55 gal Precharge to 1000 psi.6 gal (See Figures 6.7 19.6 3.6 37.2 24.2 23.0 20.8 Close Open Close Open 2.1 11.5 9. maximum operating pressure = 3000 psi.7 6.8 14.8 17.0 29.000 3.2 3.000 3.2 3.8 Figure 6.8 23. 5M annular and 3 Hydril 18 3/4 in.000 3.000 5. minimum operating pressure = 1200 psi ANNULAR PREVENTERS GALLONS OF FLUID REQUIRED TO OPERATE AN OPEN HOLE NL Shaffer Hydril Size and Working Pressure GL GK Inches psi Close Open 6 6 7 1/16 8 8 10 10 11 11 12 13 5/8 13 5/8 13 5/8 16 16 16 3/4 16 3/4 16 3/4 18 18 3/4 20 20 20 21 1/4 30 30 3.0 34.1 14.0 8.0 48.3 12.000 10.3 4.0 14.000 5.23) Total fluid required = 61.000 3.4 4.5 21.BP WELL CONTROL MANUAL The following is an example of the technique that can be used to size accumulators for a surface stack (comprising one Hydril GL 18 3/4 in.7 18.6 47.5 = 92.0 7.0 5.1 gal = 0.0 58.000 3.8 19.000 2.5 17.0 25.6 17. 10M ram preventers): Volume to close: 1 Annular 1 Ram 1 HCR valve = 44 gal = 17.000 5.4 37.6 14.6 8.000 2.8 33.000 5.0 18.9 9.6 4.000 5.22 and 6.000 10.8 8.3 33.2 11.2 17.6 25.2 32.6 21.000 2.000 1.4 47.7 gal X 1.000 5.1 11.0 44.5 61.9 3.0 58. 8 11.25 Close 5.9 3.19 26.000 3.4 5.5 10 11.07 7.5 5.000 5.11 9.9 11.05 12.45 4.29 10.14 27.000 5.9 5.5 5.40 7.5 10 8.77(S) 7.000 10.42 6.3 Open 1.74 2.9 11.03(S) 5.77(S) 17.36(S) 5.42 9.78 5.3 2.11 9.65 13.16 10.15 10.000 5.2(S) 11.70 3.00 9.81 0.50 7.3 2.36 2.000 15.5 14 14 8.10 5.11 E 6 6.55 2.31 4.52 1.5 6.31 4.35 20.500 10.59 2.2 5.46 10.000 15.000 3.03 12.89 2.05 5.16 4.77 2.07 11.61 Close Manual (a) 10 14 14 4.89 5.9 4.45 9.2(S) 4.7 5.00 8.50 4.98 0.9 11.70 2.7 1.000 3.80 5.8 3.9 11.95 0.21 17.46 6.03(S) 3.58 2.000 2.45 9.9 3.March 1995 psi 4 1/16 6 6 7 1/16 7 1/16 8 8 10 10 10 11 11 11 12 13 5/8 13 5/8 13 5/8 13 5/8 13 5/8 13 5/8 13 5/8 16 16 3/4 16 3/4 16 3/4 16 3/4 18 18 3/4 20 20 20 20 21 1/4 21 1/4 21 1/4 21 1/4 21 1/4 21 1/4 26 3/4 26 3/4 10.5 8.000 10.000 3.1 14.52 7.9 12.000 7.65 3.19 24.55 2.000 10.16 4.27 1.45 2.00 14 8.35 6.000 7.16 3.00 8.22 1.61 8.2(S) 11.77 Close Hydril SL 6.8(S) Close Open 12.000 3.88 8.23 5.35 2.54 6.41 23.16 12.35 14 8.45 11.7 2.07 16.31 3.95 3.8 4.0 5.75 Auto (a) 2.23 3.2 2.6 14.000 2.000 2.000 2.6 3.5 8.86(P) 14 14 BP WELL CONTROL MANUAL 6-49 Inches NL Shaffer Cameron Size and Working Pressure Figure 6.78 11.75 3.35 8.56 10.0 7.78 20.00 5.3 2.23 2.47 4.000 5.42 16.000 2.000 10.61 8.2(S) 4.9 3.4 11.05 10 14 14 8.000 15.46 5.000 QRC U Cylinder Size LWS Close Open Close Open 1.44 4.10 9.55 13.54 6.70 0.22 1.54 30.00 23.000 3.46 15.20(S) 21.54 5.8 11.68 4.18 3.19 6.19(S) 11.000 3.0 12.54 3.42 5.75 2.000 10.8(S) 2.8 11.5 11.17 1.03 Inches 8.25 3.000 3.62 7.000 5.000 10.17 0.23 Ram Preventers – fluid required to operate RAM PREVENTERS GALLONS OF FLUID REQUIRED TO OPERATE ONE SET .52 10 14 14 6.000 5.17 1.000 2.00 7.000 3.1 15.18 Open 0.50 10.000 5.17 1.000 3.000 10.84 Open Close Open 2.5 8.36(S) 11.5 7.75 2.44 11.58 1.000 10.42 6.99 5.50 6.36 2.000 5.67 12.81 0.76 14.88 4.97 10.20 5.5 14 14.9 12.22 1.22 1.50 15.84 9.42(S) 9.000 2.27 2.4 11. 06 V2 = 8. (Note that response time will be a function of the hose length and not water depth). Response times can be improved by mounting accumulators directly on the BOP stack.BP WELL CONTROL MANUAL Therefore: P1 = 1000 + 15 = 1015 psi P2 = 1200 + 15 = 1215 psi P3 = 3000 + 15 = 3015 psi Z1 = 1.95 gal/bottle Therefore there is a requirement for: 92.00 Z3 = 1. the speed with which subsea preventers may be operated decreases.57 gal The useable volume per bottle is given by: V2 – V3 = 8.52 – 3.55 4.00 = 1215 X V2 1.57 = 4.52 gal V3 = 3. 6-50 March 1995 .24) where: P1 P2 P3 V1 V2 V3 Z = = = = = = = precharge pressure (psi) minimum operating pressure (psi) maximum operating pressure (psi) bladder internal volume at precharge pressure (gal) bladder internal volume at P2 (gal) bladder internal volume at P3 (gal) compressibility factor for nitrogen Using the gas law: P X V = constant TXZ So in this case: 1015 X 10 1.06 Z3 = 1. This is caused by expansion of the fluid supply hoses and pressure losses in the lines. Space and weight constraints will limit the number of accumulators which can be stack-mounted.06 T = 80°F V1 = 10 gal (11 gal bottle minus 1 gal bladder replacement) (See Figure 6.95 = 19 bottles (c) Subsea Accumulators Accumulators can be mounted on subsea BOP stacks to perform three separate functions: • Response Improvement With increasing water depths.02 = 3015 X V3 1. 3 1.0 100°F COMPRESSIBILITY FACTOR 1.7 400°F 500°F 1.1 1.9 200°F 1. In such installations. This will ideally be for shear ram activation and will also include LMRP disconnect and wellhead connector disconnect.24 Compressibility Factor – Nitrogen • Emergency Use All floating rigs are generally equipped with an acoustic back-up control system.0 0.g.187 Figure 6.BP WELL CONTROL MANUAL 2.8 300°F 1. The acoustic system and accumulator system should be tailored to the stack configuration. For dynamically positioned rigs and rigs to be used in hazardous (e.1 2. The accumulators should be manifolded at the stack.2 1. ice flow) areas this is essential equipment. so that fluid is not lost should the supply lines from the rig be severed.9 2000 4000 6000 8000 10000 12000 14000 PRESSURE POUNDS PER SQUARE INCH ABSOLUTE 16000 18000 WEOX02. 6-51 March 1995 . stack-mounted accumulators should be at least capable of closing one set of rams. one annular preventer and releasing the riser disconnect upon receipt of a command from the acoustic system.5 1.6 600°F 700°F 800°F 1.2 0°F AFTER SAGE 6 LACY API PROJECT No 37 2. For subsea stacks. a tie in should be provided for diver or ROV assistance.4 1. Some preventers require surge vessels on the opening as well as closing sides.22 and 6.23) Total fluid required = 63. The accumulator capacity should be 1. The majority of the accumulators will be located at surface. the greater will be the reduction in useable volume from the accumulators. according to manufacturers’ recommendations. The useable volume from each subsea accumulator bottle will be lower than the equivalent surface bottle. (d) Sizing of Subsea Accumulators Company policy for the sizing of the accumulators for a subsea stack is more rigorous than for a surface stack.421) psi Z1 = 1.5 gal Precharge to 1000 psi plus the hydrostatic of the control fluid. 10M stack): Volume to close: 1 Annular = 1 Ram = 4 Failsafes = 44 gal 17.03 X 1. Nominal 10 gal capacity accumulators should be used. The following is a technique that can be used to size accumulator bottles for subsea operation for 500 m water depth (for 18 3/4 in. Therefore: P1 P2 P3 where: = = = = 1000 1747 1200 3000 + 15 + (500 X 1. The total volume will be provided by the sum of the fluid available at surface and subsea. if more rigorous). The surface located accumulators are sized as previously described however a different technique is used for subsea accumulators. The total volume of accumulators required will be determined by Company policy (or local legislation.09 P1 = precharge pressure (psi) P2 = minimum operating pressure (psi) P3 = maximum operating pressure (psi) V1 = bladder internal volume at P1 (gal) V2 = bladder internal volume at P2 (gal) V3 = bladder internal volume at P3 (gal) Z = compressibility factor for nitrogen 6-52 March 1995 T1 = 80°F T2 = 40°F T3 = 40°F .01 + 15 + 732 = 1947 psi Z2 = 1.BP WELL CONTROL MANUAL • Surge Dampening Surge vessels should be provided for subsea annular preventers to facilitate stripping.5 times the volume required to open and close all the well control functions and still retain accumulator pressure at 200 psi above initial pre-charge pressure. at the stack. The basic difference between designing for surface operation and for subsea operation is that the precharge pressure must be altered to take account of the hydrostatic pressure of the fluid in the supply lines.00 + 15 + 732 = 3747 psi Z3 = 1. The deeper the water.1 gal 2. however a small quantity maybe located on the stack in order to speed the response of the system.4 gal (See Figures 6. The displaced fluid from the opposite function is vented at its pilot valve. to a particular function. • Control lines should be seamless steel tubing of 1 in. A simple hook-up is impractical for subsea applications – too many individual lines to be handled easily and the pressure drop through the length of line would be too great for acceptable reaction times. • Unions and swivels should be used in the BOP stack area to preclude stressing of thelines. When considering a surface hook-up. through a regulator.01 X 540 = 1947 X V2 1. Each then allows regulated fluid to flow. When a particular function is selected. 6-53 March 1995 . the opposite function is vented and the displaced fluid is returned to the reservoir. the simplest hook-up is to assign a dedicated high capacity conduit to each individual function. Flammable hoses should not be used on surface installations.66 gal The useable volume per bottle is given by: V2 – V3 = 8. the following should be noted: • Company policy (after API RP53) recommends that the system ensures ram and small annular preventers (less than 20 in.57 gal/bottle Therefore there is a requirement for: 63.) lines (to direct and control the flow of fluid to a particular function). Concurrently.66 = 3. hose bundles are employed. The pilot lines terminate in function dedicated pilot (SPM) valves which respond to accumulator pressure when a function is selected.5 3.) conduit (to transfer the hydraulic fluid required to operate all functions and recharge the subsea accumulators) and up to 64 pilot (3/16 in. The output of the regulator is manifolded to the pilot valves.BP WELL CONTROL MANUAL Using the gas law: PXV TXZ = constant (T in °R) So in this case: 1747 X 10 1.57 = 18 bottles (e) Pipework/Hose Bundles and Wiring For surface stacks. The bulk line is “teed” with the subsea accumulators and terminates at a regulator which reduces the accumulator pressure to operating pressure. minimum nominal size and ofa pressure rating at least equal to the working pressure of the control system (usually 3000 psi).23 – 4.02 X 500 = 3747 X V3 1. via a shuttle valve.23 gal V3 = 4.) close within 30 seconds and larger annular preventers within 45 seconds.06 X 500 V2 = 8. Instead. fluid flows from the acccumulators. which contain one high capacity (1 in. directly to the function. • BOP closing and opening lines should be routed so as to minimise the risk of damage in the event of a fire or falling debris. The accumulator fluid reservoir should have a capacity of twice the working liquid volume of the accumulators. The reservoir should be self filling. Pure ethylene glycol should be added to prevent freezing when necessary – under no circumstances should sea water be used.e. there should be 100% redundancy. 6-54 March 1995 . • Systems should be duplicated in all hydraulic and electric lines from the main control panel to the BOP stack functions. prior to rerun. the fluid mix should be maintained year round such that the fluid will not freeze at the minimum anticipated temperature for the year. the fluid should be potable water.BP WELL CONTROL MANUAL The pilot valves and regulators are housed in a wireline retrievable pod. (f) Operating Fluids For subsea systems where the fluid from the main supply line is dumped when it is vented. When considering a subsea system. Operating fluids must be non-pollutant and bacteria resistant. • Any unused functions (such as when the low pressure stack in a two stack system is run) should be blanked off to ensure that fluid is not vented by inadvertent operation of that function. with an automatic mixing system for additives. • Dynamically positioned vessels and rigs operating in hazardous areas should have an acoustic back-up system to secure the well and release the riser. It is therefore important to flush out the control lines with the recommended fluid mix when the pods are pulled. Either a light hydraulic oil or a subsea type fluid is suitable. with the recommended percentage of soluble oil added to prevent corrosion. The Driller’s panel and the remote panel should be designed to select and operate either system. A shuttle valve located at each function allows control by either pod. In all cases. Electro-hydraulic systems will be required where water depths preclude satisfactory closing times with all hydraulic systems. the following should be noted: • Company policy (after API RP53) recommends that the systems ensure ram preventers close within 45 seconds and annular preventers within 60 seconds of surface actuation. Most surface installations employ a simple closed system. Control line fluid is in a closed system and hence is not replaced. i. which is duplicated to provide complete redundancy. with the operating fluid returned to the reservoir when it is vented. BP WELL CONTROL MANUAL 6.25 Typical Trip Tank Hook-up – on a floating rig 6-57 6.27 Grant Rotating Head 6-63 6-55 March 1995 .4 ASSOCIATED EQUIPMENT Paragraph Page 1 Mud Control and Monitoring Equipment 6-56 2 Mud Gas Separator 6-57 3 Drillstring Valves 6-60 4 Rotating Heads 6-62 Illustrations 6.26 An example Mud Gas Separator 6-59 6. This (Flo Show) device should have a read-out and alarm at the Driller’s station. The metal volume of the pipe being pulled can be calculated. (b) Flowline Measurement A device should be provided for measurement of flowline mud return rate. A small wireline can be used to connect a float in the tank to the scale on the rig floor. The industry uses two basic types of trip tanks – gravity feed and pump. or continuously. If mud is not added to the hole as pipe is pulled. The pump type system is recommended because it provides for safer and more expedient trip operation. most blowouts occurred due to swabbing or not keeping the hole filled while tripping the drillstring out of the hole.0 barrel the influx or efflux of fluid from the wellbore. The following measurement devices are required for all tanks: • A float for the PVT system. using a trip tank and to keep track of the fluid volume required. To prevent loss of hydrostatic pressure it is necessary to fill the hole on a regular schedule. For this reason. As the drillstring is pulled from the hole. and friction between the pipe and the mud column causes a reduction in hydrostatic pressure to a value less than formation pressure. 6-56 March 1995 . it is possible to reduce hydrostatic pressure to less than formation pressure. a kick will occur. • An internal calibrated ladder-type scale. trip tanks were developed to accurately measure within ± 1. (c) Trip Tank Trip tanks are used to fill the hole on trips. To provide more exact fluid measurements for pipe displacement.BP WELL CONTROL MANUAL 1 Mud Control and Monitoring Equipment Proper installation and operation of this equipment is fundamental to effective primary and secondary well control. but mud additions necessary to replace hole seepage losses due to filtration effects can only be predicted by comparison to the mud volumes required to keep the hole properly filled on previous trips. The following are the most important aspects: (a) Pit Volume Measurement A pit volume measurement device (PVT) should be provided. The trip tank would be isolated from the surface mud system to prevent inadvertant loss or gain of mud from the trip tank due to valves being left open. In the past. • A remote ladder-type scale. A calibrated read-out and audio alarm should be installed at the Driller’s station. It should be possible to isolate other floats when the trip tank is in use. visible from the Driller’s station for the trip tank. When this happens. Swabbing can occur when pipe is pulled too fast. the mud level will drop due to the volume of metal being removed. logging or other similar type operations. measure mud or water into the annulus when circulation has been lost. monitor the hole when tripping. it is imperative that a record of mud volume required versus number of stands pulled be maintained on the rig in a trip book for every trip made. A valve must be installed in the flow line downstream of this outlet to block all flow to the shale shakers while making a trip. The hole stays full as each stand of pipe is pulled and excess mud returns to the trip tank through an outlet on the main flow line. This closed circulation system can be monitored by a float system and a digital readout in 1-barrel increments on the Driller’s console. a centrifugal pump takes suction from the trip tank and fills the hole through a line into the bell nipple.25. 2 Mud Gas Separator The separator is installed downstream of the choke manifold to separate gas from the drilling fluid.25 Typical Trip Tank Hook-up – on a floating rig As illustrated in Figure 6. 6-57 March 1995 . This provides a means for safely venting the gas and returning usable liquid mud to the active system.188 Figure 6.BP WELL CONTROL MANUAL TRIP TANK LEVEL INDICATOR REMOTE CONTROL VALVE RIG FLOOR OVERBOARD ROTARY TABLE DIVERTER RETURNS TO SHAKERS HOLE FILL UP LINE FLOWLINE TELESCOPIC JOINT FROM MISSION PUMPS RISER CHECK VALVE DRAIN TRIP TANK PUMP WEOX02. The pump runs constantly while the drillstring is pulled from the hole. It is apparent that ‘gas busters’ for drilling rigs cannot be designed on the same basis since the properties of circulated fluids from gas kicks are unpredictable and a wide range of mixing conditions occur downhole. Since most drilling contractors have their own separator design. however. The main advantage of this type of separator is its operational simplicity which does not require control valves on either the gas or mud discharge lines. Figure 6. gas oil separators can be sized and internally designed to efficiently separate gas from the fluid. low volume gas continually feeds into the circulating fluid. The atmospheric type separator is standard equipment on virtually all rigs and is referred to in the field as a ‘gas buster’ or ‘poorboy’ separator. When a gas kick is properly shut in and circulated out. • A target plate to minimise erosion where inlet mud gas mixture contacts the internal wall of the separator.BP WELL CONTROL MANUAL Basically. During well control operations. mud rheological properties vary widely and have a strong effect on gas environment. This type of separator is installed on rigs drilling in high risk H2S areas and for drilling underbalanced in areas where high pressure. In some situations the amount of mud lost can be critical when surface volume is marginal and on-site mud supplies are limited. The atmospheric type separator operates on the gravity or hydrostatic pressure principle. There are a number of design features which affect the volume of gas and fluid that the separator can safely handle. the flow must be bypassed around the separator directly to the flare line. the main purpose of a mud gas separator is to vent the gas and save the drilling fluid. but also to minimise the risk of circulating out a gas kick without having to shut down to mix additional mud volume. • Diameter and length of gas outlet. This will prevent the hazardous situation of blowing the liquid from the bottom of the separator and discharging gas into the mud system. the mud gas separator should be capable of salvaging most of the mud. For both practical and cost reasons. the Drilling Foreman must analyse and compare the contractor’s equipment with the recommended design to ensure the essential requirements are met. 6-58 March 1995 . This is possible because the fluid and gas characteristics are known and design flow rates can be readily established. rig mud gas separators are not designed for maximum possible gas release rates which might be needed. which provides a method of inspecting plate wear.26 illustrates the basic design features for atmospheric mud gas separators. • A U-tube arrangement properly sized to maintain a fluid seal in the separator. generally 50 psi or less. The essential design features are: • Height and diameter of separator. This is important not only for economic reasons. A pressurised mud gas separator is designed to operate with moderate back pressure. The pressurised separator is considered special rig equipment and is not usually provided by the contractor. Pressurised separators are utilised to overcome line pressure losses when an excessive length of vent line is required to safely flare and burn the hazardous gas an extended distance from the rig. they should handle most kicks when recommended shut-in procedures and well control practices are followed. For production operations. there are two types of mud gas separators: Atmospheric and Pressurised. When gas flow rates exceed the separator capacity. In addition. • Internal baffle arrangement to assist in additional gas breakout. diameter and 16 ft minimum vessel height requirements have proven adequate to handle the majority of gas kicks. which creates a small centrifugal effect on the gas-fluid mixture and causes faster gas breakout. the operating pressure is atmospheric plus pressure due to friction in the gas vent line.5 SG GIVES 6. 6-59 March 1995 . Some separators use tangential inlet.26. As the mud and gas mixture enters the separator. which is usually 4 in. The 30 in. This provides the top half for a gas chamber and the bottom half for gas separation and fluid retention.26 2in DRAIN OR FLUSH LINE WEOX02.189 An example Mud Gas Separator The height and diameter of an atmospheric separator are critical dimensions which affect the volume of gas and fluid the separator can efficiently handle. The separator inlet should have at least the same ID as the largest line from the choke manifold. As shown on Figure 6. the gas-fluid inlet should be located approximately at the midpoint of the vertical height.BP WELL CONTROL MANUAL GAS OUTLET 8in ID MINIMUM GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi) STEEL TARGET PLATE INLET APPROX 1/2 OF HEIGHT INSPECTION COVER SECTION A-A TANGENTIAL INLET 30in OD A A 4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD BRACE 10ft MINIMUM HEIGHT INSPECTION COVER HALF CIRCLE BAFFLES ARRANGED IN A 'SPIRAL' CONFIGURATION TO SHAKER HEADER TANK MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1. The vertical distance from the inlet to the static fluid level allows time for additional gas breakout and provides an allowance for the fluid to rise somewhat during operation to overcome friction loss in the mud outlet lines.5psi MAXIMUM CAPACITY 10ft APPROX 8in NOMINAL 'U' TUBE 4in CLEAN-OUT PLUG Figure 6. contaminated mud returns. 3 Drillstring Valves Drillpipe valves are used to close in the well on the drillpipe bore and to protect surface equipment. This line usually discharges into the mud ditch in order that good mud can be directed over the shakers and untreatable mud routed to the waste pit.BP WELL CONTROL MANUAL The baffle system causes the mud to flow in thin sheets which assists the separation process. There are numerous arrangements and shapes of baffles used. 6-60 March 1995 . both the inside BOP and drop-in valve. Circulating out at a slow rate reduces the risk of exceeding pressure limitations for the well control equipment and provides additional decision reaction time.7 psi. or installed at surface when required and may be of a manual shut-off or automatic check valve type. It is important that each plate be securely welded to the body of the separator with angle braces. In recent years.44 SG mud and total U-tube height of 6 ft. an 8 in. This points out the importance for providing a large diameter gas vent line with the fewest possible turns to minimise line frictional losses. Assuming a 1. Large influx. As previously mentioned. It is important that drilling personnel understand the limitations of all well control equipment and are trained to take remedial action before pressure or capacity limitations occur. Some of the drillstring valves impose restrictions on future operations when installed. The key initial decision that must be made is the pump rate at which the kick will be circulated out. line is recommended to minimise frictional losses.26. For example. the fluid seal in the bottom is lost and gas starts flowing into the mud system. the fluid seal would have a hydrostatic pressure equal to 3. minimum ID gas outlet is recommended to allow a large volume of low pressure gas to be released from the separator with minimum restriction. The mud outlet line must be designed to handle viscous. On most offshore rigs. the vent line is extended straight up and supported to a derrick leg. Primarily these have resulted from drilling contractors not updating their separator design and personnel training standards to handle high pressure gas kicks for deeper drilling operations. Care should be taken to ensure minimum back pressure in the vent line. prevent access below them to the drillstring bore. there have been a number of serious accidents caused by the failure of mud gas separators during well control situations. The ideal line would be restricted to 30 ft in length and the top of the line should be bent outward about 30 degrees to direct gas flow away from the rig floor. Drillstring valves should be rated to the same pressure as the BOP and tested at the same frequency. flame arresters should be installed at the discharge end of the vent line. A 6 in. when in place. high pressure gas kicks should always be pumped out at low rates (generally 1 bbl/minute or less) to minimise the gas release rate at the surface where rapid gas expansion occurs. As shown in Figure 6. If it is intended that the gas be flared. when the gas pressures in the separator exceeds the hydrostatic head of the mud in the U-tube. The mud outlet downstream of the U-tube should be designed to maintain a minimum vessel fluid level of approximately 3 1/2 ft in a 16ft high separator. The valves may be permanently in place. as would be the case with a permanently installed flapper valve. prevents access to the drillstring bore below it. especially when handling gas migration. In the event of a kick while the pipe is off bottom. • The valve is not subject to erosion prior to use. it will be necessary to install a further valve in the string when hanging off in the BOP stack. due to fluid erosion. (c) Drop-in Valves An automatic check valve that is held on surface until required and can then be dropped or pumped downhole to a special landing sub. • The valve will prevent U-tubing. as it can be held on surface until required. Both upper and lower kelly valve should be function tested daily. It is Company policy that a landing sub will be run in all strings. preventing further circulation and continuation of control procedures. • The valve requires regular inspection to check for damage. The upper kelly valve is placed between the swivel and the kelly. • Use of the valve may make reading of drillpipe pressures difficult when a kick has been taken. The following points should be considered: • The valve can be flapper or plunger type with facility to lock open whilst running inhole. When installed. the drop-in valve can be used to allow the pipe to be stripped to bottom. the upper kelly valve provides a means of closing in the drillstring when the kelly is down through the rotary table and cannot be lifted. The lower kelly valve. (b) Float Valves Float valves are frequently used in top hole to prevent backflow during connections and flow up the drillstring in the event of a kick. The following points should be considered: • The valve will have limited ID which may plug. but may be retrieved by wireline with some designs. a float valve is a permanent part of the drillstring. • When in place. allows the closing-in of the drillstring and removal of the kelly if required. whilst downhole. The kelly valve provides a means of isolating the kelly if the drillpipe pressure approaches the pressure rating of the kelly. that may be required to free differentially stuck pipe.BP WELL CONTROL MANUAL The following are the most commonly used drillstring valves: (a) Kelly Valves Kelly valves should be full opening valves to allow running of wireline. • If a ported float is used when drilling from a floating rig. If a float is run while drilling below surface casing. the valve should be ported. 6-61 March 1995 . It should not be used whilst drilling highly overbalanced permeable sections without due consideration. Ported floats should be run whilst drilling below surface casing. Wrenches for operating the valves should be held on the rig floor. which is placed between the kelly and the drillstring. A drive unit. Commonly called a Gray valve and in accordance with Company policy. It is recommended that they are not installed for routine gas cap drilling (unless sour gas is expected) since their use precludes observation from the rig floor of annulus fluid level. or the drop-in check valve. to divert the returns through a “Blooey line”. This is especially important where Hydrogen Sulphide can be expected. They provide a seal on the kelly or drillpipe. This includes kelly cocks. • To keep gas away from the rotary table. • As a diverter for surface hole. rotating heads are installed above the BOP stack. (e) Inside BOP A surface installed check valve to close off the drillstring bore. locates in a bearing assembly above the stripper rubber. 6-62 March 1995 . Prevents access to the drillstring bore below it and cannot be removed if below the rotary. • To permit drilling with underbalanced mud. or under pressure (unless a drillpipe safety valve is installed below it).BP WELL CONTROL MANUAL • All the items in the drillstring above the landing sub must have sufficient ID to allow the check valve to pass. Realistic working pressures for rotating heads are 500 to 700 psi. allowing the drillstring to be closed in. should always be available on the rig floor as a back-up for the drillpipe safety valve. It is Company policy that such a valve should at all times be available on the rig floor. Some applications for rotating heads are: • Drilling with air or gas. attached to the kelly. 4 Rotating Heads When used. The valve should be a fullbore valve. (d) Drillpipe Safety Valve A safety valve to be installed at surface on detection of a kick. typically a lower kelly valve to allow easy stab-in wireline access if required.27 shows a schedule of the Grant Rotating Head. Crossovers between the safety valve and all other tubulars in hole must be held on the drillfloor. by maintaining a back pressure on the wellbore. mud savers etc. Figure 6. BP WELL CONTROL MANUAL Figure 6.190 6-63/64 6-63 March 1995 .27 Grant Rotating Head KELLY BUSHING SWING-BOLT CLAMP ASSEMBLY DRIVE BUSHING ASSEMBLY SHOCK PAD DRIVE RING AND BEARING ASSEMBLY BOWL STRIPPER RUBBER OUTLET FLANGE INLET FLANGE WEOX02. 5 EQUIPMENT TESTING Paragraph Page 1 General 6-66 2 BOP Equipment and Wellheads 6-66 3 An Example Test Procedure 6-67 4 Test Frequency 6-71 5 Pressure Tests of Casing 6-71 Illustrations 6.30 Schematic of BOP Pressure Tests 6-70 6.28 Choke Manifold Schematic 6-68 6.BP WELL CONTROL MANUAL 6.31 An example BOP Equipment Test Report 6-72 6-65 March 1995 .29 An example BOP/Choke Manifold Test Procedure 6-69 6. 2 BOP Equipment and Wellheads Preferably. It should be conducted to the working pressure of the wellhead or ram preventers. Equipment should be tested at the time of installation on the wellhead and at regular intervals thereafter. the initial test of the wellhead connector should be against the lowest pipe rams). 300 psi) and the final test pressure reached in increments. in the event of a leak. The bore of the test string or the casing valve should be open during testing to prevent pressure being applied to the casing or formation. 6-66 March 1995 . Common causes of failure include: • Casing wear.g. and rectified before an emergency arises. pressure testing should be conducted with water against a solid type plug which is supported by the wellhead and seals either above or below the pack-off.g. • Wellhead or BOP connections working loose through vibration. Rigorous BOP testing procedures are required in order that problems may be identified under test conditions. the initial pressure test of all BOP functions should be conducted on a test stump prior to installation.BP WELL CONTROL MANUAL 1 General The consequences of a failure of BOP equipment under operating conditions can be far reaching. • Leaks and faults occurring in control systems. the initial sequence of tests should be arranged so as to minimise the volume of fluid pressurised (e. in the event of the test plug leaking. thereby minimising the damage caused by fluid cutting. and warn of the possible risk of collapsing the casing. if a stump is not available. in accordance with Company standard policies and guidelines (unless contradicted by local policies). should be closely monitored to determine whether the pack-off is leaking. Annular preventers should be tested to a maximum of 70% of their working pressure. a wellhead/BOP test pressure that holds stable for 10 minutes is considered satisfactory. • Deterioration of seals in valves and BOPs. However. • Plugging of lines with baryte. whichever is the lowest. The recommended procedures in this section cover BOP stack installations at surface andsubsea. All high pressure tests should be preceded by a low pressure test (e. Normally. (a) Initial Pressure Test If possible. The rate of pressure increase due to volume pumped. or the burst pressure of the strongest casing to be run. Where possible. the test should be conducted on the wellhead immediately after installation. At subsequent BOP tests. suspended from the test plug. Test pressure is applied both at point A and point B at all tests other than 4 and 5. A test sub is required for testing the string tools from below.BP WELL CONTROL MANUAL After latching a subsea stack. casing have been run. This means that the failsafes on the upper kill line can only be tested from the inside to the test pressure of the annular. Also. drillpipe safety valve. The inner and outer choke and kill line failsafes can be tested from the outside before the stack test is started as these tests do not require a test plug in the stack. The blind/shear rams are tested on installation and after the 13 3/8 in. the main control panel. when it is applied at point A only. the procedures as outlined in Chapter 1. A pressure test should be carried out to the pressure rating of the wellhead or connector. 3 An Example Test Procedure The following is an example test procedure for a four ram preventer subsea stack and associated choke manifold. in this example. Tests should be carried out using. as the stack. 80% of the casing burst pressure. in rotation. the control system should be function tested on both pods. 6-67 March 1995 . a tensile test should be applied to ensure connectors are properly latched before any pressure testing. thereafter. The blind/shear rams are not tested on a routine basis in line with Company policy. the connector will be tested during BOP tests to the pressure that the BOPs will be tested to. (b) Routine Pressure Tests Routine testing of the BOP (pipe rams and valves) and wellhead pack-offs should be conducted to either the maximum anticipated wellhead pressure. (c) Pressure Testing of Associated Equipment The upper and lower kelly cocks. and to the same pressure.28. inside BOP and circulating head should all be tested to the lower of the maximum anticipated wellhead pressure or their rated working pressure. If the hole is open. the BOPs should be tested with the drillstring at the shoe. All the components of the choke manifold. Accumulator pre-charge pressures should be checked according to the manufacturer’s recommendations. ‘Drills and SCRs’ in Volume 1 should be adopted. are rated to the same pressure as the stack. Annular preventers should not be tested to more than 70% of their working pressure. and so all the components of the manifold (buffer tank etc) can be tested at the same time. The kill pump is used as the test pump and is tied into the manifold at point A and point B as shown in Figure 6. the blind/shear rams should be function tested according to Company policy. on initial installation of the stack. and 9 5/8/in. until the blind/shear rams are tested. whichever is lowest. choke and standpipe manifolds. To test whether the accumulator and charge pumps are working correctly. Driller’s panel and remote panel. the wellhead rated pressure or the BOP rated pressure. BP WELL CONTROL MANUAL Gauge Transmitter 2in 2202 Weco Female 18 31 32 30 5 19 26 13 8 6 3 1 From Mud Manifold 4 33 From Kill Pump B Gauge Transmitter 27 23 20 14 9 Choke Line 2 28 24 21 15 10 7 From Kill Pump A Auto Choke Manual Choke 29 25 Kill Line Auto Choke Manual Choke 16 17 2in 1502 Weco Female 11 12 35 34 To Production Test Facility 36 22 To Mud Gas Separator To Drain To Diverter Overboard From Cement Pump WEOX02. only one full working pressure test need be made against one pipe ram. are rated to the full working pressure of the stack. Figure 6. 6-68 March 1995 . Figure 6.28 shows a schematic of the choke manifold. Many other manifolds incorporate piping and valves downstream of the chokes that are rated at a lower pressure than the stack.29 shows the procedure for the test as well as details of each component tested at each stage.30 shows how the stack is lined up for each test. This is to confirm the integrity of the wellhead connector. in such cases. it is necessary to conduct a separate test of these components.28 Choke Manifold Schematic Figure 6.191 Figure 6. • On landing the BOP. The following operational guidelines should also be considered for these tests: • The test pressures used for each test are determined to be in line with Company policy for pressure testing of well control equipment. • All subsea pressure tests will be conducted using openbore test tools. As previously stated all the components of this manifold. that are shown on the diagram. 13 UPPER PIPE RAMS. LOWER OUTER KILL. 17. UPPER INNER KILL. 23. 28 LOWER PIPE RAMS. 12. 24. 31 MIDDLE PIPE RAMS. if tested on a separate run. UPPER OUTER KILL. 21. i. UPPER OUTER KILL.29 An example BOP/Choke Manifold Test Procedure 6-69 March 1995 . 33. test plugs will not be run on top of a bottomhole assembly except when testing the blind/shear rams agains a backed-off test plug. 30 UPPER ANNULAR. 19. 26. 17. 22. LOWER INNER KILL 3 2. 34 UPPER PIPE RAMS. 30 LOWER ANNULAR. LOWER OUTER CHOKE 6 2. LOWER INNER CHOKE 5 3. 5. 29 9 1. 19. • All tests should be recorded on a chart. 13. 7. UPPER INNER CHOKE. 19.e. 19. 30. 27. 11. LOWER OUTER KILL 4 3. 10. 8. UPPER OUTER CHOKE. • When pressure testing blind/shear rams against casing consideration should be given to pressure differential that already exists due to any difference in the weight of the mud inside and outside of the casing. 26. 36 8 4. monitor volumes pumpedclosely . 25. 12. 14. 32. 16. 18. 9. 30. TEST CHOKE MANIFOLD VALVES CLOSED BOP LINE UP FAILSAFES 1 3. 7. 22. 7. 7. • When testing blind/shear rams against a backed-off test plug. 6. UPPER INNER CHOKE Figure 6. LOWER INNER KILL. 20. 35. UPPER OUTER CHOKE 7 3. 15.BP WELL CONTROL MANUAL • All tests will be carried out using a suitable test plug with only the specified drillcollarweight below. 20. UPPER INNER KILL. 8. 33 2 2. 30 Schematic of BOP Pressure Tests 2 KILL 3 CHOKE KILL 4 CHOKE KILL UPPER ANNULAR LOWER ANNULAR TEST VALVE TEST VALVE TEST VALVE CHOKE UPPER ANNULAR TEST VALVE LOWER ANNULAR TEST VALVE LMRP CONNECTOR LMRP CONNECTOR LMRP CONNECTOR BLIND SHEAR RAM BLIND SHEAR RAM BLIND SHEAR RAM UPPER PIPE UPPER PIPE MIDDLE PIPE MIDDLE PIPE MIDDLE PIPE LOWER PIPE LOWER PIPE LOWER PIPE CONNECTOR CONNECTOR CONNECTOR 5 6 7 KILL CHOKE KILL UPPER ANNULAR TEST VALVE TEST VALVE LOWER ANNULAR CHOKE KILL UPPER ANNULAR TEST VALVE TEST VALVE LOWER ANNULAR CHOKE UPPER ANNULAR TEST VALVE TEST VALVE LOWER ANNULAR LMRP CONNECTOR LMRP CONNECTOR LMRP CONNECTOR BLIND SHEAR RAM BLIND SHEAR RAM BLIND SHEAR RAM UPPER PIPE TEST VALVE UPPER PIPE MIDDLE PIPE MIDDLE PIPE LOWER PIPE LOWER PIPE CONNECTOR CONNECTOR CONNECTOR WEOX02.BP WELL CONTROL MANUAL Figure 6.193 6-70 March 1995 . • Initial Test Normally. Results of pressure tests should be recorded on IADC reports. Applied test pressure should be the maximum wellhead pressure anticipated before the next casing string is set (i. however in general: • After installation of the wellhead component and BOP stack and prior to drilling out each casing string. high rotary speeds. 6-71 March 1995 . The following additional points should be considered: • Annular and ram (pipe) preventers should be operated on each trip into the hole with the bit at the shoe (perhaps as part of a kick drill). and is accelerated by rough hardbanded drillpipe. Casing design is based on maximum anticipated pressures caused by a limited kick volume. • Choke and kill valves should be operated daily. However.31. Wear or corrosion of the casing bore will reduce burst and collapse strengths of casing and undermine the basis for the design.BP WELL CONTROL MANUAL 4 Test Frequency Pressure testing of BOP equipment should be carried out according to Company policy. a ditch magnet should be installed to monitor metal returns. • Subsequent Tests Where significant casing wear is possible. 5 Pressure Tests of Casing The integrity of casing strings is fundamental to effective well control. if the additional tensile loading caused by the pressure test risks parting the string. the plug should be bumped with a nominal pressure and the full test pressure applied after the string has gained support from the cement prior to drilling out the shoe track. If severe casing wear is suspected. An example of a typical BOP test form is presented as Figure 6. the casing should be tested to prove the string’s integrity when bumping the top plug. • Kelly cocks should be operated daily. The rate of wear depends on the type and duration of operations. • At intervals not exceeding 14 days. following cementing. • At any time requested by the Company Drilling Representative. and crooked hole.e. and lines pumped through. • Choke manifold line-up should be checked each tour. • Blind (but not blind/shear) rams should be operated each time the bit is out of the hole. Pressure testing of casing is required to prove the string’s original integrity and that wear does not subsequently reduce casing strength below an acceptable level. casing design pressure). actual wear should be measured by wireline calliper tools and then the casing tested to the minimum acceptable pressure. Choke line pressure should be monitored before re-opening the rams. and on the BOP test form. (3000-1200psi): Precharges last checked: Recharge time (1200-3000psi): 5 ACCUMULATOR PERFORMANCE CHECK YES NO Functions left in correct mode Remote compressor available Accumulators and Pumps UNIT Time to Close Volume Pressure Initial Final Accumulators only Time to Close Volume Pressure Initial Final Annular Annular Blind Shear Ram Pipe Ram Pipe Ram Pipe Ram CL Inner Valve CL Outer Valve KL Inner Valve KL Outer Valve 6 EQUIPMENT CHECK TEST Are the following items on the rig. vol.BP WELL CONTROL MANUAL Figure 6. in good operating condition and pressure tested? YES NO YES NO YES NO Circulating head Kelly saver sub & rubber Trip tank DP Safety Valve Hang-off tool PVT and alarms XOs to DCs for DPSV Gas buster Flo-show and alarms Inside BOP De-gasser Nitrogen for precharge Drop in BOP sub + dart Gas detector Engine H2O spray and s/d 7 FAULTY EQUIPMENT Mention here leaks experienced in testing parts used. allowable pressure on remote choke: Handles on all valves Water left in K&C lines Standpipe manifold tested K&C lines pumped through Pressure applied CHARGE PUMPS All valves tested Valves last serviced: 4 Test Duration: Manifold line-up OK after test Eletric pump cut in: Accumulator pressure: Electric pump cut-out: Manifold pressure: Filters checked Air pump cut-in: U Annular pressure: Storage tank level checked Air pump cut-out: L Annular pressure: Mixing unit checked Total accumulator volume: Panel used for BOP test: Low level alarms checked Usable accum.31 An example BOP Equipment Test Report 1 BOP STACK PRESSURE TEST Unit Type Size WP Pressure applied Remaining Pressure Test Duration Annular Annular Blind Shear Ram Pipe Ram Pipe Ram Pipe Ram UL Choke Line CL Inner Valve CL Outer Valve UL Kill Line KL Inner Valve KL Outer Valve Remote Kill Line Diverter 2 CASING PRESSURE TEST Casing in hole: Pressure Applied Pressure Remaining Test Duration Mud Weight: 3 CHOKE MANIFOLD PRESSURE TEST Packer Depth: Date Previous Test: Pressure Applied: YES NO YES NO Manifold good for H2S All chokes operated Water left in manifold Setting max. faulty or missing equipment and remedial action 8 SIGNATURES Driller: Toolpusher: 6-72 March 1995 Company Drilling Rep: .