RestrictedEP 2007-3186 Guidelines for Sampling and Analysis of Reservoir and Production Fluids by M. B. Flannery (SIEP-EPT-SCF); B. A. Stankiewicz (SADBV-EPM-PM-AD); F. A. Hartog (GSNL-GSEA/4); D. F. W. Naafs (SIEP-EPT-SCF); M. Grutters (GSNLGSUA; E. Inan (SIEP-EPT-SCF); B. Dindoruk (SIEPEPT-RHF); W. J. R. Nisbet (SEPCo-EP-Americas) R. J. Lesoon; J. T. Westrich (SIEP-EPT-SCF) Sponsor: J. T. Westrich Reviewed by: C. John, T. Hassing Approved by: J. T. Westrich Date of issue: March 2008 Period of work: June 2006 - November 2007 Account code: D-001961-01.15 ECCN number: EAR 99 This report is based on and incorporates: EP2000-9021 (Stankiewicz, 2000), EP92-0980 (Steenson, 1992), TIR BTC-3540 (Westrich and Ratulowski, 1998), and EP05-0758 (Hearn and Dixon, 1979) This document is classified as Restricted. Access is allowed to Shell personnel, designated Associate Companies and Contractors working on Shell projects who have signed a confidentiality agreement with a Shell Group Company. 'Shell Personnel' includes all staff with a personal contract with a Shell Group Company. Issuance of this document is restricted to staff employed by a Shell Group Company. Neither the whole nor any part of this document may be disclosed to Non-Shell Personnel without the prior written consent of the copyright owners. Copyright 2008 SIEP, Inc. SHELL INTERNATIONAL EXPLORATION AND PRODUCTION INC., HOUSTON Further electronic copies can be obtained from the Global EP Library, Houston EP 2007-3186 -I- Restricted SUMMARY This report provides Shell professionals with recommended specifications for acquisition of samples and subsequent analyses required for development or operation of a hydrocarbon accumulation. The document is divided into three main sections: Well-site Support, Sample Management, and Offsite Laboratories; tables are compiled at the end of each section, with figures and appendices assembled at the end. Since printing of the EP92-0980 document, two important developments occurred in the oil industry: 1. Deepwater exploration and production became a routine operation, which led to rapid improvements and developments in single-phase sampling and sample handling, mainly due to flow assurance challenges. 2. CAPEX involved in developments of onshore, composition-sensitive LNG and GTL plants led to the requirement of more extensive compositional analysis and rapid improvements of both well-site chemistry and surface sample handling. Emphasis is placed on obtaining representative samples as early as possible in a development cycle to maximize information required for successful development and minimize later requirements for appraisal wells. This report combines and replaces reports EP92-0980 and EP00-9021 to cover the experience gained since 1992 in downhole sampling and analysis, as well as wellsite chemistry. Parts of the earlier reports have been included without significant alteration so as to give a complete coverage of the topic. Emphasis has been placed on the sampling and handling of single-phase hydrocarbon samples. However, the sampling and analysis of multi-phasic liquid hydrocarbon streams are also addressed. Flow assurance issues were identified as critical to successful deepwater developments, and there was a great increase in the attention given to and development of solids prediction (EP 20017026-21, EP2004-7065_02, and GS.05.51907). Only manual sampling and analysis techniques are covered in this document. Continuous, online sampling, recording or indicating devices for surveillance monitoring are outside the scope of this report but are covered by DEP 32.31.50.10.-Gen, DEP 32.31.50.11.-Gen, DEP 32.31.50.12.Gen, and DEP 32.31.50.13.-Gen. This document briefly addresses the sampling of mud-gas, but not cuttings, during drilling. There will be some differences particular to high-pressure high-temperature (HPHT) reservoirs, unconventional developments, and assisted-lift production (gas or power fluid injection). It is recommended that the appropriate Shell experts be consulted directly when considering those sampling scenarios. This document also covers manual sampling and analysis for monitoring of hydrocarbon production facilities and custody transfer. It is recognised that sampling and analysis for these purposes will frequently be carried out with automatic equipment and so would be beyond the current scope. EP 2007-3186 - II - Restricted Distribution and Intended Use This report is intended for use by all involved in the design and delivery of fluid sampling and analysis programs. Unless otherwise authorized by SIEP, the distribution of this report is confined to companies forming part of the Shell Group or managed by a Group company, and to contractors nominated by them. KEYWORDS analysis, asphaltene , crude oil, downhole samples, engineering, flow assurance, fluid samples, gas analysis, gas sample, geochemical analysis, geochemistry, high pressure, hydrate, live oil samples, oil analysis, oil sample, operation, paraffin analysis, procedures, process, processing, PVT, quality control, representative, sample, sample bottle, sample collection, sample handling, sample integrity, sample storage, sampling, water, water sample, wax Chris John. . Paul Kralert. useful comments and revisions. The following individuals deserve particular mention for their input.III - Restricted ACKNOWLEDGMENTS The author would like to thank the many people who contributed to this report. Al Kili. Wade Skelton.EP 2007-3186 . Wasim Lala. Hani Elshahawi. and Eric Hendriks. Mohamed Hashem. Pat O’Neal. Gordon Macleod. in particular the contributing authors and colleagues responsible for the earlier documents incorporated in this version. Tjerk Hassing. Dan McKinney. John Ratulowski. at specified P/T (e.S./vol.. and Xylene Carbon Carbon # plus range Capital Expenses Constant Composition Expansion Cold Finger Compositional Fluid Analyzer (SLB) Condensate to Gas Ratio (vol.IV - Restricted ABBREVIATIONS AND TERMS USED AAS ADST ADT AED AES AI AIST AMS API ASD ASME ASTM ATR BFD BS&W BSK BTEX C C#+ CAPEX CCE CF CFA CGR CPM CSB CURE CWDT DAWG Dead Oil DL DOT DST DWOP ECD EOR EOS EPB FA FDP FEAST Atomic Absorption Spectroscopy Asphaltene Dispersant Screening Test Asphaltene Dispersancy Test Atomic Emission Detector Atomic Emission Spectroscopy Asphaltene Inhibitor Asphaltene Inhibitor Screening Test Amsterdam Method Series (analytical methods developed and documented by KSLA) American Petroleum Institute Acoustic Sand Detector American Society of Mechanical Engineers American Society For Testing And Materials Attenuated Total Reflectance Basis For Design Basic Sedimentation and Water Bottom-hole Sampling Kit Benzene. Department of Transportation Drillstem Test Drilling the Well On Paper Electron Capture Detector Enhanced Oil Recovery Equation of State Exploration and Production Business Flow Assurance Field Development Planning Fluids Evaluation and Sampling Technology (formerly Fluids Evaluation and . Toluene. cubic feet) Cross-Polar Microscopy Conventional Sample Bottle Crude Upgrading and Recovery Enhancement Critical Wax Deposition Temperature Deepwater Asphaltene Work Group (also Deepwater Asphaltenes + Wax Group) Oil that has been depressurised below asphaltene onset pressure Differential Liberation U.EP 2007-3186 .). Ethylbenzene.A.g. stnd barrel per million stnd. Safety. and Environment High Temperature Gas Chromatography International Air Transport Association Inductively Coupled Plasma International Marine Dangerous Goods Institute of Petroleum Asphaltene Quantification Method International Organisation for Standardization Refers to a sample taken such that the velocity of the fluid in the sample probe is the same as the velocity of the fluid flowing in the stream being sampled. Royal Dutch/Shell Exploration and Production laboratory Royal Dutch/Shell Laboratories Amsterdam Live Fluid Analyzer (SLB) Liquid/gas ratio Oil that has been maintained at or above asphaltene onset pressure Liquefied Natural Gas Liquefied Petroleum Gas Large-Volume Sampler Logging the Well On Paper Multitask Acquisition and Imaging System Modular Formation Dynamics Tester Multisample Production Sample Receptacle MDT Multisample Module MDT Pump-Out Module MDT Sample Chamber Multi-Stage Separation Test Natural Gas Liquid .EP 2007-3186 FFU FID FPA FTHP FTHT FTU GC GCMS GLR GOM GOR GPA GSB GWR HDPE HPM HSC HSE HTGC IATA ICP IMDG IP IP143 ISO Iso-kinetic KSEPL KSLA LFA LGR Live Oil LNG LPG LVS LWOP MAXIS MDT MPSR MRMS MRPO MRSC MSST NGL -V- Restricted Stability Testing) Field Filtration Unit Flame lonisation Detection Floc Point Analyser Flowing Tubing Head Pressure Flowing Tubing Head Temperature Field Transfer Unit Gas Chromatography Gas Chromatography Mass Spectroscopy Gas/liquid ratio Gulf of Mexico Gas: Oil Ratio (standard cubic feet per barrel) Gas Producers Association Gas Sample Bottle Gas–Water Ratio High Density Poly-Ethylene (a.a.k. Nalgene) High Pressure Microscopy High-Shrinkage Chamber Health. T (P)FPD PHJ PLS POAP POOH PSA PTFE PVT RCI RFT RIH ROV RVP SARA SDS SEPTAR SHJ SPMC SRS SSB SSK STO SWOP TBP TCP TVP TWOP va. VRU WAK WBM WFAS .VI - Restricted Near Infrared Non-Reactive Single-phase Reservoir Sampler Non-reactive Sample Bottle Oil-based Mud (drilling mud) Optical Fluid Analyser Operating Expenses Organic Solids Deposition Cell Ounce Pint Pressure and Temperature (Pulsed) Flame Photometric Detector Pressurized Heating Jacket Pressure Letdown System Onset of Asphaltene Precipitation Pressure Pull Out of Hole Particle Size Analysis Poly-Tetra-Fluro-Ethylene (Teflon) Pressure. Volume. Aromatics. Resins and Asphaltenes Solids Detection System Shell Exploration and Production Technology Applications and Research SRS Heating Jacket Single-Phase Multisample Chamber Single-phase Reservoir Sampler Single-phase Sample Bottle Surface Sampling Kit Stock Tank Oil Sampling the Well On Paper True Boiling Point Tubing-Conveyed Perforating Total Vapour Pressure Testing the Well On Paper Molar Vapour Recovery Unit Water Analysis Kit Water Based Mud Wellsite Fluid Analysis System .EP 2007-3186 NIR NRS NSB OBM OFA OPEX OSDC Oz Pt P. Temperature Reservoir Characterization Instrument Repeat Formation Tester Run In Hole Remote Operated Vehicle Reid Vapour Pressure Saturates. .................. Volumes Required for Various Measurements........................................1....... 74 ................. 69 3........................................................... 4 1............................ 58 2..... 21 1... Sampling Mercury (Hg) ........................3...........Hydrocarbon Gases .................................... Incorporating Discipline Expertise................................. 58 2............ 1 1........5........................... Sampling Handling Procedures on the Rig ........................ 34 1.........................................................1.......5........................... 24 1........9. Surface Sampling Methods – Hydrocarbon Liquids ..................................IV 1...............1................................... Mud/Drilling Fluid Sample Collection ......................4......................2. 1 1..............8................................................................................................4......................3......................................................................3........... Sample Validation Carried Out by the Contract PVT Laboratory ....1.......................7.............3.............................. III ABBREVIATIONS AND TERMS USED...... 23 1........................................................ 28 1................................................... 20 1.....1........................................................................ Reservoir Geochemistry ................. 71 3.......................................Water ....3....... Surface Sampling Methods .....2..3........... 38 1... Onsite Sample Validation for Sub-surface PVT Samples – Hydrocarbons ......1........................ 9 1......................................... 63 2................. Priority ...2............... Obtaining Pressurized Downhole Water Samples................... 48 1.....................................................1...........2.. 22 1........... OFF-SITE LABORATORIES .................................. Sampling During Well Test Operations – Hydrocarbons and Water.....................................1.......................3...................4... 31 1... 8 1.......5............ Oil Reservoirs.............................................................................. 8 1............................. Volatile Oil Reservoirs............................... WELL-SITE SUPPORT.............................. 68 3..............3..... Obtaining Pressurized Downhole Hydrocarbon Samples..............................................................................................1........................................................................... 65 3.2...1...... 74 3......2...............2..................10..................................................................................................... Mud Gas IsoTube Sampling ....1.....................3............................. SAMPLE MANAGEMENT ...........1.................1.......... 70 3.........................................1......................6....... Transfer and Validation ...............2.............2...... Planning ............................2......................6.....................................3.. Reservoir Studies ....................... 23 1. Sample Containers ....2..............2.3....................................1.... Sampling Environments ............................. 43 1................................................ 22 1.................................... Open Hole and Cased Hole – Hydrocarbon and Water............... Onsite-PVT and Other Analyses for Hydrocarbons and Water........... 23 1......... 74 3............ 20 1........................... Gas Condensate.................................. 48 2....2.................................. 22 1..................EP 2007-3186 ............................................ and Gas Reservoirs.........................1.....................1.......................................... Sampling for Sand.......3...... Surface Sampling and Onsite Analysis Methods – Contaminants .............. Sampling Points and Conditions...........................................1............................ 58 2...........................................1. 60 2.................VII - Restricted TABLE OF CONTENTS SUMMARY............. IsoJar Headspace Samples ...............1........................ 58 2........................... Basic Geochemical Composition ........................... 5 1........................3.................3............ Subsurface Samples – Hydrocarbon and Water.................................. General......................................................................................................................... Surface Sampling Methods ..................2.........................................4....................................... Sampling for Total Hg by Wet Chemistry.......... Custody Transfer.3.......................5.....2.............2...1.................................................. 68 3..........................3............... 27 1........................................... Fingerprinting Methods ..1...... Sampling Preparation and Equipment Requirements .....I ACKNOWLEDGMENTS ............. Surface Samples .............. ........138 A2. Evaluation of Asphaltene Properties .......1.................................... 77 3....................135 A1........3.............................................156 APPENDIX 6....................1.......................................155 A5........................4..... Black Oil. Water .......... Product Allocation from Shared Facilities ...................................142 A2.............2.... 94 3................155 A5........151 A4......................................................................................................................... 76 3..........................153 APPENDIX 5........................................ LIVE SAMPLE PROCESSING AT THE PVT LAB...............................5............................ EXAMPLES OF ACCEPTABLE SAMPLE LABELS................ Conversion Tables. Components and Contaminants .................................................157 .............4....................... Analytical....4................................................ Differential Liberation Experiment ...... 90 3....................................... Evaluation of Scale Properties ..1................2................................ 98 REFERENCES........................................... Process Simulation and System Design......... Physical Properties................................................................................................................................................... Constant Composition Expansion (CCE) or Constant Mass Expansion (CME) Experiment........... Evaluation of Hydrate Properties........6........................................................................................139 A2....................... Downhole (Wireline and DST) Samples ...............................1......144 A2................. Petroleum Crude Oil .........................3............................... 94 3...................135 A1.........4........................................2...........3................................VIII - Restricted 3..................................136 APPENDIX 2...................... DST Surface Samples.. Fluid Valuation.1.............. Compressed or Natural Gas................................... Evaluation of Bacterial Activity..................157 A6................................ General.................... SURFACE SAMPLING PROCEDURES................................................................ 95 3....... Hydrocarbon Composition .................2..........................................EP 2007-3186 .....................................................2........................................ 94 3...6......... 87 3...............3.................1.......7.... Flammable.............................................3................................. 92 3.....................................................................................2................... EXAMPLE OFF-SITE HANDLING AND PVT PROGRAMS............................................................................150 APPENDIX 4............... 95 4......148 APPENDIX 3...............................1...................................................................... Flow Assurance...... ADDITIONAL WATER ANALYSES ..........................138 A2......................... Constant Volume Depletion (CVD) Experiment......................................................................................2.....4.........................................5................3...........................151 A4........................ 95 3...............................................................................121 APPENDIX 1....... Monitoring of Gas Facilities ................ 76 3........................................................................................................................................... Evaluation of Wax Properties..............................................136 A1......................4......... 87 3............3...7..........3................5.....3.........................4........................................... Separator Test(s) / Separator Flash Test(s) .......................140 A2.......................................4...............................4...........................135 A1................ Compressed Gases...............................................3...................................................................... Analysis Parameters....... “Standard Flash” Procedure for Processing Pressurized Fluid Samples for Asphaltene Measurements and for Obtaining Gas Samples for Geochemistry ................................143 A2........................................... 88 3........................................ FIGURES..............1............. 79 3................... Black Oil Correlations (PVT Properties) .............5....... PVT TESTS AND CORRELATIONS (FOR PRIMARY RECOVERY) ..5............................................................... Monitoring of Oil Processing and Transport Facilities .................................................................................. 84 3................................................................................................... Operational Control and Process Monitoring................................... ............... .........................................173 A7....................................................EP 2007-3186 ........................................................................... Procedures for Obtaining and Handling Pressurized Formation Water Samples ......................................184 LIST OF FIGURES Figure 1: Figure 2: Figure 3: Figure 4: Figure 5: Figure 6: Figure 7: Figure 8: Figure 9: Figure 10: Figure 11: Figure 12: Figure 13: Figure 14: Figure 15: Figure 16: Figure 17: Figure 18: Figure 19: Figure 20: Flow-chart of the Fluid Sample Assessment Procedure – Live Fluid........................................................................................ 98 Flow-chart of the Fluid Sample Assessment Procedure – Stock-Tank Fluid.....................................100 Containers acceptable for water samples as last resort................................173 A7.......................... SAMPLE TRACKING TEMPLATES .... ISOJARTM HEADSPACE SAMPLE COLLECTION .......................................................................................................................................... .............................................................101 Containers not acceptable for oil or water samples..................................... ...........2......................106 Separator oil and gas sample points and choke manifold sample point...........................4... radon analysis unit..IX - Restricted A6..................................................................... and close-up of scintillation cell.....................................................Titration UOP 212........................................... Procedures for Processing Pressurized Fluid Samples for Paraffin Measurements............. ...........................................2........105 Diagram of sample points in production stream....4....176 A7.......................... 99 Containers preferred for water samples.................... Collection of Mud Gas Samples using a Modified IsoTubeTM Sampling Rack ..........................................3.....112 Arsenic sampling apparatus....102 Container acceptable for pressurised oil sample...........................................................103 Diagram of gas surface sampling (examples courtesy of Schlumberger)............. ............... ISOTUBE™ MUD GAS SAMPLE COLLECTION .............100 Containers acceptable for stock-tank oil samples.......100 Containers acceptable for small (left) and large (right) volume gas samples..........109 H2S.................... ......108 Draeger stain tubes.............. .................................................................... Procedures for Processing Pressurized Fluid Samples from Dry Gas Reservoirs to Obtain Gas and Stock-Tank Liquids for Fluid Property.......................164 A6........................................................ Shipping instructions for flammable gas samples in single-use IsoTubesTM................................................................102 Diagrams of single-phase (left) and floating-piston (right) sampling bottles (examples courtesy of Schlumberger)............... Mercaptans.........................................179 A7.................. .......................173 A7..3...........168 A6................................180 APPENDIX 8.................................1...........................107 Mobile PVT lab apparatus............110 CO2 Orstat Titration..... Collection of Mud Gas Samples Using a New IsoTubeTM Sampling Rack.......................106 Diagram of a 3-phase-separator.111 Diagram of radon trap.............................. ...... IsoTubeTM Sampling Rack Set-up................ ....... IsoTubeTM Order Form .................169 APPENDIX 7.............104 Diagram of conventional sample bottle priming (examples courtesy of Schlumberger)................ ................................5............... ..........................182 APPENDIX 9...................113 ... .........................................................................177 Figure A7.8: Monitoring flow rates/pressures.........180 Figure A8...............................................175 Figure A7........166 Figure A6....176 Figure A7...................................178 Figure A7...4: Removal of a filled IsoTube from the rack..................119 Figure 27: Optimum location to detect sand by slip-stream sampling.......EP 2007-3186 Figure 21: Figure 22: -X- Restricted Mercury sampling diagram..................................... .......114 Mercury sampling apparatus and close-up of the acid gas filters (Malcosorb).......................120 Figure 28: Example Buckley plot (Campbell diagram) from a Nigerian crude......186 ..........185 Figure A9..................................................160 Figure A6................................... ................................... ...........................5: Sample validation flowchart..................... The blue color shows saturated Malcosorb........................................2: Loading of an IsoTube™ onto the sampling rack............................................................................2: Sample tracking sheet .........3: Diagram for obtaining STL for wax.....................................Onsite validation...................... .................................................116 Figure 24: Millipore sand-sampling units...........................................and geochemistry-related measurements......1: Sample tracking sheet ... ....................................Sampling and transfer. Single-phase sampling bottle being transferred into single-phase transport bottle (left......117 Figure 25: Norman sampling units.... ...............6: Inserting an IsoTube into the new mud gas sampling manifold.............................. (SSB cylinders in heated tape).............. ...................PVT Lab........ ..............................................................1: Diagram for obtaining stock-tank liquid for asphaltene measurements................................................................................................171 Figure A6...................................................................................................................... .....................172 Figure A7.7: Valve closure..........174 Figure A7...........................................................................................173 Figure A7............................................. ...........................118 Figure 26: Examples of sand sample locations....................115 Figure 23: Transfer of a large volume (2¾ gallon) floating piston sampling bottle..........) Pictures courtesy of Schlumberger.........163 Figure A6.........1: Single-use IsoTube™ for mud gas samples..........177 Figure A7.....................................9: Sample collection.......2: Diagram for obtaining pressurized gas samples for geochemistry..121 Figure A6...5: Adhesive-backed labels................11: Labeling of IsoTube boxes for hazardous shipment.................. ...................4: Photograph of set-up for live-oil fluid transfer..................... ........1: Isotech’s new IsoJars™ for headspace gas samples..................................................................................................................................... ................................. (Horizontal [cabinet] mounting configuration)..... .......174 Figure A7.....................................3: Actuation of the valve control handle......................................................121 Figure 29: Example mass balance diagram from a Brazilian crude..10: Isotech’s order form for new IsoTubes........................................................182 Figure A9...............178 Figure A7...........................184 Figure A9......................3: Sample tracking sheet .......................179 Figure A7............................................. EP 2007-3186 - XI - Restricted LIST OF TABLES Table 1: Table 2: Table 3: Table 4: Table 5: Table 6: Table 7: Table 8: Table 9: Table 10: Table 11: Table 12: Table 13: Table 14: Table 15: Table 16: Table 17: Table 18: Table 19: Table 20: Table 21: Table 22: Table A1.1: Table A2.1: Table A2.2: Table A2.3: Table A2.4: Table A2.5: Table A2.6: Disciplines and Consultation Topics (Alphabetically)............................................... 4 Sample Types and Acquisition Points ....................................................................... 11 Live Sample Bottle Types............................................................................................. 12 Sample Bottles ............................................................................................................... 12 Sampler Carriers ............................................................................................................ 16 Fluid Test Sample Requirements ................................................................................ 17 Sampling and Transport Cylinders, and Analyses .................................................... 18 Conditions Defining Stable Flow for Sampling Purposes ...................................... 50 Onsite Fluid Analyses ................................................................................................... 50 Summary of Onsite Trace Contaminant Analysis Options..................................... 52 Suitability and Liabilities of Stain Tubes .................................................................... 53 Summary of Surface Sampling Key Points................................................................ 54 Summary of Data Collected From the Wellhead/ Tree/ Flowline ....................... 56 Sampling Locations for Trace Contaminant Analysis.............................................. 56 Water Sample Container and Onsite Analysis Summary......................................... 57 Typical OBM Impact on Project Development ....................................................... 66 Recommended Analysis to Evaluate Sample Quality .............................................. 67 Recommended Minimum Onsite Restoration Times for Downhole Samples ........................................................................................................................... 67 Liquid Transport Containers ....................................................................................... 67 Typical Classification of Reservoir Fluids.................................................................. 69 Data Requirements for Hydrate Evaluation.............................................................. 87 Summary of Data Requirements, Sampling References, and Analyses ...............132 Correct International Shipping Classifications and Labelling for Hydrocarbon Samples ................................................................................................137 Volume Ratios.............................................................................................................148 Mass ..............................................................................................................................149 Distance........................................................................................................................149 Volume .........................................................................................................................149 Pressure ........................................................................................................................149 Temperature ................................................................................................................149 EP 2007-3186 This page intentionally left blank. - XII - Restricted EP 2007-3186 1. -1- Restricted WELL-SITE SUPPORT Two main categories exist in sampling operations – subsurface and surface. • Subsurface samples are carried out remotely using a tool conveyed either by wireline, by pipe, or as part of the drill-string in a well test and usually involves high pressure and temperature regimes. • Surface sampling is primarily carried out at the wellhead, separator, flowline, or pipeline, and involves atmospheric conditions or moderate pressures and temperatures. Subsurface and surface sampling container types and labelling are addressed in Section 1.1.5 and Appendix 1. 1.1. Planning Planning is the most important single item in a sampling operation. Compositional and analytical data of hydrocarbon fluids are key for economic evaluation, reservoir modelling, system selection, and/or process design calculations. Consequently reliable fluid data are a must for the basis for design (BFD) or field development planning (FDP), and production optimization. Sampling should always be subject to appropriate planning and should never be considered as a “routine”. It is recommended to hold a Sampling the Well On Paper (SWOP) meeting with the project team and key operational personnel, which should outline: • program objectives, • priorities, • equipment, • risks, • timing, and • subsequent analyses. Coordination with existing plans and documentation such as the well proposal, Drilling the Well on Paper (DWOP), Logging the Well on Paper (LWOP), and Testing the Well on Paper (TWOP) are essential. In some cases, where simple target sampling and analysis is needed, a short planning meeting is more appropriate. Sufficient sample quality and volume to address the project’s immediate and anticipated data requirements should be considered, as well as contingency volumes to provide insurance against possible loss of samples. Figure 1 and Figure 2 illustrate the typical sequences of analysis of reservoir and surface fluid samples. In a sampling plan, four key areas should be addressed: (A) Consultation of Different Disciplines • Risks and opportunities, synergies and contradictions are identified and optimised. EP 2007-3186 -2- Restricted • All impacted parties should have an opportunity to participate in the sample planning (e.g., petroleum engineers, well engineer, facilities engineer). • This reduces the chance of misunderstandings and resolves potential problems before instead of during the operation. • Tasks and responsibilities of all staff and engineers involved in operations should be clear and broadly understood. (B) Consideration of the Sample Point Subsurface • Rock properties expected (e.g., degree of cementation, permeability, etc.) • Fluid type anticipated (dry gas, gas condensate, volatile oil, black oil, or heavy oil) • Well deviation and other tough logging conditions • Water- or oil-based drilling mud • High temperature / high pressure conditions • Tool options to address these (One or two pumps, inflatable packers, optical fluid analysers, downhole lab options, etc) Surface • Wellhead • Choke Manifold • High Pressure Separator (oil, gas, or water) • Low Pressure Separator, (oil, gas, or water) • Flowlines • Export lines (C) Consideration of the analyses required and their relative priority: • PVT • Flow Assurance • Geochemistry • Operational Control • Process Monitoring • Production Surveillance • Valuation • System Design .EP 2007-3186 -3- Restricted At the very least the following analyses are required as these data are employed in almost every aspect of project development: • Liquid Composition C30+ including BTEX. • Gas Composition C12+ • BS&W • GOR • Stock tank (API) in situ density or specific gravity • Stock tank and in situ viscosity • Mole% and molecular weight • Saturation pressure (D) Consideration of the volumes and type of samples required: • Live (i.e. and what measurements require mono-phasic sampling? • Are the sample containers we have available and sufficient? • Do we have enough transport bottles for high-pressure samples? • Are on site-analyses required? • Do we need H2S resistant bottles? • Who is responsible for shipping and logistics? • Is export approval required and how long will it take? . at or above Pres) • Single-phase or conventional separator for recombination • Well stream or stock-tank • Gas • Oil • Water • Expected Contaminants (drilling mud. stimulation fluids) Some Frequently Asked Questions: • Who are the stakeholders? • Is the program aligned with the essential data requirements? • Do we have enough samples in the event of a bottle malfunction (leaks or doesn’t open)? • What level of contamination is acceptable? • Is the sample representative. completion fluids. daily operations. daily operations. Involvement of different disciplines is dependent on the type and scope of operations to be carried out. and they understand the objectives of the operation. and potential for CO2 and H2S Separator and surface vessel orientation. daily operations Overall sampling program targets. separator operating conditions. expected lithology. Table 1: Disciplines and Consultation Topics (Alphabetically) Discipline/ Role Analytical laboratories involved Biostratigrapher Company Man or DSV Contractor’s sampling engineers Contractor’s Well Test Supervisor Drilling Engineer (and Completion Fluids/ Mud Engineer) Geochemist Facility Design Engineer FEAST focal point Operations Geologist Petrophysicist Process and Flow Assurance Engineers Process Engineer Production Technology Engineer Project Team Lead Projects Well Test Supervisor Refinery Assay Engineer Reservoir Engineer Shallow Hazards Team Consultation Topic Analysis capabilities.1. flow assurance. Coordination regarding mud formulation (especially if tracers are added to WBM) and composition (new mud versus re-constituted mud) Analyses for petroleum system calibration and reservoir geochemistry. acidity). and contracting.1. receiving specs (metals. Incorporating Discipline Expertise Planning should never be carried out in isolation. and integration with coring. LNG requirements Review of overall sampling program and any specific complications Target sands. . LNG requirements PVT analysis and subsurface modelling requirements Target sands. mud filtrate sample preparation. design of down-hole tool configuration. Requirements for PVT. thus particular disciplines should be consulted. trace element/contaminant analysis. Formation temperature and pressure measurements. contractor selection. daily operations Sampling and onsite analysis crew should be suited for planned activities (usually 2-4 staff) – correct skills and experience should be checked. Confirmation that the necessary equipment is deployed and present on site. anticipated data turnaround time Coordination with cuttings and isotube sampling of mudgas Approval and notification of intended activities on the rig. Confirmation that the necessary equipment is deployed and present on site. A list of essential consultations is presented below. and they understand the objectives of the operation. separator and surface vessel orientation Economic valuation. logistical challenges. The data available from representative samples potentially impact several phases of the project life cycle. Requirements for surface facilities planning. detection limits. surface modelling. treating and fluid conditions Well testing. notification of sample arrival. Well testing.EP 2007-3186 -4- Restricted 1. and potential for CO2 and H2S. 250450 cm3 of live petroleum will usually be sufficient.5 pt) of black oil or gas condensate. SSB) usually contains fluid that has been transferred only once (on the rig). PVT labs such as Oilphase or Corelabs can perform full PVT measurements on as little as 250 cm3 (0.. However. use the pressurized sample that has been transferred least or not transferred at all providing their representativeness is confirmed. • Samples in storage cylinders at the PVT lab are the least desirable.1. • Single-phase samples are also preferred as they have never been below Pres.000-3. any cylinder can be selected for the PVT work. so it is the next in terms of preference. It is recommended that at least 50% of the cylinders from the same sampling point be examined (or first and the last transportation cylinder transferred from large vessels). . It is important to mention that whenever H2S is expected to contribute to the sample. API.2. it is recommended to calculate the volumes needed based on predicted or known gas to oil ratio (convert stock tank volume requirements into single-phase volume). Whenever possible. Assuming that cylinders do NOT experience significant pressure variations and no variations are observed among GOR. and other parameters. • A 600 cm3 (1. Volumes Required for Various Measurements The following points summarize the sample volume requirements for various types of analyses. undersaturated oils.EP 2007-3186 -5- Restricted 1.g. non-reactive sample chambers should be used (both for the downhole acquisition and transportation). Schematics of some of the cylinders are shown in Figure 9 and Appendix 6. when working with black. since these samples likely have been transferred a minimum of two times.25 pt) PVT shipping cylinder (e. For a typical black-oil reservoir approximately 2. 1-2 back-up cylinders are collected. PVT Measurements When there are multiple down-hole sample cylinders taken at the same sampling point. sample integrity should be confirmed by examining the following before beginning PVT work: • Closing P&T downhole • Drawdown (reservoir pressure minus sampling pressure) • Opening P&T on the rig • Transfer P&T • Opening P in the lab • GOR • API • Asphaltene content.000 cm3 of single-phase fluid provides enough volume for all necessary basic analytical work (excluding refinery assays). Transportation Engineering Measurements (Flow Assurance) and Tests • When given options. so consider all of the points detailed immediately above to apply to hydrate concerns. any sample shipped or stored at pressures above that of the reservoir (Pres) or well above the bubble point (Psat) should be used preferentially for asphaltene measurements. • Members of the Wax and Asphaltene Team in Shell Global Solutions Flow Assurance should be consulted for detailed information about the volume of fluid required for study of a particular prospect or field. and these should not be blown down until the preliminary asphaltene-related work has been finished. These are transported under pressure to the PVT lab for processing (to obtain “heated flash” samples). . • The optimum sample for all asphaltene analyses is a single dedicated 250-600 cm3 (0. • The minimum amount of stock-tank petroleum needed for a few key measurements is 250–350 ml (0. one live sample of formation water (and injection water. are always kept well above the reservoir pressure and thus do not suffer a significant drop in pressure (due to cooling during sample retrieval) below the Pres during transfer (see Appendix 6). • Additional pressurized sample material is required if paraffin-related laboratory work needs to be done on live petroleum samples.3 litres (2.75 pt). • In addition. • Members of the Hydrates Team in Shell Global Solutions Flow Assurance should be consulted for detailed information about the volume of fluid required for study of a particular prospect or field. The back-up PVT cylinder(s) should also be considered as a reserve for possible inhibitor selection or blending work. although requiring transfer on the rig.5-0.Paraffin-related • Live petroleum samples need to be taken during downhole sampling.EP 2007-3186 -6- Restricted Flow Assurance – Hydrate-related • Hydrate work is typically based on comprehensive PVT data. Flow Assurance . Members of the Wax and Asphaltene Team in Shell Global Solutions Flow Assurance should be consulted for detailed information about the volume of fluid required for study of a particular prospect or field. This should be enough to yield 60 ml (1/8 pt) of stock-tank liquid (“standard flash”) for asphaltene screen work and 50–150 ml (0. Flow Assurance .Asphaltene-related • Because the minimum solubility for asphaltenes in reservoir fluids is near the bubble point. if applicable) is recommended.3 pt) of live crude for depressurisation experiments.75 pt) is the preferred amount needed for full characterization.5 pt) single-phase bottle which.1-0. but 1. 95 pt) bottle. . Isotube sampling.Chemical Compatibility • 150–300 ml (0. • Members of the Chemical Systems Engineering Team in Shell Global Solutions Flow Assurance should be consulted for detailed information about the volume of fluid required for study of a particular prospect or field.3-0. which does NOT need transfer on the rig.4 kPa (500– 1200 psi)) also are collected for geochemistry. This should be collected in non-reactive bottles. foaming. and sludge forming tendency. Ar. Flow Assurance .3 or 1. Section 3. Samples are to be analysed within 72 hrs (time sensitive). This should be collected in non-reactive bottles. Geochemical Analyses • A minimum of 30 ml (1/16 pt) of stock-tank fluid (either an “unheated” or a “standard flash” sample) is needed for the basic set of geochemical measurements. Downstream Measurements • A minimum of 500 ml (1. CO. H2) speciation.1. and archiving of sample material in the Shell petroleum libraries for future work. • Members of the Fluids and Basins Team in EPT Solutions should be consulted for detailed information about sample quality.1. • Members of the Chemical Systems Engineering Team in Shell Global Solutions Flow Assurance should be consulted for detailed information about the volume of fluid required for study of a particular prospect or field. • A full crude oil assay requires about 60 liters of oil or condensate. analytical requirements.EP 2007-3186 -7- Restricted Flow Assurance – Scale-related • The optimum sample for all scale-related analyses is a single dedicated 450-600 cm3 (0. The preferred gas collection procedure is described in Appendix 3. repeat analyses.1-0.0 pt.2 pt) of water for composition analyses and basic fluid properties to enable scale screening and modelling. and logistics. Validation of sample quality is detailed in Section 2.5 details a typical program of downstream analyses. Additional determination of hydrogen cyanide (HCN) and organic acids can be carried out with sufficient advance notification. Sample archiving is critical to allow for possible reservoir fingerprinting work later in the field development. but 50–100 ml (0.2 pt) of sample would allow for specialty analyses. This is sufficient to yield gas for analysis and 100 ml (0.1 pt) of gas is required for detailed trace gas analyses (He. Samples are to be analysed within 72 hrs (some species are time sensitive).6 pt) of dead oil is required for the general study of compatibility of injected chemicals with produced fluids and emulsion. • A minimum of 500 ml (1.1 pt) of gas and 500 ml of liquid is required for detailed sulphur speciation including mercaptans. • Gas samples in the amount of 150 or 500 cm3 (0. at ~3450 – 8270. and collection is only feasible during a well test. e.1.g. four different types of stock-tank liquid samples can be obtained for later lab use: • “heated” – for all wax-related transportation engineering measurements. • Surface sample points (Section 1. 5.EP 2007-3186 -8- Restricted Types of Stock-Tank Liquids Different analyses require stock-tank liquids that have been handled in different ways. and include a small amount of redundancy to allow for unexpected analysis requirements or sample loss through mishaps. Note that this sequence may be frequently different. can also be used for wax-related and geochemistry analyses. Hydrocarbon and water PVT (the latter only when available).4. Based on the procedures in this report. sulphur species and flow assurance measurements. • “unheated” – for all geochemistry measurements. Priority A sampling program should be designed to provide sufficient volume to address all the analysis requirements. and stock tank containers for the volumes of oil and water needed for other analyses.3. compatibility assessment). Hydrocarbon Flow Assurance Studies (more in-depth than just screens.2) can be often best served by a combination of single-phase and piston cylinders. Hydrocarbon basic physical fluid properties. Sampling Environments Two main categories exist in sampling operations – subsurface and surface. . 6.. this will be a “heated” sample and primarily suitable for wax work. Single-phase for the sensitive PVT. based on the impact of the analysis data on the project.1. standard piston can be used to obtain volumes required for other analyses. according to the project requirements. kinetic deposition studies. Any specialized downstream analyses. 2. Non-hydrocarbon gases composition (often part of the PVT). 1. • “rig flash” – according to the procedures recommended here.3) can be also a combination of single-phase and piston cylinders for oil and gas “live” sample measurements. 1. 1. • Downhole sample points (Section 1. Hydrocarbon Flow Assurance Screens and Oil Geochemistry. 3. 4. • “standard flash” – for asphaltene-related transportation engineering measurements. The following priority sequence is suggested as a default sequence for a new well or well test. and the third contains the hydrocarbon sample.2). Close attention should be paid to the restoration times and procedure. In this case.1. the second contains a gas (usually air or nitrogen). One chamber contains backpressure fluid (usually water + glycol or drilling mud). then transfer into single-phase transport container is necessary. close attention should be paid to the restoration times and procedure (Section 2. ideally single-phase transport/storage cylinders (typically more sturdily constructed and larger). • Non-reactive versions of these bottles are available for samples containing H2S. . They are typically only used for transporting dry gas or condensate below the dew point.EP 2007-3186 -9- Restricted 1. however they must be specifically requested and prepared several weeks prior to the actual deployment of the bottles to the operation site. The role of the air or nitrogen chamber is to ensure that the sample remains single-phase from the sampling to analysis. the second contains the hydrocarbon sample. 1. If the pressurized hydrocarbon sample is single-phase then for the transportation of such sample the backpressure fluid must be bled off until the hydrocarbon phase drops below the saturation pressure and a gas cap is created. High Pressure Containers High-pressure cylinders come in the following three main categories: Single-phase (Gas-compensated) Cylinder/Bottle • These cylinders contain three separate chambers separated by two floating pistons. Standard (Floating) Piston Cylinder/Bottle • These cylinders contain two chambers separated by one floating piston. Sample Containers Figure 3 through Figure 11 illustrate the preferred sample containers for high pressure and stocktank fluids. • If it is desired to maintain the sample single-phase during transport.1.4. however they must be specifically requested and prepared several weeks prior to the actual deployment of the bottles.5. and must be transferred into approved transport cylinders. These containers are not suitable for transporting pressurized single-phase hydrocarbons. • Most downhole single-phase sample containers are not approved as transport cylinders. NOTE: It is always recommended to use new containers for sampling and transportation of stock tank liquids.5.1. Tank (“Hard”) Cylinder/Bottle These cylinders consist of just a single chamber.1. One chamber contains backpressure fluid (usually water + glycol or drilling mud). as those hydrocarbons have a gas cap by definition. • Non-reactive versions of these bottles are available for samples containing H2S. .1.10 - Restricted 1. The usual volumes required are 1 L.5. flammable substance is critical to safe transport.1.Hydrocarbons Liquid samples collected at stock tank condition: • Colourless glass containers or amber dark-brown glass containers • Metal UN/IATA drums (containers) – size up to a barrel. toxic. narrow-mouth Nalgene or glass bottles. • Collection vessels should not be filled to more than 90% capacity. 1. but are less preferred as Silica and other trace minerals in the glass may leach into the water sample over long periods. Glass bottles with a Teflon cap (Figure 4) are acceptable as an alternative. Appropriate labelling as a hazardous.2.EP 2007-3186 . • The preferred sample container for the collection of a water sample is a Nalgene (Figure 3) bottle.Water • Water samples can be collected into large (one quart/litre). Verify the shipment options with the intended carrier(s) prior to sampling. Ambient Pressure Containers . A 10% headspace should be left before sealing any hydrocarbon containers.5. Ambient Pressure Containers . to allow the liquids to degas without increasing in pressure.3. No or Low OBM contamination Small volumes typical Rig transfer to transport bottles usually needed Requires producing well Reservoir has already been depleted due to production Requires producing well Reservoir has already been depleted due to production Sample not suitable for Asphaltene work.11 - Restricted Sample Types and Acquisition Points Possible Acquisition Points Sample Suitability Advantages Disadvantages At formation face in open-hole with wireline tool All Earliest data from several zones of interest Above perforations (and above Psat) in cased-hole during welltest using casing conveyed carriers (e. weather.. etc) Small volumes typical Rig transfer to transport bottles usually needed Requires well-test. and Water Stock-tank Oil. hole deviation. may not be suitable for Wax and scale work (depends on temp and pressure conditions) Requires well-test or producing well Sample not suitable for Asphaltene work. may not be suitable for Wax and scale work (depends on temp and pressure conditions) . contamination. or Water Large volumes possible. hole integrity. Metrol) At perforations in completed hole with wireline tool All Early data Low OBM contamination sample from producing zone Low OBM contamination sample from producing zone Small volumes typical Rig transfer to transport bottles usually needed OBM contamination risk Sampling subject to difficulties/uncertainties (lithology. may not be suitable for Wax and scale work (depends on temp and pressure conditions) Requires well-test or producing well Sample not suitable for Asphaltene work. or Water sample points Recombination PVT Geochemistry Some Flow Assurance Valuation Recombination PVT Geochemistry Some Flow Assurance Valuation Recombination PVT Geochemistry Some Flow Assurance Economic Valuation No or Low OBM contamination Wellhead Separator – Oil. may not be suitable for Wax and scale work (depends on temp and pressure conditions) Requires well-test or producing well Sample not suitable for Asphaltene work. and Water . No or Low OBM contamination Large volumes possible.g. Gas.EP 2007-3186 Table 2: Type Live Oil. Gas. SCAR. Gas. All Wellhead above Psat upstream of choke PVT Geochemistry Most Flow Assurance Valuation No or Low OBM contamination Separator Oil. Gas. .12 - Restricted Live Sample Bottle Types Sample collection bottle Transferred into Suitable for PVT Oil Single-phase or gas-compensated Single-phase Transport Y Floating-piston transport Y Heated flash (and Rig flash) N Unheated/Standard flash N PVT Gas Y Y N Y Asphaltenes Y N Y Y* Wax Y Y Y N Geochemistry Y Y N** Y Standard floating piston Single-phase Transport Floating-piston transport Heated flash (and Rig flash) Unheated/Standard flash Y Y N N Y Y N Y N N Y N Y Y Y N Y Y N** Y Conventional “hard” Floating-piston transport Y Heated flash (and Rig flash) N Unheated/Standard flash N Y N Y N N N Y Y N Y N** Y *: Dead oil Asphaltene screens only **: Not suitable for gasoline-range analyses (e.g.000psi (SPTII). GOR.000 psi (SPT). 25. C7 compositions and isotopes). Acceptable for other Geochemical analyses. both 205°C Open Hole 400 cc to 600 cc Nitrogen Compensated. viscosity.EP 2007-3186 Table 3: . *** Suitable for Stock-tank analyses (e. (Single Phase Tank) . liquid composition). H2S rated (volume variable because of piston/nitrogen configuration).g.. API. Density. DOT approved. but not live PVT work without recombination and restoration Table 4: Sample Bottles Manufacturer Abbreviation (Full Name) T & P Rating Location Volume and Notes Baker SPT/SPTII 20. H2S rated.8 liter to 10.4 depending on configuration. check with supplier for temperature spec options Open Hole 3. 205°C Open Hole 600 cc Nitrogen compensated tank. RDT Sample Bottle II Check with supplier for operating specification options Open Hole 600 cc to 800 cc Part of Multi-chamber System in RDT Tool (Single phase with piston and nitrogen compensation). H2S rated. H2S rated Volume changes between 3.000 psi. check with supplier for temperature spec options Surface 600 cc Halliburton RDT Sample Bottle I 20.8 and 10.13 - Restricted Abbreviation (Full Name) T & P Rating Location Volume and Notes PVT Sample tank Check with supplier for operating specification options Open Hole 840 cc Standard Floating Piston.000 psi. Sample Bottle 15.000 psi.4 liter Part of sampling tool. Conventional PVT Sample Tank 20. Sample Tank Check with supplier for operating specification options Open Hole 3.4 depending on configuration. Volume changes between 3. 205°C Open Hole 1000 cc Part of Multi-chamber System in RDT Tool. DOT approved.4 liter Non-DOT transportable (Standard Floating Piston) tank. Standard Floating Piston. DOT approved.8 and 10.000 psi. Standard Floating Piston. .8 liter to 10.EP 2007-3186 Manufacturer . Fesco Single Phase Bottle 15. 000 or 15.000/15. Activated by clock or electric slickline. Exothermal 20.000 psi and 170°C Surface 600 cc Nitrogen Compensated. PDS (Positive Displacement Sampler) Ratings available in 20. Single Phase Bottle 10.000 psi and 205°C Open Hole 400cc H2S resistance (Inconel) SPS (Single Phase Sampler) 20. Piston Bottle Ratings available in a range of specifications. Nitrogen compensated. temperature compensated.000 psi and 205°C Open Hole 450 cc Standard Floating Piston . MPSR (Multisample Production Sample Receptacle) 20.EP 2007-3186 Manufacturer Pencor Petrotech/ Expro Schlumberger . Cased Hole 4 liter Standard Floating Piston.000 psi.000 psi and 150°C Cased Hole 600 cc Standard Floating Piston.000 psi. Do not use with H2S 20 liter bottle Check with supplier for operating specification options Surface 20 liter Conventional “hard” sample bottle Dual Phase Piston Bottle Check with supplier for operating specification options Cased Hole 690 cc Standard Floating Piston. or 10. both to 121°C Cased Hole 700 cc Nitrogen Compensated.000 psi and 170°C. Available in non-corrosive version for high H2S.14 - Restricted Abbreviation (Full Name) T & P Rating Location Volume and Notes AIS (Armade Inconel Sampler) 20. 200°C Cased Hole 500cc Not DOT approved. Surface 20 liter Conventional “hard” sample bottle Steel Drums Ambient conditions Surface 1 liter to 5 liter to 11 liter to 25 liter to 110 liter UN Approved Steel Drums.000 psi and 200°C Open Hole 250 cc Nitrogen Compensated.000 or 20. 100 cc is validation chamber volume. both to 200°C Surface 600 cc Nitrogen Compensated.000 psi.4 liter to 22 liter Standard Floating Piston.a.15 - Abbreviation (Full Name) T & P Rating Location Volume and Notes SPMC (Single Phase Multi-Sample Chamber) 20.EP 2007-3186 Manufacturer . Can be coated for H2S resistance (NRS). CSB (Conventional Sample Bottle) Ratings available in a range of specifications.000 psi Cased Hole 300 cc Nitrogen Compensated.k.000 psi and 200°C Open Hole 600 cc + 100 cc Nitrogen compensated. Surface 600 cc Standard Floating Piston. . Volume changes between 3. GSB (Gas Sample Bottle) Ratings available in a range of specifications.000 psi. SLS (Slim-line Sampler) 15. a. 200°C Various Restricted SSB (Single Phase Sample Bottle) Ratings available in 15.000 psi and 200°C Open Hole 3. MRSC (Modular Sample Chambers) 15.8 and 22 depending on configuration).8 lite to 10. Volume changes between 1 and 110 liters depending on configuration. “Super-Sampler” SRS (Single Phase Reservoir Sampler) 15. 200°C Cased Hole 600 cc Nitrogen Compensated. MSB (MRSS Sample Bottle) 25. 75 in.5 in. pressure pulses Acoustic real time communication with samplers * IRIS (IFSM) has 160ºC limit Electronic clock has 125ºC limit.000 psi. 177ºC Pressure: .16 - Restricted Sampler Carriers Contractor Sampler Carrier Sampler Spaces T&P Rating Communication/ Firing Mechanism SchlumbergerOilphase SCAR-A OD: 7.000 psi. mechanical clock 200ºC . 8 SLS 10.Disk rupture .000 psi. 205ºC EXPRO SIMBA Halliburton Armada 10 AIS Metrol Metrol Carrier 2 Comments P/T gauge can replace sampler P/T gauge can replace sampler Pressure (rupture disks) Inconel (H2S resistant) Can be fired in 3 slots P/T gauge can replace sampler Acoustic.EP 2007-3186 Table 5: . 177ºC SCAR-B OD: 5.Pulses (IRIS)* Mechanical clock (6-12 hrs)* Electronic clock (7 days)* 15. 8 SLS 15. 177ºC SCAR-C OD:5.25 in.000 psi. 6 SRS/ 8 SLS 10. 17 - Restricted Fluid Test Sample Requirements Sample Test Volume Requirements (Volumes represent per fluid/per reservoir totals) Gas: PVT Wax.HTGC Wax cloud point Wax pour point Geochemistry Flow Assurance (future) Total Dead Oil Volume Required: Oil: minimum live oil sample volumes Viscosity API Liquid composition C36+ Gas composition C12+ GOR (can include C36+) CCE (Non-destructive and fluid can be used for other purposes) Differential Liberation (5 press.EP 2007-3186 Table 6: . vapour phase density and C15+ comp.HTGC Geochem (SARA included) Sulphur species Total Gas Volume Required: Oil: minimum dead oil sample volumes SARA Asphaltene content (Mod2000 IP14) Titration screens (FPA and P-value) Wax. steps. C30+ comp of residual oil) Separator test (Single-/Multi-stage) Sample and Test Typical Priority Sample Chamber Required Volume (ml) Typical Receiving Lab 1 5 5 Varies Single-Phase/ Piston *Many *Many Single-Phase/ Piston 450 (min >250) 90 50 250 800 PVT Lab WTC/AMS Baseline PVT Lab 2 2 2 2 2 2 2 3 Single-Phase/ Piston Single-Phase/ Piston Single-Phase/ Piston Piston **Any **Any **Any **Any 10 5 50 50 200 200 50 600 1165 BTC/AMS/RIJ BTC/AMS/RIJ WTC/AMS WTC/AMS WTC/AMS WTC/AMS Geochem Lab WTC/BTC/AMS 1 1 1 1 Single-Phase/ Piston Single-Phase/ Piston Single-Phase/ Piston Single-Phase/ Piston PVT Lab PVT Lab PVT Lab PVT Lab 1 1 Single-Phase/ Piston Single-Phase/ Piston 50 5 10 Depends on the GOR 50 50 1 Single-Phase/ Piston 125 PVT Lab 1 Single-Phase/ Piston 125 PVT Lab PVT Lab PVT Lab . open hole Sampling: SPMC (Schlumberger). SSB (Schlumberger) Single-phase*. Table 7: Sampling and Transport Cylinders. Cation/anions Total Water Volume Required: Restricted Sample Chamber Sample and Test Typical Priority 1 1 Single-Phase/ Piston Single-Phase 4 Single-Phase Required Volume (ml) 500 (min >250 cc) 250 800 1965 Typical Receiving Lab PVT Lab PVT Lab 450 450 BSI + WTC/AMS * Approximately 4 chambers will be required for each gas sample since the gas condensate is generally highly contaminated.g. consider the sample non-representative. If a surface sample is taken below 71. resistivity. and Analyses Bottle (see Table 4) Singe-phase*.EP 2007-3186 . Haliburton’s Single-phase bottle Single-phase transport e.. open hole Sampling: MRSS (Schlumberger).: SSB (Schlumberger) Suitable for PVT Flow Assurance (All) Geochemistry (All) Sulphur species (time dependent) Refinery specifications PVT Flow Assurance (All) Geochemistry (All) Sulphur species (time dependent) Refinery specifications PVT Flow Assurance (All) Geochemistry (All) Sulphur species (time dependent) Refinery specifications . and a cloud point is determined to be at or above the sample temperature. cased hole SLS (Halliburton) SRS (Schlumberger) Single-phase transport e. ** Sample temperatures must be above cloud point for sample to be representative. Single-phase sample bottle (Baker) Transfers into Direct to lab Singe-phase*.18 - Sample Test Volume Requirements (Volumes represent per fluid/per reservoir totals) Complete PVT fluid analysis Asphaltene Onset Test Total Live Oil Volumes Required: Total Live and Dead Volumes Required: Water: pH.g.1°C (160°F). or refinery Samples for Mercury analysis Stock-tank water for most analyses Stock-tank oil for chemical compatibility or rel-perm Refinery specifications *: Also available with H2S resistant coating from certain manufacturers for sampling sour fluids. MRSC. or refinery Water for mineral analysis Stock-tank oil or water for wax. . cased hole Single-phase transport Floating piston transport Hard Tank No transfer needed Colourless glass No transfer needed Amber glass No transfer needed Nalgene Metal IATA No transfer needed No transfer needed Restricted Suitable for PVT Flow Assurance (Wax and Scale) Geochemistry Sulphur species (time dependent) Refinery specifications PVT Flow Assurance (Wax and Scale) Geochemistry Sulphur species (time dependent) Refinery specifications PVT Flow Assurance (Wax and Scale) Geochemistry Sulphur species (time dependent) Refinery specifications PVT Flow Assurance (Wax and Scale) Geochemistry Sulphur species (time dependent) Refinery specifications Gas samples from separator GTL specifications Stock-tank oil for wax. geochem. open hole MPSR. geochem. Standard sampling .19 - Transfers into Single-phase transport Floating piston transport Standard Floating Piston*.EP 2007-3186 Bottle (see Table 4) Standard Floating Piston*. Contact the FEAST team for advice. and corrosionrelated production problems. • General measurements for petroleum quality/value/type assessment.20 - Restricted 1. • RDT – Formation Description Tool (Halliburton) or cased-hole sampling devices such as • SRS – Single-phase Reservoir Sampler. However.2. and is always operator-initiated through an electronic connection.Sample Carrier and Recovery (Schlumberger/Oilphase).3 addresses collecting stock-tank oil samples from producing wells. Open Hole and Cased Hole – Hydrocarbon and Water Unless otherwise noted.g. Single-phase samples are collected for the following general types of analyses: • Standard PVT measurements for reservoir and other engineering work. such as surface PVT samples collected from test separators.1. Sample cylinders are either standard piston or single-phase.. • Surface engineering design including flow assurance (e. many of the guidelines and procedures can be applied to any type of pressurized samples. (Schlumberger). • SCAR .3. These are usually timer-dependent or initiated through pressure pulses. . • Open-hole sampling is usually incorporated as part of a well logging program. and geochemical properties.EP 2007-3186 . • RCI – Reservoir Characterization Instrument (Baker Atlas). Subsurface Samples – Hydrocarbon and Water Two main categories of subsurface sampling exist – open. 1. these procedures are specifically applicable to downhole reservoir fluid samples obtained with either open-hole tools such as: • MDT – Modular Dynamic Formation Tester. • Cased-hole sampling can be either line deployment into a producing well or through sample bottles conveyed as a part of a DST. to be recovered at the end of the well test. fingerprinting studies. • Water properties – used often for prediction and understanding of scale. paraffin and asphaltene deposition prediction).and cased-hole. • Specialized and time sensitive measurements such as sulphur species and trace element/contaminants. • PDS – Positive Displacement Sampler (EXAL). Section 1.2. or Schlumberger’s 1. a water sample collected with a downhole sampling tool should be treated with the same care as a pressurized petroleum sample. Halliburton’s 1 litre (2 pt). • It is essential important to collect a sample of the actual drilling mud. . If this option is taken.2.EP 2007-3186 . Some of these chambers are transportable (e. A bottom-hole pressure gauge should be run with any sampling tool to record the exact sampling pressure at the time of sampling.g. the preferred method is to collect a sample into single-phase cylinder. Schlumberger’s SSB). Schlumberger’s SPMC) and must be transferred into single-phase transport bottles prior to transportation (e. Report EP 87-1006 must be followed for detailed procedures and policies related to wireline operations. Baker-Hughes’ Single-phase sampler. At least a survey of pressure and temperature is required during sampling operations.. Electric samplers are typically run in conjunction with tools giving surface read out of pressure. 1. • If larger samples are taken (e. gas water ratio (GWR) and dissolved gas composition. they must be transferred into transportable cylinders (either single-phase or floating piston below Psat) on the rig. cation. particularly oilbased mud for backing out contamination of hydrocarbon samples.1.g. • Most single-phase cylinders are not transportable (e. A minimum of 3 bottom-hole samples should always be obtained so that sample consistency can be verified and to allow for some redundancy if one container leaks during transit..g..or 2¾gallon 3.g. Schlumberger’s MRSS) and can be shipped directly to a PVT laboratory for analysis. For cylinder types refer to Section 1. Ideally one cylinder should be retained until it is definite that no further high pressure analyses will be needed (including fluid compatibility studies) at which point it can be blown down.2.21 - Restricted • NOTE: To ensure the accurate measurement of pH. and water based mud for formation water samples (see Section 1. and density for monitoring sampling conditions. For PVT data. hydrocarbon samples can be obtained in using three general cylinder types: • The preferred method is to collect a single-phase sample in a nitrogen-compensated vessel.2. soluble organic composition.5. temperature.4 for details). the rig transfer procedures below do not apply. anion. Obtaining Pressurized Downhole Hydrocarbon Samples An experienced petrophysicist should supervise the wireline sampling operation to ensure: • Appropriate sample point selection • Successful seals • Accurate pressure gradient determination • Optimum sample quality At the time of writing..785 cc or 10.400 cc) chambers). 2. Obtaining Pressurized Downhole Water Samples • The preferred method is to collect a water sample into a transportable chamber. If this option is taken.e.) The procedure for collecting new IsoTube samples is given in Appendix 7. .. hydrate inhibitor. Mud/Drilling Fluid Sample Collection The following Samples should be collected with the aid of the Mud Engineer during drilling of the objective interval(s): • 1L sample of whole mud and 5 cc sample of mud filtrate should be taken at both the top and base of the objective interval(s) • In the event of a large interval (>30 m. >90 ft) one additional 1 L+5 cc sample pair should be taken every 10 m (30 ft).5 and Table 4. These chambers can be shipped directly to a laboratory for analysis (if possible the samples should be shipped to the laboratory on ice). 1. • API and compositions of the mud and the filtrate.3.g.22 - Restricted 1. demulsifier. casing point to above the target intervals and then 5 m (15 ft) intervals over zones of interest. IsoTubeTM mud gas samples should be collected at 30 m (90 ft) AH intervals from the 13⅜ in. At least two IsoTube samples must be taken for each show— one as the total gas readings rise and another just after the values peak (personnel should work closely with the MWD vendor to identify these zones prior to the arrival of the show stream at the mud-logging unit. the rig transfer procedures below do not apply. • 50 cc pure (i. etc).or 2¾-gallon chambers. they must be transferred into transportable cylinders on the rig.5.1. corrosion inhibitor.2. • If larger samples are taken in 1. 1. • Clear record of any tracers and their concentrations that are used in the mud formulations. Mud Gas IsoTube Sampling In operations where the gas samples are collected for the isotope work. • A sample of any LCM material that has been used during the drilling of the reservoir section should also be obtained.EP 2007-3186 . record any hydrocarbon soluble components that have been added to the mud.4. • In the case of water-based mud. unmixed) sample of any additives (e. For cylinder types refer to Section 1.2.. The following should also be collected/reported with each mud sample (from the Mud Engineer) and included in the final sampling report: • Current mud report. 23 - Restricted Well engineers must check in advance that a purpose-built IsoTube gas-sampling manifold is set up in the mud-logging unit by contacting the mudgas logging representative. once collected. and Figure 14 provides examples of sample points on a choke manifold (well-head) and separator. . casing point to above the target interval and then 5 m (15 ft) intervals over zones of interest to TD. Sampling Points and Conditions 1.: +31 (0) 345 620 120 Email:
[email protected] 2007-3186 .3.1. 1.6. IL 61821 USA Tel.3. following the procedures discussed in Section 2. Figure 13 is a diagram of a typical 3-phase separator. Sampling guidelines for IsoJars are given in Appendix 8. These pressurized samples should be processed/handled similarly to downhole samples. or Isolab (EU) or IsoTech (US): Isolab Attn: Rob Kreulen 1e Tieflaarsestraat 23 4182 PC Neerijnen The Netherlands Tel.: +1 217 398 3490 Fax: +1 217 398 3493 Email: mail@isotechlabs. Additional samples must be collected across show zones and before and after every bit trip/casing point. Separators Pressurized samples from test separators should are frequently obtained for surface recombined PVT work and/or for other fluid property studies. Inc. Surface Samples 1. 200 m (600 ft) intervals.1. IsoJar Headspace Samples Ditch cuttings samples for headspace gas analysis shall be collected in IsoJar containers at 30 m (90 ft) AH intervals from the first mud returns below the 13⅜ in.2.com 1.1.1. Figure 12 illustrates a simple sequence of the process stream. must be shipped to the geochemistry lab of choice. IsoTubes can be ordered from the following supplier: Isotech Laboratories. Attn: Dennis Coleman 1308 Parkland Court Champaign.3. Mud samples are also to be taken (in IsoJars) at regular.com All IsoTube samples. it is easier to collect gas and stock-tank liquid samples at the wellhead or choke manifold.3.g.EP 2007-3186 . The line should be purged before collecting a liquid sample to avoid getting a slug of precipitated solid that may be present in the line/valve. 1. depth zone. • These samples are not appropriate for PVT analysis. When a well stream is two-phase at the wellhead.24 - Restricted 1. reservoir. • Multiple samples can be taken over the course of the well test. Sampling During Well Test Operations – Hydrocarbons and Water During a well test it is the best opportunity to obtain representative samples of a range of trace components and bulk samples: • The clean-up period minimizes any remaining contaminants in the wellstream. these samples may also be appropriate for live-oil asphaltene analyses. pressure..2. NOTE: In some circumstances. and a description of the sample point should be recorded and returned with the sample to the receiving laboratory. 1.3. Planning Well Testing • Sampling during a well test should always be subject to appropriate planning prior to testing and should never be referred as a "routine". wellhead samples collected isobarically can be valid for PVT and other analyses requiring single-phase fluids. Samples taken after the field has been producing may be misleading as a result of possible phase changes through pressure depletion throughout the reservoir and.2.2. • Larger samples are easily obtained. Planning well testing and the well conditioning operation are therefore highlighted as separate issues below.1. Basic sample identification information should be included on the sample bottle (e.. around the well bore.1. early in the life of a well) the wellhead pressure may be higher than the saturation pressure. enabling verification of analyte detection. . • Long duration allows for stabilization and representativeness of trace components in the wellstream. especially. • At high flow rates (e. the volume of each phase collected is sensitive to the geometry of the sample port and rarely representative of the true well stream. sampling date).g. the collection of fluid samples down hole is a viable alternative to collecting samples from surface flow lines or separators. well number. • In order to obtain representative data on the initial reservoir fluid it is important to take an adequate quantity of good samples during the exploration and appraisal stages of the life of a field. In this case.3. • Depending on the degree of undersaturation at the wellhead. Wellhead and Choke Manifold • For low flow-rate wells. • The temperature. 2. Unstable production will result in liquid hold-up and slugging.2. The most pertinent aspects of the API practice (from the sampling point of view) are summarized below assuming sampling during production testing of a new well. • High flow rates often require large tubing diameters. Preparation of the Well Test Separator Conventional surface sampling of two-phase streams is only possible with reliable flow. there may be significant grading. water cut. 1. • Conditions that are likely to provide stable tubing flow should be calculated before the test takes place.. inflow performance etc. sea-water and spent acid. However. from the sampling viewpoint the tubing diameter should be as small as practicable. This can be estimated roughly for a range of possible well conditions. • Well clean up should be as short as possible. a drawdown should be kept to a minimum to limit the possibility of phase changes in reservoir fluids near the bore hole (i. which can only be eliminated by either increasing the production rate or reducing the tubing size. using in-house computer programmes such as WIPCO/WIPCOG or ICEPE well performance simulator to generate a set of curves of well-head pressure against flow rate for the main parameters of GOR. However. Mud. pressure and temperature measurements of the separator inlet and outlet streams. must be produced out of the well bore before sampling but the well should be sampled before any significant production of reservoir fluids has occurred. • In general. . Well Conditioning API RP 44 contains a thorough description of well conditioning operations and should be followed in detail.25 - Restricted • With long hydrocarbon fluid columns. However. The objective of well conditioning is to replace the non-representative fluid (created as a result of phase changes through pressure reduction during clean-up) located around the well bore by displacing with original fluid from more distant parts of the reservoir.3. if any. A typical test program should therefore consist of a short high rate clean up period followed by a choked-back stable flow rate well conditioning and sampling. 1. and in addition may require several discrete intervals to be tested. the effect of prior production on reservoir analysis from well tests can be compensated for (as long as production details are known) so that sampling could take priority and can be carried out before any other stages in the well test programme. sampling can be planned and conducted during a multistage flow phase of the well test. This may dictate that only limited intervals are perforated. a productivity test may also require more complete perforation to avoid complications in reservoir analysis as a result of partial penetration of the reservoir thickness.e. Table 8 summarises criteria to judge whether a well may be producing at constant composition. • During sampling.3.EP 2007-3186 . if possible do not produce with bottom-hole pressures below saturation pressure prior to sampling).2. • It is essential that production is stable prior to and during sampling.3. including steam cleaning. • If in doubt consult a process engineer.26 - Restricted • Dirty sampling lines contaminate samples and containers. • Out-flow lines should also be checked (see report EP 93 1315). Both liquid and gas capacity must be considered. • The process engineer can contribute to ensuring that separators used are appropriately designed for the flow rates expected during sampling and testing. all sampling lines. caustic soda and/or solvent rinsing of the separator. • The well-test supervisor should check to ensure that the separator has been adequately maintained and its internals and controls are in working order. caused by high flowrates • Liquid level in separator too low or not correctly controlled • Faulty gas and liquid metering.should be carried out prior to the test. • The separator should be operated at well below its maximum capacity to avoid carry-over or carry-under. • The engineer responsible for the well test should obtain information from the service company on the dimensions and geometry of the separator and ensure that this information is used to calculate allowable flow rates over a range of operating pressures and gas/oil ratios. • The concentrations of Hg and H2S should be measured AFTER cleaning as they are easily invalidated by contamination (from previous operations). caused by (for example): o Badly calibrated meters o Badly calibrated pressure gauges o Badly calibrated thermometers o Use of wrong correlations for determining gas densities o Gas breakout downstream of the separator but upstream of the liquid meter through pressure reduction .EP 2007-3186 . and access points . Thorough cleaning . The following are main causes of unreliable samples for recombination: • Flow rates too high • Inefficient separation • Foaming • Emulsions • High separator levels • Blocked or holes in demister pads • Gas carry under into the liquid stream. ” • Accurate metering of very low liquid rates is difficult. it is important that the liquid levels for both water and hydrocarbon remain constant throughout the metering period. The liquid levels should be noted at the beginning and end of the sampling period and corrections made to the liquid throughput if the levels have changed. The orifice plate should be of the correct size to cover the expected range of gas flow and should be checked to ensure that it is clean. plastic.27 - Restricted 1.3. • Liquid hydrocarbon flows are nearly always measured by positive displacement meters or turbine meters. • The difficulty in accurately measuring low liquid flows also applies to water meters. are clearly dependent on good metering. It is important that the actual rate measured at the test separator is reported along with the separator temperature. and any “meter factors. Metering Around the Separator The validity of gas and liquid samples taken for later recombination. because the correct temperature and pressure must be known to determine molar ratios for recombination of the gas and liquid samples in the laboratory. For testing well streams with a low liquid content. • In an atmospheric collection tank it is necessary to flash a sample of the separator liquid to tank conditions in the laboratory in order to determine the shrinkage factor.3. secondly. flat.EP 2007-3186 .. the relationship between tank and separator liquid volumes. . • The meters should be calibrated before and after the test using a fluid with physical properties as close as practical to those of the fluid to be measured. • Gas flow rates are almost always measured with orifice type meters. Liquid carry over will seriously disrupt the density component of the meter calibration. 1.4. The engineer responsible for the well-test design should specify that the meters have a sufficient range to cover the flow rates that are likely to be encountered. In some cases better results can be obtained by measuring the liquid build-up in either the separator or an atmospheric collection tank.3.e. Surface Sampling Methods – Hydrocarbon Liquids General Liquid Sampling Issues Liquid samples can only be taken in special acid washed borosilicate bottles. and normal glass. • Temperature and pressure measurements during well-test sampling are also important: firstly for the effect that they have upon the corrections for both liquid and gas measurement. Mercury will adsorb to any other type of material including steel. and free of nicks and burrs. i. The gas gravity and compressibility factor affect gas measurement and are usually calculated from the observed gas specific gravity. pressure.2. although an error in metering water will not usually have as serious a consequence as an error in metering the hydrocarbon liquids. Hydrocarbon Gases Critical moments to the sampling are: For PVT . • Refer to EP 93-1315 for a more detailed description of the practices and precautions when sampling crude/water mixtures for dehydration/de-oiling tests. • Manual sampling of hydrocarbon liquids for compositional analysis should be carried out using only gas-compensated transport bottles or mercury-free floating piston type samplers. flow line sampling).g. o Refer to ISO 3170 for advice on the manual sampling of: o liquid petroleum products o crude oils o intermediate products o glycols at low pressure which are o stored in tanks at or near atmospheric pressure o transferred by pipelines o handled as liquids at temperatures up to 100°C (212°F) for o preliminary analysis o evaluation purposes o custody transfer. because it does not avoid lighter fractions evaporating during the sampling process.Gas: • Connection to the separator • Flushing of dead sample from connection lines • Proper sampling time (30 min.28 - Restricted Sampling Oil and Gas Condensates for Process Design and PVT Analysis Contact of the fluid samples with air should be minimised.EP 2007-3186 .. • Refer to ISO 3171 for advice on sampling heterogeneous mixtures (e. 1. • ISO 3170 is not suitable for PVT quality samples or light end analysis. This is suitable for obtaining representative samples for all standard specification tests (ASTM D 1835) on LPG's apart from compositional analysis.) . • Refer to ISO 4257 for advice on sampling Liquefied Petroleum Gases. Surface Sampling Methods .3.4. 4. However analysis for low levels of hydrogen sulphide should normally be carried out in the field as metal scavenging can quickly deplete H2S concentrations. then breathing apparatus must be worn and an observer acting as a safety standby must be in place a safe distance from the sampling operation. • AISI 316 or AISI 304 stainless steel are still not completely inert so cannot be used when accurate determination of hydrogen sulphide in the laboratory is required. (see Shell standard EP 95-0317-32). If the hydrogen sulphide concentration of the gas being sampled may be greater than 50 mg/m3. which have been evacuated prior to sampling. • Sample containers should be constructed to ASME section VIII division 2 in either AISI316 or AISI 304 stainless steel and appropriately pressure rated for the planned sampling conditions. but the recommended method is to use dual valve cylinders. • The purged gas must be vented to a flare or to a well-ventilated safe area.1. Section 1. . For PVT . time schedules ensuring proper sampling. Coated cylinders (Teflon) are available. whichever is the most stringent.3. • It is possible to use single valve cylinders. They must also have been tested to 1.1. • Samples taken for trace sulphur analysis with hydrogen sulphide levels less than 50 mg/m3 should be taken in salinized glass containers (with obvious regard for reduced pressure rating). but these also absorb hydrogen sulphide to a certain extent. and simultaneous sampling of gas and condensate.EP 2007-3186 .Liquid • Connection to separator • Flushing of entire bottle prior to sampling • Check for clear condensate from the sample line • Avoid large pressure drop during bleed of 10% of volume to create safety gas cap for transport • Minimum pressure of 50 psi (piston will not move below 50 psi) 1. purging.3.6 covers onsite analysis of H2S in detail. • The cylinder valves should be soft-seated in preference to the metal-seated variety.5 times rated pressure or according to local regulations. PVT Sampling Special attention is paid to stable separator conditions.29 - Restricted • Visual check for leaks by purging all connections with a special solution • Hydrocarbon gases sampled for preliminary analysis. • Care should be taken to ensure that the cylinder is held upright and the outlet valve is pointing downwards. the “Purge and Fill Method” must sample process monitoring or custody transfer following GPA standard 2166 section 7. high hydrogen sulphide content gases).3.. hydrocarbon composition C1 – C12.. • GPA 2166 may also be used for custody transfer when the contract is based on light components in dry gas (i. N2. Both gas and liquid samples are taken simultaneously.30 - Restricted 1. • Any pressure drop across the sampling system should be minimal in order to avoid condensation forming in the cylinder or its connecting line. CO2) or for more detailed analysis of gas streams that are known to be dry.e.C12). • The temperature of the sampling line and cylinder must be kept at or above the temperature of the gas being sampled while sampling is taking place. C1 . . no entrained liquid). • Sample depressurisation should be sufficiently slow to avoid condensation and consequent build up of heavy ends in the sample container. If a representative sample of the total process stream is required then a sample line separator should not be used.g. the evacuated cylinder method may be the only practical method of sampling. GPA 2166 also gives relevant precautions on the use of heat tracing on sample lines and cylinders. • The “evacuated container method” detailed in GPA 2166 may also be considered but is limited to sampling pressures below 7590 kPa (1100 psig). density. This recommendation is only supported if it is just required to collect the gas (i. Ideally.EP 2007-3186 . Samples collected by this method must be corrected for air contamination since containers will never be completely evacuated prior to sampling. Condensate Sampling Some volatile hydrocarbons are lost (light components) during sampling due to the pressure difference between the separator (approx 750 psi) and the atmospheric pressure at the sampling point.. • If no safe means can be found to vent purge gas (e. This correction will involve separate analysis for oxygen.4. heat-tracing or insulation should be applied to the sample-line. GPA 2166 details the required number of purge-fill cycles depending on sampling pressure.g. • GPA 2166 recommends the use of a “sample line separator” to remove any liquids from the sample upstream of the sample container. • GPA 2166 is adequate for samples for which a simple analysis only is required (e.2.e. • GPA 2166 requires an extension tube between the final valve and the cylinder so that the pressure drop is taken some distance away from the cylinder.. • The sample container is repeatedly filled then emptied using the gas to be sampled. Losses are minimized by sampling as fast as possible and rapid closure of the sampling devices. • The mixing/sampling manifold (with static mixing device) is installed upstream of the choke manifold.3. inorganic non-metallic constituents. and C-H-O isotopes. These inefficiencies compound metering problems and may lead to inaccurate recombination ratios being used to generate separator feed stream compositions. enhanced by Petrotech. proper calculations of the production rates for the sampling have to be made and achieved so valid samples can be taken during the well test. and therefore recombined fluid composition. The isokinetic sample stream is processed in a separation unit (Mini-lab). Standard (well-test) separators have been demonstrated to be highly inefficient when separating volatile oils and gas condensates at higher flow rates. allowing a sample stream of the two-phase stream to be withdrawn isokinetically. The fluid can be processed through a 1.3. 1. the TRC developed method (developed by Shell. now part of the ExproGroup) remains the only alternative for sampling gas gas/condensate well or process streams.4. 2.4.3. corrected accordingly. The first is collected with an upstream facing sample probe and the second with the sample probe facing down stream. volatile organic acids. Comparison of the two samples allows the liquid carry-over to be estimated and the well stream GOR.EP 2007-3186 .31 - Restricted 1. The principle advantages of the method lie in the fact that it does not rely on efficient separation and metering of streams in process separators and also that it allows phase separations to be made at reduced temperatures so as to provide sufficient liquid sample for subsequent analysis. The gas retention time in the first stage separator in the Mini-lab is approximately 3-16 times longer than in the test separator. or 3 stage separation process.3. Therefore.5. The technique can therefore be considered when the analyses from samples taken from such streams are to be used as the basis for reservoir studies and/or process design. These data are . • This technique allows both conventional PVT and non-pressurized samples for compositional characterization to be taken. Split Phase Sampling (IsoSplit®) • The method is based around the controlled phase separation and subsequent analysis of a representative side stream iso-kinetically removed from the stream being sampled. without a need for the split phase sampling device. • Although the mixing device used in the TRC sampling manifold has grater uncertainty at lower flow rates. Surface Sampling Methods .4. 1.Water This section contains procedures for collecting water samples for several analyses: metals. Isokinetic Separator Sampling • The method involves collecting two isokinetic samples. It is assumed that the first sample will be representative of the entire stream (all liquid carry over is assumed to be evenly distributed as a fine mist) while the second sample will not contain any liquids so will be representative of the gas stream alone. 1. During surveillance they can be taken at any time. biodegradation indication. Dissolved oxygen. The following guidelines should be considered: Immediately: pH. Appendix 3 addresses standard Shell procedures for surface sampling Analysis planning is key to obtaining accurate water data (more so than for hydrocarbons). Alkalinity. narrow mouth Nalgene bottles. or other locations in large (one quart/liter). the separator. samples should be collected during the final 12 hours of the main flow period – directly from the water line on the separator. The reader is referred to the document “Guidelines for Sampling and Analysis of Produced Water for Reinjection or Disposal” by the Water to Value Team for collecting water samples for analyses other than mentioned above. Conductivity <6 months: Metals (if sample is preserved with HNO3) During a well test. Rinse container three times before proceeding with sampling. H2S <28 days: Chloride.ONLY in water leg • 1 x 25 ml vial with nitric acid for acidification 1. origins of water determination. Pre-Sampling Preparation at the Sampling Site • Water samples can be collected from the wellhead. scale calculations. e.EP 2007-3186 . This reference is referred to as “Standard Methods” hereafter.32 - Restricted used in a variety of applications.5. CO2.g. These guidelines are not extensive and should not be considered as a substitute for the skill and judgment of an experienced sampling technician. T. which may require additional and/or different sets of sampling procedures. The procedures in this document are based on in-house experience and are in line with procedures and recommendations in “Standard Methods for the Examination of Water and Wastewater. A minimum of approximately one liter (2 pt) of water should be collected from a given sampling point. etc. (1 ml glutardehyde per 250 ml sample) • 1 x 100 ml glass serum bottle • 2 x 250 ml filtered water samples • 1 x 25 L UN drum . 20th edition” edited by Clesceri et al. If this volume presents a problem then a 125 ml (½ pt) Nalgene bottle can be substituted. . (10 ml HNO3 per 1 L) • 1 x 1 L Nalgene or glass with glutardehyde..3. The following should be considered minimum requirements for water samples • 2 x 125 ml Nalgene or glass with ‘red’ cap • 1 x 1 L Nalgene or glass with ‘red’ cap acidified using HNO3 to pH~2. do not rinse the bottles. 1.g. pH is altered very quickly and taking a pH-measurement immediately is crucial for correctly calculating the original concentration of pHdependent species in the water such as bicarbonate. Sampling for Inorganic Non-metallic Constituents and Organic Acids Analysis • Fill bottle to the top of the rim. unused.3.3. 1. 1. . • Take pH reading immediately.5. Sampling for Oxygen-Hydrogen Isotope Analysis • Fill bottle to the top with water drawn with the syringe from the middle of the first 1 litre aliquot.. Volatile organic acids will partition into the headspace. • Acidified and untreated natural high pH samples are transported and collected in Nalgene bottles to avoid metals and Si contamination from glass.. The amount of water per sample is maximized and all samples are inspected visually to guarantee no entrainment of condensate or leakage.5. • Secure top with electrical tape. Initial Water Collection • Fill the 1 litre Nalgene bottle. as this will remove the preservative.3. and blown with nitrogen before adding preservatives (such as acid or zephrin chloride) and sampling. especially when trace metal analyses are required.4. If a preservative has already been added to the bottles before sampling.3. • All lines are flushed prior to sampling of water into prescribed bottles (glass and PE) and IATA containers. Leave no headspace. There should be as close to zero headspace as possible. Sample for oxygen-hydrogen isotope analysis should be collected and sealed as soon as possible to avoid interaction with atmospheric oxygen. as oxygen will readily exchange between the atmosphere and water sample. phosphorous) content (ICP) analyses are acidified using nitric acid (pH checked) to avoid precipitation of solids (e. Do not filter. Do not wash bottles with tap water to clean. ensure that the containers are clean. Use funnel if needed. Do not filter. iron oxide). • Water samples for cations and some non-metals (e. • Proceed with sampling in the sequence given below.EP 2007-3186 .5.2. • Seal top using crimping tool.g. • The use of ultrapure nitric acid is strongly advised. which will alter the isotopic signature of the sample. If preservatives are added at the time of sampling. rinse containers with produced water three times prior to adding any preservative. • Attach label. • Add 4 ml gluteraldehyde.33 - Restricted • If using your own containers. 6 cm) headspace for expansion. Post-Sampling Procedures: • Re-fill the 1 litre bottle after filling the other containers. • Seal top with electrical tape.3. (Zephrin chloride can be added during sampling as well). • Fill bottle to the top if sample not in danger of freezing.2 pt) glass serum bottle. Pour water from the 1 litre bottle into the syringe. Nigeria) • When you may be facing lengthy export delays (e.g. Leave room for acid.5. • Attach label.g.3. flow assurance. Sampling for Metal Analysis • Fill the 125 ml (1/4 pt) Nalgene bottle to the neck using the syringe/filter assemblage.34 - Restricted 1.6.3. Malaysia) • When project would benefit from quick information. if bottle was not pre-acidified.7. 1.05 oz) nitric acid with small plastic syringe if container was not preacidified. (e.5. • Attach label. Use the syringe/filter assemblage for filling the glass serum bottle. • Properly dispose of the used syringes and filters after sampling is complete.25 in (0.EP 2007-3186 . • Seal top using crimping tool. otherwise leave 0.. • Maintain samples in an icebox until arrival at the laboratory 1. last minute tune of the well test design) Several companies offer onsite analytical services ranging from simple density measurements to limited scope PVT. Do not filter. and trace contaminant detection. This batch will be kept as a back-up sample.3. • Add 125 ml (0. • Attach label. 1.5.. Sampling for Carbon Isotope Analysis • Add 2-3 drops of zephrin chloride to the 100 ml (0.g.5.6. . Onsite-PVT and Other Analyses for Hydrocarbons and Water Utilization of the onsite PVT should be always considered in the following situations: • In countries where local analysis facilities have a inadequate capacity (e. • Secure top with electrical tape.. Egypt. Onsite PVT • The equipment of usual mobile PVT labs (which in reality is a 20 ft container) is modular. • The separator gas and oil compositions are mathematically recombined to obtain the reservoir fluid composition based on the measured gas and liquid compositions and GOR values. Thus. high hydrogen sulphide content). • The purged gas must be vented to a flare or to a well-ventilated safe area. Fluid Validation and Recombination • An atmospheric flash provides parameters such as GOR and stock tank oil density. If the hydrogen sulphide concentration of the gas being sampled may be greater than 10 mg/m3 (ppm). thus ensure that the right equipment is requested . The gas released is captured in an atmospheric Gasometer.35 - Restricted In general.. then breathing apparatus must be worn and an observer acting as a . • Note that due to the offsite situation all analyses may be prone to an error of ±10% of final onshore-lab-determined values. the evacuated cylinder method may be the only practical method of sampling. • Care should be taken to ensure that the cylinder is held upright and the outlet valve is pointing downwards. • The flashed fluids (gas and liquid) are subjected to compositional analysis using gas chromatographic techniques. whereas the more detailed PVT analyses will require a “full blown” lab. Significant differences are found for low concentrations (<100 mg/l). • If no safe means can be found to vent purge gas (e. The corresponding volumes of gas and liquid are then measured. Subsequently. onsite water analyses are similar to laboratory results when the analytes are high in concentration (>1000 mg/l).3. a quick P-V relationship is established to determine the saturation pressure. 1. A small portion of homogenized single-phase reservoir fluid is subjected to a zero flash experiment to determine the Gas-Oil-Ratio (GOR). measurements of the GOR and API may require only small 10 ft container and very basic equipment.1.EP 2007-3186 . a sub-sample taken from each cylinder is isobarically transferred into a PVT cell (Figure 15) at reservoir temperature. Figure 15 illustrates a typical mobile lab set-up.g. • In addition to flashing. QC-ed data within 1-2 weeks). the data have to be treated with a full understanding of such limitation. Rigsite pH and specific gravity analyses appear to be adequate. • Flashing is conducted from a pressure above the bubblepoint pressure at reservoir temperature to ambient conditions.6.depending on the actual analyses required: for example. • The increased uncertainty is compensated by the rapid availability of data (raw data within 24-48 hours of wireline tool recovery. • Flashed gas is collected in a piston syringe and injected.6.g. Ag+(aqu) + Cl-(aqu) → AgCl(solid) {1} .36 - Restricted safety standby must be in place a safe distance from the sampling operation.3.2. The data from these two sub-samples are compared to obtain the liquid composition. The so obtained diphasic fluid is pressurized to the reservoir pressure and rocked for a minimum of two hours to homogenize it. with Helium as the carrier gas. Ion concentrations require additional analytical equipment as follows: Titrations Chlorides Determined by simple titration with silver nitrate solution. can be carried out as part of the standard onsite PVT analysis. • The volume of separator liquid at separator condition to be added to the gas to obtain the reservoir fluid is determined from the GOR. • A known volume of separator gas is first charged to the recombination cell (which is maintained at the separator temperature) and the cell is allowed to stabilize at that pressure. a quick P-V relationship is established to determine the saturation pressure. Persistent appearance of a milky white solid suspension indicates the reaction has gone to completion and the concentration of chlorides can be calculated. a small portion of the single-phase reservoir fluid is isobarically transferred into the PVT cell at the reservoir temperature.EP 2007-3186 . Subsequently. Water Analyses The standard physical measurements. Gas Chromatography • Flashed gas and residual liquid obtained from the zero flash are used to measure molecular compositions using a gas chromatograph. (see Shell standard EP 55000-32). and density. • The residual liquid is divided into two sub-samples. conductivity/resistivity. Recombination of Separator Samples (for Separator Samples) • The chosen separator gas and liquid samples are stabilized to a known pressure and separator temperature in two different bottles. A known amount of sample is titrated with a known concentration of AgNO3 solution. 1. • The monophasic fluid is allowed to stabilize at the reservoir conditions and before subsample are taken for individual experiments.. One is diluted with CS2 while the second is doped with a known amount of internal standard and diluted with CS2. pH. e. Recombined Fluid Validation (for Separator Samples) • After homogenizing. One EDTA titration will determine Ca and Mg. The persistent appearance of a dark blue/black colour indicates that no further I2 can be consumed. and free iodine is complexing with the carbohydrate indicator. which can quantify a wide range of ions in a single analysis. and the following ions are separated out and quantified: Lithium. Sr2+. Typically. ion balance calculations quality checks of rig data are invalid. Sodium is typically calculated by the difference between total anions and total cations. Once the instrument is calibrated and a steady baseline has been determined. an analysis program for tracers is custom designed for the task. Ba2+. Main Cations (EDTA Titration) Typically. Multi-ion analyses This is possible using a multi-ion analyser. Li+. Mg is calculated by difference. Each kit is dedicated to a single ion. K+) Measured using a HACH kit. This instrument also measures pH and conductivity. The concentration of sulphides can then be calculated. Two inflection points will be observed. The mixture is shaken well and the cell is placed in a colorimeter. Sr2+. which provides a concentration reading. As a result of the sodium calculation. Analyses are based on colour reactions between specific reagents and the major cations and anions. Sulphides Measured using titration of an iodine solution of known concentration and a carbohydrate indicator (usually starch). only the main cations are analysed offshore using HACH chemistry including Calcium and Magnesium. A separate analysis is necessary for each ion. the first corresponding to the carbonate.37 - Restricted Main Cations (Li+. .3 oz) of sample. but the amylose is the most common. Strontium. The analysis cell is filled with 10 ml (0. and the HACH sachet of indicator powder is added. the water sample is simply injected into the ion chromatograph. Carbonate and Bicarbonate (CO32-. a second will determine Ca only. I2 (aqu) + 2H2S → 2I-(aqu) + 2HS+(aqu) {2} I2 + amylose starch solution (colourless) → amylose-iodine complex (blue-black solid) {3} Other carbohydrate indicators are available providing different indicator colours. Na+. HCO3-) Measured using a straightforward acid base titration with a universal indicator solution. A calibration curve is established for each analyte of interest using proper standards. Colorimetric Analyses Trace cations and anions can be analyzed using colorimetric methods (in conjunction with a spectrometer). the second to the bicarbonate.EP 2007-3186 . • Samples for Mercury and Radon are caught and utilized onsite or transported to the shore – large volume flow is necessary to obtain reliable results. Due to the time-sensitivity of these analytes.38 - Restricted Sodium. Surface Sampling and Onsite Analysis Methods – Contaminants Certain trace or reactive components. NOTE: reliable data can only be obtained during a well test.3. Br-. • It has been our field experience that approximately 10-30% of the most reactive sulphur species (C1-4 mercaptans) is decayed within first 24 hours after surface sampling (the mechanism is still unknown.g. but the decrease of pressure from reservoir to ambient is a main trigger). Mg2+. Magnesium.. Mercury) • Samples for H2S. can only be reliably detected when large volumes of sample are available. Radon. Potassium. SO42-. N2. and Sulphate.EP 2007-3186 . Readers should familiarise themselves with standard procedures on handling H2S (see EP 95-0317). Most of these compounds are toxic. the following points should be considered when planning to ensure all samples and analyses get completed within time available • Time sensitive sampling (mercaptans) at the end of the flow period • Avoid interference (only 1 sampling point per fluid type) • Allow sufficient flow time for analyses (e. • Radon is radioactively unstable with a half-life of 91. specifically those listed below.7. regardless of the container type. Calcium. Ca2+.2 hrs. . and/or analysis is possible within a few minutes to hours of collection. Na+. Ba2+. Bromide. Barium. Cl-. • Mercury adsorbs onto a wide range of materials and is impossible to stabilize when low levels present. CO2. 1. and C7+ hydrocarbon gases are initially caught in the ‘gas-bags’ taken from the gas line. particularly H2S. Sub-samples are then drawn from the gasbag for analysis. Chloride. K+. and easy to execute by almost any personnel. the H2S content can be calculated.39 - Restricted Several analytes can be measured by stain tubes or titration. some stain tubes do not distinguish between H2S and total mercaptans. consider these factors: 1. titration. Iodine solution has a characteristic blue-purple shade. or micro-GC can be used to determine H2S concentrations at the wellsite. which changes colour according to the analyte concentration. • Based on the known amount of iodine to the known volume of gas. • Unlike the titration method. when selecting the preferred method. through an absorbing train of 2 bottles of 40% Potassium hydroxide (KOH) solution and 1 bottle of 5% mono-ethanol-amine (MEA) to remove CO2 and COS. sequentially corresponding to the H2S and mercaptan amounts as illustrated in Figure 17. while thiosulphate (product of the H2S reacting with the iodine) is colourless. • This method is fast. The plot of potential (mV) against amount of AgNO3 (mole) typically displays two inflection points.EP 2007-3186 .1. and titrated with silver nitrate (AgNO3) while being constantly monitored by a potentiometer. H2S • Stain tubes. respectively. • The KOH solutions are then combined. • A Teflon-lined hose is attached to the gas export line from the separator (a gas line manifold with a vent line must be installed to allow pressure and flow rate control). Stain Tubes (Figure 16) • An appropriate stain tube (Dräger or Sensitive) is selected and a sub-sample of gas is drawn out of the gasbag through the indicator material. Unfortunately the stain tubes are prone to interference from other compounds (see Table 11) and only one chemical can be quantified per stain tube. Titration: UOP212 (Figure 17) • UOP 212 is the standard followed for mercaptans and H2S determination when the H2S concentration is >0. simple. • A known concentration of iodine solution is then added until the blue is no longer visible after shaking. Concentrations can be calculated by dividing by the volume of gas analysed.1 ppm in the gas. The gas is then passed through a flow meter to measure the volume. Results from this technique usually correspond well with laboratory data.2 pt) gas from the gasbag into the Tutweiller unit using a gas syringe. .3.7. Titration: Tutweiller method • Transfer 100 ml (0. inexpensive. treated with ammonium hydroxide. 3. and easy to execute by almost any personnel. inexpensive. respectively.2. • The KOH solutions are then combined. and titrated with silver nitrate (AgNO3) while being constantly monitored by a potentiometer. . CO2. blank. • This method is fast.40 - Restricted Micro-GC • The GC is initiated and appropriate baseline. and O2 (4 channel output only). some stain tubes do not distinguish between H2S and total mercaptans. which changes colour according to the analyte concentration. • Only trace amounts of O2 are found in producing systems and process plants. Mercaptans • Total mercaptans can be determined using stain tubes or by titration. 1. Concentrations can be calculated by dividing by the volume of gas analysed. its presence in significant concentrations is an indicator of contamination with air. Stain Tubes (Figure 16) • An appropriate stain tube (Dräger or Sensitive) is selected and a sub-sample of gas is drawn out of the gasbag through the indicator material. sequentially corresponding to the H2S and mercaptan amounts as illustrated in Figure 17. a known volume of gas is removed from the gasbag and injected in the micro-GC. Unfortunately the stain tubes are prone to interference from other compounds (see Table 11) and only one chemical can be quantified per stain tube. Lines must be flushed to remove ambient gas (which will contaminate with high amounts of N2 and O2). Compounds typically analysed in a single run are: C1-C7. • Using a gas syringe. • Unlike the titration method. N2. H2S. • A Teflon-lined hose is attached to the gas export line from the separator (a gas line manifold with a vent line must be installed to allow pressure and flow rate control). simple.1 ppm in the gas.7.EP 2007-3186 . The H2S concentration should be corrected for dilution by air contamination (considering air to consist of 4:1 volume of N2:O2). through an absorbing train of 2 bottles of 40% Potassium hydroxide (KOH) solution and 1 bottle of 5% mono-ethanol-amine (MEA) to remove CO2 and COS. treated with ammonium hydroxide. The gas is then passed through a flow meter to measure the volume. Titration: UOP212 (Figure 17) • UOP 212 is the standard followed for mercaptans and H2S determination when the H2S concentration is >0. The plot of potential (mV) against amount of AgNO3 (mole) typically displays two inflection points. and calibration runs are carried out. Titration: Orstat (Figure 18) • Using a gas syringe. blank.3.41 - Restricted 1. 100 cc of gas sub-sample is removed from the gasbag.3. The H2S concentration should be corrected for dilution by air contamination (considering air to consist of 4:1 volume of N2:O2). FEAST’s preferred stain tubes for CO2 determination are the amine variety. N2 Micro-GC • The GC is initiated and appropriate baseline. blank.7. and O2 (4 channel output only). Lines must be flushed to remove ambient gas (which will contaminate with high amount of N2 and O2). or micro-GC can determine gaseous carbon dioxide concentrations. The H2S concentration should be corrected for dilution by air contamination (considering air to consist of 4:1 volume of N2:O2). Micro-GC • The GC is initiated and appropriate baseline. . Hydroxide stain tubes are influences by the presence of H2S. H2S. CO2. and calibration runs are carried out. The CO2 is then scrubbed by repeatedly passing through a 30% KOH solution. • Only trace amounts of O2 are found in producing systems and process plants. leading to erroneously high determinations. Lines must be flushed to remove ambient gas (which will contaminate with high amount of N2 and O2). Compounds typically analysed in a single run are: C1-C7.EP 2007-3186 . titration. N2. and displaces an inert brine solution in a burette.4. a known volume of gas is removed from the gasbag and injected in the micro-GC. CO2 Stain tubes. Therefore. Stain Tubes • CO2 stain tubes are available in either amine-based (Dräger) or hydroxide-based (Kitigawa) indicators.7.3. 1. The CO2 scrubbed from the gas is replaced by inert sodium sulphate brine. • Using a gas syringe. • Only trace amounts of O2 are found in producing systems and process plants. its presence in significant concentrations is an indicator of contamination with air. Figure 18 illustrates the apparatus in this technique. and calibration runs are carried out. The CO2 concentration is read from the calibrated scale by levelling the brine level in the inner burette with the level in the levelling jar. using a bladder to stimulate the movement of the gas sample into contact with the KOH solution. its presence in significant concentrations is an indicator of contamination with air. Trace gasses (e. and through a flow meter. Accurate measurements of these concentrations require either a 4 channel Micro GC or a dedicated O2 analyser. 1. N2. a known volume of gas is removed from the gasbag and injected in the micro-GC. Ar) Like Radon. emitting a radiation and producing radioactive 120Po as a daughter product. It uses an electrochemical fuel cell and can detect a wide range of O2 concentrations. Compounds typically analysed in a single run are: C1-C7. In operations it accumulates in LNG/GTL plants causing safety and heath hazards.1 ppm) up to 30% of O2.7.7. causing health hazards. which are then shipped to labs for analysis by Gas chromatography-Mass spectrometry. blank. Micro-GC • The GC is initiated and appropriate baseline.3.EP 2007-3186 • . . He. these gases accumulate in LNG/GTL plants.42 - Restricted Using a gas syringe. • During sampling the apparatus is connected to the gas line as shown in Figure 19. H2S.6. O2 • Only trace levels of Oxygen are produced in production and process plants. and calibration runs are carried out. CO2. and O2 (4 channel output only). Lines must be flushed to remove ambient gas (which will contaminate with high amount of N2 and O2). from trace levels (0. a known volume of gas is removed from the gasbag and injected in the micro-GC. Systech O2 analyser • The O2 analyser can be connected directly to the gas sample point.3. • Using a gas syringe.3. which monitors the volume and rate.7.7. The radioactive 222Rn isotope decays. 20 L of gas sample flows at 0.5 L/min through a liquid knockout bottle and filter (to ensure no liquid carry-over or Radon daughter products interfere with the analysis) through two scintillation-counting cells. H2S. and O2 (4 channel output only). Sampling consists of collecting 600 cc gas cylinders. 1. • The scintillation cells are then left for at least 3. N2.g. Sample lines should be flushed and collection vessels evacuated prior to sampling. Radon • Radon is naturally generated by radioactive decay of uranium (via radium) in granite. CO2.5 hours while the 222Rn decays. Compounds typically analysed in a single run are: C1-C7.. arranged in series. • The 222Rn activity concentration is reported as Bq/m3 1.5. and through a flow meter. The trapped mercury is then quantified using a conventional analytical procedure.g. Additional scrubbers are placed if needed. The analysis is performed onsite due to the reactive nature of metallic mercury e. adsorption to solids and surfaces.3. prior to analyses. 1. The standard ISO 6978 method is designed for elemental mercury measurement in “dry” gas. the gas is slightly depressurized to about 500 psi. etc.3. mercury has to be collected and separated from aromatic hydrocarbons. • During sampling the apparatus is connected to the gas line as shown in Figure 20. mercury can not be determined directly in natural gas. The PLS will heat the sample and keep the pressure above atmospheric sample to avoid condensation due to JT cooling when significantly decreasing the pressure. Trace Compounds (e. Two Au/Pt sorption (Shell preferred) tubes are placed in series between the acid gas scrubbers and the flow meters (Figure 22). The gas from the scrubbers is let directly into the Pressure Letdown System (PLS). • The trap is then sealed and transported to a lab for analysis by ICP (inductively coupled plasma). Therefore. Sampling Mercury (Hg) Since the presence of hydrocarbons.g. This regulated gas flow is connected directly to the acid gas scrubbers. special care should be taken when attempting to sample Hg from natural gasses under nearly condensing conditions. Through a pressure relief valve.8. H2S and other sulfur components are stripped by acid gas scrubbers placed prior to the sorption tubes (Figure 21 and Figure 22). Sampling from dry natural gasses poses no particular problems.8.g. 700 psi). in particular aromatics present in (low) concentrations in almost every natural gas. which monitors the volume and rate.. However. Methods used by the oil and gas industry for the quantitative measurement of elemental mercury in hydrocarbon gas involve “trapping” mercury from a known volume of gas. The method does not appear to address sample point issues such as JT liquids and retrograde .. • Flow rates of greater than 0. these compounds can accumulate in LNG/GTL plants.. The sulfur concentration after the acid gas scrubbers is checked using Kitigawa tubes.5 L/min through a liquid knockout bottle and filter (to ensure no liquid carry-over) across a trap of AgNO3 on silica gel.43 - Restricted 1. Set-up for Gas Sampling of Hg Samples are taken from the horizontal separator gas flow line (running at e.EP 2007-3186 . 1. 20 L of gas sample flows at 0. causing health hazards.5 L/minute risk incomplete adsorption and total volume flow of greater than 20 litres risk saturation of the trap. interferes in the determination of Mercury by AAS or AFS. As.3. both resulting in erroneously low concentration measurements. conversion to HgS.1. Li) • Like Mercury.8.7. There are two types of tubes available on the market at the moment. Tubes are to be cleaned within hours after sampling to minimize memory effects due to diffusion of Hg into the inner layer of the collector materials. while purged with clean air for a couple of minutes. The unit should be sent offshore only when contamination levels are acceptable (<10 ng/m3). Au/Pt coated sand tubes are . lines are flushed to saturate all lines with Hg. For fields with high Hg content. Sand coated tubes (Shell preferred) and wire-type tubes. • Pressure should be released very controlled from the separator gas line into the mercury sampling line.3. With time and use. both elemental mercury and mercury in organo-mercury compounds are sorbed and detected. The tubes are analysed for their Hg content before and after flowing 10-50 liters to check and calculate the contamination. Sampling Tubes Elemental mercury is trapped by the Au/Pt tubes as a chemically stable amalgam.5. saturation of the acid gas scrubbers with sulfide is to be avoided as this will affect the sampling of mercury. In some situations the method is applied without rigorous assessment of whether the gas stream is a true dry gas stream when sampled. condensate) or mercury due to JT cooling. Lines should be pressurized during flushing to avoid condensation due to JT cooling by connecting a valve at the connection between sampling line and waste line. A stable gas flow (N2 or Hg free hydrocarbon gas) should be let through the PLS filled with two sample tubes. 1. Au/Pt sorption tubes are conditioned at 800ºC. the color will shift from clear white to blue indicating that the sorbent needs to be replaced. Most importantly.3. Acid Gas Filter Concentrations >50 ppm sulfur hamper adequate adsorption of Hg. all lines are flushed for 30 minutes. Most importantly: • Sampling and transfer lines should be kept as short as possible. For fields with low Hg content. The lifecycle of the sorbent is indicated by its color. lines are flushed to remove accumulated Hg. H2S and other acidic gases (Figure 21).8. Pressure Let Down System (PLS) The PLS needs to be checked for contamination before being sent offshore.4.EP 2007-3186 . This particular approach has been tested by Oilphase-DBR on fresh Malcosorb (hydroxide form) on request by Shell. and have proven not to interfere with Hg analyses. The use of a pressure let down system (PLS) or heated valves is strongly advised to avoid condensation of liquid (oil.2. The gas flows from the bottom to the top through the filters to ensure optimal contact between sorbent and gas. Malcosorb consist of sodium hydroxide (NaOH) pellets.8. 1. General Gas Sampling Issues Prior to sampling. 1. As indicated by the ASTM methods and PSA. Gas is passed through ‘Malcosorb’ scrubbers to remove moisture.8.3. 1.3.8.44 - Restricted condensation. All fittings are kept in a sterilized and sealed plastic bag. checked for zero Hg and sealed with rubber caps.3. However. and O3 will cause damage to the gold tubes. Relatively high levels of Hg (0. • Tubes to lab conditions immediately after sampling. • Pre-sample check gas flow and wet gas meters.3.8. zero reading required in 3rd tube. Au sand tubes are most often used in the field and have been shown to provide good results as well. • Check that there are no liquid drops in sample tubes. Gold is not inert. • Seal tubes immediately after sampling. Sample volumes should be restricted to a maximum of 50 liters to avoid poisoning of collector materials by other gas components. liquids can be entrained in the separator gas offtake. SO. • Check volume amount . or glycol could . Au reacts with ozone to form gold oxide. SOx..45 - Restricted Shell preferred as they were shown to be more efficient than Au tubes. off-white color indicates contamination. Au forms chlorides and chloroauric acid. HCl. H2O.inform operator if other than expected. oil or condensate. in the sampled gas stream can give unreliable data.7 nm and precipitate as HgO on the walls of the quartz tubes. • Teflon braided with stainless steel lines to be used on the high pressure side (prior to regulator).5 l/min to allow optimal adsorbing of Mercury to the tubes. Gas Sampling for Hg Duplicate sampling of Hg (two trains of tubes) typically using 10-50 liters of gas is conducted to verify consistency of results. For example. • Visual inspection of H2S filter. Cl2. e.EP 2007-3186 . Hg may be oxidized by a reaction with O3 formed in the detector at 253.1 to 5000 μg/m3) may also be sampled at pressures up to 40 Mpa by chemisorption on iodine-impregnated silica gel. Two tubes in series per train are evaluated and a third one is added when a significant amount of Hg is found in the second tube. This technique is not currently used in the field. The gold in the tubes is attacked by aqua reagents and hot sulfuric acid. In addition. The presence of entrained liquids.6. • Check for decreasing concentrations in each train. Critical to sampling: • Extensive conditioning of sample lines. • Controlled depressurization of gas from separator into gas lines using pressure letdown system (PLS) for sampling • The PLS needs at least two hours to stabilize • Use of heated valves is strongly advised • Sample lines to be kept as short as possible. The sample flow is restricted to 0.g. • Check sample seals. NOx. 1. The latter can be visually detected by yellow-brown stains on the quartz walls. and polyethylene are less desirable alternatives. etc. Data from this calibration are sent to the FEAST focal point before the unit is shipped to the rig. Liquid Sampling for Hg Liquid is sampled directly from the separator into the special acid washed borosilicate bottles. This phenomenon can be overcome by the use of a liquid knock-out pot upstream of the sampling device..3. Evaporated hydrocarbons and Hg are transported into a second cold Au/Pt tube where Hg is sorbed while the hydrocarbons pass through the detector without generating a .3.7. In general. Also. it is unclear how effective liquid knock-out is for fine dispersions.EP 2007-3186 . thereby giving apparently low mercury in gas phase mercury content. followed by distilled water • The bottle then dried inverted in dust free environment (lab cabin) 1. 1. Theoretical Background of Analysis Au/Pt tubes are (slowly) heated to 650ºC to vaporize hydrocarbons and Hg. Teflon. followed by distilled water o HCL 36%. The headspace should be minimized within the safety limits for transporting the sample and flushed with N2 before closing the bottles. Total Hg can be determined in the onshore lab but sulphur speciation on liquids is done onsite to avoid e. The temperature of natural gas will drop by 4ºC/Mpa. offshore • The bottle is detergent washed with tap water and then rinse with: o HNO3 69%.8. Preparation of borosilicate bottles • The bottle is acid washed onboard. condensate collected in a liquid knock-out pot may strip mercury from a gas stream. Samples should be transported to the lab and analysed as soon as possible to avoid losses.g. Direct condensation of mercury due to Joule-Thompson cooling may also appear. Data are reported in ng Hg/volume. apparently high gas phase mercury content will be measured. thereby giving apparently low mercury in gas phase mercury content.8. mercury can also be entrained on particles. the Sir Galahad unit is only to be sent offshore after a proper calibration onshore. o Due to its sensitivity for contamination.8. scavenging of Hg by sulfur compounds. Consequently. which starts to desorb at 450ºC. Nonetheless. any minor delay in the analyses will not affect results considerably.46 - Restricted be entrained in the TEG contactor offtake. analyses are performed as soon as possible to minimize mercury losses through diffusion or leakage. Results are reported including standard deviation and confidence levels. However. sampling is to be performed at least 10ºC above the dewpoint of the gas. The liquids can contain relatively large amounts of mercury in comparison to the gas phase. Sir Galahad Elemental Hg Analyses of Gas Samples As mercury forms a chemically stable amalgam with gold. Pyrex. In addition to liquids. This can result in condensate “blinding” of the sampling device. Stripping of mercury from gas phase by retrograde condensate created by JouleThompson cooling and/or equilibrium pressure may occur. and Reporting • Check the remote port of the Sir Galahad using a known sample. • The temperature of the calibration vessel is checked with a separate thermometer (ΔT < 1º). Calibration At a fixed temperature. A unit to stabilize the rig power is to be placed in between the Sir Galahad unit and the rig power inlet. Hg can absorb and emit 253. Only scattering in the data as a result of water is observed prior to saturation of the tubing and valves. If the quality of the gas supply is questionable. causes a 10% error in the calibration). Varian/Chrompack number CP17971). Stability of Sir Galahad on “day” periods is preferred.999 the following should be taken into account: • The analyzer is calibrated for at least three Hg concentrations prior to each analyses series. Interpretation. The second tube is heated fast to 800ºC to release the Hg into the analyzer carried by Argon flowing through the system (1 L/min –1). • Confirm the latest Hg calibration points on graph. Varian/Chrompack number CP17972).. It is crucial to remove any aromatics from the system as they will interfere with the UVfluorescence detection. If rig air is to be used. . This will avoid fluctuations due to fluctuations in the rig power system. Analyses.7 nm light.EP 2007-3186 . special filters are placed in front of the Sir Galahad to ensure that the argon carrier gas and the cooling gas (air) are free of moisture and hydrocarbons. • The calibration syringe is kept in a warm place to avoid drop out of mercury. Hg is passing through the analyzer where it is analyzed by measuring the absorbance or fluorescence of mercury vapour at 253.47 - Restricted signal. N2 may also be used as carrier gas. the saturated vapour pressure of Hg is known and a fixed volume of vapour will contain a known quantity of Hg.g. To ensure a linear calibration curve with a required correlation coefficient (R2) of ~0. • CP-gas charcoal filter (e. a set of two filters should be used: • CP-gas moisture filter (e.g. but is not advised as it will quench the signal. The use of helium and air from cylinders is highly recommended. • Check for liquid drops in the sample tube. A “noisy” high baseline and scattered data have been observed as a result of a contaminated gas supply.7 nm. • Include water bath for the calibration vessel to exclude temperature fluctuations (1º ΔT.. • The calibration syringe is conditioned or flushed with mercury vapor at least three times before the actual injection. Instrumental Set-up The Sir Galahad unit needs to be stable for at least 1 hour. gas is scrubbed through an acidic Potassium Permanganate solution followed by reduction of mercury ions. especially in view of the very low concentrations that are looked for (5-15 pounds of sand per thousand barrels) and the fact that sand production may not be continuous. preferably ng/m3. Full Production Stream Sampling (Well-head desander. In oil fields sampling for sand is frequently carried out in conjunction with water cut determination but techniques for quantitatively representative sampling for sand are not well developed. Norman filter. Sampling for Sand • Sampling well effluent for sand may be required to monitor the sand production level of producing wells.EP 2007-3186 .9. the sample could be combusted and the liberated mercury determined by atomic adsorption. The technique is known to be very unreliable.48 - Restricted • Replace injection septum regularly (±10 injections). Sampling for Total Hg by Wet Chemistry Sampling of Mercury using wet chemistry is not to be used any more. . • The program that calculates the Hg concentrations is independently checked. • The first sample tube of each train is analyzed prior to the other tubes. Mercury Analyses in Liquid Hydrocarbon Samples Typically. In addition. The difference with the above techniques is that instead of using Gold sand tubes. fluorescence. mercury is reduced and determined by cold vapour atomic adsorption or fluorescence. • Main method available. hydrocyclone): • Most accurate method but requires significant budget. ICP or ICP/MS. The elemental Hg produced is analyzed using a spectrophotometer in the onshore laboratory. 1. Not normally used Slip Stream Sampling (Millipore filter. • Peak area is used to integrate data (peak height will lead to incorrect results due to irregular peak shape).10. PS 8645 Methods • A critical aspect of this operation is to ensure that a representative sample of the flow is taken. 245-248.3. Shake-out. Figures 24 and 25). Or the digested solution could be analysed by ICP or ICP/MS. • Concentrations are expressed as ng/volume. the sample is acid digested. 1. • Sand sampling and detection techniques are covered in more detail in Chapter 5 of report EP 92-1150 and EPE Topsides sand management guide (report EP 2003-5184): see p.3. 49 - Restricted Deposit Sampling This does not measure size accurately due to sorting effects.. Sample Duration and Offtake Velocity Sand production is generally transient so “grab” samples (shake-outs) will generally only detect sand in the event of massive solids production. combining at least 2 methods can significantly improve quantification estimates. The optimum is when the offtake velocity is greater than the flowline velocity (remember we are trying to get maximum sensitivity in detection). Tulsa SPPS).e. Solids Accumulation in Vessels: Use of IR temp gun or camera can be very effective (and easy) in monitoring build up of sand in vessels..g. Use of strain gauges to measure weight of vessel has been proposed but not applied yet (but should be cheap if incorporated in design). This is addressed at several levels. However it is critical that raw data is also stored as g/s output can be messed up due to lack of input parameters (i. Sampling over extended time is required.. ER Probe: Estimate of sand production is based upon metal loss sand size and back calculating amount of sand from the erosion model (i. rate etc). Solids Calibration (amount of solids) It is critical to conduct sand injection to calibrated ASD’s (acoustic sand detectors) and validate that the solids sample point actually picks up sand. sometimes non-ideal locations may be demonstrated to work effectively (Figures 26 and 27). the samples are sent onshore for further assessment (wet . Solids Characterization After solids are obtained their nature must be confirmed (is it sand. etc).e. Solids Sample from Slip Stream: Sample point efficiency (how much sand was captured versus how much was injected) can be determined and applied to estimate total amount of sand produced while sampling. slag drilling material. The key for it to work is for the inlet fluids to be hotter than ambient. However. If needed. scale. The pictures are sent to experts for assessment.EP 2007-3186 . Sample Location It should be recognized that solids are heterogeneously distribution in pipe so the sample point should be based upon where sand is most likely to be (at the bottom of pipe). However. Pictures are normally taken using a low magnification microscope. Injected sand should be 2 sand sizes (e. ASD: Calibration tables can be generated as a function of rate and sand size (typically assume formation d50) to convert raw data to g/s. typically similar to gravel pack and similar to d50 of formation). and it is difficult to determine when the solids are deposited. A few sand injections will not in general be detected by a ER probe: Quantification (At best semi-quantitative): Any single use of these methods is at best going to provide an order of magnitude estimate regarding the amount of sand. 50 - Restricted chemistry tests.Oil Monitoring Frequency Onsite Analysis GOR* Stock tank density (API)* OBM contamination* Constant Composition Expansion incl.5.8 kPa (±30 psi) Constant ±3°C (±5. Laser Size).8. analyses marked with * do not require sophisticated lab .5°F) Constant (±10%) Variation <3% Variation <3% Constant ±5% Psep no longer increasing ±5% ±0. SEM EDAX. every 30 or 60 min) Stable Flow when Constant ±206. and 150°F) In situ viscosity Formation Volume Factor STO subsampling for various analyses offsite (optional)* solution gas for Geochemistry (optional)* Equipment Mobile PVT lab. XRD. Table 8: Conditions Defining Stable Flow for Sampling Purposes Property Separator pressures constant Separator temperatures are stable GOR (separator level) Total cumulative flow Individual flow rates Wellhead pressure Downhole P decreasing at constant rate Water specific gravity Water pH Water Salinity BS&W %OBM (STL basis) H2S and CO2 Table 9: Constantly At intervals (e.. 37. and 65.5°C (60.1 ±5% <5% <10% Constant ±5% over 3 consecutive readings Onsite Fluid Analyses General Grouping PVT . saturation pressure Liquid composition (C36+) Gas composition (C12+) In situ density Stock-tank viscosity at 15.g. 100. Contact Production Chemist/Technologist specialists for interpretation.EP 2007-3186 . Results are archived against the well so a production history is built. Gas PVT . unless bone dry) Gas composition (C12+) CGR (unless bone dry) API OBM contamination STO subsampling for various analyses offsite (optional)* solution gas for Geochemistry (optional)* pH Chlorides concentration GLR Gas composition (C12+) Density Resistivity Pour point by ASTM D-97 Hg by gold tube/Sir Galahad II Rn by scintillation counter H2S by Titration/Stain Tube/Micro GC CO2 by Titration / Stain Tube/Micro GC (also usually detected in standard PVT gas composition) Mercaptans by Titration /Stain Tube N2 by Micro GC O2 by Micro GC/ Systech analyser The most prominent mobile labs available at the time of writing are as follows: • Schlumberger: PVT Express (PVTX) • ExproGroup: GOLD System • Petrotech: SmartLab and TuboPVT • Reslab: Reservoir Fluid Analysis (RFA) Restricted Equipment Mobile PVT lab Mobile PVT lab Pour-point kit See below .51 - Onsite Analysis Constant Composition Expansion incl. dew point Liquid composition (C36+.EP 2007-3186 General Grouping PVT .Water Flow Assurance (Oil) Trace Analysis . (O2) Currently in development: main mercaptans (C1-C4) Analyses require little time and effort (2 minutes) Recommended as FEAST’s preferred method to analyse gas composition in the field Disadvantages Interference results by other compounds No detailed speciation Results affected by tube selection Only one compound per tube (e.52 - Restricted Summary of Onsite Trace Contaminant Analysis Options Advantages Easy to use Everywhere Does not require a trained technician Fast (1-2 minutes) Least expensive of the three options Accurate data Can be used everywhere Not very expensive Accurate data Results agree with other techniques Detailed speciation C1-C7.g.g. Helium. N2. H2S or CO2) Requires trained/skilled engineer/technician Labour intensive Time consuming No detailed speciation (e. total mercaptans) Only one compound per titration (e.. space.. . H2S.EP 2007-3186 Table 10: Technique Stain Tubes Titrations Micro-GC .. CO2. H2S or CO2) Equipment is fragile Requires trained/skilled engineer Requires stable lab conditions Power.g. logistics Most expensive of the three options. .525 ppm SO2 – 103SC Mercaptan 0.. minor H2S H2S 2/b260 ppm H2S – 120SB Issues SO2 0. HCl) H2S 2/a2200 ppm H2S Normally accurate. HCl).EP 2007-3186 Table 11: .1/a0. reduce H2S for lead acetate reading per mfg. HCl) Strong acids (e.5/a0. Most accurate.g. subject to strong acid interference Normally accurate.. Questionable after acid job Both accurate for SO2 Starch Iodide/ pH Indicator SO2 Palladium chloride + pH indicator Mercaptans Some to H2S Not recommended Copper H2S Chloride-> copper sulphide Mercuric Chloride > Mercuric sulphide + pH indicator Restricted H2S SO2. If SO2 detected. First stage yellow: mostly mercaptans Very sensitive to acidity Very sensitive to acidity .g. Vapour phase only.115 ppm Methyl mercaptan – 164SA Check for SO2. subject to strong acid interference First stage black: significant H2S present. Mercaptans.g.53 - Suitability and Liabilities of Stain Tubes Type Detect Recommended Lead H2S Acetate Interferences Draeger Sensidyne Normal Use Checks/ SO2 Mercaptan Strong Acids (e. H2S 1/d1200 ppm H2S Mercaptans Strong Acids (e. or depleted in heavier components.g. although representative samples can be obtained.) Storage/transport bottles and associated equipment (bottle stands. Matched sets of equilibrated separator gas and liquid taken simultaneously. Collection of large volumes of fluid for tests.54 - Restricted Summary of Surface Sampling Key Points Sample Type Key Points Separator Advantages Good PVT requires: stabilized rates and recombination at representative (true) GOR/CGR. Always taken as back-up. Psat is critical. Used for geochemical studies and physical fluid properties – attention to water content affects API. liners. each collected simultaneously Stable flow conditions Note P&T conditions Consider not to sample if: BS&W excessive Chemicals injected Separator P unstable Emulsions present Slugging flow Gas carryover Wellhead sampling may be a good alternative to separator samples. PVT sampling basics: At least 3 pairs (gas + liquid). pumps.) Qualified staff Well Test . FWP. Cost advantage if well test is already planned or if production facility is in place. but often used as the main samples. Used for crude oil assay (volume 10-20 L). Tres. Knowledge of Pres. Not recommended for wax studies. asphaltenes and/or wax) Minimum Requirements Wellhead sampling assembly (manifolds. Not recommended for asphaltene measurements. etc. pressurizing equipment. TAN (total acid number). the fluid is > Psat. viscosity.. If FWP < Psat multiphase sampling will occur. Monophasic sampling is only feasible when at the wellhead T&P.EP 2007-3186 Table 12: . Disadvantages Fluids often emulsified. stripped of light. FWT. etc. etc. Often the only way of obtaining samples from producing fields Advantages Collection of fluids when bottom-hole samples were not/could not be collected. Disadvantages Collected fluids may not be applicable in some flow assurance studies (e. mercury. but may be suitable for geochemistry and physical properties measurements .EP 2007-3186 Sample Type . The validity of wellhead samples needs to be compared against data from other sources. Issues during multiphase sampling Often the only source of fluid samples Phases not at equilibrium Phases not separated Oil contains excess gas and water Gas contains excess oil and water Risk of plugging – Sand and hydrates Considerations after sampling Condition single-phase samples at Tres/Pres before any analysis Samples collected at FWT > cloud point are suitable for wax studies Samples collected at FWT < cloud point may not be valid for some stock tank oil measurements Samples collected at FWP < Psat are not appropriate for most FA testing. Record flow and thermal-hydraulic parameters prior and during sampling for sample validation and troubleshooting. and mercaptans are needed? Stable flow must be reached before sampling OBM and BSW levels must be low prior to sampling Take multiple samples Record conditions during sampling Potential Pitfalls Lean condensates – injection of hydrate inhibitors may not be avoidable. radon.55 - Restricted Key Points Additional Equipment Heating jacket for bottles Heat tracing for liners Bottle transfer equipment Issues to consider prior to/during sampling Stable flow at wellhead – monitor GOR/CGR Well has been cleaned-up Adequate fluid mixing upstream of sampling point FWP should be higher than the asphaltene onset P at the FWT Flush sample ports prior to sampling Collect single-phase samples in pressure compensated bottles Consider whether data on H2S. CO2. Tree.g. Only the separator sample points should be used to “reconstruct” a total fluid composition.56 - Summary of Data Collected From the Wellhead/ Tree/ Flowline Data Collected BS&W PH Chloride H2S CO2 Flow rates gas. Dräger) in separator gas or headspace sample choke manifold Flow meters on separator or choke manifold Ranarex meter after sampling in gas bag/ balloon Thermometer in fluid Floating meter in fluid for density Sampling Locations for Trace Contaminant Analysis Analysis H2S and CO2 (Dräger tubes) BS&W Gas and Condensate densities H2S. read levels of fluids BS&W Indicator paper Refractometer (Calibrated for NaCl. Kitigawa) in separator gas or headspace sample choke manifold Stain tubes (e. however these are likely to give non-representative liquid-gas proportions. CaCl2 brine or other salts will give deviated results) Stain tubes (e. and Flowlines are all alternative sampling points.. .. N2 and Gas Composition Sample Points* Separator Gas Line Choke Manifold and Separator Oil Line Separator (Gas and Oil lines. condensate Gas gravity Temperature API gravity Table 14: Restricted Technique Used Centrifugation of 100 ml of degassed fluid. water. CO2.g. respectively) Separator Gas Line *: Note that the Wellhead.EP 2007-3186 Table 13: . and HS-Iodometric titration Record pH profile versus amount of acid added to distinguish between organic acids and HCO3Calculated upon completion of above analyses . all the listed analyses Ag NO3 titration HACH kit and spectrometer @ 60°F using densiometer/hydrometer Conductivity meter Calculated upon completion of above analyses Should be stable Acid-base titration S2.EP 2007-3186 Table 15: .57 - Restricted Water Sample Container and Onsite Analysis Summary Container and Onsite Analysis 1 litre glass bottle 1 litre or 125 ml glass bottle 1 litre HDPE bottle 1 litre or 250 ml HDPE bottle Vial 100 ml glass serum bottle 25 litre UN/IATA drum Onsite Chlorides Calcium Magnesium Sodium Potassium Specific Gravity Resistivity/Conductivity Ion balance Temp and Pressure Carbonate and Bicarbonate Free sulphide Total Alkalinity Total Dissolved Solids Suitability and Treatment Red Teflon cap Acidified using HNO3 to pH2 (10 ml HNO3 per 1 L sample) c/w Red Teflon Cap Acidified using HNO3 to pH2 (10 ml HNO3 per 1 L sample) c/w Red Teflon Cap With Gluteraldehyde (1 ml Gluteraldehyde per 250 ml sample) c/w Red Teflon Cap With 25 ml Nitric Acid (used for acidification) For carbon isotope analysis Only to be taken on a Water Zone 1 sample every 3-4 hours. NOTE: In cases where high volumes of the water based mud are expected in sample cylinders it may be advisable to position a sampling bottle in a vertical position and performed controlled drain of the water prior to the restoration. 2.58 - Restricted SAMPLE MANAGEMENT 2. 3. Figure 22 illustrates examples of sample transfer. Check the closing pressure at Tres of transferred cylinders (recommended ~27. Transfer of samples (if required) above Pres +6.EP 2007-3186 2.000-2. 2. NOTE: Multiple samples of the same type from the same depth should retain similar pressures. a stand is already incorporated . However. Several relatively straightforward numerical checks should be performed to help establish the validity of the reported data and may be used to supplement the contract laboratory’s standard procedure validation checks. .000 psi). as identical compromise is unlikely in all three. Transfer and Validation 2.1.1. Opening pressures – at or above the reservoir pressure required.1. It should be noted that the overall validity of results obtained from PVT laboratory measurements would depend to a large degree on whether or not the samples were representative of the reservoir fluid – i. as described in the previous sections. indicate if one or more of the samples have been compromised since sample acquisition. however.000 psi) and at Tres to transportation cylinders. It is imperative therefore that every effort is made to obtain representative samples through proper well conditioning and sampling. transfer.1. sampled and handled at or above existing reservoir conditions. and validation.500 kPa (4. Onsite Sample Validation for Sub-surface PVT Samples – Hydrocarbons The following steps should be executed to validate subsurface fluid samples after recovery on the rig floor: 1.2.e.900-13.800 kPa (~1. If there are any problems communicating with the service company or vendor lab regarding these recommended procedures contact the FEAST team for advice. For a sample bottle. General This section describes the techniques used to check that samples and their analysis results are representative of the reservoir or wellstream fluid (formation). The majority of international service companies and labs are familiar with Shell’s recommended practices regarding sample restoration. most of Shell’s preferred procedures have to be specifically requested. The validation checks described below are aimed at establishing the consistency of the measured data and are unlikely to detect non-representative sampling.. as they are more time consuming than standards employed in those laboratories. They will. For highly contaminated samples and their use. not necessarily lead to “useless fluids.4. This flowchart shows a detailed validation procedure and can be altered depending on the well/fluid characteristics.3.0 wt% WBM contamination. In addition.2.1. 2.” The factors that may lead to unusable samples include but are not limited to OBM character. and FVF.EP 2007-3186 .1. Contact the FEAST team to discuss this. • Heavy oils (API <20) frequently form stable emulsions that require a more involved separation treatment. consult the PVT team. Wireline Tool Pressure Plot Validation • The pressure profile measured by the wireline tool should be compared with the measured density at reservoir conditions of the sampled fluid.000 ppm (liquid phase).2. shows the process by which samples are analysed for validation purposes.5 at the end of this document.1. each 10 ppm increment of KI in the sample indicates 1. • WBM contamination of water samples can only be determined through the use of a tracer. Typically. then a sample bottle stand needs to be obtained. OBM Contamination Measurement OBM Contamination levels will be calculated using the “subtraction method. different physical quantities exhibit different types of uncertainties under the high contamination levels. • The reservoir fluid density at the point of sampling can be used to calculate the slope of the pressure profile at that point and identify possible supercharging. Single-phase Cylinder Validation The flowchart in Appendix 6. Figure A6. 2. At this concentration.” For numerical fluid description (PVT modelling) the desirable limits are 5% w/w for condensates and 10% w/w for oils per STO basis. The free aqueous phase can then be drained off into a graduated container to enable measurement. WBM Contamination Measurement • WBM contamination of hydrocarbon samples usually can be separated out by allowing the sample cylinder to stand vertically with the drainage valves lowermost for ~1 hr following restoration. 2.1. GOR. KI is used to achieve this (as it occurs in low concentrations in typical formation waters) added to the mud composition prior to drilling at a concentration of 1. OBM values beyond these limits will increase the uncertainty for the fluid description.2. .1.2.59 - Restricted into most heating jackets.2. 2. For any analysis that is performed directly from the sample cylinder. EP 2007-3186 . Middle and Far East). Additionally.g.2) have been shown to be effective in removing potential contaminants from high-pressure chambers/cylinders. the procedures should be followed to minimize further degradation of sample quality..1 of the Sample Transfer and Analysis Information Excel Sheet. Sampling Handling Procedures on the Rig 2. MRSC. • On retrieval to surface steps outlined on the beginning of this section shall be followed and information should be collected on the Sample Transfer and Analysis Information spreadsheet and a first version of the spreadsheet should be communicated to the Shell contact person as soon as possible. • After a downhole module (e. the standard transfer procedures used by the wireline operator are often sufficient to ensure quality pressurized samples for both PVT and other sensitive measurements (Appendix 6 describes the rig transfer and shows schematics of transfer modules).g.1. Acceptable practices are now well established with major contractors involved with our largest operations (North and South America. should fill out the relevant columns on Figure A9. MDT or SCAR assembly) is fully retrieved. the Engineer responsible for sample transfer and handling. SSB. • The Shell cleaning procedures (Appendix 6. • All non-transportable Sample Chambers must be transferred onsite. • Even if sample quality is suspect.) and transportation PVT cylinders (e.g. overpressures should be noted (due to lowshock sampling technique) and communicated with Shell staff. etc. • Both engineers should be available during downhole sampling operations to answer/advise on any issues that arise during sampling.3.60 - Restricted 2.3. CSB) are well cleaned prior to use. The procedures have recently been updated. Nigeria. Transfer Procedures for Pressurized Hydrocarbons Samples on Rig • It is essential that downhole cylinders (e. in consultation with the wireline engineer. SPMC. which accompany these guidelines (see Appendix 9).1.1. . with a focus on safety and material compatibility issues. • During the Sampling section of the wireline run... Europe. visual description of leaked fluid. • It is also possible to obtain field measurements of GOR. note any unusual conditions during sampling or transfer (e.EP 2007-3186 .g. Often this type of data is useful when evaluating PVT sample quality. loss of seal. • After transfer on the rig is finished and all pressurized samples are taken. the MRSC chamber or other downhole cylinder is bled down to atmospheric pressure to obtain a “rig flash” sample. If possible. contamination.. record this information with the PVT data. Keep cylinder at minimum 55ºC (130ºF) (Schlumberger constraint). and Psat.). or higher if permitted by HS&E regulation of the sampling vendor. tool malfunction.61 - Restricted The following data should be recorded during the Sampling and transfer of fluids: Sampling Depth Formation/Zone Pres Tres Sampling P Sample Shell ID Sample Carrier Slot # in the tool Sample Chamber Drawdown Closing P Downhole Closing T Downhole Comments Rig Opening P Rig Opening T Rig Transfer P Rig Transfer T Transport Bottle Bottle Type Sample Volume Closing P Validation of samples: Sampling Depth Formation/Zone Pres Tres Drawdown Sample Shell ID Sampling Cylinder ID OBM % (STL) STL density API GOR CGR Liquid Flash Volume Gas Flash Volume Gas comps Liquid comps Psat Comments • This information is usually contained in a standard PVT report. In addition. . etc. 2. Reduce pressure by either removing displacement fluid or backing off on piston. The usual procedures of companies like Oilphase are considered acceptable with the following provisos: 1. APIº. which also can be useful for evaluating sampling quality (EP 2000-9021). . it is important to have the appropriate type and size of container. especially those that meet relevant transport and environmental/safety regulations. or sample chambers. labels. • Try to collect small cylinders of any gas that may be in the sample chambers after a failed downhole run. grease. 2. 3. The shipping cylinder. and drilling mud). The cylinder should be labelled and returned to the PVT lab for PVT measurements as soon as possible. Quickly drain all sample material (petroleum plus water and solids) from chamber into an appropriate glass container. 5.EP 2007-3186 . should be thoroughly clean and contain no traces of petroleum. The sample in the downhole collection tool should be purged until clear water is flowed. 4. During and after draining. It is possible that these data could be used to estimate the relative amounts of light gas components and certain diagnostic isotope ratios or at the very least set minimum and maximum limits on key gas parameters. a flashed gas sample can be collected for geochemistry using special cylinders available from BTC or RIJ.3.. contact the relevant Shell representative. 6. Once the pressurized water sample has been obtained it should be stored on ice as soon as possible. collect and save any fluid in the sampling tool lines. During this process. • A copy of the “field service summary” prepared by contractor staff on the rig should also be sent to the receiving lab with the samples.2. Transfer Procedures for Pressurized Water Samples on Rig 1. Appendix 1 addresses transport and labelling requirements. pre-rinses. or organic solvents. Cap the container lightly until cooled to ambient and then tighten cap. care should be taken to minimize evaporation and exposure to air. Do not try to clean-up sample on the rig.1. • For all types of samples from the rig that will be sent to the Shell lab or designated vendor lab (e. • Even a highly contaminated dead-oil sample is better than no sample. • Even small amounts of dead oil can be used to obtain information about the C7+ fraction of the oil or condensate.62 - Restricted 3. Slowly bleed down pressure by venting gas. 2. the pressurized shipping cylinder should be filled. When clear water flows from the downhole collection tool. and shipping materials. • When in doubt regarding the availability of sample containers. used for accepting the transferred pressurized water from the sampling tool. • In the case of a failed downhole sampling run. pump-out module.g. gas and rig flash samples. 4. 7. undergo safety inductions. because it can destroy containers and alter the water chemistry.4. • Ideally all flashed samples should be kept cold (<4oC (40oF)) for preservation and to avoid biodegradation from the time they are collected until analysis. • Shell policy is to overpressure the conventional MDT sample chambers (MRSC. Pack bottles with acid in the 5 gal open top UN1A2 drums. In some cases. Sampling Preparation and Equipment Requirements • Ensure that all sample chambers are pre-rinsed with Toluene and air-dried. If the water samples are being collected from an inline separator. because these are unpreserved samples. However. The service company should supply these agitation inserts. and work permit training. Secure the top by squeezing the ears down with a pair of pliers (Figure 6). • Agitation Inserts (Rings or Balls. 8. if there is a space constraint for shipping. before the bottle is filled with the remaining sample. any remaining water in the sampling tool should be flashed down to a flash separation unit or a collection jug and collected in Nalgene polyethylene sample bottles. so as to have very little headspace and nitrogen should be put in the headspace void.1. The collection bottles should be numbered (with a waterproof marking pen) in sequence as they are filled from the separator unit. • Place the containers in dry. 6. 9. The bottles should be filled. The remainder of the water held by the piston controller in the sample chamber must not be wasted. placed on ice. into a receptor jug. and returned to BTC or RIJ as soon as possible. When filling the headspace of the Nalgene bottle with nitrogen from the nitrogen line.2 pt) glass serum for oxygenhydrogen isotope analysis should be given highest priority. sealed plastic bags in ice chests with wet ice for shipping. the line itself should not come into contact with the water sample. Dry ice should not be used be used. this will retrieve the sample above the reservoir . depending on the sample chamber design) should be installed in all large volume (>450 cc) chambers.25 pt) Nalgene bottles for metal analysis are corrosive and must be properly labelled.EP 2007-3186 . 10. Each Nalgene sample bottle should be rinsed with approximately 1/10 of its total volume of the water sample (which should then be disposed of). 2. 60 ml (1/8 pt) Nalgene bottles (for inorganic non-metallic constituents and volatile organic acid analysis) and 100 ml (0.63 - Restricted 5. the receptor jug should be thoroughly clean. • The acidified 125 ml (0. MPSR) downhole where possible. • The sampling equipment/engineers and specialists should be onsite 48 hours before RIH with the MDT tool to allow for time to set-up. If possible the sample should be shipped on ice. Heating and Restoration Times Once all opening pressures have been recorded.4.64 - Restricted pressure and so Single-Phase Sample Bottles and NOT Conventional Sample Bottles should be used for all samples.e.1. All information should be collected on the Sample Transfer and Analysis Information spreadsheet and a first version of the spreadsheet should be emailed to the FEAST contact as soon as possible.4. 2. and chlorides of any water sampled. • All SPMC and MRSC Sample Chambers must be transferred onsite. the SPMC opening pressure will be measured only when heating commences. the opening pressures of the standard piston samples destined for transfer should be performed and recorded. This will be confirmed by the Shell FEAST contact. regardless of whether or not the down-hole bottles are DOT approved. . these requirements should be relayed by the FEAST contact as early as possible. • Bottles (excluding SPMC bottles) should be agitated during heating to ensure all solids are dissolved. 2. the sample chambers should be coated with sulphur resistant compound to minimize H2S scavenging and the GC composition analyses should be calibrated with a calibration gas containing H2S. If further measurements are required. In order to minimize risks to the sample integrity. It is important to allow sufficient time for sample heating and restoration to ensure the sample is fully monophasic prior to transfer. Key Items Regarding Sample Transfer: • Immediately on retrieval to surface. Wellsite Chemistry: A basic water analysis kit should be available to measure pH. not exhaustive Live Oil Viscosity: For environments with heavy oil is expected (<23. it is essential to begin restoring the samples to reservoir conditions as soon as possible. PVT Express on Onsite PVT Rig: The PVT Express Flash Unit and GC will be required to perform sample validation and provide early fluid properties. Equipment Requirements – Guidelines Only. In cases where the reservoir pressure is expected to be close the saturation pressure (such as gas condensate wells) then the full PVT Express unit (i.5 API) the use of a live oil viscosity unit (Cambridge Electromagnetic Viscometer) should be considered and discussed with the FEAST and PVT teams. Table 18 lists restoration guidelines.2. Trace Contaminants: these requirements should be relayed by the FEAST contact as early as possible. Sample Bottles: Enough Single-phase Sample Bottles to transfer all downhole sample chambers into separate bottles should be available.. density. including the cell) should be discussed/considered.1. This allows for samples to be saved in the event of a slow leak in one of the seals. H2S Environments: When H2S is expected.EP 2007-3186 .1. 65 - Restricted All samples should be heated at reservoir temperature or 70°C (160°F) whichever is greater. The FEAST contact should confirm this. 2. or vapour pressure.1. water/salt content.5. This is in order to collect any solids that may have precipitated will the samples were being POOH or during transfer. transfer price is frequently established according to calorific value and/or Wobbe Index.10.4. Custody transfer of natural gas will generally require the use of on-line process analysers. 2. quote the InTouch report (Content ID #4040812).1. • Typical analytical requirements are for crude density.50. which establish its sales price. quote Oilphase procedure OP192r2.3. Sample Number.1.e. 12. The choice and application of devices of this type are outside the scope of this report (see DEPs 32. retain as much of the lighter ends in the liquid phase as possible by keeping the receiving vessel cool..). • For gases. 11. Sample Chamber Post-Rinse • The sample chamber should be post-rinsed with Toluene and the individual rinses collected in separate glass containers and marked with the Well Information. • If Oilphase-Schlumberger is the service company.5. Custody Transfer • The properties of a gas or liquid stock.4.EP 2007-3186 • .4. sulphur content.g. 2. and 13-Gen. • Ensure that the sample is fully restored/conditioned before blow-down as all of Shell’s atmospheric samples are sent to the relevant Shell lab for Wax and Asphaltene Analysis. 2.1. Sample Transfer Documentation FEAST team should be kept updated with all data from this using the Sample Transfer and Analysis Information spreadsheet (included in Appendix 9). TAN. and Sample Chamber Serial Number. • If the Samples are volatile oil/gas condensate then Toluene rinsing may not be required. • Contracts for custody transfer will frequently place restrictions on the level (maximum or minimum) of a specific fluid property rather than specifying a required range (e. Blowdown Procedure for Pressurized Cylinders • When blowing down any pressurized sample chamber to atmospheric conditions light end losses should be minimized – i. crude density). However manual samples must frequently (typically quarterly) be taken and analysed for the purpose of proving or validating on-line process . timing of restoration begins when sample reaches Pres or 70°C (160°F).4. If Schlumberger is the service company.31. are explicitly stated in the relevant contracts.. sulphur content. . In this case the data required is the same as that which the automatic system is providing. since the contamination imposed uncertainties are functions of many factors as highlighted above. Table 16: STO Wt% OBM Typical OBM Impact on Project Development <10 5-15 (*) 15-25 25+ Medium quality sample PVT uncertainty 5-15% Some Flow Assurance not possible Dry Gas PVT not possible Poor Quality sample PVT uncertainty 20+% Viscosity not possible Most Flow Assurance and Geochem assessment not possible Virtually unusable sample. the FEAST team contact should be immediately consulted. Y Y Y ? Y Y N? N Y Y N? N Y Y N? N Y Y? N? N Y Y N N Y N? N? N Ideal Oil Sample SBM preferable to diesel-based mud Basin. For modelling such systems consult PVT team contact.EP 2007-3186 . All but the most simplistic and robust measurements are not possible. Play and Prospect Evaluation Appraisal and Reservoir Evaluation Processing and Refining Production Surveillance Reservoir Performance Well and Production Engineering Facilities and Transport Engineering ?: indicates a few data points may be acceptable (*) Overlapping boundaries.66 - Restricted analysers. If the contamination levels exceed 10 wt% in Stock-tank Fluid. the rig flash sample can be used for other stock-tank liquid measurements. 25 L and bigger) Acid washed borosilicate glass for Mercury in condensate Glass bottles with ‘red caps’ Teflon lined bottles HDPE (Nalgene) bottles Glass bottles Steel UN Drums NOTE: Always use new. etc Wax Measurements Asphaltene Measurements Additional STO measurements *possible on the rig-site If the data for the two types of samples agree.67 - Restricted Recommended Analysis to Evaluate Sample Quality Measurement General Measurements* Validation Analyses Opening Pressures. compositions %OBM (also compositions of OBM/Filtrate and API). Metals.EP 2007-3186 Table 17: . TAN #. API. water % HTGC SARA S%. Table 18: Recommended Minimum Onsite Restoration Times for Downhole Samples Sample and Cylinder Hydrocarbon – SPMC or similar (~250 cc) Hydrocarbon – MPSR or similar (~450 cc) Hydrocarbon – MRSC or similar (~3785 cc) Water Table 19: <35 API 4 hours 4 hours 8 hours 1 hour >35 API 2 hours 2 hours 4 hours Liquid Transport Containers Fluid Type High Pressure Hydrocarbons High Pressure Water Stock Tank Hydrocarbons Stock Tank Water Container Single-phase transport bottle Conventional transport bottle (below Psat) Gas cylinder (gases only) Single-phase transport bottle Conventional transport bottle (below Psat) Steel UN Drums (1. clean containers! . 11. GOR. However saturation pressure will also have a bearing on the requirements so that the following should be used as a guideline minimum only. The following sections attempt to categorise the reservoir engineering data requirements according to fluid GOR and density. Detailed explanations of each of these tests are presented in Appendix 2. In addition there are many less common tests that may sometimes be required but are not described here (report EP 91-0703). All studies will require a (recombined) reservoir fluid composition with hydrocarbon detail up to at least C16+ (although C30+ is now standard) and including common non-hydrocarbons (nitrogen. data smoothing. • The standard tests will normally require a PVT cell rated to 103. volume and temperature (PVT) for the reservoir fluid in question. The pressure at which the second phase is formed is also recorded (saturation pressure). hydrogen sulphide). Empirical correlations can be used for comparing the available data against an established trend. carbon dioxide. This re-combined well fluid sample is then used for various experiments designed to determine the relationships between pressure. . pressure (for a given sub-section of the reservoir/entire reservoir) is the main variable that affects the fluid properties and the volumetric behaviour. Standard PVT tests are fluid-type specific and they are intended to mimic the depletion processes. reservoir pressure usually declines while reservoir temperature stays constant. PVT tests are intended to study and quantify the phase behaviour of reservoir fluids at the presumed recovery conditions. Analytical requirements for reservoir studies depend very much on the type of fluid and the anticipated recovery mechanism for the reservoir in question.EP 2007-3186 3. Reservoir Studies Accurate and reliable phase behaviour and volumetric data are essential for the management of hydrocarbon reservoirs. • All pressure and temperature measurements must be accurate to within 15 psia (for most cases) and 0.68 - Restricted OFF-SITE LABORATORIES 3.5°C (1°F) respectively.1.5 MPa (15. Phase behaviour and volumetric data are usually obtained through standard laboratory procedures. The gas and liquid samples are then physically re-combined in a ratio corresponding with the corrected test separator GOR. following compositional analyses (by GC) and accurate determination of liquid densities. Therefore. etc. For separator samples. The effects of water present in the reservoir are ignored for most of the cases. .000 psi) and 200°C (392°F). Typically the pressure is lowered and various properties are measured. the meter factors used for determining separator gas and liquid flow rates in the field are checked using the laboratory determined fluid properties (densities) and the field GOR adjusted if necessary. During the depletion process.000 psi) at 150°C (302°F) but are frequently available up to 138 MPa (20. The standard experiments performed are described below. Empirical correlations and charts are used when PVT data are not available. and standard laboratory tests are performed by varying the pressure. DL. zero-stage flash.EP 2007-3186 Table 20: . Psat +690 kPa (100 psi).825 <0.000 None m3/m3 <285 <285-623 445-8. 8 .600 1. • GOR (GCR for condensates) with ambient or separator conditions clearly stated.900 None Initial STO API <45 >35 >35-40 >40 Density g/cc >0.500 2. Composition of gas and residual oil). and 2 phase volumes). • OBM (reported as wt % at stock tank and at reservoir conditions. etc. ideally C16+) with MW clearly stated and specific gravity of the C30+ fraction from the zero-stage flash. density.825 <0.000 >50. • Psat (bubble point or dew point) at Pres.500-50. Psat+3450 kPa (500 psi).. Measurement technique (rolling ball. • Constant Composition Expansion* at 54.5°C (130°F.7 *Note that the perception of each broad category varies according to discipline.600-3. • Constant Composition Expansion* at Tres (in situ compressibility. 5 pressures and viscosities.702 C7+ mol % >22 22-11 <11 <4. in situ compressibility.) clearly stated. and 2 phase volumes). Psat+10340 kPa (1.900 >8. • Composition of Oil (C30+) and gas (at least C7+. and separation pathway clearly indicated (i. capillary.45 API) is: • The Shell ID “SAM#” . . Oil Reservoirs The recommended minimum data requirement for medium and heavy oil reservoirs (GOR up to ~312 m3/m3. • BS&W content. multi-stage septest. etc).500 psi). ~1.1. density. Pres.802 <0. • For the gas component please pay particular attention to ensure that the CO2 component is accurately measured and reported. 3.1.if you do not know this please request from the Shell lab contact and one will be assigned. EMV. composition and mol wt reported. vapour density.e. The categorization suggested here are frequent approximations and should not be considered as binding. • Viscosity at Reservoir Temperature (Tres) and the following pressures: Psat.750 scf/bbl.69 - Restricted Typical Classification of Reservoir Fluids Property Black Oil Volatile Oil Retrograde Gas Wet Gas Dry Gas Initial GOR scf/bbl <1. GC trace included). • Differential Liberation* at Tres (for oil.5 None <0. 5. DL. • Molecular weight (clearly reported whether calculated or measured. raw data and data corrected for OBM contamination should be reported and clearly identified accordingly. 100.EP 2007-3186 . ideally C10+) with MW clearly stated and specific gravity of the C30+ fraction from the zero-stage flash. and separation pathway clearly indicated (i. etc). zero-stage flash. and reported for each pseudo-fraction of the CCE.500 psi).2.1. • Psat (bubble point or dew point) at Pres. 3. and 2 phase volumes). >310 m3/m3. • Where appropriate. Psat +690 kPa (100 psi). density. density.. • BS&W content. Psat+10340 kPa (1. which can form stable emulsions that take extensive measures to break. include ambient as the final stage and always clearly state conditions). Volatile Oil Reservoirs. and 2 phase volumes).70 - Restricted • Dead oil density and viscosity at 15. Psat+3450 kPa (500 psi). gas condensate and gas reservoirs is: • The Shell ID "SAM#" . 37. >45 API).e. Gas Condensate. and Gas Reservoirs The recommended minimum data requirement for volatile oil reservoirs (GOR >1. BTEX. GC trace included).if you do not know this please request from the Shell BTC or RIJ lab contact and one will be assigned. • Constant Composition Expansion* at 54. Note: For very low GOR (and low API) reservoirs (less than 10 m3/m3) bubble point pressures and incremental gas volumes may be so low that a differential liberation experiment could be meaningless and separator tests will be sufficient. CVD. composition and mol wt reported. *: For the gas component pay particular attention to ensure that the CO2 component is accurately measured and reported. and DL compositions).5°C (130°F. Measurement technique (rolling ball.8.750 scf/bbl. EMV.5°C (60. Pres. in situ compressibility. Water content is a particularly important measurement for heavier oils.. • Composition of Oil (C30+) and gas (at least C7+. and 150°F) • Separator Test (at conditions representative of planned topside facilities. multi-stage septest. • Viscosity at Reservoir Temperature (Tres) and the following pressures: Psat. . • Constant Composition Expansion* at Tres (in situ compressibility. capillary etc) clearly stated. and 65. • GOR (CGR for condensates) with ambient or separator conditions clearly stated. • OBM (reported as wt % at stock tank and at reservoir conditions. • Separator Test (at conditions representative of planned topside facilities. Hydrocarbon Samples . CVD.. • Where appropriate.e. Sample Validation Carried Out by the Contract PVT Laboratory Before any experimental PVT data are used for design or study purposes. 3. • Gas viscosities at Pres and Tres. Composition of gas and residual oil). In each case. Composition of gas and residual oil). and reported for each pseudo-fraction of the CCE.1.1. raw data and data corrected for OBM contamination should be reported and clearly identified accordingly. vapour density. * For the gas component pay particular attention to ensure that the CO2 component is accurately measured and reported. bubble point pressure) must be determined at sampling temperature. it is necessary to ensure that there are no errors or major inconsistencies that would render any subsequent work useless. In addition. and 150°F). 3. • The measured saturation pressure of a separator sample should correspond with the sampling pressure when collecting the sample from the liquid outlet of a gas liquid separator.3. water or mud).1. and DL compositions).Liquid • Upon receipt in the laboratory the cylinder opening pressure must be checked to assess any loss of gas due to valve or seal failure during transit.5°C (60. • All sample containers should be checked for contaminants (e.3. OBM % and OBM analysis must be incorporated where applicable. • Tank oil density and viscosity at 15. 37.5. for at least 3 days (5 days. 100.. • Restoration to reservoir conditions. • The measured saturation pressure of a downhole sample should be at or above reservoir pressure. if the sample may be destined for Flow Assurance analyses) sample saturation pressure (i.g.8. • Molecular weight (clearly reported whether calculated or measured. vapour density.EP 2007-3186 . rocking frequently or continuously.71 - Restricted • Constant Volume Depletion* at Tres (typically 5 pressures and calculated viscosities. a significantly lower saturation pressure would indicate sample leakage with loss of light ends and the sample should be rejected. include ambient as the final stage and always clearly state conditions). typically 5-7 pressures and viscosities. • Differential Liberation* at Tres (for volatile oils only – not gases or gas condensates. . and 65. For one mole of feed the above equation can be rearranged to: YVZj = . or numerical errors in the data reporting. This may not be a problem since it is common practice to adjust the measured nitrogen concentration in the sample for the nitrogen present due to air contamination (air being approximately 78% nitrogen by volume) and report the composition on an air free basis.3. flashed Liquid and flashed Vapour respectively. Thus. This technique is described by Campbell. Mass Balance Diagram The mass balance diagram is based on the following general flash equation describing the individual component material balances around a flash separation stage: F. the concentration of air present in the sample is determined. Interpretation of these plots may not always be very simple. Buckley Plot (or Campbell Diagram) • For hydrocarbon gas and liquid phase in equilibrium. and V are the molar flow rates of “Feed.1. Hydrocarbon Samples .Zj .3. it is common for the components heavier than C5 to show such deviations.72 - Restricted 3.1. there is a linear relationship between the log of the individual component K-values (mole fraction of a component in the gas phase divided by the mole fraction of the same component in the liquid phase) and their respective critical temperatures squared (see Figure 28).L X i/ V . • Any significant deviation from the original sampling pressure indicates leakage during transit and the sample should be rejected.Gas • The sample cylinder is brought to a temperature as close as possible to the on site sampling temperature and the opening pressure of the cylinder is measured. and Yj are the mole fractions of component i in the Feed.” and “flashed Vapour”. • During analysis. Although slightly more difficult to construct. From theoretical point of view Hoffman plot is a better method than Campbell Diagram. an alternative method is Hoffman et al. the greater will be the deviation from linearity.4. • For the light components.Yj where F. 3. • The presence of air is indicative of poor sampling techniques. L. plot and can be used to diagnose such disequilibrium issues.1. in other words.2. Xj. respectively and Zj.3.2i + 1 /V .3. every deviation from log-linearity does not necessarily mean that the subject oil-gas pair is not in equilibrium.EP 2007-3186 . It is not uncommon for small amounts of air to be present due to failure to thoroughly purge the sample bottle prior to sampling and ingress during sample transfer procedures.LXj + V. This pressure must be reported in the PVT (analysis) report. 3.” “flashed Liquid. Note that as components become less paraffin in nature. any significant deviations from the linear relationship indicate possible non-equilibrium separation. suspect analyses. • Restoration to reservoir conditions.1. . in such cases. • All sample containers should be checked for contaminants (e. Comparison of calculated density from TDS with measured density/specific gravity Densities calculated with ScaleChem or similar software based on analysed components should be compared to measured density/specific gravity measurement for consistency. Generally. • A charge imbalance in excess of 7% probably indicates a bad analysis or partial analysis.. rocking frequently or continuously. with delay interval noted) upon sub-sample push-off.UV (see Figure 29). water or mud). Comparison of TDS values with TDS derived from conductivity measurements The conductivity analysis is deemed correct if the TDS derived from measurement is within 20% of calculated and measured TDS.g. 3.e. Greater differences probably indicate incomplete or bad analysis. Fluid composition of the recombined fluid is also usually measured. for at least 1 day.5.73 - Restricted This is a linear equation and thus a plot of Yj/Zj versus X/Zj should result in a straight line of gradient . the well fluid composition is calculated by a component mass balance. Total Dissolved Solids.3. resistivity. This functions as an additional check on the mathematical recombination. Temperature. density. or the presence of residual hydrocarbons. due to incomplete drying of the sample. Note: The well fluid compositions reported in PVT reports are normally obtained from a mathematical recombination of the test separator gas and liquid compositions in a mole ratio corresponding with the measured separator GOR. The speciation software EQ3NR or similar is recommended for the calculations. Comparison of measured and calculated total dissolved solids (TDS) values • TDS calculated using the analysed components and gravimetrically measured TDS should be consistent with each other. • Measured TDS values are commonly higher than calculated TDS.. and pH must be determined immediately (<2 hrs. deviations on a mass balance diagram normally indicate arithmetic errors in the data recombination. Basic quality control of water analysis data consists of: Charge balance calculations • Acceptable ion (or charge) imbalance is 7% of the total charge.EP 2007-3186 . measured and calculated TDS are considered consistent if they are within 20 % of each other. Water Samples • Upon receipt in the laboratory the cylinder opening pressure must be checked to assess any loss of gas due to valve or seal failure during transit. i. Casing leakage problems are also much more easily resolved when geochemical techniques are used to narrow down possible leak locations. This is a powerful technique. Basic Geochemical Composition Qualitative analyses of petroleum composition data enable insights into reservoir connectivity through assessment of relatively simple measurements specifically: • Total Acid Number (TAN) by ASTM D 3339 or D 664. Resins. and other geologic and engineering data. geochemical concepts and statistical analysis.74 - Restricted Data check for extreme values Analyses with 5 > pH > 10. If end-members of a commingled production stream are sufficiently defined. This section addresses only the analyses pertinent to the initial evaluation process.2.are not common in nature and may indicate contamination with completion and other engineering fluids. Reservoir Geochemistry Reservoir geochemistry is a broad term that applies to the integration of petroleum composition and fingerprinting data.2. Comparison of sample data with regional trends: An analysis may fulfill all requirements listed above. Aromatics. representative production samples can be analysed and production allocation assigned from the net chemical signature.not expected in formation waters. yet still may be an unrepresentative sample due to various reasons.EP 2007-3186 . 3. accurate characterization of the “neat” fluids from each reservoir (during initial exploration and appraisal) is just as important as analysis of the production sample. • Water content by Karl Fisher (titration. and Asphaltenes (SARA) by medium pressure liquid chromatography and IP143 (Shell modified version). Fingerprinting Methods Hydrocarbon fingerprinting requires quantitative analysis using high quality GC data and a more statistical approach to interpretation. . 3. as the differences are subtler.2. Similarly. Before embarking on these analysis programs. allowing insight into compartmentalization. connectivity. it is strongly suggested that the basic geochemical composition is considered and the relevant Subject Matter Experts in the FEAST or Hydrocarbon Systems are consulted. Consequently. Report BRC 52-89 provides a more detailed description of petroleum geochemistry. ASTM D 4377) • Bulk composition – Saturates. • Metal content (Nickel and Vanadium) by ASTM D 7260. • Sulphur content by ASTM D 3516. high Ba2+ and SO42concentration indicates very high Barite supersaturation . such as contamination with completion fluid or mud. high Ca2+ and Br.1.2. and compositional grading. 3. which have come into equilibrium with the reservoir rocks over geologic time. • This is a Shell-proprietary technique and it is strongly recommended that the sampling and analysis program is discussed with the FEAST team or the Hydrocarbon Recovery Team in EPT-S before initiating such a campaign. . when taking a sample destined for geochem analysis.4.2. and some fluids are too alike to be distinguished from each other with this method.2. as the various compounds are not grouped together into pseudo-component batches. especially for the n-alkanes. This is usually in addition to the C30+ composition derived from the PVT analyses.Gas Chromatography (GC-GC) • In cases where the characters of two or more oils are too similar to separate by usual MDGC fingerprinting methods.2. this enables confident allocation of production proportions from two or more geochemically dissimilar fluids in a commingled stream. High Resolution Gas Chromatography • This provides an analysis of the diesel-range hydrocarbon components separated by boiling point. and standards regularly run to calibrate the machine’s response. GC-GC is an alternative that may provide the necessary resolution.1. 3. and the baseline should rise only slightly during the elapse of the temperature ramp (this will be apparent from the blank run). • Sub-sample containers should be filled so that no more than 10% of the vessel total volume is headspace.2.2. • Baseline resolution of the peaks is essentially. Gas Chromatography . to reduce inaccuracies arising from evaporation. 3.3.EP 2007-3186 . 3. Because of their volatility.2. • Discuss the sampling and analysis program with the FEAST team or the Hydrocarbon Recovery Team in EPT-S before initiating such a campaign.2. the receiving container and delivery tube (from the sample cylinder) should be at ambient temperature. • Uncertainty varies with geochemical similarity.2.75 - Restricted 3. • Blanks should be run before and after each set of analyses.2. C7 Gas Chromatography • This is a high-resolution analysis of the gasoline-range hydrocarbon component of the Stock Tank Liquid. Multi-dimensional Gas Chromatography (MDGC) • A higher resolution analysis technique than HRGC. 3. Typically δ13C of C1 to C5. in case of deviation the analytical laboratory is informed on the specifics.3. as the compounds are unaffected by most phase behaviour.2. gases and water for the purposes of reservoir studies/ geochemistry. but gas samples from a separator or production line are also sometimes used.2. and indicates the maturity of the heavier components.2 and that. Typically δ13C values for methane below -55‰ indicate increasing biogenic contribution. operational control/ process monitoring and system design for specific applications of the produced hydrocarbons in downstream facilities requires dedicated off-site (but sometimes also onsite) analysis.g. o color of the sample. For some specific determinations. A zero-stage flash to atmospheric conditions is considered standard. no common industry standard methods are available yet.76 - Restricted 3.2. flow assurance. while those above are primarily thermogenic. • It is important to inform the analytical laboratory on (visual) observations made during sampling. and it is strongly recommended that the sampling and analysis program is discussed with the FEAST team or the Hydrocarbon Recovery Team in EPT-S before initiating such a campaign. Gas Chromatography . and δD (deuterium) of methane. although exceptions do exist.1. 3. e. CO2.EP 2007-3186 . custody transfer. These analyses are also typically carried out on IsoTubes taken during the drilling of the well.. • The analysis and interpretation is a non-trivial challenge. A presumption for all analysis is that samples have been taken according to the best practices described in Section 1. In these cases it is advised to discuss business need with the analytical focal point in the FEAST team to come up with a fit-for-purpose solution. Analytical 3.5. it is the gas evolved when the sample is flashed to conditions below the bubble point. General The characterization of hydrocarbon fluids. Isotopic Analysis on Solution Gas (or IsoTubes) • Solution gas is the gas component of a given production stream.2. .Mass Spectrometry (GC-MS) • Analysis of biomarkers is frequently required to determine the source-rock and maturity of a hydrocarbon. 3. • Standard clean stock tank fluid from a zero-stage flash or a well-stream surface sample are sufficient for this analysis.6. This chapter contains an overview of commonly applied standardized international and Shell proprietary analytical methods and some remarks on scope and limitations. In the case of singlephase samples. • This technique indicates the extent of thermogenic verses biogenic contribution of gas. fluid valuation. 2.3. Gas Chromatographic Analysis • As described in Section 3. addition of biocides. If any preservation technique has been used. system design and to assess the applicability of hydrocarbons in downstream processes. . Aromatics) technique (as performed according to ASTM D 6730. o precipitation. the PINA (Paraffins. and comparable methods like ASTM D 6729 and ASTM D 6733. 3.3. Naphtenes.77 - Restricted o homogeneity. e. • The gas chromatographic analysis of hydrocarbons with a boiling point of up to 260°C (500°F) can be performed according to ASTM D 3710.1. with main differences being the use of a precolumn and the column length) and multi-dimensional gas chromatography (see ASTM D 5443) can be used. • Details on proper sample containers for various samples can be found in Section 1.EP 2007-3186 . o presence of solid particles. where the C9+ fraction is not allowed on the column.The light fractions (with a boiling point up to 150°C (302°F)) are commonly characterized using Detailed Hydrocarbon Analysis (DHA).2. Iso-paraffins. various gas chromatographic techniques are employed for geochemical typing. Hydrocarbon Composition 3.1. For this technique.5.2. • For group type analysis in the C4 – C11 range. Proper labeling (in line with the recommendations in Appendix 1 and Appendix 3) is a prerequisite. • It is also recommended that the analytical laboratory is informed beforehand on the on the amount and packaging of the samples that will be submitted together with airway bill numbers / flight details. it is essential that the analytical laboratory receive detailed information on the applied technique as well as samples of the actually chemical(s) added to the samples. • For some (especially aqueous) samples. Gas chromatographic analyses are also used in the analytical laboratory for process monitoring. acidification with nitric acid. preservation techniques are required. dilution etc. o phase separation. • Comprehensive Two-dimensional Gas Chromatography (GCxGC) is evolving into a frequently used technique for detailed group typing in the range of C8 – C40 compounds as well as for the quantification of individual components. Since DHA for components heavier than C9 does not provide sufficient separation (resulting in a high number of “unknown” compounds in the analysis report) often a “front-end” approach is used. etc.g. no common industry standards have been accepted yet..2. isothermal separations on e.10% ±1% fractions 0. Repeatability of GC measurements should be as follows: fractions >10% (mole/mole) ±0. The industry standard for sulphur analysis in hydrocarbons up to C12 with GC-AED is described in ASTM D 6968.1% . the standard distillation method is the potstill distillation as described in ASTM D 5236. • A versatile selective detection system is Atomic Emission Detection. which is short and narrow to allow very rapid. • Next to gas chromatographs equipped with a flame ionisation detector or a thermal conductivity detector (which are commonly used for the detection of hydrocarbons).0. Much better fraction cuts are obtained by this method than by conventional distillation at atmospheric (ASTM D 86) or at reduced pressure (ASTM D 1160). fractions of effluent from the first column are focused at regular. the comparable test method using chemiluminescence sulphur detection is given in ASTM D 5504. Distillation analysis may only be used on stable samples. ASTM D 2892 has to be used.. • Selective detectors for hydrocarbon analysis include the Electron Capture Detector (ECD. • For the identification of unknown compounds.1% ±30% fractions 0. short intervals and injected onto a second capillary column. also selective detectors are available. including sulphur and carbon.78 - Restricted • In GCxGC. process design or HSE reasons.2. Also nitrogen selective detection can be achieved with GC-AED. The sample is first separated on a high-resolution capillary GC column in the programmed temperature mode. • Selective detection systems are also with GCxGC analysis.0. two independent gas chromatographic separations are applied to the entire sample. with a very high selectivity and sensitivity for chlorine).001% . polarity. .01% . Distillation Analysis • For crude evaluation purposes of crudes with an initial boiling point greater than 150°C (302°F). The relevant test method for the selective detection of sulphur in hydrocarbon liquids is given in ASTM D 5623.3.. Using a device called a thermal modulator.1% (relative) fractions 1% . this application can easily be expanded to the heavier hydrocarbons. with a high selectivity for sulphur or phosphorus). often gas chromatography with mass spectrometric detection is used. the (Pulsed) Flame Photometric Detector ([P]FPD.1% ±10% fractions 0.01% ±50% 3. A GC-AED has been developed for the analysis of many elements.EP 2007-3186 .g.2.For the distillation of stabilized crude petroleum to a final cut temperature of 400°C (752°F). Analysis using these detectors is commonly requested when detailed compositional information is required for e.g. but it may not always produce the most accurate results. and has not replaced. which consumes an equivalent amount of water (in the liquid under investigation). Components and Contaminants 3.79 - Restricted samples with a Reid vapour pressure greater than 83 kPa (12 psi) (e. The presence of excess iodine.g. ASTM D 96: “Standard Test Method for Water and Sediment in Crude Oil by Centrifuge Method (Field Procedure) has been discontinued as an analytical procedure in the lab. • Since gas chromatography does not allow the collection of distillation fractions.3.via gas chromatographic methods. such as ASTM D 2887 (for petroleum products and fractions having a final boiling point of 538°C (1081. • Determinations of water in crude oils include the Karl Fischer titration (ASTM E 203 or more specifically ASTM D 4377. determination of physical properties like relative density and molar mass cannot be done. sulphur compounds may interfere with the Karl Fischer titrations. well test separator liquid samples) should first be flashed to ambient conditions.1.15% mass) can be used. • True Boiling Point distributions can also be obtained – much quicker than via distillation . In crude oils. Sediments and Water • The centrifuge method for the determination of sediments and water (as published by the American Petroleum Institute) is still considered the most practical method for field determination of water and / or sediment.02 to 2% in crude oils). the GC techniques are unsuitable as a source of data for process simulation. a higher degree of accuracy is required the laboratory procedures described in Test Methods ASTM D 473 (extraction method..3. Hence. which is not converted when all of the water present has been consumed. • Alternatively in ASTM D 4006 a distillation analysis technique is described which covers the range from 0. 3. which covers the determination of water in the range from 0.01% mass and greater) or ASTM D 4807 (membrane filtration method.001% mass up to approximately 0.3.0 % water in crude oil. applicable in the range from 0. • Recent trends in TBP GC analysis include the use of sulphur selective detection. The analysis is based on the reaction between iodine and sulphur dioxide (which are present in the “Karl Fischer Reagent”). .EP 2007-3186 . • The vapour released must be quantified and analysed by gas chromatography to ensure that the light ends are not lost when the recombined stream composition is calculated. • Karl Fischer titrations can be used to determine the amount of water in a variety of nonaqueous liquids. • For sediments. • For accuracy reasons. is detected (voltametrically) by an indicator electrode.01 to 1. applicable for sediment levels from 0.3.4°F) or lower) and ASTM D 7169 (for the boiling point through a temperature of 720 °C [1328°F]). but unfortunately no common industry standard is available yet for their quantification.EP 2007-3186 . .3. Example 1: A representative sample of the crude oil or hydrocarbon is weighed out and diluted with methylene chloride. ASTM D 3516 Test Method C). and a final recovered polar residue weight determined. but they should be of the same order of magnitude. Sulphur Content • The flash combustion method (Schöniger combustion) should be applied (see e. • Speciation (i. several proprietary analytical techniques have been developed. 3. Example 2: The total amount of naphthenic acids in a crude or hydrocarbon condensate sample can also be determined by the liquid – liquid extraction of these acids with a sodium hydroxide solution from the hydrocarbon condensate. These cyclopentane and cyclohexane carboxylic acids are of special importance from a corrosion point of view. The sample is then reconstituted in heptane for the quantification of naphthenic acids by infrared analysis. An amino Solid Phase Extraction (SPE) cartridge is initially charged with methylene chloride and the diluted sample is applied onto the cartridge. qualitative and quantitative determination of the identity of the individual naphthenic acids) can be achieved by LC-MS (liquid chromatography with mass spectrometric detection) analysis of the organic solvent. for additional information the reader is referred to the analytical focal point in the FEAST team.80 - Restricted 3. Two commonly applied are outline below. The polar hydrocarbons are adsorbed onto the cartridge. The solvents are evaporated at low temperature with a nitrogen flush. • The acid numbers obtained by test method D 3339 may or may not be numerically the same as those obtained by test method D 664. Naphthenic Acids • A special class of acids in crude oils are the naphthenic acids. The free acids are extracted from the acid phase with an appropriate organic solvent. • Within Shell Global Solutions.3. A large percentage of the hydrocarbons are washed through the cartridge with methylene chloride and collected in a beaker. The end point of this titration can either be done by colour indication following ASTM D 3339 or using potentiometric end point determination (ASTM D 664). 3. containing the extracted free naphthenic acids. The extracted acids (in their salt form) are converted into the free acids by acidification with hydrochloric acid..g.3. The polar fraction is then collected in a tared vial by rinsing the cartridge with a series of appropriate solvents..3. the total amount of acids is determined by evaporation of the organic solvent and weighting the total amount of naphthenic acids. Acid Number • The acid number (sometimes also referred to as the total acid number or the neutralization number) is determined by titration with potassium hydroxide.3.3.2.3.e.4. 5. • Robust portable EDX systems are available.3.00 mass percent sulphur.2°F) and containing 3.35 % (m/m) halogen(s). The applicable concentration range for EDX is 0. for WDX this range is 0. suitable for onsite analysis.00 mass percent sulphur.0 to 8000 mg/kg total sulphur. it must be ensured that the matrices of the crude oils under investigation have a comparable composition (especially on C/H ratio and total oxygen concentration) as the calibration standards. SMS 177 is similar to ASTM D 3227. In view of the much higher energy dissipation in WDX as compared with EDX. GCxGC with quantitative group type analysis per carbon number offers detailed quantitative information. dissociation and pH dependence). Mercaptan Sulphur Content • Total mercaptan sulphur (range from 3 to 100 mg/kg) in distillate fuels (with a boiling point up to 300°C (572°F)) in the presence of organic sulphur compounds like sulphides.2). For both X-ray methods. • For hydrocarbons boiling in the range from 26 to 274°C (78. but which is very time consuming. but is not suitable for liquid hydrocarbons containing over 0.0 to 1000 mg/kg total sulphur.3. Because of the inherent better resolution of WDX as compared with EDX-systems. ASTM D 5453 is suitable for crudes containing 1. 3.EP 2007-3186 .001 to 5.0150 to 5.5 to 100 mg/kg total sulphur.3. 3.3. can be determined according to ASTM D 3227.6.3. ASTM D 6920 can be used for light hydrocarbons containing 0. • For the determination of sulphur in liquid hydrocarbons with a boiling range from approximately 25 to 400°C (77 to 752°F) also ASTM D 5453 or ASTM D 6920 can be used. Hydrogen Sulphide • In view of the reactive nature of hydrogen sulphide and because of its physical properties (distribution coefficient. disulfides and thiophene. • The mercaptan sulphur in crudes can also be assessed using GCxGC with selective detection (see Section 3. • The total amount of sulphur in crudes can also be determined using Energy-Dispersive X-ray Fluorescence spectrometry (EDX) or Wavelength Dispersive X-ray Fluorescence spectrometry (WDX).81 - Restricted • Next to the speciation of sulphur compounds in crudes by GC methods the total amount of sulphur (as precipitated in the form of barium sulphate) can be measured according to ASTM D 129. measurement of the . which is applicable to almost any petroleum product. solubility. but has a better precision and allows measurement of mercaptans in the presence of hydrogen sulphide. WDX is preferred for the analysis of crudes still containing produced water or production chemicals. oxidative microcoulometry can be used.8 to 525. WDX is generally not recommended for crudes with an initial boiling point below 50°C (122°F) because of evaporation losses. Both methods should be used for crude oils only with caution. Though no industry standard is available yet. including crude oils. Heavy fuels/ distillates are defined as mixtures with a kinematic viscosity at 40 °C (104°F) between 5. • For the determination of hydrogen sulphide in heavy fuels / distillates. • Chemiluminescence involves the high temperature combustion of the sample.0 and 50. N determination) described in ASTM D5291. microcoulometric methods (according to ASTM D 3431 or SMS 1730) might still be in place. A photomultiplier tube detects the light emitted as the exited NO2 decays and the recorded signal is a measure for the nitrogen contained in the sample.3. The Kjeldahl method is a labour-intensive method requiring sample digestion in a mixture of amongst others concentrated sulphuric acid and mercuric oxide and is not preferred if alternative techniques can be applied.5 and 24. H.05% mass. but also applicable for crude oils. Conradson Carbon Information on the relative coking tendency of amongst others crude oils can be obtained via ASTM D 189.015 to 2. inclusive at 100 °C (212°F). Nitrogen Content • The method of choice for nitrogen determinations is the chemiluminescence technique. 3. ASTM D 4629 can be used whereas for the concentration range from 40 to 10000 mg/kg ASTM D 5762 should be used. the Kjeldahl method can be used.0 mm2/s.0 mass percent in lubricating. • The qualitative assessment on the presence of hydrogen sulphide developed for use in aromatic hydrocarbons and in fuels and solvents can also be applied for most crude oils. It should be noted that. which involves “destructive distillation” and can be used when sufficient sample is available. multiple headspace extraction with gas chromatography can be used. Gas chromatography with sulphur selective detection (see Section 3.82 - Restricted concentration of H2S in hydrocarbon fluids is better addressed by onsite analyses and is not always a first requirement in the lab. • Potentiometric titration according to SMS 177 is most suitable for the determination of H2S in hydrocarbon liquids. ASTM D 4530 is to be used. where nitrogen is oxidized to nitric oxide in an oxygen atmosphere followed by contact with ozone under the formation of excited nitrogen dioxide.1) can also be used for the quantitative determination of hydrogen sulphide in light petroleum liquids.3. can also be analysed as part of the organic elemental analysis routine(C.1 to 2 mass percent) in a variety of matrices. Nitrogen concentrations (range 0. inclusive or between 5.8.7.3 to 100 mg/kg total nitrogen. When only small amounts of sample are available.2.and fuel oils. For samples containing 0. • For determination of the total amount of nitrogen in the concentration range of 0.3.3. these methods are discontinued and have not been replaced. • In some laboratories. because of interference by sulphur at levels above 0.0 mm2/s. 3. In .3.EP 2007-3186 . which add in both methods to the carbon residue value. no common industry standard is available for the determination of mercury in hydrocarbon liquids. • The determination of mercury in crude oil is complicated by the partitioning of mercury over different phases as well as by the different chemical forms in which this element can be present (elemental mercury and organic c. which converts all mercury to mercuric ions.9.3. ASTM D 5708.3. . reduction of mercuric ions to metallic mercury followed by clod vapour atomic absorption analysis).EP 2007-3186 . Interferences may arise from the presence of other conductive material in the crude oil sample. Care should be taken to ensure the complete retention of all (volatile) mercury compounds in the sample during preparation and analysis. 3. calcium and magnesium) is done according to ASTM D 3230. proprietary methods are available at different analytical service providers. This method is based on the conductivity of a solution of crude oil in a polar solvent when subjected to an electrical stress. The pre-treatment may either involve dilution with an appropriate solvent (often toluene is used) or acid digestion with concentrated sulphuric acid and / or nitric acid. More accurate analysis is more likely possible during onsite analyses. Inductively Coupled Plasma (ICP) analyses with Atomic Emission Spectrometry or Mass Spectrometry detection are increasingly being used for mercury analysis. • Next to Atomic Absorption Spectroscopy. The determination of metals with ICP requires sample pre-treatment by either dilution or digestion as described in e. such as sodium.q. Mercury • Getting a truly representative sample for the analysis of mercury in hydrocarbons can be very cumbersome because of the adsorption / desorption behaviour of (elemental) mercury on the inner steel surfaces of tubing and separation and processing equipment. in contrast to the standardized analysis of mercury in natural gas and analytical service providers often use proprietary methods.q. thee should be determined separately using ASTM D 482. for aqueous samples a standardized method for the determination of total mercury has been described in ASTM D 3223 (essentially the wet chemical oxidation.g. Inorganic mercury compounds in petroleum liquids. for more information the reader is advised to contact the analytical focal point in the FEAST team. • The commonly applied analytical technique for mercury determinations is Atomic Absorption Spectroscopy (AAS).3.10.. Salt The determination of salt (due to the presence of common chlorides. • Unfortunately. 3. inorganic mercury compounds). Pretreatment is required because the measuring solution is nebulized into the plasma. • For mercury speciation (determination of the amount of elemental mercury and organic c.3.83 - Restricted case ash-forming constituents are present in the crude. 3. the method described in ASTM D 7111 can be applied.1. . the radium isotopes (Ra228. Mg. a Shell proprietary method has also been published. This method can also be applied for the determination of the radium isotopes (in water.3. • Although ASTM D 3649 is developed for the analysis of aqueous samples. Mo. Sc.3.3.84 - Restricted Other Trace Elements • Commonly required trace element analyses in crude oils are the determination of nickel. Cr. Si. • Generic procedures for the determination of Al. Pb. provided that proper safety procedures are adhered to and that adequate matrix calibration corrections are used. Physical Properties 3.4. . Focus for the analysis mostly is on polonium210 (Po210) and occasionally on lead210 and. • Trace elements in crude oil can also be determined after sample digestion.12. Ca. Ti. Naturally Occurring Radioisotopes • In crude oil and in hydrocarbon condensate naturally occurring radioactive isotopes (NORs) from the uranium238 and from the thorium232 series can be present. A standardized method for the quantification of Po210 in petroleum liquids is under development. B. Density • The determination of density of crude oils is preferably performed using a digital density analyzer according to ASTM D 5002. iron and sodium for which industry standard analytical methods have been issued. the preferred method for the qualitative and quantitative analysis of gamma-emitting naturally occurring radioactive isotopes is described in SMS 2830. it can also be applied for the analysis of hydrocarbons.4. Ba. The noble gas radon222 is determined as part of the well site analysis of the produced gas. 3. Cu. followed by ICP or AAS analysis of the resulting aqueous phases. • Lead210 can be determined via high-resolution gamma spectroscopy. The use of either the hydrometer method or of the thermohydrometer method is also acceptable..EP 2007-3186 3. Ni.11. • Polonium210 is determined after acid sample digestion followed by electroplating of the Po210 and an internal standard (Po208) from the acid phase on silver disk and subsequent analysis by alpha spectroscopy. and Zn in petroleum liquids after dilution with a proper solvent using ICP-AES are described in ASTM D 7260. Na. Ra226 and Ra224) are more associated with the aqueous phase. condensate.3. Mn. 3. P. Fe. sludge and deposits). For the determination of these trace elements in petroleum liquids with an initial boiling point above 150°C (302°F). Co.3. Y. • Specific methods are available for the determination of aluminum and silicon and for organically bound chlorine in crude oil. vanadium. S. using either X-ray fluorescence (XRF) spectrometry or AAS. K. V. Li. 3. 3. The precision depends on the type of viscometer used (i. which has been the method of choice until 1999. This method also provides a calculation method to determine the Reid vapour pressure equivalent. • For non-Newtonian waxy crudes.3.4. from which also the kinematic viscosity can be calculated. . The kinematic viscosity can also be calculated from the dynamic viscosity.3.EP 2007-3186 • .3. 3. The method measures the time for the liquid to flow through a calibrated glass capillary viscometer and is only intended for Newtonian fluids (shear stress proportional to shear rate). Dynamic Viscosity • The dynamic viscosity is defined as the ratio of kinetic viscosity to the density of the sample and can therefore be calculated as described in ASTM D 445.3.3% of the mean and reproducibility 0. For clean. relative density (or specific gravity) and API gravity. the apparent dynamic viscosity must be determined using a (direct indicating) Bingham viscometer for a range of temperatures and shear rates chosen to be representative of future (pipeline) transport conditions.4. • IP 481 is a test method for determination of the air-saturated vapour pressure of crude oil. transparent oils repeatability can be expected in the order of 0. • The determination of viscosities of fluids under pressure (reservoir fluids) is made using a rolling ball viscometer. Distillation Analyses • For crude evaluation purposes the standard distillation method is the potstill distillation described in SMS 2767. whereas dark opaque samples are recommended to be measured in the reverse flow type.4. • For process design a TBP analysis of a liquid sample will be required. Accuracy is expected to be within 2%.5. Kinematic Viscosity • The kinematic viscosity is determined according to ASTM D 445. The Reid Vapour Pressure (commonly known as RVP) is determined according to ASTM D 323. The former is used for transparent Newtonian liquids.7% of the mean.4. ASTM D 7042 provides a method for the simultaneous determination of the density and the dynamic viscosity. 3.85 - Restricted The analysis includes determination of the density.2.. suspended level or reversed flow type). 3.4. Vapour Pressure • The vapour pressure of crude oil can best be determined using ASTM D 6377.e. For crude oils data are less precise. This should be carried out according to ASTM D 2892 which utilizes a 15 theoretical plate column and so obtains significantly finer fraction cuts than the D 86 or D 11 60. 4.8. Because of the low concentration of components greater than C8. • IS0 6976 must be used for calculating gas calorific value from the gas composition. which is quicker and easier to perform. . 3. well test separator liquid samples) should first be flashed to ambient conditions and the vapour released quantified and analysed by GC to ensure that these light ends are not lost when the recombined stream composition is calculated.4. Dehydration and De-oiling Analyses • The reader is referred to report EP 93-1315 for details of the numerous test which are carried on oil/water samples in order to design and monitor crude oil dehydration and de-oiling facilities.6. emulsion settling tests for testing screening of demulsifiers/ de-oilers) while others can be carried out off site. However.g.g. 3. Wobbe Index of a Gas Sample • Wobbe index is defined as: Wobbe No.EP 2007-3186 .7. Gas Calorific Value • Calorific value can be measured directly with suitable equipment but the achievable accuracy is only 1-1. Greater accuracy can be obtained by first determining the composition of the gas and then calculating the required property from the known composition and component basic data. in general crude oil and/or emulsion samples should be processed as soon as possible (within 24 hours) of sampling. Samples with RVP greater than 83 kPa (12 psi) (e.4. This approach is strongly recommended. = Gross Heating Value Gas Relative Density {4} The GHV is determined according to ISO 6976 and relative density determined according to IP59 method C. there will not normally be significant error introduced by assuming heating value of octane for C8+.86 - Restricted • ASTM D 2892 may only be used for stable samples.3. However the GC technique will not allow measurement of relative density and molar mass of fractions so is unsuitable as a source of data for process simulation. • ASTM D 2887 describes a GC alternative to ASTM D 2892.3.. particularly where the gas sales contracts are written in terms of thermal content of the gas sold. • It should be noted that many of these tests must be carried out onsite (e.3. 3.. • This method can however only be applied for compositions up to and including C8 since pure component data for only these components is provided in IS0 6976.5%. 4. Most importantly.1. from conventional floating piston bottles.EP 2007-3186 . manifolds. system design. Table 21: PVT Analyses Sample Type Volumes Data Requirements for Hydrate Evaluation Oil Psat Composition GOR API OBM CCE Difflib Septest Standard flash stocktank fluid from subsurface samples or separator oil line 100 ml STL Gas Psat Composition CGR Density OBM CCE CVD Septest Solution gas from subsurface samples or separator gas line Water pH Gas composition TDS Ion composition Resistivity Density Sufficient for recombination (depends on GOR) 100 ml STL Standard push-off from subsurface samples or separator water line (pH measured immediately after sampling). gas. and onshore processing facilities. dropping the temperature of the hydrate curve somewhat. Prevent. wellhead or separator samples are adequate providing that the entire production stream (oil. Flow Assurance Shell Flow Assurance (FA) Technology uses information pertaining to fluid properties and thermal-hydraulic analyses to develop a system design and to optimise operability to control solids. standard flash push-offs of oil are suitable for hydrate work. asphaltenes and scale.87 - Restricted 3. water) is sampled and QC-ed. flowlines. for example. as well as flow impairment issues caused by. a sample of the solution gas. In this case. Full PVT reports on each of these are essential. including hydrates. The integrated approach keeps the fluid flowing. Consequently. wax. From surface samples. . flow assurance presents an integrated approach for onand offshore shore production systems that includes wellbores. increased viscosities. Shell’s proprietary approach to wax and asphaltenes over the last decade is based on the following three technical objectives: Predict. providing optimal conditions for gas and oil transport from reservoir to onshore processing facilities and further through export pipelines. a sample of standard stock-tank oil. and operational strategies.4. some experimental data are needed to calibrate these curves as the polar components (resins and asphaltenes) can interfere with the formation of hydrates. If the gas and water samples are not available. the sample requirements are usually less exacting than those for wax. and a sample of the water can be combined to replicate production scenarios. Flow assurance strategies usually involve a combination of fluid phase behaviour. and naphthenate screens. From subsurface samples. 3. Evaluation of Hydrate Properties While hydrates are undoubtedly the most frequently encountered organic solid in hydrocarbon production. Gas hydrate curves for gas wells can be modeled accurately if accurate compositions of the hydrocarbon stream and water are available. asphaltenes. and Remediate. they can be artificially re-constituted in the lab from accurate PVT reports. For oil wells. trees. 0 0. The finger is a metal cylinder with two surfaces that can be independently maintained at constant temperature. and approximately 500 ml of stock-tank oil is necessary to evaluate these options.2.8-4.7 4. The Hydrate Team in Shell Global Solutions Flow Assurance Group should be consulted when planning any of these analyses. . • For less transparent crude oils AMS 259-1 (microscopic cloud point) must be used.1 -10. The finger is immersed in a well-mixed oil bath with bulk temperature above the cloud point.0 0.1 -6. Cloud point is determined according to ASTM D 2500 for semi-transparent crudes with cloud point less than 49°C (120.Precision is reported as follows: Wax content (mass %) Reproducibility (mass %) 1. addressing the rates of formation.4. the aggregation of the initial crystals.EP 2007-3186 . Each of these types of inhibitor require additional testing. Deposits are identified visually on the cold finger surfaces. Evaluation of Wax Properties Wax Content Wax content of petroleum products is determined according to SMS 1769. Typically the experimental program should be designed to address sufficient combinations and conditions to enable confident modeling of behaviour during the anticipated field life. • Cloud point is also estimated from the Shell-proprietary HTGC correlation.8 6.0 0. which correlates well with cloud points using cross-polar microscopy (CPM). • The cloud point temperature is also measured with the cold-finger (CF) technique. The method has a repeatability of 6°C (42. In a “standard” test the finger remains in the oil for 2 hours.2°F).9 >10 10% of mean Cloud Point • The cloud point of an oil is the temperature at which wax precipitation begins. and the conditions required for hydrate nucleation to occur. Three main categories of inhibitors exist.8°F) and reproducibility of 6°C (42. 3.88 - Restricted Experimental determination of onset conditions (pressure and temperature) and crystallization rate for a given composition (hydrocarbon/water mix) are determined.8°F) for oils other than distillates. g. The thermodynamic model can be used to calculate wax cuts (% wt wax out of solution). The “mini” pour point has been calibrated to the ASTM D97 method. This method yields absolute concentrations of normal paraffins above n-C20. The inversion point (the minimum temperature to which the sample should be reheated so that it will return to its minimum pour point) is determined by repeating the pour point test for repeated starting temperatures. a “mini” ASTM D97 pour point can be run. cloud points.5°C for residual waxes. N-paraffin Distribution by High Temperature GC (>C20) • The concentrations of individual normal paraffins in ppm on a whole-oil stock tank basis are determined using quantitative HTGC. These precision data should be regarded as optimistic for crude oils.. Then. Wax Thermodynamic Model and Critical Wax Deposition Temperature • Wax precipitation is modelled with Shell’s equation-of-state (EOS) based phase behaviour models. A standard analysis can typically quantify normal paraffin concentrations to about n-C60.4°F) temperature intervals. well bores and subsea flowlines). . The sample is pre-heated to remove the wax ‘history’. a gravimetric method for determining the amount of solid precipitate at a given temperature. which gives both maximum and minimum pour points. • Cloud points and pour points can be estimated from HTGC normal paraffin distributions with proprietary correlations. which allows for quantification of n-paraffins >nC60 up to n-C90. For refined products repeatability is 3°C and reproducibility is 6°C.EP 2007-3186 .89 - Restricted Pour Point • The pour point temperature is measured according to ASTM D 97. Wax Congealing Point • The congealing point of a wax is determined according to ASTM D 938. the sample is cooled under controlled conditions to determine its gelling temperature at 3 °C (37. and critical wax deposition temperature (CWDT) A cloud point is defined as the temperature at which a measurable amount of wax is out of solution in some specified test time (usually 2 hours). Pour point can also estimated from HTGC data correlations. On normal solid-forming species may also be included as a solid solution. • When sample volume is limited. to measure the minimum pour point the sample is pre-heated to 15°C (59°F). • The HTGC data are also used as input for Shell’s proprietary thermodynamic modelling programs for predicting wax deposition n live oil systems (e. The model has been validated with normal paraffin solubility data in live and dead crude oil systems. The actual pour point without heat is always between the maximum and minimum.Repeatability is of the order of 1°C and reproducibility is 2. To measure the maximum pour point the sample is pre-heated to 45°C (113°F). Normal paraffins are described with an in-house multi-crystalline solid phase model. • A “wax cut” can be performed. detailed in Shell report EP 2001-3026.Shell employs a modified version of this standard. when doing wax deposition simulations. we have defined a more conservative deposition threshold. It is Shell’s procedure to use CWDT. P-Value (Titration) Screen • P-value is a direct measure of asphaltene stability under stock-tank conditions. Values range from a low of 1. A longer test will reveal wax at a higher temperature.05.EP 2007-3186 . unstable (<2.90 - Restricted • Because of precipitation/ deposition kinetics. . This should be kept in mind when dealing with samples that may have undergone loss of pressure prior to reaching the analysis lab. CWDT is usually in the range of 3 – 11°C higher than cloud point. The “floc” points are determined visually with a microscope. Shell has calibrated these techniques using petroleum samples of known asphaltene stability. For the dead oil screens. Floc Point Analyser (Titration) Screen • The Floc Point Analyser. CWDT initially decreases owing to solution gas effects then increases owing to density effects. • CWDT is a function of system pressure. ShellMod2000IP143.3. or marginal (2. or FPA value is determined by n-heptane titration. To account for this effect. the measured value of cloud point depends on the test time. As pressure in increased from stock-tank conditions.5).Based on inhouse calibration work with known problematic and non-problematic fields. Evaluation of Asphaltene Properties Precipitation and deposition can occur on the timeframe of minutes to days.0). It is a titration test using n-hexadecane (cetane). samples that have been depressurised and repressurised may not be returned to initial conditions within operational or experimental timeframes and are potentially “irreversibly” altered for the industry purposes. The floc point is detected with a near infrared laser in a manner analogous to the Oilphase-DBR Schlumberger depressurisation test. The CWDT is the temperature below which significant deposits form in the field during a period of up to a year. which controls liquid phase composition and density. and not lab cloud point.51907. Asphaltene Content by Modified IP-143 • Asphaltene content of crude oil and petroleum products is typically measured by precipitation with heptane or pentane according to IP 143. while redissolution can take days to years. At stock-tank conditions. and calibrated it to field data. no cetane required to initiate flocculation) to a high value of > 5.0 . • Several dead oil screening tests and live oil depressurisation are used to evaluate asphaltene stability. Asphaltene behaviour and evaluation are dealt with in detail in Shell report GS.4.0 (asphaltene flocs already present. the CWDT.2.5). 3. numeric P-values are used to characterize a petroleum sample as stable (>2. These tests address different aspects of asphaltene phase behaviour and therefore are complementary. Therefore. The P-value parameter is related to the amount of cetane required to initiate asphaltene flocculation. In these tests. rather than precipitation tendency. an equilibrated live oil sample is isothermally depressurised. SARA-based parameters and plots have been developed to assess asphaltene stability. The PVT screen is a cross-plot of in situ density and the degree of undersaturation with respect to gas (the difference between reservoir and saturation pressures). and 2. At the same time. Hence. Based on our in-house calibration studies that contain data from over 20 asphaltene problem fields (and 200 other prospects/fields) worldwide. • Because of differences in procedure and solvent. resins. This screen has been calibrated against a suite of known problem Shell oils from around the world and is an indicator of deposition tendency.0 stable. and particle size analysis (PSA) techniques are utilized to assess the onset of asphaltene precipitation for live oil. Failure of this screen should be viewed as necessary but not sufficient criteria for asphaltene instability. greater than 3. Live Oil Depressurisation Test • A near-infrared (NIR) solid detections system (SDS). and asphaltenes by a combination of induced precipitation (for asphaltenes) and column chromatography. aromatics. Deposition (or Elemental) Screen • The deposition screen plots the ratio of Hydrogen over Carbon (H/C) against the Nickel (Ni) content of the asphaltenes obtained from the dead oil. it is conservative. the transmittance from an NIR laser through the oil and the visual observation of the fluid are recorded.3. FPA values less than 2. De Boer PVT Screen • This screen is based on the published work from De Boer et al.91 - Restricted • The FPA test can be more diagnostic for samples with sediment and low asphaltene concentrations.5 are considered unstable.0 marginal. and is a modification of the standard IP143 procedure. . The FPA test has also been calibrated with a set of known problem and non-problem fields. • Because this screen assumes the fluid is saturated with respect to asphaltene at reservoir conditions. high-pressure microscopy (HPM). the screen tries to estimate the severity of potential deposition problem IF the asphaltenes were to have precipitated during production (either by natural depletion or with blending). the amount of n-heptane required to induce precipitation in the FPA test is usually larger than the amount of cetane required in the standard P-value test. SARA Screen • SARA analysis is the determination of the amount of saturates. and it essentially evaluates the loss of asphaltene solubility as a reservoir fluid sample is depressurised.EP 2007-3186 ..5 . The screen is an effective cross-verification of the asphaltenes collected from the interior cell wall in the live oil depressurisation experiments (see below). The asphaltene analysis procedure uses n-heptane as the flocculating solvent. • Immediate measurement of the water sample pH upon push-off of STL is necessary to compensate for this possibility.4.g. 3. Evaluation of Scale Properties Scale can occur due to depressurisation of saturated (at reservoir conditions) formation water.4. The amount of asphaltenic precipitates are quantified and further analysed. and at the very least pH. naphthenic acids can complex with calcium to form calcium naphthenates upon a drop in acidity.1. during depressurisation). Hence. any precipitated barium sulphate sales will not be detected by the analysis lab that receives the sample.2. • At a point near the bubble point. This should be considered when observing any sample that is apparently saturated with Barium upon arrival in the lab.EP 2007-3186 . Naphthenic Acids • The naphthenic acids are present in the hydrocarbon. if a water sample experiences a pH rise due to loss of CO2 (e.4.4. and density. • Immediate measurement of the water sample pH upon push-off of STL is necessary to compensate for this possibility. Also a sample of water should be acidized to pH 2 (using a few drops of 10 M nitric acid. Calcium Naphthenates • Similar in principle to the barium salts. and quickly harden to concrete-like consistency in air. 3. GLR. Barium Salts • Upon a drop in acidity. they remain malleable. usually 1% of the original sample volume is sufficient). but the calcium and sodium are typically found in the aqueous phase. Any water samples from a well where naphthenates are a known risk should be screened for calcium and sodium concentrations. usually 1% of the original sample volume is sufficient). or due to breakthrough of injection water. the fluid is isobarically filtered and the cell and lines are rinsed. If hey are kept out of contact with the air. Also a sample of water should be acidized to pH 2 (using a few drops of 10 M nitric acid.4.92 - Restricted • Asphaltene precipitation are detected by (1) an abrupt drop in transmittance below the asphaltene instability onset pressure (due to light scattering by the newly formed asphaltenic phase) and by (2) visual observation of the formation of an asphaltenic phase. 3. but their high viscosity poses a serious threat to chokes and surface vessels. should be carried out as soon as possible. Sodium Naphthenates . commingled production of two or more incompatible water streams. resistivity. These organo-metallic complexes are also insoluble. The irreversible nature of some scale formation means that scale analyses should be carried out as soon as possible upon sample recovery. barium forms insoluble salts in the presence of sulphates that will not readily re-dissolve even when returned to an acidic environment.4. • This process should be repeated up to 3 times before considering more aggressive options. The sample should be pressurized to Psat + 13785. possesses a centrifuge designed to accommodate a highpressure cylinder. centrifugation is the only non-chemical option remaining.5 kPa (Psat +500 psi) for 24 hrs. while remaining above Psat. This process should be repeated up to 3 times before considering more aggressive options. 3. If the emulsion is too stable to break through heating and pressure cycling. and the BS+W determined of the remaining emulsion layer.EP 2007-3186 • .000 psi) for 24 hrs. up to Tres +10°C) and leaving the chamber to stand for 3-5 days with the pushoff valve lowermost (to enable the draining of free water). then depressurised to Psat +72.4. reducing or eliminating the surface facility efficiency. Canada. which tend to display surfactant behaviour. Centrifugation Oilphase-DBR in Edmonton.93 - Restricted Naphthenates also form soapy complexes with sodium. Water mixed with these oils readily forms water-in-oil emulsions. • Live oil samples can be separated by heating the sample chamber to reservoir temperature (or above. The free water should be drained and the BS+W determined of the remaining emulsion layer. It should be considered that the cylinder will experience the usual pressure differential due to the reservoir fluid.3.7 kPa (Psat +2. This can be calculated by PC=((ρ x ω2)/2) x ((R2)2)-(R1)2) Where: • PC = additional head of pressure due to centrifugation (dynes/cm2) • ρ = density of the fluid (g/cc) • ω = angular velocity (rad/s) • R2 = radial distance to base of fluid column (outlet valve) • R1 = radial distance to top of fluid column (inlet valve) . viscosity. Water/ Oil Emulsions • Heavy oils frequently have relatively high proportions of polar components (resins and asphaltenes). Cyclic Pressurization Pressurising and depressurising of the sample. After 5 days. with viscosities that can be one or two orders of magnitude above that of the base oil. the free water should be drained. and the additional head due to centrifugation. thereby. encourages the droplets of water to coalesce. Separation of these fluids is a serious challenge that must be overcome if the properties of the water and oil (such as density. resistivity) are to be distinguished from each other. gently vibrated for 15 minutes using a small amplitude agitator.4. which stabilize foams and emulsions in the separator. on-line sampling. Note that these chemicals are designed to alter physical properties of the oil. Operational Control and Process Monitoring 3. These properties are used as key features in the quality specifications attached to gas sales agreements. and the health hazard of escaping hot high-pressure hydrocarbon. concentrations of sulphur compounds or inerts are used in specific instances as key properties for monitoring performance or for quality control.12. crude density. adequate control may be obtained by periodically sampling and suitably analysing the appropriate streams. In these cases a simple chromatographic analysis to C8 or even a dew point measurement will generally suffice. and in that case a high degree of accuracy may be required. relative density.5.k.) but they require validation by manual sampling and analysis. Because of the wide variation in circumstances it is not possible to specify minimum data requirements for monitoring liquid process streams.2.1. • Calorific value. crude vapour pressure. Demulsifiers (a. 3. other properties. hydrocarbon and water dew points. • In many cases where the operation is a relatively simple one or where plant upsets are unlikely infrequent or of less serious consequence. . performance of demulsifying chemicals) is also important but this is treated in detail in report EP 93-1315. However. and viscosities obtained after addition of demulsifies are unlikely to be correct. Monitoring of Oil Processing and Transport Facilities The main variables requiring monitoring in oil producing operations are crude BS&W..g.10. de-emulsifiers) A wide range of emulsion breakers exists on the market.5.EP 2007-3186 . recording or indicating devices for this purpose. &13-Gen. hydrogen sulphide content (for protection of downstream facilities). TAN. salt content.a.31. loss of sample. and possibly sand production.11. such as API and Psat. of varying efficiencies. 3.94 - Restricted Care must be taken to ensure that the speed of the centrifugation does not generate a centrifugal head inside the cylinder that leads to seal failure. In many instances either the nature of the operation or the stringency of contractual requirements make it a requirement to apply continuous. Testing on STO should be carried out first before applying to the live samples. Monitoring dehydration / de-oiling performance (e. will not be significantly impacted by the addition of a small volume of these chemicals. Monitoring of Gas Facilities • In most gas handling or treating operations it is necessary to check either plant performance or product quality or both at regular intervals.50. These devices are beyond the scope of this report (see DEPs 32.5. It is recommended that a detailed geochemical analysis of the hydrocarbon “fingerprint” (HRGC and MDGC) is taken to facilitate confirmation of allocation determinations. • The analytical requirements for the simple and the standard evaluations are described in detail in report MF 81 0430. It may also be necessary to carry out routine measurements to determine the trace components in the gas. particularly at the inlet and outlet of the pipeline. Both the “standard” and the “simple” evaluation involve a standardized distillation of the crude and then varying levels of detailed analysis of the fractions. Process Simulation and System Design In all cases the compositional and analytical data of hydrocarbon fluids are to be used as the basis for process design calculations. 3. • Liquids should be routinely monitored for relative density. whether for new plants or facilities or for changes and additions to existing plants or facilities. • Geochemical “fingerprint” analysis of the oil by HRGC & MDGC should be carried out to enable confirmation of the allocations.7. and individual aromatics and hydrogen sulphide. inerts. • For this purpose all gas samples.5.10-Gen. Regular. new discovery. . the mixed pipeline fluid and the plant products will be necessary to ensure equitable intercompany accounting. crude or full production stream to shore through a shared pipeline and treatment facilities. • A “simple” crude oil evaluation may be carried out on a crude from a production test of a promising well in a new area or on crude from a new field making a significant contribution to an existing facility.6.EP 2007-3186 • . TAN and RVP.) 3.95 - Restricted Periodic monitoring of the condition of glycol in dehydration or hydrate protection systems will also be required. sulphur. In offshore production areas it is common for different companies to transport their gas. Fluid Valuation • For general oil refining processing information and to determine the economic value of crude or condensate SIPM-MFSO/6 has established two different levels of required data.04. in the event that the meters and bulk properties are insufficient. Data requirements for monitoring glycol condition must be according to DEP 20. BS&W. the more extensive and detailed the data available the better. should be analysed routinely for hydrocarbons up to C8 and for water. • A “standard” crude oil evaluation will be carried out on crude from a proven commercial.10..3. Product Allocation from Shared Facilities • Monitoring of plant outlet fluids is also important for product allocation from shared facilities. salt. periodic analysis of the different production streams. 3. • As an alternative to a TBP analysis. .53139 shall be used to characterise the heavy end for process simulation and system design.e. • This analysis should determine volume. • An accurate description of the properties of the individual carbon number fractions from C7 and above. • It is not adequate to assume that these fractions have the properties of the paraffins nor is it adequate to assume “standard” crude properties from published data. GCMS also allows greater possibilities to identify and quantify all components present in a hydrocarbon mixture (particularly for gas and condensate samples). C7+ or at most up to C12+ is adequate. GS. not weathered). gas refrigeration plant) a TBP analysis of the Cn+ fraction by distillation is required.EP 2007-3186 . The TBP analysis described in Section 3.. This information is then sufficient to characterise these fractions for use in process simulation packages. This is a useful calibration check against an experimentally determined TBP. as the limit because analysis to this level is feasible using industry standard methods (ISO 6975) and standard columns. relative density) of these fractions calculated. size equipment and predict product yields.96 - Restricted These data should at least include the following: • The composition of the fluid up to C30+. mol wt and specific gravity of the fluid components including individual determination of BTEX species.06. crude separation plant. (usually equivalent to the paraffinic hydrocarbon components). • For typical EP applications (e. surface engineers do not require analytical composition up to C30+. • Note that modern process simulation programs provide the facility to generate TBP or distillation curves from a compositional stream input. LPG plant. C30+ analyses are standard Shell requirements and are frequently available at reputable analysis labs.g. which are performed to simulate new or existing plants in order to. The GCMS will provide normal boiling point (equivalent by chromatography) and average relative molar mass for the individual carbon number fractions from C7 and above.. • Experimental measurements of phase behaviour (liquid/gas ratios and compositions.53139. and average density for hydrocarbon fractions between specified boiling points. The components identified may then be lumped into a usable number of fractions and the average properties (molar mass. This information defines the “character” of these fractions and process simulation programs can use this information to generate all other relevant properties for each fraction. For general EP applications. This should include mol%. • C16 is an alternative acceptable resolution. average molar mass.4. at least one service company is now offering analyses based on GCMS. Based on the Guide for Fluid Characterization using C7PLUS method in HYSYS.5 should be carried out on a fresh sample (i. C7+ is good enough and GS. The description of the individual carbon number fractions has a significant effect on the accuracy of computer simulations.06. dew points) of the well stream at anticipated future processing pressures and temperatures so as to enable simulated phase behaviour to be accurately calibrated.3. In addition.97 - Restricted • The equation of state models used in process (and reservoir) simulators cannot be expected to be 100% accurate. • Other standard PVT experiments that will be required for reservoir engineering purposes also provide useful calibration data for phase behaviour models. Bubble point of the original reservoir fluid is also required and preferably at least one extra bubble point measured at a different temperature. • For oils (bubble point systems) this should include a separation train experiment at likely process separation conditions culminating in a flash to stock tank conditions. a similar separation train experiment is required along with the same gas analyses and stock tank fluid properties. . Therefore. • The GOR should be reported at each separation and an analysis of the separator gas to C8 will also be required. • For gases and condensates (retrograde dew point systems).EP 2007-3186 . it is essential to calibrate them with measured data (see report EP GS-06-53139). 3 dew point temperatures across the likely process pressures are required to calibrate phase behaviour models near the phase boundary. Input from Stock Tank Fluid Assessment Modeling and Designs (Various types) Chemical Compatibility Screening Interference assessment . Asphaltenes) Recombination (if necessary) Filtration at Pres and Tres Live oil C30+ analysis Molecular weight STO viscosity and density at 80F Constant Composition Expansion Constant Volume Depletion (gas) Differential Liberation (oil) Separator Test Asphaltene Screens Blending Stock Tank Fluid Assessment See next chart Figure 1: pH Ion suite concentration Resistivity Density %CO2 Gas composition PVT Filtration at Pres and Tres Live oil NIR + HPM + PSA Quantification (mass balance) of solids Ni-C/H screen Chemical Testing PVT Performance Assessment Emulsion breakers Foam breakers Corrosion/Asphaltene/Wax/Scale Inhibitors Flow-chart of the Fluid Sample Assessment Procedure – Live Fluid.EP 2007-3186 4. . Wax.98 - Restricted FIGURES Live Oil Fluid Sample Sample Transfer on Rig (if needed) Hydrocarbon Water Restoration Sample restoration (1 day) Opening pressure Cylinder transfer Restoration Sample restoration (3-5 days) Opening pressure Cylinder transfer Validation API GOR/CGR % Asphaltenes (IP143) Bulk sediments and water % OBM in situ viscosity % N2 % CO2 C30+ Psat STO for Geochem. EP 2007-3186 - 99 - Restricted Water Stock Tank Fluid Sample Scale Hydrocarbon Geochem istry pH Ion suite concentration Resistivity Density %CO2 Gas composition Biomarkers (MDGC) High Resolution GC TAN Nickel & Vanadium content % Sulphur SARA Asphaltene Screens SARA screen Ni-C/H screen De boer screens FPA and P-value screens Input from Live Fluid Assessm ent Wax Screens HTGC Pour Point Cloud Point Extened HTGC CWDT (from Cold Finger) Modeling and Designs (Various types) Physical Properties Density Viscosity Valuation Assay Chemical Testing Perform ance Assessment Emulsion breakers Foam breakers Corrosion/Asphaltene/Wax/Scale Inhibitors Figure 2: Chemical Compatibility Screening Interference assessment Flow-chart of the Fluid Sample Assessment Procedure – Stock-Tank Fluid. EP 2007-3186 - 100 - Restricted Figure 3: Containers preferred for water samples. Figure 4: Containers acceptable for water samples as last resort. Figure 5: Containers acceptable for small (left) and large (right) volume gas samples. EP 2007-3186 Figure 6: - 101 - Containers acceptable for stock-tank oil samples. Restricted EP 2007-3186 - 102 - Figure 7: Containers not acceptable for oil or water samples. Figure 8: Container acceptable for pressurised oil sample. Restricted EP 2007-3186 Figure 9: . .103 - Restricted Diagrams of single-phase (left) and floating-piston (right) sampling bottles (examples courtesy of Schlumberger). 104 - Diagram of gas surface sampling (examples courtesy of Schlumberger).EP 2007-3186 Figure 10: . Restricted . EP 2007-3186 Figure 11: . Restricted .105 - Diagram of conventional sample bottle priming (examples courtesy of Schlumberger). 106 - Figure 12: Diagram of sample points in production stream. Restricted . Figure 13: Diagram of a 3-phase-separator.EP 2007-3186 . EP 2007-3186 .107 - GAS OIL Figure 14: Separator oil and gas sample points and choke manifold sample point. Restricted . .108 - Restricted GC API/GOR PVT apparatus GOR PVT cell Viscometer Figure 15: Mobile PVT lab apparatus.EP 2007-3186 . 1.1. Tubes Figure 16: Draeger stain tubes. Restricted .109 - Pump 1.1.EP 2007-3186 . 110 - H2S.Titration UOP 212. Mercaptans.EP 2007-3186 Figure 17: . Restricted . . .EP 2007-3186 . so increasing the surface area per volume. Figure 18: CO2 Orstat Titration.111 - Restricted Absorption pipette contains a large number of glass tubes. EP 2007-3186 Figure 19: . and close-up of scintillation cell. Restricted . radon analysis unit.112 - Diagram of radon trap. Restricted .113 - Arsenic sampling apparatus.EP 2007-3186 Figure 20: . Restricted .EP 2007-3186 Figure 21: .114 - Mercury sampling diagram. .115 - Restricted Gas line from separator H2S scrubbers (KOH) Au/Pt sorption tubes Figure 22: Mercury sampling apparatus and close-up of the acid gas filters (Malcosorb).EP 2007-3186 . The blue color shows saturated Malcosorb. EP 2007-3186 • • • .) Pictures courtesy of Schlumberger. Single-phase sampling bottle being transferred into single-phase transport bottle (left.116 - Heating Jacket Agitation Frame Split Piston Restricted Sampling Cylinder Transportation Cylinder Figure 23: Transfer of a large volume (2¾ gallon) floating piston sampling bottle. . Portable “suitcase” Millipore Restricted .EP 2007-3186 .117 - Portable “skid type” Millipore Figure 24: Millipore sand-sampling units. EP 2007-3186 .118 - Norman Filter Figure 25: Norman sampling units. Restricted . Restricted .EP 2007-3186 .119 - MANIFOLD Sample Locations 12’ position 4:30 position Vertical Figure 26: Examples of sand sample locations. FLOW ? Success of sampling immediately downstream of a bend is highly dependent upon local flow conditions Sampling >10D downstream of a bend on vertical is second choice ? Sampling at 6 o’clock position >10D downstream of bend on horizontal is best sample location Figure 27: Optimum location to detect sand by slip-stream sampling.120 - Restricted Sand is never evenly distributed across the pipe.EP 2007-3186 . It tends to travel with the liquid phase and concentrate at the bottom due to gravity. . 2 2.8 0.EP 2007-3186 .4 0 Re port e d 0 0.6 1.5 1 1.8 2.4 2 1. . Yi / Zi Mass Balance Check: Sample BRAO-1334A (Paleocene) 3.2 0.121 - Restricted Campbell Diagram Check: 12314 ft Fluid 8 Reported ln [Ki] 4 0 -4 -8 0 100000 200000 300000 400000 Tcritical2 Figure 28: Example Buckley plot (Campbell diagram) from a Nigerian crude. 5 2 Xi / Zi Figure 29: Example mass balance diagram from a Brazilian crude. (Elsevier). J. G.122 - Restricted REFERENCES Shell Reports and Guidelines Apte. A. Westrich. and Leitko... BTC-3540: (1998).. EP 92-1150: EPD/41. de Kruijf. Ratulowski. The Integrity of RFT Oil Samples Obtained from the Deepwater GOM: An Interim Report Based on Analysis of Oil Samples from the Bullwinkle J2-RB Reservoir. BRC-3198: (1994). (Intec). T. EP 87-1 006: SlPM EP0/53. A. Choate. Guidelines for Sampling and Analysis of Produced Water for Reinjection and Disposal. Danesh. S. Weiss. J. R. revised July 1992. J.. D.. Skogsberg. V. Recommendations on the Surface Sampling and Analysis of Natural Gas. T. Couch. J. BTC-3534: (1998). and Russell. Mehta. J. J...J. D. . and Ratulowski. G.. A.. Steenson. J. Well Services Guidance Manual. Dubey. PVT Sampling. Kruka. R. T. EP 92-0980: (1992). J. Lorimer. W. D... Procedures for handling and processing fluid samples from RFT and MDT tools for transportation engineering. L. PVT and Phase Behaviour of Petroleum Reservoir Fluids. Westrich. J. S. Hudson.. Ellison B..T. L.. G.E. den Boer J.. S. Flocculation Point Analyzer: A New Tool for Screening Crude Oils to Evaluate Asphaltene Stability.. A. T. Iyer. (2003). P. L. Wasden. EP 91 –0703: (1991). Produced Water Analysis Guidelines.. Knigge.. A. E. Apte.. March. Westrich. M. and geochemical analyses. J. Leitko.. PVT evaluation and geochemical analysis. F. K.. Sea Water Sampling and Analysis Guidelines.. Ratulowski. June. J. P. S. EP 91 –0951: (1991). Broze. S. L. A. Paraffin-Related Measurements.. T. Hearn.. Dubey.. and Dixon. J. PVT evaluation. D. Subsea Oil Production System Design and Operations Methodology.. BTC-3540: (1999). Analysis and Quality Control Manual. S.. Kushner. J. (2002). Dubey. and Geochemical Analyses Westrich. M. Procedures for handling and processing fluid samples from RFT and MDT tools for transportation engineering. Scherpenisse. Zabaras. A. J. D. BTC-3344: (1996). S. S. EP 05-0758: (1979). Guidelines for Manual Sampling and Analysis of Hydrocarbon Fluids. (1998). O. J. (2003). Ratulowski. B. Procedures for Handling and Processing Fluid Samples from RFT and MDT Tools for PVT Analyses. Measuring the Wetness of Wet Gas in Producing Flow Lines: Field Trial of a Prototype Tracer Method and a Commercially Available Sampling Method.EP 2007-3186 . J. Sand Control Manual. and Ratulowski. Westrich. D. T. M. F. T. BTC 1299: (1999).. S. Nimmons. Leitko. 17th ed. 205. Killi A. A. Rocks and Fluids. W. M..80043: (2002). EP 05-0758: (1979). Williamson. A.05.. IFSN-3010: Inan E. Utech N.. Utech N. Total Dissolved Solids (TDS). B... Cornelisse. Fuex. EP 95-0319: Safe Handling of Chemicals.. OP. MF 81-0340: Shell Crude Oil Evaluation Schemes (Laboratory Manual). IFSN-1010: Dead Oil Sampling for Reid Vapour Pressure. PVT: Hydrocarbon Fluid Properties and Phase Equilibria (Class Notes by Dindoruk B. Guide for Fluid Characterization using C7PLUS Method in HYSYS. N. A.. Lesoon. Stankiewicz B. IFSN-1000: Dead Oil Sampling for Manifold Shake Out Sink and Test Separator. M. EP 95-0317: Hydrogen Sulphide (H2S) in Operations. Dubey. T.1 (2007). N. (1990). and Lockett. GS. Hendriks. (PennWell). EP 2001-3026: (2001). and Geochemical Analysis.. National Association of Corrosion Engineers (NACE). PVT Team. 2007) Shell International Oil Products Dehydration Manual 1. (1989) . EP 2003-5184 (2003) Shell Expro Topside Management Guide. and Liakhovitch. Conductivity/Resistivity. Stankiewicz.123 - Restricted EP 93-1315: De-oiling Manual. D.53139: (2006). IFSN-2000: Sampling procedures for pressurized gas samples from the test separator. EP 2000-9021: (2000). Methods for determining water quality for subsurface injection using membrane filters. and O’Neal P.. J. Killi A.. E. Analysis and Evaluation of Organic Deposits.02. Sampling Procedures for Water Samples for Isotopic Measurements. Killi. E. McCain Jr. Utech. and Remediation of Asphaltenic Flow Assurance Issues in Subsurface and Surface Facilities.. Fuex. and O’Neal P. Hearn and Dixon. pH. PVT Calculator V. density/specific gravity.. The Properties of Petroleum Fluids. PVT Evaluation. Procedures for Water Samples for Inorganic Nonmetallic Constituents (Major Anions and Cations). B.. A. N..51907: Prediction. Standard Methods for the examination of water and wastewater. P. Improved Tools for Prediction of Asphaltene Stability..0 1999. Volatile Organic Acids. Rijkwijk. Metals (for short term storage). Flannery.. V. IFSN-1100: Sampling procedures for pressurized oil samples from the test separator. S. Tegelaar. Handling and Processing Downhole Fluid Samples on the Rig and in the PVT Lab for Transportation Engineering. M. Water Sampling Procedures For Metals.06. A.. Prevention. SIEP EPT-RHF.EP 2007-3186 . and O’Neal. Flannery M. R. IFSN-3000: Inan E.. P. GS. B. EP 2007-3186 TNER.88.006: - 124 - Restricted (1988), Hydrocarbon Fluid Evaluation by Split-Phase Methods: Field Equipment and Procedures, Dixon A. G., Ebbrell, H. K., Rimmer, C. P., Wilde R. G. Standards Referenced American Petroleum Institute Recommended Practice No.45. AMGR.96.113: Characterisation of Petroleum Acids in Crude Oils by Spectrometric and Chromatographic Techniques. AMGR.96.113: Characterisation of Petroleum Acids in Crude Oils by Spectrometric and Chromatographic Techniques. AMS 259-1: Paraffin Wax Cloud Point of Dark Fuel Oils: Microscopic Method. AMS 607-2: Mercury in Aqueous Solutions, Water Soluble Materials, Urine, Clay and Drilling Materials: Flameless AAS Method. AMS 743-2: Radon 222 Activity in Natural Gas: Ionisation Chamber Counting Method. AMS 780-2: Po-210 Radioactivity Concentration in Hydrocarbon Condensates: Gas Proportional Method. ASTM D 1160: Standard Test Method for Distillation of Petroleum Products at Reduced Pressure. ASTM D 1250: Standard Petroleum Measurement Tables. ASTM D 129: Standard Test Method for Sulphur in Petroleum Product (General Bomb Method). ASTM D 1298: Standard Test Method for Density, Relative Density (Specific Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method. ASTM D 1298: Standard Test Method for Density, Relative Density, or APR Gravity of Crude Petroleum and Liquid Petroleum Products by Hydrometer Method. ASTM D 1657: Standard Test Method for Density or Relative Density of Light Hydrocarbons by Pressure Hydrometer. ASTM D 1835: Standard Specification for Liquefied Petroleum (LP) Gases. ASTM D 189: Standard Test Method for Conradson Carbon Residue of Petroleum Products. ASTM D 2500: Standard Test Method for Cloud Point of Petroleum Oils. ASTM D 2622: Standard Test Method for Sulphur in Petroleum Products by X-Ray Spectrometry. ASTM D 2887: Standard Test Method for Boiling Range Distribution of Petroleum Fractions by Gas Chromatography. ASTM D 2892: Standard Test Method for Distillation of Crude Petroleum (15-Theoretical Plate Column). ASTM D 3120: Standard Test Method for Trace Quantities of Sulphur in Light Liquid Petroleum Hydrocarbons by Oxidative Microcoulometry. ASTM D 3223: Standard Test Method for Total Mercury in Water. EP 2007-3186 - 125 - Restricted ASTM D 3227: Standard Test Method for (Thiol Mercaptan) Sulphur in Gasoline, Kerosene, Aviation Turbine, and Distillate Fuels (Potentiometric Method). ASTM D 3228: Standard Test Method for Total Nitrogen in Lubricating Oils and Fuels Oils by Modified Kjeldahl Method. ASTM D 323: Standard Test Method for Vapor Pressure of Petroleum Products (Reid Method). ASTM D 3230: Standard Test Method for Salts in Crude Oil (Electrometric Method). ASTM D 3246: Standard Test Method for Sulphur in Petroleum Gas by Oxidative Microcoulometry. ASTM D 3339: Standard Test Method for Acid Number of Petroleum Products by Semi-Micro Colour Indicator Titration. ASTM D 3431: Standard Test Method for Trace Nitrogen in Liquid Petroleum Hydrocarbons (Micracoulometric Method). ASTM D 3516: Standard Test Method for Ashing Cellulose. ASTM D 3648: Standard Practices for the Measurement of Radioactivity. ASTM D 3649: Standard Practice for High-Resolution Gamma-ray Spectrometry of Water. ASTM D 3710: Standard Test Method for Boiling Range Distribution of Gasoline and Gasoline Fractions by Gas Chromatography. ASTM D 4006: Standard Test Method for Water in Crude Oil by Distillation. ASTM D 4292: Standard Test Method for Sulphur in Petroleum and Petroleum Products by EnergyDispersive X-ray Fluorescence Spectrometry. ASTM D 4377: Standard Test Method for Water in Crude Oils by Potentiometric Karl Fischer Titration. ASTM D 445: Standard Test Method for Kinematic Viscosity of Transparent and Opaque Liquids (and Calculation of Dynamic Viscosity). ASTM D 4530: Standard Test Method for Determination of Carbon Residue (Micro Method). ASTM D 4629: Standard Test method for Trace Nitrogen in Liquid Petroleum Hydrocarbons by Syringe/Inlet Oxidative Combustion and Chemiluminescence Detection. ASTM D 4691: Standard Practice for Measuring Elements in Water by Flame Atomic Absorption Spectrophotometry. ASTM D 473: Standard Test Method for Sediment in Crude Oils and Fuel Oils by the Extraction Method. ASTM D 4807: Standard Test Method for Sediment in Crude Oil by Membrane Filtration. ASTM D 482: Standard Test Method for Ash from Petroleum Products. ASTM D 4929: Standard Test Methods for Determination of Organic Chloride Content in Crude Oil. ASTM D 4952: Standard Test Method for Qualitative Analysis for Active Sulphur Species in Fuels and Solvents (Doctor Test). EP 2007-3186 - 126 - Restricted ASTM D 5002: Standard Test Method for Density and Relative Density of Crude Oils by Digital Density Analyzer. ASTM D 5134: Standard Test Method for Detailed Analysis of Petroleum Naphtas through n-Nonane by Capillary Gas Chromatography. ASTM D 5184: Standard Test Methods for Determination of Aluminum and Silicon in Fuels Oils by Ashing, Fusion, Inductively Coupled Plasma Atomic Emission Spectrometry, and Atomic Absorption Spectrometry. ASTM D 5236: Standard Test Method for Distillation of Heavy Hydrocarbon Mixtures (Vacuum Potstill Method). ASTM D 5443: Standard Test Method for Paraffin, Naphtene, and Aromatic Hydrocarbon Type Analysis in Petroleum Distillates Through 200°C (212°F) by Multi-Dimensional Gas Chromatography. ASTM D 5504: Standard Test Method for Determination of Sulphur Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and Chemiluminescence. ASTM D 5623: Standard Test Method for Sulphur Compounds in Light Petroleum Liquids by Gas Chromatography and Sulphur Selective Detection. ASTM D 5673: Standard Test Method for Elements in Water by Inductively Coupled Plasma – Mass Spectrometry. ASTM D 5708: Standard Test Methods for Determination of Nickel, Vanadium, and Iron in Crude Oils and Residual Fuels by Inductively Coupled Plasma (ICP) Atomic Emission Spectrometry. ASTM D 5762: Standard Test Method for Nitrogen in Petroleum and Petroleum Products by BoatInlet Chemiluminescence. ASTM D 5863: Standard Test Methods for Determination for Nickel, Vanadium, Iron, and Sodium in Crude Oils and Residual Fuels by Flame Atomic Absorption Spectrometry. ASTM D 5954: Standard Test Method for Mercury Sampling and Measurement in Natural Gas by Atomic Absorption Spectroscopy. ASTM D 6021: Standard Test Method for Measurement of Total Hydrogen Sulfide in Residual Fuels by Multiple Headspace Extraction and Sulphur Specific Detection. ASTM D 6377: Standard Test Method for Determination of Vapor Pressure of Crude Oil: VPCRx (Expansion Method). ASTM D 6463: Standard Test Method for Determination of Total Sulphur in Light Hydrocarbons, Spark Ignition Engine Fuel, Diesel Engine Fuel, and Engine Oil by Ultraviolet Fluorescence. ASTM D 664: Standard Test Method for Acid Number of Petroleum Products by Potentiometric Titration. EP 2007-3186 - 127 - Restricted ASTM D 6730: Standard Test Method for Determination of Individual Components in Spark Ignition Engine Fuels by 100 Metre Capillary (with Precolumn) High-resolution Gas Chromatography. ASTM D 6822: Standard Test Method for Density, Relative Density, and API Gravity of Crude Petroleum and Liquid Petroleum Products by Thermohydrometer Method. ASTM D 6920: Standard Test Method for Total Sulphur in Naphthas, Distillates, Reformulated Gasolines, Diesels, Biodiesels, and Motor Fuels by Oxidative Combustion and Electrochemical Detection. ASTM D 6968: Standard Test Method for Simultaneous Measurement of Sulphur Compounds an Minor Hydrocarbons in Natural Gas and Gaseous Fuels by Gas Chromatography and Atomic Emission Detection. ASTM D 7042: Standard Test Method for Dynamic Viscosity and Density of Liquids by Stabinger Viscometer (and the Calculation of the Kinematic Viscosity). ASTM D 7111: Standard test Method for Determination of Trace Elements in Middle Distillate Fuels by Inductively Coupled Plasma Atomic Emission Spectrometry (ICP-AES). ASTM D 7169: Standard Test Method for Boiling Point Distribution of Samples with Residues Such as Crude Oils and Atmospheric and Vacuum Residues by High Temperature Gas Chromatography. ASTM D 7260: Standard Practice for Optimization, Calibration, and Validation of Inductively Coupled Plasma – Atomic Emission Spectrometry (ICP-AES) for Elemental Analysis of Petroleum Products and Lubricants. ASTM D 853: Standard Test method for Hydrogen Sulfide and Sulphur Dioxide Content (Qualitative) of Industrial Aromatic Hydrocarbons. ASTM D 86: Standard Test Method for Distillation of Petroleum Products at Atmospheric Pressure. ASTM D 938: Standard Test Method for Congealing Point of Petroleum Waxes, Including Petrolatum. ASTM D 96: Determination of Water and/or Sediment in Crude Oil by the Centrifuge Method (Field Procedure). ASTM D 97: Standard Test Method for Pour Point of Petroleum Oils. ASTM D 5291: Standard Test method for Instrumental Determination of Carbon, Hydrogen and Nitrogen in Petroleum Products and Lubricants. ASTM E 203: Standard Test Method for Water Using Volumetric Karl Fischer Titration. ASTM E 697: Standard Practice for Use of Electron-Capture Detectors in gas Chromatography. ASTM E 840: Standard Practice for Using Flame Photometric Detectors in Gas Chromatography. Campbell, J. M., (1988), Gas Conditioning and Processing; 6th Edition, Campbell Petroleum Series, 1215 Cross Roads Blvd., Norman Oklahoma 73072, USA. SMS 2828-96: Determination of the activity concentration of 210Po in aqueous solution.Determination of Mercury at High and Low Pressure.Determination of Sulphur Compounds (parts 1 . ISO 3170: Manual Sampling of Liquid Hydrocarbons. GPA 2166: Obtaining Natural Gas Samples for Analysis by Gas Chromatography.EP 2007-3186 .13-Gen: On-line Process Stream Analysis: Part 4. and Relative Density. Sample Take off and Transportation.Cooled Surface Condensation Hygrometers. 121 1 Geneva 20. Rue de Varernbe.5). ISO 6978-1: Natural Gas – Determination of Mercury – Part 1: Sampling of mercury by chemisorption on iodine.31 S0. DEP 32. scraping and scales. IISO 6978-2: 2003 Natural Gas .11-Gen: On-line Process Stream Analysis: Part 2. 1992.Method of preparing sample by electroplating.Determination of hydrogen. sludge.Gas Chromatographic Method. ISO 3171: Automatic Pipeline Sampling of Liquid Hydrocarbons. ISO 6326: Natural Gas . Analyser in-House Systems. DEP 32. Density. ISO 6570: Natural Gas .128 - Restricted DEP 32.31 S0. NVN 5694: Method for the Determination of Polonium-210 in Hydrocarbon Condensate (in Dutch). DEP 32. ISO 6978-2: Natural Gas – Determination of Mercury – Part 2: Sampling of mercury by amalgamation on gold/platinum alloy.Determination of Mercury. Issued by international Organization for Standardization (1. Nozzles and Venturi Tubes inserted in Circular Cross-section Conduits Running Full.α-spectrometric method..12-Gen: On-line Process Stream Analysis: Part 3. ISO 6975: Natural Gas. GB/T 12376-90: Analytical method of polonium-210 in water . Switzerland).31 S0. Analysers. ISO 6327: Natural Gas. Inert gases and Hydrocarbons up to C8. Sample Conditioning. ISO 6978: Natural Gas.10-Gen: On-line Process Stream Analysis: Part 1.Method of Sampling. ISO 5167: Measurement of fluid Flow by Means of Orifice Plates. catalysts and hydrocarbon condensates ex gas / oil production .Determination of Hydrocarbons from Butane (C4) to Hexadecane (C16).Analysis by Gas Chromatography.Determination of Potential Hydrocarbon Liquid Content.Determination of Water Dew Point of Natural Gas.31 S0.Gas Chromatographic Method. .Calculation of Calorific Value. ISO 7941: Commercial Propane and Butane. ISO 4257: Liquefied Petroleum Gases. ISO 6974: Natural Gas. EP 95-0317: Hydrogen Sulphide (H2S) in Operations. ISO 6976: Natural Gas. SMS 217: Hydrogen Sulphide.129 - Restricted SMS 2830-96: Determination of the activity concentration of Naturally Occurring Radionuclides of the 238U-. GC Method with Microcoulometric Detection. SMS 1730: Nitrogen in Organic Materials. IP 77/79: Salt Content Crude. SMS 2384: Acid Value of Dark-Coloured Petroleum Products . Freezing Point Depression Method. and Iron in Petroleum Oils by Atomic Absorption Spectrophotometry. SMS 1807: Sulphur in Organic Materials. Vacuum Potstill Method. Potentiometric Titration Method. SMS 2268: Existent Hydrogen Sulphide in Crude Oils. SMS 2294: Average Molar Mass of Gasoline. SRC 00206-04R: Determination of Naphtenic Acids in Crude Oils Using Solid Phase Extraction and Infrared Spectroscopy. Iqscher Reagent Method. SMS 1346: Average Molar Mass. SMS 1803: Atomic Absorption Spectroscopy. Crystallization Method. Nickel. Fischer Reagent Method.and 232Th-decay series in all type of sample matrices: Semi-conductor γspectrometric method. IP 143: Asphaltenes Precipitation with Normal Heptane.Potentiometric Titration Method. and Iron in Petroleum Oils by XRF. SMS 177: Determination of Hydrogen Sulphide. Density or Relative Density of Gases . Oxygen Flask Combustion Method.EP 2007-3186 . . England. British Standards IP 59: Method C. 61 New Cavendish Street. Supporting Method. SMS 2336: Individual Sulphur Compounds.The Effusion Method. London W1M 8AR. Steam Distillation Method. UOP 800: Vanadium. Absorption Method. Elemental Sulphur. IP 481: Test Method for Determination of Air Saturated Vapor Pressure (ASVP) of Crude Oil. SMS 1769: Wax Content of Petroleum Products. SMS 1553: Water in Gases. SMS 2269: Potential Hydrogen Sulphide in Crude Oils. SMS 2767: Distillation of Heavy Petroleum Residues. SMS 1347: Density of Liquids. and Petroleum Products. Hydrogenation-Microcoulornetric Method. Issued by: The Institute of Petroleum. Potentiometric Titration Method. 235U. and Mercaptans in Organic Liquids. Shell Standards SMS 1329: Water in High Pressure Gases. Nickel. UOP 842: Vanadium. Total Evaporation Method. Reischauer Pycnometer Method. Mercaptans and Carbonyl Sulphide in Gases. Section VIII.EP 2007-3186 . NY 10017. Issued by: American Petroleum institute. Issued by: American Society of Mechanical Engineers. 2101 L Street Northwest. New York. DC 20037. ASME Boiler and Pressure Vessel Code. IATA Dangerous Goods Regulations available from: or: IATA Payload Asia 2000 Peel street 35 Duxton Road Montreal Singapore 0208 Quebec Canada H3A2R4 or: Freight Merchandising Services Green Lane Hounslow Middlesex TW4 6DD England . 345 East 47th Street. USA. ASME Section VIII. USA. Publications and Distributions Section. Recommended Practice for Sampling Petroleum Reservoir Fluids.130 - Restricted American Standards API RP 44. Washington. Dairy Ashford Houston.com Melton Hows Staff Petrophysicist Tel: +1-281-544-4795 Fax: +1-281-544-2176 Melton. Tel: +31 70 447 2193 Fax: +31 70 447 2332 J. Tel: +31-70-447 3792 Fax: +1-504-728 0445 Cell: +31-610-973 792 mohamed.com Matt Flannery Senior Geochemist and Fluid Properties Specialist EPG FEAST Focal Point Shell International Exploration & Production
[email protected]@shell.com Dennis Naafs Subsurface Fluid Property Specialist. 200
[email protected] Peter Cornelisse Senior Flow Assurance Engineer EPA FEAST Focal Point Shell Global Solutions (Malaysia)
[email protected] Mohamed Hashem Formation Sampling & Testing Principal Technical Expert Shell International Exploration & Production
[email protected]@shell. TX
[email protected] Torbjorn Carlson Staff Engineer -Formation Sampling & Testing EPE FEAST Focal Point Shell International Exploration & Production Inc. Tel: +31 70 447 2483 Fax: +31 70 341 2959 Torbjorn.com Artur Stankiewicz Subsurface & Planning Manager Fluid Sampling and Fluid Properties SME Shell Abu Dhabi BV Fax: +971-26148742 Tel: +971-26333640 Artur.Bhd.com Hani Elshahawi Staff Petrophysicist Shell International Exploration & Production Inc. Dairy Ashford Houston. USA Tel: +1 281 544 3780 Cell:+1 504 232 3315 daniel.com
[email protected] Mike Shammai Staff Petrophysicist Tel: +1-281-544-2569 Michael. USA Tel: +1 281 544 8293 matthew. TX
[email protected] 2007-3186 FEAST Contact Details Joe Westrich FEAST Team Leader EPM FEAST Focal Point Shell International Exploration & Production Inc. 200 N. USA Tel: +1 281 544 3638 hani.com Daniel McKinney Reservoir Characterization Staff Geochemist EPW FEAST Focal Point Operational Geochemistry SME Shell International Exploration & Production Inc.131 - Restricted Ed Clarke Fluid Specialist Tel: +31 70 4475873 Fax: +31 70 4472332 Ed. Tel: +60 3 2170 3925 Fax: +60 3 2170 3699
[email protected]@shell. Geochemist EPR FEAST Focal Point Shell International Exploration & Production Inc.flannery@shell. Dairy Ashford Houston. Tel: + 31 70 447 7046 Cell: +31 6 1208 5986 Dennis. TX 77079. 200 N.com . 2 Gases: GPA 2166 3. and D6730 Micro GC. Anal.C12+ Density liquid BS&W (crude) Salt RVP H2S (in crude) TAN Operational Control & Process Density gas Monitoring Water dewpoint in gas Calorific Value Wobbe index Comp C1 – C12+ H2S.1-3. and D 4377 ASTM D 3230 ASTM D 323 SMS 117 ASTM D 664 and D 3339 IP 59 Method C IS0 6327 IS0 6976 IS0 6976 and IP 59 method C ASTM D 3710. D 473. D 5134.2 A3. C1-C30+ H2S.3 4. ASTM D 3710 and SMS 117 IS0 6976 and IP 59 method C. ASTM D 3710.liquid BS&W crude API Preliminary Analysis OBM* and Validation Comp.2 EP 92115 Stable Liquids: ISO 3170 3. and D 5134 ASTM D 1298 ASTM D 96.2 7.4 . and Analyses Data Required Density .gas Comp. and D6730 ASTM D 3710.3-3.5 7.EP 2007-3186 Table 22: Objective . D6730 Micro GC. D 5134.2 Gases: GPA 2166 7. CO2 (in gas) Hydrocarbon dewpoint Sand Custody Transfer Density liquid Water content Salt Analytical References ASTM D 96 ASTM D 1298 ASTM D 1298 ASTM D 3710. Sampling References. EP 91-0703 ASTM D 1298 ASTM D 4377 ASTM D 3230 RVP ASTM D 323 H2S (in crude) TAN Sulphur content TBP Distillation Density gas SMS 117 and 2268 ASTM D 664 and D3339 ASTM D 3516 ASM D 2892 and D 2767 IP 59 Method C / ISO 6976 Sampling References Liquids: ISSO 3170 Relevant Sections 3. Stain tubes. D 5134. CO2 (in gas) Density .2 A3. C1. Stain tubes.132 - Restricted Summary of Data Requirements.) 7.8 LPGs: ISO 4257 (not for comp.2-3.2 Dry Gases: 7. SMS 117 IP 59 Method C ISO 6974.4 Liquids: ISSO 3170 7. 51907 EP 93-1315 8. ASTM D 3710.3 EP 91-0703 ASTM D445 SMS 1769 ASTM D 97 ASTM D 2500.3 and 7. D 5134. and D6730 IS0 6327 IS0 6976 and IP 59 method C.4.EP 2007-3186 Objective Process & Pipeline Design . AMS 259-1 ASTM D 938 Modified IP143 ASTM D2622 and D 3516 ASTM D 7260 ASTM D 664 and D3339 ISO 6327/Panametrics SMS 2336 ISO 6974 ISO 6978 Iso 6978. and D 5134 Micro GC. ASTM D3710.1-7. ASTM D 3233 and D5708 Relevant Sections 5.2 EP 2001-3026 GS.4 8. 7.05.3 GPA 21 66 .SMS117 SMS 2336 ASTM D 3516 ASTM D 3710. D 5134. EP 91-0703 ASTM D 1298 ASTM D 4377 ASTM D 3230 ASTM D 3710. C1 – C30+ H2S (in crude) TBP distillation PVT experiments Kinematic viscosity Dynamic viscosity Wax content Pour point Cloud point Congealing point Asphaltene content Asphaltene behaviour Emulsion properties Total sulphur (liquid) Heavy metal TAN Water dewpoint in gas Nitrogen Helium Hydrogen Mercury ISO 6327/Panametrics ISO 6976 ISO 6974 ISO 6974. Appx 2 7. CO2 (in gas) Nitrogen Sulphur content Comp C1-C30+ Water dewpoint Hydrocarbon dewpoint Density liquid Water content Salt Comp. Stain tubes. and D6730 SMS 117 and 2268 ASM D 2892 and D 2767 GPA 21 66 GPA 21 66 Liquids: Appendix 2.133 - Restricted Data Required Analytical References Sampling References Water in gas Calorific Value Wobbe index Comp C1-C12+ H2S.1-5.3 7. and D6730 Comp C1-C12+ ASTM D 3710.3.1. ASTM D 3710 & SMS 117 Reservoir Studies CCE @ Tres GOR <1.2 Rich gases/ Condensate Split phase sampling 2.750 scf/bbl (medium CCE @130 F and heavy oil) Diff Lib @ Tres EP 91-0703 Sep Test Viscosity @ Pres+Tres Specialised experiments CCE @ Tres CCE @130 F CVD @ Tres Reservoir Studies GOR >1.1. 5.4. A3.3-A3.750 EP 91-0703 Sep Test scf/bbl (gas/condensates) Viscosity @ Pres+Tres Specialized experiments Miscibility Experiments Restricted Sampling References Relevant Sections Dry Gases 7. 5. 3. D6730 TBP Distillation ASM D 2892 and D 2767 Dynamic viscosity ISO 6974 PVT experiments Density gas IP 59 Method C / ISO 6976 Comp C1 – C30+ ASTM D 3710. A3. D 5134.2 and Appx 2 Appendix 2 2. A3. 5. Stain tubes.2.5 GPA 2166 and Appendix 2 2. D6730 H2S.EP 2007-3186 Objective . D 5134. ASTM D 3710 & SMS 117 Comp. Stain tubes.3-A3. 5. CO2 (in gas) Micro GC.2.3.2 EP 91-0703 3.3.5 .3. 3. 5.134 - Data Required Analytical References Radon AMS 780 Polonium210 Polyaromatics Sulphur in gas ASTM D 3516 Density gas IP 59 Method C / ISO 6976 H2S.4 5. C1 – C12+ ASTM D 3710.2. D 5134. 3. 5.2.4. CO2 (in gas) Micro GC.1-A3. Danger.:________________ Date Sampled: _____________ WELL __________________________________________________________ Sampling Point or Vessel ____________________ Depth: ____________ (iii) Sampled By: _______________________ Restricted . Fire . Spleen. .0.2.1. Specific .UN1267 (ii)NFPA: Health . Compressed or Natural Gas (i)COMPRESSED GASES. Skin. Spleen.UN1954 or NATURAL GAS – UN1971 (ii)NFPA: Health . Testicular. Reactivity .4. Specific .0.1.NONE OSHA: Highly Toxic. Blood. Contains Benzene. Immunotoxicity.EP 2007-3186 APPENDIX 1. Lung.135 - EXAMPLES OF ACCEPTABLE SAMPLE LABELS A1. Skin. FLAMMABLE. Embryo/Fetotoxicity.NONE OSHA: Highly Toxic. N. Carcinogen Shell Lab No. Testicular.:________________ Date Sampled: _____________ WELL __________________________________________________________ Closing Pressure ________ PSIG & Temp. Carcinogen Shell Lab No.O.(METHANE) . Immunotoxicity.2.3._______ ºF Sampling Point or Vessel ____________________ Depth: ____________ (iii) Sampled By: _______________________ A1. Eyes. Lung. Fire . Eyes.S. Petroleum Crude Oil (i) PETROLEUM CRUDE OIL . Blood Danger. Reactivity . Embryo/Fetotoxicity. May Contains Benzene. Specific .2.NONE OSHA: Highly Toxic. Spleen.O. Lung.0.:________________ Date Sampled: _____________ WELL __________________________________________________________ Sampling Point or Vessel ____________________ Depth:____________ (iii) Sampled By: _______________________ NOTE: The white area in the labels is required information to adequately identify the sample.o.136 - Restricted A1. Fire .4. Reactivity . Embryo/Fetotoxicity. Specific –if any OSHA: is it toxic. Skin. . Eyes. what target organs may be affected Shell Lab No.(METHANE contains PETROLEUM CRUDE OIL) . Reactivity .3.N.3.(Methane.EP 2007-3186 .________ Date Sampled:__________ WELL __________________________________________________________ Sample Volume _____ Closing Pressure _____ PSIG & Temp. Water (i)WATER SAMPLE (ii) NFPA: Health – 0 to 4. Danger. Testicular. Compressed Gases. Contains Benzene.S.UN1954 (i) COMPRESSED GASES. Blood.0.______ F Outage Volume _____ Closing Pressure _____ PSIG Sampling Point or Vessel ____________________ Depth: ____________ (iii) Sampled By: _______________________ A1.0. contains Petroleum Crude Oil) .s. Fire . FLAMMABLE. Flammable n. Immunotoxicity.UN1954 (ii)NFPA: Health . Carcinogen TYPE SAMPLE: GAS/OIL LAB NO. EP 2007-3186 Table A1.1: - 137 - Restricted Correct International Shipping Classifications and Labelling for Hydrocarbon Samples Type of Sample UN # Correct Shipping Name Class Sub-Risk Hazard Label Technical Name Reservoir Fluid, Separator Oil, Wellhead Sample UN 1965 Hydrocarbon Gas Mixture, Liquified, n.o.s 2.1 n/a Flammable Gas Hydrocarbon Sample with High Octane/Nonane Content Separator Gas Sample, Chromatograph Calibration Gas, Standard-piston Reservoir Sample (e.g., MPSR) of Dry Gas UN 1954 Compressed Gas, Flammable, n.o.s. 2.1 n/a Flammable Gas Methane/Ethane Mixture Separator Gas Sample UN 1964 Hydrocarbon Gas Mixture, Compressed, n.o.s. 2.1 n/a Flammable Gas Methane/Ethane Mixture Pressurised Hydrocarbon with H2S Content UN 1953 Compressed gas, Toxic, Flammable, n.o.s. 2.3 2.1 Toxic Gas and Flammable Gas Pressurised Methane/Ethane with H2S Content Gas Condensate Sample UN 1075 Petroleum Gases, Liquefied or Liquefied Petroleum Gas 2.1 n/a Flammable Gas Methane/Ethane Mixture Separator Gas Sample UN 1971 Methane, Compressed or Natural Gas, Compressed with High Methane Content 2.1 n/a Flammable Gas Methane/Ethane Mixture Standard-piston Reservoir Sample (e.g., MPSR) of Dry Gas UN 3161 Liquefied Gas, Flammable, n.o.s. 2.1 n/a Flammable Gas Methane/Ethane Mixture STO Crude UN 1267 Petroleum Crude Oil 3 n/a Flammable Liquid Petroleum Crude Oil EP 2007-3186 APPENDIX 2. - 138 - Restricted PVT TESTS AND CORRELATIONS (FOR PRIMARY RECOVERY) Accurate and reliable phase behaviour and volumetric data are essential for the management of hydrocarbon reservoirs. Phase behaviour and volumetric data are usually obtained through standard laboratory processes. During the depletion process, reservoir pressure usually declines while reservoir temperature stays constant. Therefore, pressure is the main variable that affects the fluid properties and the volumetric behaviour under primary depletion conditions. Therefore, laboratory tests are performed by varying the pressure. In general, PVT tests are fluid-type specific and they are assured to mimic the in-situ depletion processes. While allowing a composition path dictated by reservoir depletion process, these experiments are also expected to produce coherent data for routine surface separation. Empirical correlations and charts are used when PVT data are not available. Empirical correlations can be used for comparing the available data against an established trend, data smoothing, etc. PVT Tests (Experiments) PVT tests are intended to study and quantify the phase behaviour of reservoir fluids at the presumed recovery conditions. The effects of water present in the reservoir are ignored for most of the cases. Most of the tests are designed to capture the depletion characteristics of the reservoir fluids only. Typically, the pressure is lowered and some of the properties like density, viscosity, etc. are measured. The pressure at which the second phase is formed is also recorded (saturation pressure). A2.1. Black Oil When the pressure drops bellow the bubble point pressure, gas dissolved in oil (solution gas, gas in solution) will come out of solution. The gas liberated from the oil will not flow until it reaches so-called critical gas saturation, S gc (typically 5%). The gas will form in discrete bubbles in each separate pore space until the critical saturation is exceeded. When the gas in the neighbouring pores unites it begins to move. Since the gas viscosity is much smaller than that of the liquid phase (oil), it is assumed to move away from the oil phase rather quickly. Many times this leads to secondary gas cap formation. oil Pi Pbp Pwf r EP 2007-3186 - 139 - Restricted A2.2. Differential Liberation Experiment The process, as explained above, is approximated by differential liberation experiment. In differential liberation experiment, the cell pressure is reduced below the bubble point pressure by expanding the system volume. Liberated gas, during the process, is removed from the cell under constant pressure. This process is repeated for 6-20 pressure steps. At each pressure reduction step, liberated gas is displaced from the cell and its volume and composition determined. Final pressure step of differential liberation process is always equal to the ambient pressure (i.e., 14.696 psi). The following must be reported • oil formation volume factor • solution gas-oil ratio (differentially liberated gas) • compressibility factor • gas formation volume factor • gas gravity • composition of liberated gases (ISO 6974) • reservoir fluid density • residual oil gravity and composition After the final pressure reduction step and bringing the sample to stock tank temperature the composition and properties of the stock tank liquid are determined. Compressibility factor Z is calculated from: Z= VPTsc (Z sc ≅ 1) Vsc Psc T Where V is the expelled gas volume at P and T. Gas formation volume factor (B g ) is calculated once the Z factor is known: Bg = Vreservoir T Psc =Z Vsc Tsc P The remaining oil volume at the end of the test (P = Patm ) is converted to the volume at 15.5°C (60°F). The conversion usually assumes an average thermal expansion coefficient (i.e., 0.00046 (V/V)/°F). This remaining oil is often referred to as residual oil. The volume of oil at each stage is scaled by the relative oil volume. Bod = Volume of oil at P and T Volume of residual oil The total volume of gas liberated at each depletion step including all the previous steps are converted to the volume at the test pressure, and added to oil the oil volume to obtain the total volume. Total volume is also scaled by the residual oil volume. Btd = Total volume Volume of residual oil EP 2007-3186 - 140 - Restricted Liberated gas is reported by the solution gas oil ratio (Solution GOR), Rsd.Rsd is defined as the difference between the total gas evolved at the atmospheric pressure (the final stage of the differential liberation experiment) and each pressure level, P, divided by the residual oil volume. Rsd = Total gas @ 14.7psia Total gas evolved at P Residual oil volume The laboratory data is often smoothed and extrapolated by using a dimensionless function of compressibility curve. In the petroleum engineering literature it is known as the “Y-function”. Y= Pbp − P ⎡V ⎤ P ⎢ t − 1⎥ ⎢⎣Vbp ⎥⎦ Vt is relative total volume at pressure P Vbp The Y-function is usually linear when plotted against pressure. Relative volume data can also be ⎛ smoothed by plotting log⎜⎜1 − ⎝ Bo @ P Bo @ Pbp ⎞ ⎟ versus log Pbp − P ⎟ ⎠ ( ). This relation is also linear or near linear (This is also known as Hurst Method). Y-function may exhibit erratic behaviour around bubble point pressure due to potential measurement errors. A2.3. Separator Test(s) / Separator Flash Test(s) A measured quantity of (re-combined) reservoir fluid is pumped (with a calibrated positive displacement pump) into a visual cell. The pressure and temperature of the cell are maintained at the equivalent to the likely first stage separator pressure and temperature in future facility operations (to be provided by the production or facility engineer). In the separator test, known volume of fluid (could be oil or condensate) is flashed in specified number of steps. Generally, the last stage always represents the stock tank conditions. Stock tank conditions do not have to be standard conditions (101.3 kPa (14.695 psi) and 15.5°C (60°F)). Stock tank conditions are usually at P = Pambient (103.6 kPa (15.025 psi) in our region / Gulf Coast), and T = Tambient (a typical regional, yet somewhat average temperature). For the laboratory experiments, Tambient usually corresponds to the steady room temperature recorded at the laboratory (i.e., 68-75 F). Separator tests are usually conducted at a number of stages. Generally, the main objective is to minimize the gas evolved from the oil and maximize the oil API. Therefore, total # of stages will be determined by: • Approaching the objective (max. API, min. solution gas) • Hardware in hand: It is hard to arbitrarily define the operating conditions. In many instances an analysis to C16+ would be beneficial & should be ordered..696 psi) o Composition and the specific gravity of the flashed gases (at every stage) o Composition to C30+ including individual aromatics and inerts (ISO 6974 ) o Total molar mass o Gas density o Tank oil density o Tank oil viscosity (not always required) o GOR (v/v and molar ratio) o Separator volume factor o Formation volume factor from bubble point to standard conditions and from reservoir pressure to standard conditions o Hoffman et al. Based on the direct measurements: • Bo • Rs can be calculated The final outcome of the separator test is a function of the number of separator stages and the operating conditions of the separators.EP 2007-3186 . C7+) can further be processed to extract / liquefy their intermediate components.141 - Restricted • “Tie-in” constraints: sometimes our intermediate step should correspond to the conditions at which the fluids are collected. • Operating conditions of one of the stages may have to be fixed due to trapping some unwanted substances / components.. (i. Using the compositional data. see the example PVT reports distributed). C2 and N2. the lines might be tied into an existing facility / pipeline operating at P and T that we may not have control over. the amount of these components can also be expressed in terms of . C2 to C6 and the plus fraction. which are rich in intermediate hydrocarbon components. or Buckley/Campbell plot o Volume of the flash gas at every stage Note: Compositional analysis to C8+ is a minimum requirement. • In separator tests. Regardless of the number of the stages stock tank oil tends to contain very small amounts light-ends (CH4. Separator gases. etc. the following parameters are measured for the gas and the liquid at each separator stage (including the tank) and should be reported: o Volume of the reservoir fluid at Psat o Volume and specific gravity of the stock tank oil at Standard Conditions 15.e. For example. • Operational / Practical constraints • It is not practical to select many (usually more than four) separator steps just because our objective function is satisfied a bit better.5°C and 1 Atm (60°F and 14. The liquid specific gravity of all the hydrocarbon components are normally tabulated in books and as well as at the appendix of most PVT reports.3151 y i M i gal γ oi MSCF where γoi is the specific gravity of the component as a liquid at standard conditions (γwater =1) Mi is the molecular weight and γi is the mole fraction of the subject component .6638e. Special caution is / should be taken at the saturation pressure. Following the initial pressurization. while for black oils pressure versus volume plot is sufficient to reveal the bubble point in sufficient accuracy. The following measurement are made during the CCE experiments: • Initial mass in the cell • Pressure versus cell volume • Volume of the liquid at the bottom of the cell (for condensates. the cell pressure is reduced gradually by increasing the volume of the cell stepwise. Again the objective of the separator test is to produce the maximum amount of liquid (min Bo). For example the specific gravity of ethane is 0. cell is agitated to ensure that the contents are at equilibrium. which translates into maximum API and minimum total gas-oil-ratio (GOR). a known amount of live (re-combined) reservoir fluid sample is conditioned to reservoir temperature and a pressure ±2. The pressure at which the slope of the P-V plot changes is the bubble point pressure .142 - Restricted gallons per thousand standard cubic feet of gas or GPM. the following parameters can be calculated / reported • Relative volume (V @ P/ V @ Psat) • Density (Mass/Total volume): density below the saturation pressure will be the average fluid density • Single-Phase Compressibility • Liquid % (dropout): Volume of the liquid at P divided by the volume at the saturation pressure.3562 and the specific gravity of nC6 is 0. this experiment is sometimes referred to as “flash vaporization / liberation / expansion experiment”. A2. and near-critical fluids only) Based on the measurement above. For every step of pressure change.500 kPa (362. for condensates and near critical fluids.4.7 psi) above reservoir pressure. No fluid is removed from the cell during the experiment (hence the occasional reference to this experiment as CME). This is typically required / requested for condensates unless otherwise the lab is specifically instructed. visual observation is often required.EP 2007-3186 . In CCE experiment. Constant Composition Expansion (CCE) or Constant Mass Expansion (CME) Experiment In older reports/books. GPM (or plant products) of a particular component is calculated from: GPM i = 0. the test is always started from the dew point pressure (for simplicity). After stabilizing at each pressure reduction step the volume of the cell is returned to its original value at constant pressure by displacing some of the gas phase from the cell.C8. Condensate properties can be calculated at the other pressure stages by utilizing the cell material balance. dropped out in pore space.ISO 6974) • molar mass of C7+ in produced gas • volume of gas produced • residual liquid composition and density • gas compressibility factor • two phase compressibility factor The gas sample displaced may also be flashed through a two-stage separation to stock tank conditions to simulate condensate yield at each pressure depletion stage. Note that the properties of the liquid phase at the bottom of the cell are not measured during the experiments (except the last stage). the cell volume at the dew point pressure is kept constant during the test. It is commonly assumed that the condensate. The final pressure reduction step will take the sample to stock tank conditions (or standard conditions) where upon the composition of the remaining liquid must be determined. At each stage. It is possible to measure the density of liquid-vapour . All volumetric data reported are to be referenced to the volume of the sample at the dew point pressure. Z factor and the composition of the expelled gas is measured. the amount. During each step enough gas is expelled to the level at which the original cell volume is retained (cell volume is constant). The volume of gas displaced from the cell is measured accurately along with the liquid remaining. The pressure in the cell is lowered by bleeding the gas from the top.EP 2007-3186 . A volume of reservoir fluid is charged to a pressure ±2. Since the composition of the system is fixed. % • composition of produced gas (C1 .143 - Restricted A2.500 kPa (362. the constant volume depletion test may also prove useful for these as well.7 psi) above saturation pressure. Again the liquid volume is scaled to the volume of the dew point pressure. In other words. The following should be reported at each step: • Liq. One of the most important parameters measured during the test is the % liquid dropout (similar to CCE). The pressure is then reduced in about 10 even steps at constant temperature (to an assumed abandonment pressure).5. The volume at the dew point pressure is used as a reference similar to the other expansion experiments. aromatics and inerts . Although it is not strictly applicable to reservoirs containing volatile oils. Constant Volume Depletion (CVD) Experiment This test is to be used for primarily for gas gas/condensate systems and simulates the production of gas from a condensate reservoir while leaving behind the liquids (once the reservoir is depleted below its dew point). remains immobile (that’s why only gas is removed /produced from the cell). API. the dew point measurement could be more accurate then the lean gas condensates. Black oil correlations tend to be unreliable for volatile oils (high GOR oils). and South America) • Vasquez and Beggs ( Bo and Rs correlations are developed 6004 data points) • Glaso (45 oils from North Sea) • Marhoun (160 Pbp data on 69 Middle Eastern crudes) • Petrosky-Farshad (For primarily GOM.EP 2007-3186 . (i. some of the volatile oil reservoirs can be operated like condensate reservoirs. used different ± of data points for volumetric properties and the viscosity correlation) . These properties are widely used in petroleum engineering and known as “Black Oil Properties. In such cases the fluid may be identified as volatile/near critical oil. Taking the argument from this point.e. In very rich condensate systems sometimes.” Black oil properties are normally measured in the laboratory. quotas on oil production will not apply to condensates).144 - Restricted in equilibrium by direct samplings and the densities can be measured in-situ by oscillating tube densitometer. In most cases. Notes on Dew Point Pressure / Phase Identification In rich gas condensates (i. Correlations are widely used in those cases. Black Oil Correlations (PVT Properties) Formation volume factor (Bo Bw B g ) solution gas-oil ratio (Rs ) and solution-gas ratio (rs ) are typical volumetric quantities that are used to simplify engineering calculations..6. Their main functionality is to enable the engineer to uses the standard volumes of oil and gas and water in material balance equations. Although depletion characteristics of both fluids might be very similar/same (from practical point of view). the economical and/or political impact might be very critical. Western and Mid-Continental U. However.e. close to their critical temperatures). the initial liquid build-up is gradual.. Therefore. the amount of liquid that dropped in the cell (after the first stop below the dew point pressure) may exceed 50% of the cell volume. since a large amount of gas condensate can drop just below the dew point pressure. for some cases. An accurate prediction of the volumetric behaviour of complex multicomponent systems with only a few parameters should not be expected. Pbp or Rs and Tres . Black oil correlations are the outcome of simple repression on members of data points.S. Black oil correlations are designed to use maximum amount of data. A2. Geographical biases of some of the commonly used correlations are as follows: • Standing (105 data points on 22 crudes from California) • Lasater (158 Pbp data on 137 crudes from Canada. The main input parameters are γ g . the observed dew point might be subjective. During the operation/production phase gas recycling and pressurization /depressurisation cycles can help vaporizing the liquid phase into the gas phase. such data may not be available to the engineer. EP 2007-3186 • . Bo (BBL/STB) 2. typically for the gas phase: Gas Formation Volume Factor P . Watch for what “standard/base pressures” are used for the gas volumes.6 kPa (15.696 or approximately 101.3 kPa (14. California 101.696 psia) Ambient Pressure versus Standard Conditions In general 14.73 psia) See page 166 of McCain for the full table for the regional ambient pressures.65 psia). STB STB BBL Mixed units are also used. but it is still often indicated to remind us the relevant conditions.3 kPa (14.145 - Restricted Dindoruk-Christman (For GOM – extended range correlations & applicable to deepwater prospects as well) Most of the correlations mentioned above and as well as QC tools and many other utilities are implemented in PVT-Calculator.5 kPa (14.7 psia). P= 101.0 1. Formation Volume Factor (B) B= Volume occupied at reservoir conditions Volume occupied at standard conditions Oil Formation Volume Factor(Bo) Bo = Volume of oil at reservoir conditions Volume of oil at standard conditions unit = dimensionless.0 Pbp BBL RB RB . Alaska 101 kPa (14. In Texas/GOM area it is 103. Some Definitions Standard Conditions (SC) T = 15.5°C (60°F).025 psia). . 5 Rs .EP 2007-3186 . etc. SCF SCF MSCF MSCF For B g .97 ≅ MWg 29 Specific gravity of oil ( γ o ) γ o = relative density to water at 60°F.146 - Restricted B g could have the units of ft 3 BBL ft 3 RB or or or .0 1. In other words. real gas law can be utilized: Bg = 5. Bo .02 ZT RB P MSCF Gas solubility / Solution Gas Oil Ratio Rs Rs = Volume of dissolved gas at standard conditions Volume of the residue oil at standard conditions Bo (BBL/STB) 2. the path followed from reservoir conditions to stock tank conditions (or standard conditions) matters! . γ g are process dependent quantities. . γ o .API is more commonly used API = 141.0 Pbp P Typical units for Rs are SCF MSCF STB . etc… STB STB STB Specific gravity of gas ( γ g ) γg = MW g MWair = MWg 28.5 γo − 131. . Jr.147 - References: Danesh. A.. 1990 (PennWell). The Properties of Petroleum Fluids. 1998 (Elsevier).EP 2007-3186 . PVT and Phase Behaviour of Petroleum Reservoir Fluids. D.. Restricted . McCain.. W. 00E-04 2.562 1.000 5.615 1.810 8.1 0.000 500.000 5.0561 0.1 20 112 50 281 100 561 200 1.2 5 28.000 178 1.178 1 1 5.7.000. this table should be consulted.0281 0.00E-04 1.12E-04 2.000 1.05 0.000 100.294 .781 891 356 178 89.0011 0.61E-04 0.6 17.78 10 0.000 17.891 5 0. Table A2.105 89.810 100.02 0.112 0.005 0.000 3.148 - Restricted A2.281 0.561 1.000 50.000 56.562 20.621 17.61E-05 1.781 10.001 5.00E-04 5.1 35.052 35.000 112.2 0. however where omissions may have occurred.0 0.1 10 56.1: Volume Ratios Condensate: Gas (CGR) bbl/mmscf 1 5 10 20 50 100 200 500 1.905 3.229 5.EP 2007-3186 .56 20 1.000 356 2.123 500 2.000 20.91 50 3.00281 0.000 8.000 200.81E-05 5.81E-04 5. Conversion Tables Every effort has been made to present both SI and Field (or US) units in this document.000 1.000 891 5.000 35.5 0.00561 0.000 11.000 89.147 20.01 0.000 10.6 200 17.905 50.002 0.000.807 5.8 100 8.073 10.356 2 0.00E-05 Gas: Oil or Liquid(GOR or GLR) m3/m3 scf/bbl 178.807 1.6146 2 11.1 500 35.000 2.000 28.615 2.000 178.91 m3/m3 5.0112 0.61E-06 2.123 2.621 200.8 8.105 1. 6 60 26.4536 1 inches 0.000 Table A2.6146 bbl 1.0 E-06 0.00629 0.6 1.7 5 41 10 50 15.08333 1 3.4 10 20 32 40 psi 1.3937 1 12 39.03937 0.527E-05 0.59E-07 0.3 200 100 212 149 300 200 392 .00220 0.000264 0.54 30.2 -6.11 8 59.02381 0.03527 1 16 35.8 336 litre 0.27 lb 2.8 0 oz 3.003281 0.1337 1 5.7 0 4.0353 0.001 0.0625 1 2.03281 0.4 1.7 80 atm 9.000473 0.000 Table A2.3048 1 Distance mm 1 10 25.0075 1 51.3: g 0.281 m 0.000 28.0013 0.6: °C °F -17.264 1 7.000001 0.8 100 50 122 93.48 100 cm3 or ml 1 473.20 kg 0.EP 2007-3186 Table A2.7 760 Temperature (°C= 5/9 x (°F-32)) -12.53E-05 0.02832 0.5: Pa 1 133.125 0.35 453.0680 1 37.4: Restricted Volume pint 0.0254 0.0167 0.592.37 ft 0.2 1000 3785 28317 158987 Table A2.003785 0.149 - Mass mg 1 1.45E-04 0.001 1 28.02835 0.8 1.001 0.349.32 159 gallon 0.001 0.4732 1 3.02 1 14.205E-06 0.17811 1 m3 1.76 101325 Table A2.000.00298 0.4 304.785 28.32 6894.000 cm 0.002 1 2.1 1 2.001 0.01 0.52 453.2: .87E-06 0.48 42 scf 3.159 Pressure mmHg 0. EP 2007-3186 APPENDIX 3. updated as necessary Livelink/swwus-ep-livelink.150 - Restricted SURFACE SAMPLING PROCEDURES Shell standard step-by-step procedures for sampling are constantly being improved and updated as well fittings and sampling equipment and regulations change. this site details the most up-to-date protocols. intended to remain an “evergreen” site. . At the time of printing.shell.com (online)/Enterprise Workspace/NetworksCommunities/Fluids Surveillance Network/Protocols . fluid density. which will advise on which sample(s) to perform subsequent work. samples should be maintained at Tres.6 kPa (200 psi) below the FBHP then measure CGR and CCE of sample 2. a. etc) • Viscosity of Stock Tank Condensate . 2. Proceed with CGR. .If this cylinder also shows unacceptable Psat then the project focal point will advise which of the 3 cylinders to proceed with. It is not intended as a requirement and any project should have a sampling program tailored to requirements. Downhole (Wireline and DST) Samples Contracted PVT analyses (off-site): • Validation followed by Restoration of prioritised cylinders for 24 hours at reservoir P&T • Single-phase composition (C12+ for gas and C36+ for condensate) • CGR/ GOR including API. Z. Opening pressure at ambient T b. and CCE measurements on cylinders #1 and #3. liq dropout %. single and two phase Z. dew point. Once restored. Check with the relevant Shell sampling specialists to confirm suitability for particular projects.EP 2007-3186 .. if highest Psat is more than 1378. Restoration of all cylinders of interest at Pres & Tres for a minimum of 48 hrs. CCE should include 2-3 pressure points between dew point pressure and first estimated CVD depletion pressure. GPM. Conversely if both cylinders show Psat > Pres then measure CGR and CCE of cylinder #2. it is assumed that three cylinders have been taken at each target zone. However. RLD) • CVD (percent fluid produced. fluid Density. produced gas compositions. RLD.per point 1. General strategy is as follows: a. If one or both of the cylinders shows Psat<Pres then pick the sample with the highest Psat < Pres. liq dropout %. Restricted EXAMPLE OFF-SITE HANDLING AND PVT PROGRAMS This is a suggested typical sampling program for downhole (wireline and DST) samples. Report CCE and dew point results to project focal point. Restoration and validation in on-shore lab of priority samples comprising sample pairs #1 and #3 from each zone.1. calculated gas viscosity. and flash conditions • Dew point pressure at Tres • CCE at Tres and Tlow (Pd.151 - APPENDIX 4. A4. b. 3. Based on existing compositional data from well-site lab set priorities and order of analyses. In this example. Bg. RV. Heat content xi. i. ii. Compositions of produced gas up to C12+ iii. Gas volume factor viii. C10+ and C12+ v.4°C (130 °F) d.152 - Restricted c. Liquid measurements will include cryscopic MW ii. Residual liquid composition (to C36+. CCE at 54. to ensure adequate liquid drainage. Done after completion of the PVT program when the samples are blown down to generate the necessary liquid volumes. but particularly after the first few depletions. Composition for liquid (up to C36+) and gas (at least to C12+). Percent initial reservoir fluid produced. Calculated cumulative recovery during depletion f. NL. or Isotech. iii. Properties of C7+. Subsequent Test program will consist of: i. Gas viscosity ix. Condensate viscosity at ambient conditions – on each sampling point (total 6). (receiver vessel). x. Constant Volume Depletion Experiment (at Tres). Collect in NGB at 1033. All compositions will list BTEX breakouts. . Collection of solution gas for isotope geochemical analyses in Isolab. Immediately send to Shell designated lab e.9 kPa (150 psi) following Shell procedures from the cylinder selected by the project focal point’s coordinator. US: i. g. Retrograde condensation during depletion. Separator Test(s): If enough sample. GPM content of produced well stream vi. Reservoir fluid Z-factor and two-phase Z-factor vii. CVD with minimum 7 pressure depletion steps.EP 2007-3186 . If enough liquid. Hydrocarbon analyses of produced well stream: ii. Sufficient equilibration time must be allowed at each point. This is “secondary” to other PVT experiments @ reservoir conditions. or at least C30+) and if possible MW iv. liquid hydrocarbons plus air content • Gas Composition to C12+ (including BTEX and gas density) • Composition of Separator liquid (C12+ for gas and C36+ for condensate) Includes BTEX. DST Surface Samples This is a suggested typical sampling program for surface (separator and wellhead) samples.2. • Shrinkage measurement and sep liquid flash products • Recombination-check. • Equilibrium check/ consistency of data using a K-value or Buckley/Campbell plot • Composition of Recombined sample (C12+ for gas and C36+ for condensate) • Separator liquid density measurement at separator conditions. single-phase and two-phase Z-factor. etc) • Viscosity of Stock Tank Condensate . hydrocarbon volume. water.per point • Adjustment of Psat by adjusting the recombination CGR .153 - Restricted In general. opening pressure. Bg. Simulated Separator test (1 stage + tank) with compositions iii. A4. Pb at Tsep • Quality check on Separator gas sample -Heat to Tsep. fluid Density. Especially if the volumes are not available. Summary of Contracted PVT analyses (off-site): • Quality check on Separator liquid sample . i. GPM. RLD. (done by the vendor without calibration). Z. It is not intended as a requirement and any project should have a sampling program tailored to requirements. with the right “disclaimers/footnotes” it is not a bad idea. fluid produced. Compositions. the simulated composition is not required. Experimental Separator test (1stage + tank) with compositions (only if volumes of fluids allow). RLD) • CVD (liq %. Check with the relevant Shell sampling specialists to confirm suitability for particular projects. • CGR/ GOR including API and MW • Recombination up to Separator condition (Physical recombination) • Dew point • CCE at Tres (liq %. gas viscosity.water. RV. Pd. CGR/ GOR including API. For the simulated sep test compositions etc. only the most straightforward and less prone to experimental errors type of sep tests is recommend. fluid density.EP 2007-3186 . Additional Separator stage (Simulated) Note mud filtrate content of all samples at blow down. ii. compositions. Stable gas and liquid flow rates. The Shell representative will then determine the appropriate recombination-pairings and conditions. Separator liquid dumping should be avoided during the 3 hour sampling period. iii. Samples will be sent to the Shell-designated PVT lab. 3 x 600 cc NSB per DST for condensate. Lowest possible BS&W (<5% or better). Samples for PVT taken 3 times. Stable wellhead pressure. Sub samples should then be taken and their compositions determined (C15+ for gas. . iv.154 - Restricted 1. The following criteria must be attained before sampling: i. b.16 hrs in the main flow period: i.16 hrs after the start of the main flow period (varies depending on expected clean-up time). 2. v. Fg. separator rate reported along with assumed meter factors. Quantity.EP 2007-3186 . ii. Sample acquisition during DST operations: a. every 1 hour after approx. Gas and condensate sampled at the same time ii. 3. and oil shrinkage. 3 x 20L GSB per DST for gas. Data from separator gauges and Oilphase gauges must be reported. Stable separator pressure and temperature iii. Fpv. Sampling should begin approx. d. P&T. C30+ for oil) and reported to Shell.(only 1 GSB per condensate sample) c. Gas and oil PVT samples should be restored for a minimum of 48 hours. Gas and condensate samples will be taken at the same time. (1989) National Association of Corrosion Engineers (NACE) ‘Methods for determining water quality for subsurface injection using membrane filters’ American Petroleum Institute Recommended Practice No. handled. All the analytical results obtained from the analyses are dependent on how the sample was obtained. 45 . . Assuming that the standard procedures were followed and appropriate precautions were taken. with an aliquot retained for future use. • Total Organic Carbon (TOC) • Dissolved Organic Carbon (DOC) -Standard methods3. SM5210 • Chemical Oxygen demand (COD) -Standard methods3. the following parameters should also be measured. 17th ed. Analysis Parameters Please note temperature and pressure of analysis conditions.3. They are essential from a reservoir souring analysis perspective. ~0. Water samples saved for long-term storage are maintained frozen in order to minimize potential alterations. For interpretation of the results of these measurements from a reservoir souring perspective.1. for produced water disposal and produced water reinjection applications this is not needed) • Turbidity -Using Hach 2100A or 2100P turbidity meters • Dissolved Oxygen (DO) -Standard methods1. Regardless of the method of collection. SM 4500-O. SM 5220 • Total Suspended Solids (TSS) 01-73 -Standard methods3.3. please contact the Water to Value team (EPT-AWW).2-0. it is recommended that an aliquot (~100-200 ml. SM 5310 The gas phase associated with the produced water sample should also be analysed for CO2 and H2S. In addition to Section 1. ICP) and also wet chemistry (including sample prep. Chemetrics kit • Biological Oxygen demand (BOD) -Standard methods3. The present procedures utilized in the US include immediate analysis of waters after blow down.4 pt) be saved for future use. SM 2540D or NACE ii TM- • Oil-in-water -ASTM D3921-96 or API RP iii 45 • Dissolved H2S -Hach and Chemetrics kits -Standard methods i .EP 2007-3186 APPENDIX 5.155 - Restricted ADDITIONAL WATER ANALYSES It is recommended that any detailed water evaluation plan be developed with consultation of the relevant Shell experts. titration and colorimetry). SM (only when assessing produced water handling issues. and preserved and whether the appropriate analytical procedures were adhered to rigorously. i ii iii Standard Methods for the examination of water and wastewater. The lab analysis should be conducted and reviewed by a person well versed in analytical chemistry with experience in ion chromatography and/or atomic emission spectroscopy (also. techniques. then the quality of the analytical results obtained is dependent on analytical protocols followed. A5.3.6 and Section 3. Evaluation of Bacterial Activity In many cases. 6-10μm.EP 2007-3186 . 100 ml. • Coulter counter • Laser particle analyser • Plankton analysis types of plankton dominate? Hard bodied. soft bodied? Waxy? • Light microscopy • Electron microscopy • Filtration tests • Cerini Plots – Flow rate in ml/s against cumulative volume • Barkman Davidson Plots – Cumulative volume against √time • Bacteria • Filter concentration tests to enumerate SRB (10 ml.156 - Restricted A5. 2-5μm. typical ranges are < 2μm. 10000 ml) • Most probable number serial dilution tests for GHB . • Particle size analysis. 1000 ml.2. the following data should also be measured in order to assess whether the water supports sustained sulphate reducing bacteria (SRB) growth failing which can have a significant impact from a reservoir souring perspective. Procedures for handling a pressurized water sample are outlined in A6. and procedures themselves were revised in cooperation with (and with input from) Oilphase and D.g.1 (“standard flash” liquid for asphaltene-related measurements and gas samples for geochemical analysis) and A6. There are three possible alternatives for obtaining stock-tank oils for asphaltene work: (1) a goodquality MPSR is collected specifically for asphaltene stability measurements (as recommended in this report). For fluid samples from drier gas reservoirs (CGR < ~50 bbl/MMscf).2 are specifically for wet gas (CGR > ~50 bbl/MMscf) and black-oil reservoirs. it is recommended that a small amount (5-30 cm3) of stock tank liquid is flashed from each cylinder (by a procedure like that outlined below) and subjected to simple tests such as API gravity. Also included in this section is the procedure required to obtain a gas sample for geochemistry.157 - Restricted LIVE SAMPLE PROCESSING AT THE PVT LAB Specific bleed-down and transfer procedures are detailed below in A6.For any questions about these procedures. SSB). whenever possible. it is not practical to use this method to obtain the large volume of stock-tank oil needed for wax-related analyses if the PVT bottles have been in storage or were kept at ambient conditions for a long time.2 (“heated” samples for wax-related measurements and “unheated” liquid samples for geochemistry work). please contact any one of the core members of FEAST Team (Fluid Evaluation and Stability Testing). This is sometimes called an “isobaric displacement.1. It is recommended. all schematics. . B. To check on sample quality/representativeness. which should be taken care of at the same time. Based on all of the tests performed. A flash GOR also is measured. the procedure in A6. The procedures in A6. . asphaltene %. to collect enough “standard flash” liquid for both asphaltene screen and geochemical work and.3 is used to obtain an “unheated” liquid sample that can be used for all stock tank oil measurements. In carrying out this procedure.” or “push-off” sample. The “standard flash” may be considered as universal and the sample obtained can be used for any stock-tank oil measurement. a representative stock-tank liquid sample is obtained without compromising or fractionating the remaining pressurized sample. or (3) a MPSR sample is not available and a suitable sample for asphaltene work needs to be obtained from a 600 cm3 PVT cylinder (after transfer from MRSC).” “standard flash. a good-quality PVT sample should be identified and set aside for all asphaltene-related analyses and experiments. A6. for the wax work as well.1 and A6. photos of the transfer procedures.4. Robinson PVT laboratories). and drilling fluid contamination determination. a number of PVT cylinders commonly are available from a specific depth interval. “Standard Flash” Procedure for Processing Pressurized Fluid Samples for Asphaltene Measurements and for Obtaining Gas Samples for Geochemistry Overview The procedure outlined here is the same procedure used by PVT labs to obtain a stock-tank liquid via a single-stage flash to standard conditions (In fact.EP 2007-3186 APPENDIX 6. if sample volumes permit.. However. (2) Oilphase’ SPMC bottles are used for downhole sampling and transferred above the Pres into single-phase bottles (e. In the latter case. water content. 5 pt) of live fluid in the same cylinder for possible depressurisation experiments pending the results of the asphaltene screening tests. Canada. and cylinder number).1) 1. Both DBR and Oilphase offer the SDS (solid detection system) live-oil stability screening as a part of the PVT package at discounted prices.g.158 - Restricted Standard Flash Liquid for Asphaltene Screens (General Comments) 1. 2. well. SSB). Send the “standard flash” dead-oil sample to BTC in Houston or appropriate OU lab. For either MPSR or other PVT cylinders (e. the dead-oil sample for asphaltene screening work should be the first sample removed from the pressurized cylinder. sampling date. and be sure the type of sample is clearly printed on the sample bottle.. or CSB) at reservoir temperature and a pressure above the reservoir pressure. 2. it is recommended that the logging number (Shell ID# or other appropriate log) be preassigned to the sample and forwarded to the PVT lab. USA or Edmonton. P-value.3 kPa (1500 psi) above the original reservoir pressure (after checking the working pressure of the cylinder!). let the conditioning process last a week.1 and connect the pre-charge side of the sampling cylinder to a positive-displacement pump through valve V1. In such cases.EP 2007-3186 . Equilibrate the cylinder at reservoir temperature and pressure equal to or greater than reservoir pressure. and FPA). The equilibration should be by heating the sample and maintaining it at the above conditions and continuously rocking it in a stand for 5 to 7 days (as required). 6. 3. or Oilphase. 5. Keep the sample cylinder vertical (sample side facing up) and connect a liquid trap (T) to the sample side of the cylinder through a high-precision controlled valve (V2). Mount the sample as shown in Figure A6. Equilibrate the subsurface sample (MPSR. PVT labs performing standard flash can be contacted and requested to forward subsamples directly to the vendor lab for SARA analysis and to WTC. Our preferred contract lab for live-oil depressurisation work is DBR in Houston. SSB. especially for light oils with relatively low asphaltene contents.Maintain the pressure in the sample cylinder at least 10339. Enough sample should be flashed to obtain 50–60 ml (1/10-1/8 pt) of stock-tank liquid for asphaltene stability screening tests (e. . Retain a minimum of 50–250 ml (0. SARA. Houston.g. The sample should be maintained at these conditions for at least 2 days (recommended 5–7 days). it is recommended that this option be considered when dealing with black oils (350–500 ml (1 pt) of live fluid is preferred). 4. Steps for Obtaining Stock Tank Liquid Sample for Asphaltene-Related Measurements (Figure A6.1-0. block. depth. thus.. If time and costs permit. along with other sample identification information (field. Flash a sample of the fluid to ambient conditions while maintaining the temperature and pressure used to condition the fluid in the cylinder. slowly open the valve V4 in a controlled fashion. The process should be continued until the required volume of stock-tank liquid is collected (in volumetric flask) at the bottom of the trap. The stock tank liquid collects at the bottom of the trap. and if you are interested in the C4–C6 fraction.g. a mixture of ice and acetone). 5. . you may consider cooling the sample before opening and sub-sampling for analysis. whereas the gas is vented to the atmosphere.1).EP 2007-3186 . This could result in incorrect compositions and GOR’s. This should cut down on the loss of these very volatile light ends. For the cold condensates. Minimize the time the bottle is left open. 6. Two pressure gauges are mounted on both sides of the sample cylinder to confirm the pressure at all times (Figure A6.. the liquid samples should be kept in sealed containers that can withstand some pressure. to flash the liquid into T. NOTE: Cooling to sub-ambient conditions should be performed only for lean condensates (50 bbl or less) due to the possibility of losing C4–C7 components when the fluid warms to ambient before analysis.159 - Restricted 3. the pressure will go up in the bottle. Immerse the liquid trap (T) in a cold bath (e. While maintaining the pressure inside the cylinder at the original value (by continuously operating the pump). As the sample heats. 4. 160 - Diagram for obtaining stock-tank liquid for asphaltene measurements. Restricted .EP 2007-3186 Figure A6.1: . 2.500 psi) above the original reservoir pressure (after checking the working pressure of the cylinder!).339. SS tubing as shown in Figure A6. or CSB) at reservoir temperature and a pressure above the reservoir pressure. 6.Maintain the pressure in the sample cylinder at least 10. While heating.2) 1. Connect the positive displacement pump to the pre-charge side of the buffer cylinder as shown. Once the tubing is pressurized to the cylinder pressure. slowly open valve V3. high-pressure SS tubing (as shown in Figure A6. . (for collection of the gas sample) to the buffer cylinder using 1/8 in.2) next to the sample cylinder. 5. 7. Allow sufficient time to stabilize the temperature of the buffer cylinder before starting the sample transfer. 8. Connect the sample side of the sample cylinder to the sample side of the buffer cylinder through a pressure gauge using 1/8 in.. The equilibration should be done by heating the sample and maintaining it at the above conditions and continuously rocking it in a stand for 5 to 7 days (as required). C3 in Figure A6.3 kPa (1. By opening valve V2.2). Position another piston-type buffer cylinder (C2 in Figure A6. Close valves V3. by pumping pre-charge fluid into the sample cylinder. Steps for Obtaining Gas Sample for Geochemistry (Figure A6.2. Equilibrate the subsurface sample (MPSR. 2. 10. Connect an evacuated sample cylinder. SSB. 11. Keep the sample cylinder vertical (sample side facing up). 4. Allow a minimum volume of sample (depending on the solution gas in the sample) to be transferred into the buffer cylinder and then close valve V3.EP 2007-3186 .This will allow the sample to fill the top of the buffer cylinder piston until the pressure gauge on the buffer cylinder reads the same as the sample cylinder. 3. Any pressure reduction in the sample cylinder will be compensated by the positive-displacement pump. Now open valve V6 in a controlled manner and drain pre-charge fluid from the buffer cylinder. water/glycol) filled and the piston all the way up on the sample side. The buffer cylinder should have the pre-charge fluid (e. This will allow sample to be transferred into the buffer cylinder at the original sample pressure 12. and V6 on the buffer cylinder.g.161 - Restricted Flashed Gas Sample for Geochemistry A gas sample for geochemistry is collected right after the “standard flash” liquid sample for asphaltene screening work. Mount the sample as shown in Figure A6. allow fluid to pressurize the SS tubing. 9. bleed the pre-charge fluid below piston in the buffer cylinder (V6) so that the pressure in the cylinder will not overshoot. V5. Wrap a heating jacket and heat the buffer cylinder to the same temperature as that of the sample.2 and connect the pre-charge side of the sampling cylinder to a positive-displacement pump through valve V1. and opening valve V4 in a regulated manner. from time to time drain the liquid from the buffer cylinder (C2). This should be put into the sample collection at BTC as an “A” sample.EP 2007-3186 . . set the positive displacement pump to 400° @172. The pressure in the buffer cylinder (C2) is bled off. 14. 17. When the pressure inside the buffer cylinder reaches about 400° @172. To ensure that no liquid portion passes on to the ballast (gas sample) cylinder (C3). Repeat steps 9 to 15 until the pressure gauge at the bottom of the ballast cylinder reads a pressure of 400 ±172. Agitate the buffer cylinder until the sample inside stabilizes.162 - Restricted 13. Further open valve V5 and drain pre-charge fluid. 15. After the assembly is detached and taken apart. 16.While transferring the sample.3 kPa (25 psig). the gas sample cylinder (C3) is sent to BTC in Houston (or local OU). and any liquid in the cylinder is drained into an appropriately sized glass jar and sent to BTC/RIJ (or local OU). close valve V6.3 kPa (25 psig). Now open valve V5. It is suitable for standard geochemical work.3 kPa (25 psig) so that the gas sample will be transferred into the ballast cylinder at the same pressure. transfer gas inside the buffer cylinder into the ballast cylinder by opening valve V7. Restricted .163 - Diagram for obtaining pressurized gas samples for geochemistry.2: .EP 2007-3186 Figure A6. followed by two rinses with distilled or potable water. Wrap a heating jacket and heat the buffer cylinder to the same temperature as that of the sample. are sufficient. water/glycol) filled and the piston all the way up on the sample side. The buffer cylinder should have the pre-charge fluid (e. for cylinders that have been stored and/or are at ambient temperature. . Connect the positive-displacement pump to the pre-charge side of the buffer cylinder as shown.3) next to the sample cylinder. 2.3) 1. either the “heated” or the “unheated” procedures can be used to obtain stock-tank fluid samples for further analyses. oven dried.g. the equipment should be either air dried. proceed to points 2–15. bleed the pre-charge fluid below the piston in the buffer cylinder (V6) so that the pressure in the cylinder will not overshoot. or blown dry using cleaned compressed air. Procedures for Processing Pressurized Fluid Samples for Paraffin Measurements “Heated” and for Geochemistry “Unheated” Pressure Reduction to Atmospheric Conditions If a PVT cylinder reconditioned to the Pres and Tres is available.3 kPa (1500 psi) above the original reservoir pressure (after checking the working pressure of the cylinder!).Maintain the pressure in the sample cylinder at least 10339. To begin the bleed-down procedure. Position another piston-type buffer cylinder (C2 in Figure A 6.95 pt) (0. In the case that no restored fluid is available in the PVT lab. it is best to use a “standard flash” sample for asphaltene. cylinder. While heating.164 - Restricted A6. wax.3.EP 2007-3186 . or simply collect “standard flash” sample following procedure for asphaltene sampling.2. Heated Procedure for Paraffin Sample In the case that a geochemical sample is not taken. Mount the sample as shown in Figure A6.g. gauge. and valves) should be cleaned beforehand to avoid contamination. Keep the sample cylinder vertical (sample side facing up).. 1–2 days restoration prior to paraffin or geochemical sub-sampling is recommended. After rinsing.. Three sequential rinses with toluene (~100 ml each for the 500 cm3 ballast cylinder). 5. the buffer cylinder should be heated to 60°C (140°F). and geochemical analyses. the pressurized cylinder (either a SSB-type PVT cylinder or a Schlumberger 450 cm3 (0. 4.3 and connect the pre-charge side of the sampling cylinder to a positive displacement pump through valve V1. The assembled equipment is firmly attached to a special rocker/holder. It has to be stressed here that these steps should only be taken only if there is no opportunity to perform “standard flash” – no cylinder restored to reservoir PT is available at PVT lab or the fluid is of a highly volatile nature and stripping of heavy ends may be suspected. Opening pressure of the sample cylinder is routinely monitored. All of the equipment used in the procedure (e. tubing.95 pt) MPSR bottle) is rigged-up as shown in Figure A6. which allows the fluid in the pressure cylinder to be mixed by gentle rocking. Steps for Obtaining Stock Tank Liquid Sample for Paraffin and Geochemistry-Related Measurements – “Separator Test” Procedure (Figure A6. If equilibrated at reservoir temperature and a pressure cylinder is available. 3. Otherwise. set the positive-displacement pump to 9650 – 8271. Connect the sample side of the sample cylinder to the sample side of the buffer cylinder through a pressure gauge using 1/8 in. by pumping precharge fluid into the sample cylinder.Allow a minimum volume of sample (depending on the solution gas in the sample) to be transferred into the buffer cylinder and then close valve V3. slowly open valve V3. 13.4 kPa (1400–1200 psig) so that the sample will be flashed at the same pressure. will compensate any pressure reduction in the sample cylinder.4 kPa (1400 –1200 psig). 8. Agitate the buffer cylinder until the sample inside stabilizes. and by opening valve V4 flash the entire liquid inside the buffer cylinder into a receptacle R. V5. 11. allow fluid to pressurize the SS tubing. 9. By opening valve V2.3).This will allow the sample to fill the top of the buffer cylinder piston until the pressure gauge on the buffer cylinder reads the same as the sample cylinder. . Allow sufficient time to stabilize the temperature of the buffer cylinder before starting the sample transfer. and V6 on the buffer cylinder. The positive displacement pump. Now open valve V6 in a controlled manner and drain pre-charge fluid from the buffer cylinder. This will allow sample to be transferred into the buffer cylinder at the original sample pressure 11. close valve V6.165 - Restricted 6. 14. When the pressure inside the buffer cylinder reaches about 9650 – 8271. Further open valve V6 and drain pre-charge fluid. high-pressure SS tubing (as shown in Figure A6. While flashing the sample. 10. Close valves V3. Repeat steps 9 to 14 until sufficient stock-tank oil sample is collected in the receptacle. Once the tubing is pressurized to the cylinder pressure.EP 2007-3186 . Now open valve V5. 7. 12. 3: ..and geochemistry-related measurements. C7 analyses. it is important to get a representative subsample of the flashed (stock-tank) petroleum for geochemical work that has not been subjected .EP 2007-3186 Figure A6. and whole-oil GC analysis).166 - Restricted Diagram for obtaining STL for wax. excessive front-end loss affecting API. Sample for Geochemistry To avoid potential artefacts associated with sample heating (e.g. When the PVT work at the lab is completed and the pressurized samples have been released by the field/prospect team at the OU. . Similar procedures apply for the transfer of reservoir fluid from one cylinder to another in the PVT lab. should be sent to BTC as soon as possible following sample processing. the well name and number. which may occur during flash of volatile fluids. This needs to be done especially if there is a need to get the geochemical work started right away. (In most cases. To minimize light-end loss. with only the difference that for the geochemical sample. the bottle should be more than half filled). petroleum plus any residual water and/or solids) in the heated buffer cylinder should be collected in the glass sample bottle — do not attempt to clean up the sample at this point.1.. A brief writeup of the procedures. and whether the sample is a “heated” or an “unheated” sample. with any significant observations. Glass containers and shipping material are available from BTC.3 and Figure 23 describe and illustrates transfer procedure of downhole tool (SRS) sample into single-phase bottle (SSB) as performed on the rig.2). Both the sample cylinder and the buffer cylinder should be drained into the same. the dead volume in the container should be equal to or less than the volume of the sample (e. or condensate) also should be sent to BTC (or the local lab for a particular OU) for cataloguing and long-term storage. the liquid transfer should be done quickly and the sample bottle should be capped as soon as possible. and any geochemical samples (both gas and unheated liquid samples).3) should be used. after the PVT analyses have been completed.g. single container. with a Teflon cap. General Considerations Samples should be drained into an appropriately sized glass container. any unused petroleum samples (e. The transfer described for paraffin sample (Figure A6. The geochemistry sample can be taken at the time of obtaining asphaltene sample (Figure A6. should be sent to BTC in Houston or the local OU lab. the buffer cylinder should NOT BE HEATED. stock-tank oil.. the sample for geochemistry can be obtained from remaining PVT sample material. The “unheated” procedure should be used only if there is a risk of stripping the hydrocarbon light end of the fluid during the “standard flash” procedure.167 - Restricted to the heating procedure discussed in the next section. When filled. Transfer of the Pressurized Samples Section 2.g. flashed. Collect 30–35 ml (1/16-1/14 pt) of petroleum for geochemistry. If the geochemical work can be delayed. “standard flash” can be collected at reservoir PT during the PVT analysis).. the depth in the well at which the sample was taken. This sample is sometimes referred to as the “unheated” or “as received” sample.1) or gas sample (Figure A6. The heated samples. All bottles should be labelled with the PVT/MPSR cylinder number.EP 2007-3186 . All of the material (e.g. This should be done behind a safety shield and with personal eye protective equipment to protect the operator from accidental breakage. Isobarically displace (push off) enough of the fluid into an evacuated gas sample cylinder to obtain a sample at 2067. Sample Processing Procedure for Fluids Samples Having GCR <50 bbl/MMscf 1. and transfer the liquid to an appropriately . quantify the amount of liquid (if desired by weight and/or volume). compared to a possibly much higher sample pressure. “Unheated” samples obtained by this procedure are considered satisfactory for wax. Procedures for Processing Pressurized Fluid Samples from Dry Gas Reservoirs to Obtain Gas and Stock-Tank Liquids for Fluid Property Overview Pressurized fluid samples from gas reservoirs that contain relatively dry gas (CGR <~50 bbl/MMscf) have to be handled differently than fluids richer in liquids in order to avoid excessive loss of light ends. Flashing through a trap at dry ice temperature will maximize liquid fallout from the gas stream during bleed-down. which can be immersed in a dry ice/acetone bath. When the trap has reached room temperature (after no more than 1 hour). BUT knowing its concentration can be very important in designing gas production facilities for deepwater fields. The gas should be vented safely either through a gasometer to measure the gas for calculation of a GCR or directly to the outside. most of which have pressure ratings of 12407. The liquid trap should be made of glass so that the operator can see how much liquid is coming out and whether plugging of the flow is a problem.9 – 3446. 5. 4.4 kPa (300–500 psi) pressure (for geochemistry).3. Bleed the sample very slowly through the separator system while maintaining the reservoir pressure and temperature with a constant-pressure pump. Sample cylinder (assumed here to be a piston sample bottle) should be equilibrated at reservoir PT.1 kPa (1800 psi). CAUTION: Fluid samples having a CGR <1 will yield very little liquid. 3. Connect the sample valve of the sample cylinder (through a high-pressure regulating valve/needle valve) to a suitably sized liquid trap. Then remove the dry ice bath and let the liquid warm up slowly to room temperature with the possibility of volatiles exiting safely and without pressure build-up in the glass trap. Bleed off as much of the sample as desired.] Consideration should be given to using just the atmospheric-pressure gas from the liquid flash below for geochemical analysis. Five hundred cm3 of gas at just over 1 atmosphere is quite sufficient to do all the geochemical gas analyses available. 2.and asphaltene-related measurements because stock-tank condensate recovered from this type of reservoir sample typically has low wax contents (cloud point less than 70°F) and has nearly zero asphaltenes. [CAUTION: This must be done with care and a view to the possible overpressuring of the gas sample cylinder. When the endpoint is reached. remove the trap. shut off the flow from the sample bottle. but leave the gas exit plumbing open to either the gasometer or the vent.EP 2007-3186 . The following procedure can be used on either MPSR cylinders or PVT cylinders such as CSB and SSB.168 - Restricted A6. or organic solvents. .If larger samples are taken in 1.The preferred method is to collect a 450 ml (1 pt) sample in a MPSR chamber. Send the stock-tank liquid and the gas samples to BTC in Houston (or the local OU’s lab). If possible. however. For cylinder-types. they must be transferred into PVT shipping cylinders on the rig.4. the samples should be shipped to the laboratory on ice. it should be stored on ice as soon as possible. the receptor jug should be thoroughly clean. The cylinder should be labelled and returned to the PVT lab for PVT measurements as soon as possible. anion. should be thoroughly clean and contain no traces of petroleum.2.and corrosion-related production problems. as well as proximity to missed pay. The shipping cylinder. soluble organic composition. 5. and dissolved gas composition. 2. a water sample collected with a downhole sampling tool should be treated with the same care as a pressurized petroleum sample. If this option is taken. Transfer Procedures for Pressurized Water Samples on Rig 1. A6. and processing of downhole pressurized water samples and not the more routine processing of downhole water samples that have been flashed on the rig to stock-tank conditions.EP 2007-3186 . into a receptor jug. When clear water flows from the downhole collection tool. grease. An appropriately sized sample bottle for the liquid is one in which the headspace volume is less than 50% of the total volume of the bottle. water samples can be obtained in two ways with the Schlumberger MDT tool: 1. 6. Procedures for Obtaining and Handling Pressurized Formation Water Samples Analysis of downhole pressurized water samples could provide invaluable data for the prediction and understanding of scale.or 2¾-gallon chambers. if possible. used for accepting the transferred pressurized water from the sampling tool. gas water ratio (GWR). If the water samples are being collected from an inline separator. These chambers are DOT-approved and can be shipped directly to a PVT laboratory for analysis. The sample in the downhole collection tool should be purged until clear water flows.169 - Restricted sized glass sample bottle. The remainder of the water held by the piston controller in the sample chamber must not be wasted. transportation. refer to Section 2 of this report. the sample should be shipped on ice. 4. The procedures are written as if Oilphase were contracted to collect and process the samples. Obtaining Pressurized Downhole Water Samples At this time. cation. To ensure the accurate measurement of pH. Once the pressurized water sample has been obtained. any remaining water in the sampling tool should be flashed down to a flash separation unit or a collection jug and collected in Nalgene polyethylene sample bottles. 3. The procedures covered here involve the collection. other contractors can be used for this work. the pressurized shipping cylinder should be filled. the rig transfer procedures below do not apply. a subsample of dead water (a maximum of 30 ml) should be analysed for pH and alkalinity. If possible. Bubble point pressure should be determined at reservoir temperature on each sample. placed on ice. When filling the headspace of the Nalgene bottle with nitrogen from the nitrogen line. Care should be taken to prevent prolonged exposure of the dead liquid to air prior to the pH measurement. 9. and the remainder sent to BTC/RIJ (or other local OU lab) for storage. As quickly as possible after blowdown.EP 2007-3186 . The bottles should be filled so as to have very little headspace. 4. blown down by isobarically displacing the water from the pressurized cylinder. As quickly as possible after the bubble point and GWR are determined. The collection bottles should be numbered (with a waterproof marking pen) in sequence as they are filled from the separator unit. . Handling and Analysis of Pressurized Water Samples at PVT Lab (“Dead water” sample can be collected from the pressurized cylinder. 5. the pressurized cylinders should be kept as cool as possible. The dead water sample should be decanted into clean. 8. and returned to Bellaire Technology Center (BTC) for isotopic analysis as soon as possible. 7. If the Nalgene sample bottles are being filled directly from an inline separator unit.170 - Restricted 6. Figure A6. 7. a cushion of the liberated gas should be maintained over the water. and returned to Bellaire Technology Center as soon as possible. the line itself should not come into contact with the water sample. 8. An accurate GWR should be reported. While stored at Oilphase. the bottles should again be rinsed as described above with sample water. The MPSR or transfer cylinder should be equilibrated at reservoir pressure and temperature prior to bubble point determination. preferably on ice. before filling to a small headspace and covering with nitrogen. The dead water sample (50–100 ml) should be transported on ice to Peak Analytical for analysis as soon as possible.1): 1. 2. labelled. The liberated gas should be collected analysed for composition. labelled Nalgene bottles and stored on ice. Each Nalgene sample bottle should be rinsed with approximately 1/10 of its total volume of the water sample (which should then be disposed of) before the bottle is filled with the remaining sample. the sample should be 6. and nitrogen should be put in the headspace void. 3. follow the “asphaltene standard flash” procedure. Use funnel if needed. For filtered samples pour water from the bottle into the 60 cc syringe. Replace filter at each sampling point. and as needed.171 - Restricted Filtering Attach the syringe to the input side (the side with no writing on it) of the filter. . Filter only the samples for metal and carbon isotope analysis. (SSB cylinders in heated tape). do not filter. indicating precipitation. For unfiltered samples draw water with 60 cc syringe from the bottle. CAUTION: Some waters containing sulphides will appear black. Figure A6.EP 2007-3186 .4: Photograph of set-up for live-oil fluid transfer. EP 2007-3186 . VALID SAMPLES * Calculated on a Live Fluid Basis .172 - Restricted Sample A Sample B Restore and Condition Sample Restore and Condition Sample GOR Measurement GOR Measurement GOR Values < 5% Contact FEAST Team for Review GC Gas Composition GC Gas Composition Good Match on Gas Compositions GC Liq Composition GC Liq Composition OBM Contamination * < 15mol% for Oil < 2mol% for Gas OBM Contamination * < 15mol% for Oil < 2mol% for Gas Good Match on Reservoir Fluid compositions Good Result Bad Result Figure A6.5: Sample validation flowchart. Detailed instructions for mounting/installing both the new and old IsoTube rack assemblies can be obtained by contacting the supplier or FEAST.1: Single-use IsoTube™ for mud gas samples.1). • Insert one of the stem valves into the spring-loaded chuck on the IsoTube rack on the side opposite the ball on the valve control handle (Figure A7.1. The required adaptors can be ordered from Isotech Laboratories. IsoTubeTM Sampling Rack Set-up It is important to check well in advance that an IsoTube sampling manifold is available and properly installed in the mud logging unit. Compress the spring to allow the stem valve at the top of the IsoTube to slip into place in the fixed chuck.173 - APPENDIX 7.EP 2007-3186 . Remove the caps from the stem valves at each end of the IsoTube and set them aside. Significantly shorter than the original IsoTubes. Collection of Mud Gas Samples using a Modified IsoTubeTM Sampling Rack The instructions given below are based on documentation provided by Isotech Laboratories. A7. The boxes themselves meet all DOT and IATA requirements for shipment of flammable gases and can be re-used to transport the IsoTubes. (Figure A7. The next generation of mud gas sampling manifold specifically designed to accommodate the new IsoTubes is now also available for purchase from Isotech. single-use IsoTubes manufactured by Isotech Laboratories.10).2. • Remove an (unused) IsoTube from its plastic wrapper and discard the wrapper.) Figure A7. Inc. Inc.(Shipping instructions are included in each box. they can be purchased from the supplier in boxes of 25 (a copy of Isotech’s order form is reproduced in Figure A7. . to the destination laboratory. Restricted ISOTUBE™ MUD GAS SAMPLE COLLECTION IsoTubesTM Mud gas samples should be collected in the new. The new IsoTubes can be used with existing IsoTube sampling racks after a few simple adjustments are made to the manifold set-up. A7. Inc. once filled.2). 3).3: Actuation of the valve control handle. 1.EP 2007-3186 Figure A7. Rotate the valve control handle until it comes down on top of the IsoTube that was just inserted (Figure A7. Figure A7. .174 - Restricted Loading of an IsoTube™ onto the sampling rack.2: . 4. The first tag on each sheet (Figure A7. 2. 2. Complete one of the adhesive-backed sample information tags (Figure A7. Repeat step 1 with another IsoTube and insert it into the other position on the IsoTube rack. This will close off the IsoTube in which the mud gas is to be collected and switches the next IsoTube into the stream so that it can be purged. Sheets of adhesive-backed tags are included in each box of IsoTubes. and well names. 1. The tags are pre-numbered and should be used sequentially so that the numbers increase with well depth.4: Removal of a filled IsoTube from the rack.EP 2007-3186 . field. Note: Turning the control handle so that it is perpendicular to the rack will close both valves and completely stop the gas flow. Figure A7. Replace the valve caps on the stem valves at both ends of the IsoTube. . 3. The other IsoTube is shut-in. rotate the valve control handle 180° so that it is in contact with the IsoTube in the other position. When a sample is to be taken.5a) provides space for the company/rig. 3. Remove the IsoTube containing the gas sample (the one opposite the ball on the valve control handle) by pulling it downwards in the direction of the spring-loaded chuck and tipping it to the side as shown in Figure A7. Sample collection should be timed so that it takes place just after the automatic monitoring equipment has sampled so that the results are not affected by the purging of the next IsoTube.7. Gas flow is always through the IsoTube that is positioned underneath the control handle. This tag should be placed on the inside flap of the box. Use a ballpoint pen to fill in the information (press hard since two carbon copies are being made). Attach the tag to the body of the IsoTube.175 - Restricted 1.5b) for the sample just collected. 6. 1. The white copy should be placed in the box with the IsoTube samples.3. If none of the IsoTubes in the carton are pressurized and none of them have methane concentrations in excess of 5% by volume (lower limit of flammability). Remove an (unused) IsoTube from its plastic wrapper and discard the wrapper. Repeat steps 6 through to 11 for the collection of additional mud gas samples. Some downward pressure must be applied to the “saddle” that locks the moveable chuck open when it is not in use. 4.5: Restricted b Adhesive-backed labels.11.176 - a Figure A7. Remove the valve caps from another unused IsoTube and insert it into the vacant position on the IsoTube rack. A few extra caps are provided in case any are lost. 1. 2. Remove the caps from the stem valves at each end of the IsoTube and set them aside.). Once a box of 25 IsoTubes is filled. A set of warning labels and shipping instructions are included in each carton (a copy of the latter is presented for information purposes in Figure A7. the box can be sealed and shipped without any hazardous materials labels. Insert the IsoTube into the manifold as indicated in Figure A7. 7. the carton must be shipped as hazardous material. 2. Remove the yellow copy of the sample identification tags and keep for record purposes. check to ensure that all stem valve caps have been replaced. If any of the IsoTubes in a given box are known to be under pressure or are suspected to contain more than 5% methane. 5. 3. Return the IsoTube to the shipping box.EP 2007-3186 . Collection of Mud Gas Samples Using a New IsoTubeTM Sampling Rack The instructions given below are based on documentation provided by Isotech Laboratories. 6. For (a) well/field identification and (b) sample information. . Inc. A7. Note: Monitoring flow rates and pressures will help to identify any apparatus malfunctions. Figure A7. Failure to do so will result in a missed sample and also block flow downstream to other monitoring equipment.EP 2007-3186 Figure A7. Ensure that the IsoTube is securely centered and seated in both chucks.8) should show approximately the same reading when there is flow through either the IsoTube or bypass.6: .7). Move the control handle until it comes down over the top of the IsoTube (Figure A7.7: 4. If difficulties are experienced with closing the valve. Both gauges (Figure A7. open the control handle fully to release the pressure on the saddle. 3. A problem is indicated if there is no flow registered on the flow meter and/or if either gauge reading is significantly different from the other. Caution: Leaving the control handle in an intermediate position can completely stop the gas flow. . Valve closure.177 - Restricted Inserting an IsoTube into the new mud gas sampling manifold. (Horizontal [cabinet] mounting configuration). check to ensure that all stem valve caps have been replaced. Return the IsoTube to the shipping box. 8. and well names. open the control handle until it “locks” into place (Figure A7. Figure A7. Attach the tag to the body of the IsoTube. Remove the IsoTube containing the mud gas sample from the manifold. 9.5b) for the sample just collected. Figure A7. The first tag on each sheet (Section A7. Gas sample collection should be timed so that it takes place just after the automatic monitoring equipment has sampled so that the results are not affected by the purging of the IsoTube.9: Sample collection. Once a box of 25 IsoTubes is filled.5a) provides space for the company/rig.8: .178 - Restricted Monitoring flow rates/pressures. Replace the valve caps on the stem valves at both ends of the IsoTube.9). Insert another IsoTube as per step 1 to allow for sufficient flushing of the new vessel and to prepare for collection of the next sample. Complete one of the adhesive-backed sample information tags (Section A7. field. 6. Figure A7.3.EP 2007-3186 Figure A7. This shuts off flow to the IsoTube in which the sample is to be collected and switches flow through the bypass. This tag should be placed on the inside flap of the box.3. 10. 11. The tags are pre-numbered and should be used sequentially so that the numbers increase with well depth. Sheets of adhesive-backed tags are included in each box of IsoTubes. 7. . When a sample is to be taken. Use a ballpoint pen to fill in the information (press hard since two carbon copies are being made). 5. The URL is http://www. the box can be sealed and shipped without any hazardous materials labels. (A copy of the latter is presented for information purposes in Figure A7.179 - Restricted 12.. IsoTubeTM Order Form To expedite the purchase and delivery of new IsoTubes from Isotech Laboratories.EP 2007-3186 . Figure A7. Copies of the document can be printed directly from Isotech’s website. it is recommended that their customized IsoTube order form be used (see Figure A7. 13. If any of the IsoTubes in a given box are known to be under pressure or are suspected to contain more than 5% methane.10: Isotech’s order form for new IsoTubes.isotechlabs. Inc.com/literature/pdf/IsotubeOrderFormFax. the carton must be shipped as hazardous material. Remove the yellow copy of the sample identification tags and keep for record purposes. If none of the IsoTubes in the carton are pressurized and none of them have methane concentrations in excess of 5% by volume (lower limit of flammability). A set of warning labels and shipping instructions are included in each carton. 14. .10). The white copy should be placed in the box with the IsoTube samples.4.) A7.11.pdf. .g.. Additional assistance regarding completion of the necessary paperwork and/or labelling requirements can be obtained by contacting the courier directly. Detailed shipping instructions.EP 2007-3186 . Flammable and/or pressurized gas samples must be identified as hazardous materials when transported from the wellsite. Inc. DHL. Shippers have their own dangerous goods forms. International Air Transport Association (IATA) regulations require that the following labels are attached to the outside of the box: • Flammable gas label • UN2037 label • Air eligible sticker Isotech Laboratories. This sticker should be placed on the same side of the box as the address label or airway bill.5. together with a set of DOT/IATAapproved hazard labels. If the IsoTube samples are known to be at atmospheric pressure and contain less than 5% methane (or other hydrocarbons) by volume. The guidelines presented in this section only pertain to collected mud gases that are flammable and/or at elevated pressure. Labels must not be folded or affixed in such a manner that parts of it appear on different faces of the package. 1.180 - Restricted A7.11: Labeling of IsoTube boxes for hazardous shipment. are included in every carton of new IsoTubes to ensure that the cylinders can be transported by shipping companies that routinely accept such consignments (e.11. they are not considered to be hazardous for shipping purposes. Figure A7. Please note that the outer carton in which the IsoTubes were originally sent can be discarded. as illustrated in Figure A7. 2. Inc. provides a single label that incorporates all of these elements. Shipping instructions for flammable gas samples in single-use IsoTubesTM The instructions given below are based on documentation provided by Isotech Laboratories. FedEx). Place the filled IsoTubes (together with the white copy of the sample identification tags) in the UN certified box and seal it with packing tape. an MSDS (material safety data sheet) is provided on the back of the instruction sheet included in each IsoTube box. In order to use one of these numbers. The above instructions have been prepared to simplify the task of shipping gas samples and are based on the IATA Dangerous Goods Regulations. Such gas mixtures are classified as Class 2.1 kg Packing instructions: 203 Shipment type: Non-radioactive Prepared per: ICAO/IATA Additional information: None (leave blank) Limitations: None (leave blank) 4. Check the original Shell manifest from the rig clerk and sign it only if all samples are listed. to ensure the safe and legal shipment of samples as per the most recent applicable local.EP 2007-3186 3. and additional shipping restrictions apply. 6. 44th Edition. use Chem-Tel’s telephone number 800 255 3924 for shipments within the US/Canada or +1 813 248 0585 for international locations. 2003. the shipper must fax copies of the airway bill and dangerous goods declaration to Chem-Tel on 813 248 0582.It is ultimately the responsibility of the shipper. please follow the special instructions enclosed in the IsoTube carton. state and international shipping regulations. if available. small. To facilitate scheduling and processing of the IsoTube samples. Provide a 24 hour emergency contact number. Place a copy of the shipping manifest on the well database website. toxic gas. 7. copies of all shipping documents should be faxed to Isotech on +1 217 398 3493 at the time of dispatch. 1%) cannot be transported by air.181 - Restricted Fill in a Shippers Declaration for Dangerous Goods form.3. Although not generally required as part of the shipping documentation. For international consignments. . . Information that may be needed to complete the form is listed below. however. If not. Warning: Samples containing high concentrations of hydrogen sulphide (greater than ca. containing gas Class or division: 2.1 UN or ID number: UN2037 Subsidiary risk: None (leave blank) Packaging group: None (leave blank) Quantity and type of packaging: Fiberboard box(es) x 0. 5. This document can be obtained from the shipping company. Proper shipping name: Receptacles. 3.EP 2007-3186 . Immediately seal the container with the lid supplied.or under-filled. The free space remaining in the IsoJar after sample collection must be ¼ to 1/3 of the total container volume. Figure A8. (The bulk sample should be comprised of small quantities of cuttings collected every foot during the drilling of the sampling interval. Add two drops of concentrated Zepherin Chloride bactericide. Inc. Note: IsoJars should not be over.) 2. Inc. Place a copy of the shipping manifest on the well database website. IsoJars should be shipped to the designated vendor laboratory after every 1.1). and can be purchased from either Isotech Laboratories. 5. Fill half of the remaining volume in the IsoJar with water. Using an indelible MARKS-A-LOT marker. or Humble Instruments and Services. Do not take half a container of cuttings from the top of the pile on the shale shaker. Fill each IsoJar half-full with cuttings that are representative of the depth interval being sampled. Each IsoJar must be filled in the same manner in order to obtain good headspace gas data. Restricted ISOJARTM HEADSPACE SAMPLE COLLECTION Ditch cuttings samples All ditch cuttings samples earmarked for headspace analysis should be collected in IsoJars (Figure A8. label the IsoJar (on the side of the container) with the following information: • Well name (and number) • Sample depth interval • Sampling date • Name of the person who filled the IsoJar • Date 6. These containers are superior to the steel cans traditionally used for this purpose.000 ft (300 m) drilled or weekly and/or at casing points. .1: Isotech’s new IsoJars™ for headspace gas samples.182 - APPENDIX 8. 1. As a general rule of thumb. 4. Repeat steps 1 through 5 for the next headspace cuttings sample to be collected. 200 m depth intervals.1 should be followed for mud samples. . across pay zones and before and after bit trip/casing point. The same basic procedure as that given in Section A7. Mud samples Drilling mud samples for headspace gas analysis must also be collected in IsoJars.EP 2007-3186 . In general.183 - Restricted Check the original Shell manifest from the rig clerk and sign it only if all samples are listed. samples should be taken (while circulating) at regular. Restricted SAMPLE TRACKING TEMPLATES Field name Well Name Rig name Contractor Date Table 1: Summary of Sampling Info Downhole Shell ID SAM# Sampling Depth MDm Formation P RES TR ES o psia C Sampling P Sam ple ID psia Sample Slot # in the Sample Carrier Serial # tool Chambe r Serial # Drawdown psia Closing P Closing T Downhole psia Downhole degC Sample Volume Closing P Table 2: Summary of Sampling Info Rig Figure A9.Sampling and transfer. o C psia o C Transport Bottle Serial # Bottle Type 3 cm psia Comments .184 - APPENDIX 9.1: Shell ID Sampling Depth SAM# MDm Zone Sample ID Sample Chamber Serial # Rig Opening P Rig Opening T Rig Transfer P Rig Transfer T psig Sample tracking sheet .EP 2007-3186 . PVT Lab.EP 2007-3186 . ml Transport Cylinder ID C12+ Gas Transport Cylinder Type C36+ Liquid Closing P P psia psia Viscosity PSAT psia Restoration T Priority Duration o C batches hrs CCE DifLib SepTest Comments .185 - Restricted Field name Well Name Rig name Contractor Date Sampling Depth Opening Conditions Formation Sample ID Sampling Cylinder ID MDm Sampling Depth Rig Opening Rig Opening P T psig Formation MDm Figure A9.2: Sample ID Sampling Cylinder ID GOR o Sample Volum e Rig Transfer P Rig Transfer T C cm3 psia F API HC volume WBM volume OBM% scf/bbl Sample tracking sheet . Sample ID Sam pling Cylinder ID OBM % (STL) STL density API GOR CGR Liq Flash Volume Gas Flash Volume scf/stb bbl/mmscf cc cc Gas comps Liquid comps .EP 2007-3186 .186 - Restricted Field name Well Name Rig name Contractor Date Table 3. Summary of the on-site sample validation Shell ID Sampling Depth SAM# MDm Figure A9.3: Zone PRES psia TRES o C Drawdown psia Sample tracking sheet .Onsite validation. R. Dindoruk EPT-RHF 1 PDO P. Hassing GSUD 2 SIEP M. M.187 - Restricted DISTRIBUTION LIST OU Recipient Ref. Lesoon EPT-SCF 1 SIEP D. R. M. P. of copies SIEP A. Okon EPG-PN-VPR 1 SIEP P.EP 2007-3186 . Hashem EPT-SCF 1 GSNL T. E. Axon EPT-SUP 1 SIEP R. Carlson EPT-SCF 1 GSMY B.-F. J. M. F.ind. T. John GSUD 2 SIEP R. Cornelisse GSUA 1 SIEP C. Berhitoe EPT-SCF 1 GSUSI J. Flannery EPT-SCF 3 SIEP D. Dutchak GGPS25 1 GSUSI S. Clarke EPT-SCF 1 GSMY P. Frigo EPT-PDS 1 SPDC H. Davidson EPT-O-TFPL 1 GSUSI A. Elshahawi EPT-SCF 1 SIEP M. W. Chang GSUA 1 SIEP E. H. O’Neal EPT-SCF 1 . A. Grutters GSUA 1 GSNL F. Ganz EPX-G-XNTC 1 GSNL M. No. J. W. B. Dawodu GSUA 1 SIEP B. J. Naafs EPT-SCF 1 SEPCo W. Hartog GSEA/4 1 SIEP M. E. M. Nisbet EP-Americas 1 SPDC E. U. Burgess GSUA 1 SIEP T. Mckinney EPT-SCF 1 SIEP D. Dubey GSUA 1 SIEP H. J. Inan EPT-SCF 1 GSNL C. Hows EPT-SCF 1 SIEP E. Shepherd GSUA 1 SIEP L. A. Wilie EPT-WD 1 SHLOIL-SRE-PITB S. T. Poteau GSUA 1 SIEP A. of copies GSUSI S. Skelton EPT-SCQ 1 GSNL A. No. Tegelaar EPW-T-TM 1 STI S. Westrich EPT-SCF 2 SIEP C.188 - Restricted OU Recipient Ref. Stankiewicz EPM-PM-AD 1 SEPCo E. W. Gilmore Houston EP Library 2 TOTAL 48 . Venkitadri EPT-SCIF 1 PDO J. Saha EPT-SCF 1 SIEP M.ind. Slagle EPT-SCF 1 SADBV B. V. Walsh UIK16 1 SIEP J. K.EP 2007-3186 . Shammai EPT-SCF 1 SIEP W. P. G. EP 2007-3186 . . reprographic. Houston.189 - Restricted The copyright of this document is vested in Shell International Exploration and Production Inc. mechanical.. recording or otherwise) without the prior written consent of the copyright owner. Neither the whole nor any part of this document may be reproduced. Texas. All rights reserved. stored in any retrieval system or transmitted in any form or by any means (electronic. USA.