Core Analysis Manual

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Report EP 94 - 1130 April 1995

CONFIDENTIAL

CORE ANALYSIS MANUAL by H.H. Yuan SIPM EPD/222 and B.A. Schipper KSEPL RR/37 Contributions by R.M.M. Smits KSEPL RR/37 J.G. Maas KSEPL RR/44

PETROPHYSICS AND RESERVOIR ENGINEERING This document is confidential. Neither the whole nor any part of this document may be disclosed to any party without the prior consent of Shell Internationale Petroleum Maatschappij B.V., The Hague, the Netherlands. The copyright of this document is vested in Shell Internationale Petroleum Maatschappij B.V., The Hague, the Netherlands. All rights reserved. Neither the whole nor any part of this document can be reproduced, stored in any retrieval system or transmitted in any form or by any means (electronic, mechanical, reprographic, recording or otherwise) without the prior written consent of the copyright owner. SHELL INTERNATIONALE PETROLEUM MAATSCHAPPIJ B.V., THE HAGUE EXPLORATION AND PRODUCTION

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The authors appreciate the comments and review of the following people: P.van Ditzhyijzen, SIPM- EPD/22 A.J.T. Grimberg, SIPM- EPD/21 A.B. Graper, SIPM- EPD/21 H.Niko, SIPM- EPD/221 P.R.A. Betts, SIPM- HTRH/52 P.M.T.M. Schutjens, KSEPL- RR/37 K.A. Heller, SIPM- EPD/21 J.P. van Hasselt, EPX/43 E.C. Thomas, SOC F.R. Bradburn, SOC Many petrophysicists at PDO, EXPRO, NAM, SSB, SVEN

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SUMMARY Core analysis is the acquisition of experimental data measured on core material for determining parameters used for developing and managing a hydrocarbon reservoir from initial discovery to mature field development. There are two main reasons for core analysis. Firstly, core analysis data are used by petrophysicists to calibrate wireline logs in the determination of hydrocarbon reserves. Such data include routine core analyses as well as special core analyses such as measurement of electrical parameters for resistivity log interpretation. Secondly, reservoir engineers use core analysis measurements such as relative permeability and pore volume compressibility to provide input parameters for reservoir computer simulation. Core analysis data are also used by other disciplines such as for production technologists to determine injectivity and well performance and for explorationists in quantifying acoustic rock properties. Geological core analysis (the subject of a manual in preparation) is done to establish the geological framework of a reservoir. Careful planning of a core analysis programme requires the involvement of an integrated team of petrophysicsts, geologists, reservoir and production engineers and explorationalists to ensure that core measurements meet critical data needs. Since optimum analysis programmes require multi-disciplinary input, the manual is prepared in such a way to assist teams of petroleum engineers to develop core analysis programmes. The contribution of each PE discipline is highlighted. An appendix on application of value of information concepts as applied to core analysis is given to provide a clear method for evaluating and justifying core analysis projects. The various parameters which can be obtained from the analysis of core material are discussed briefly. The available measurement techniques are detailed and discussed briefly. The available measurements techniques are detailed and recommendations are made concerning the reliability of the techniques and how best to obtain quality results. Core sampling guidelines that allow easier application of core data, proper core preparation procedures, core screening methods for obtaining representative cores, wettability considerations and ancillary measurements that ensure quality and data applicability are described in detail.

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GENERAL RECOMMENDATIONS •

A core analysis programme should be assembled with input from all PE disciplines to ensure that the right data are measured with the proper procedures on appropriate core material. The core analysis programme allows proper planning in the multi-disciplinary environment and assists in the management of the core analysis programme.

•

Value of information concepts should be used for core analysis programmes and in programmes justification.

•

High quality data can be obtained with careful core selection, core screening and core preparation steps. Proper core screening is necessary to obtain relevant core data.

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Extensive special core analysis programmes can be discussed with SIPM EPD/22 and/or KSEPL RR/37 to assist in decisions as to where work should be carried out.

•

SIPM recommends that special core analyses be carried out in-house using facilities at KSEPL. Bellaire Technology Center, Houston, and Calgary Research Center can be used as alternatives with sufficient prior planning and available capacity. If Shell E&P laboratories are not available, core contractors approved by SIPM can be used.

•

If contractor laboratories are used it is recommended that KSEPL be requested to carry out duplicate special core analysis measurements on a small number of samples in order to verify the performance of the contractor. A review of any extensive core analysis programme is recommended and will be provided by SIPM upon request.

•

To date quality assessments have been made on the techniques used at Core Laboratories, Simon Petroleum Technology, Poroperm-Geochem, GAPS Geological consultants, and Corex (Aberdeen). SIPM recommends regular quality assessment of any core analysis contractor involved in Shell work.

•

All measured data, procedures and equations used should be requested from the analysis laboratory, including any data used in calculating final results such as raw data.

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Recommendations for multi-disciplinary core analysis planning A core analysis programme should address all issues in core analysis from justification, core acquisition, well-site handling, core preparation to core measurements and data application. Planning should include the following: •

Justification (see Chapter 2 and Appendix 1) and clearly stated objectives of the core analysis programme (Chapters 3 and 4)

•

Core acquisition considerations including type of coring bit, core barrel, overbalance, drilling fluids, well-site handling (see Core Handling Manual); core transport and fluid sampling considerations

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Multi- disciplinary input ensuring proper utilisation of core material and representatives of the samples to be used in the core analysis programme

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Core analysis considerations including types and scope of the core analysis, numbers of samples, core sample screening methodology, core preparation methodology especially cleaning, experimental conditions (confining pressure, temperature, pore pressure, fluids to be used, experimental duration, etc), wettability conditions and so on

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Fluid analysis considerations focusing on types of fluid analyses that can be used to support interpretation of core data. It is a frequently overlooked aspect of formation evaluation

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Detailed measurement sequence defining expected measurements on each core sample. Scheduling is important so that the performing organisation can meet the deadlines required for core analysis data

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Costs and value of information concepts used in programme justification

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Finalised core analysis programme allowing each discipline to contribute and to agree to the goals and methods and allows for better project management.

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Acknowledgements Many people have contributed to the preparation of this manual. Staff at SIPM and KSEPL have extremely reviewed the manual and helped in ways too numerous to detail. Interest and review from Opcos has also encouraged us to make the manual as useful as possible. The information contained in this manual has been collated from a number of previous SIPM and KSEPL publications. Especially useful in the writing of this report were: EPD/22/23 SIPM Coring Series Bulletin l: Core Justification EP 88-1465 EPD/22/23 SIPM Coring Series Bulletin IIl: Core Analysis EP 89-0105 Rock Characteristics Research – Special Core Analysis KSEPL, brochure 1991. B.A. Schipper, R.J. van den Oord, and S.J. Adams Petrophysical Core Analysis Contractors - Procedures and Quality Assessment . EP 92-1355 S.J. Adams and R.J. van den Oord Capillary Pressure and Saturation Height Functions EP 93-0001 This manual completes a series of three manuals dealing with aspects of coring, core handling and core analysis. The first two manuals are: J.A. Okkerman and L.C. van Geuns Core Handling Manual EP 93-2200 L.C. van Geuns and J.A. Okkerman (in preparation) Geological Core Analysis

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Contents SUMMARY GENERAL RECOMMENDATIONS Recommendations for multi-disciplinary core analysis planning Acknowledgements List of Figures (p) denotes photo List of Tables 1.

I II III IV X XIV

Introduction About this manual Problems solved by core analysis SIPM/KSEPL recommendation on core analysis Availability of other Shell E&P Laboratories for core analysis Quality in core analysis Literature

1 2 6 8 9 10 12

Economics of core analysis 2.1 Value of Information (VOl) 2.1.1 VOl Nomenclature 2.1.2 Value of prospect screening - Summary 2.1.3 Value of project optimisation - Summary 2.1.4 Value of correct core analysis data - Summary 2.2 Value of information examples as applied to core analysis projects 2.2.1 Example 1 - Prospect Screening (Unconsolidated Sandstone) 2.2.2 Example 2 - Ekofisk 2.2.3 Example 3 - Project optimisation 2.2.4 Example 4 - An Opco VOl Example 2.3 Core analysis aspects of VOl 2.4 Literature

13 14 15 16 17 18 19 20 22 24 26 28 30

1.1 1.2 1.3 1.4 1.5 1.6 2.

3.

Planning a core analysis programme 3.1 Planning in an integrated PE team 3.1.1 Core analysis programme development 3.2 The core analysis programme 3.2.1 An example of a core analysis programme 3.3 Considerations for major lithologies 3.4 Where to perform the core analysis programme 3.5 Literature

31 34 35 36 39 43 46 47

4.

Core and fluid analysis considerations 4.1 Scope of a core analysis programme 4.2 Multi- disciplinary considerations 4.2.1 Petrophysics 4.2.2 Geology 4.2.3 Reservoir engineering 4.2.4 Other disciplines 4.3 Core measurements 4.3.1 Basic core analysis 4.3.2 Special core analysis 4.4 Coring considerations and well-site planning 4.5 Core handling 4.5.1 At the well-site 4.5.2 Upon arrival at the Laboratory 4.6 Core screening

48 49 50 50 51 53 54 55 55 58 61 64 64 65 66

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4.7 Core sampling 4.7.1 Sampling for basic core analysis 4.7.2 Sampling for special core analysis 4.7.3 Sampling considerations 4.8 Core sample preparation 4.9 Core sample screening for special core analysis 4.10 Core preservation 4.11 Fluid measurements 4.11.1 Brine measurements 4.11.2 Oil measurements 4.12 Fluid handling considerations 4.13 Sequencing and scheduling 4.14 Costs 4.15 Economic impact and justification 4.16 Project reporting 4.17 Project review 4.18 Literature

67 67 68 69 70 71 75 76 76 77 78 79 79 79 80 83 85

5.

Core preparation 5.1 Plug drilling 5.1.1 Drilling consolidated samples 5.1.2 Drilling unconsolidated samples 5.2 Core cleaning 5.2.1 Cleaning consolidated samples 5.2.2 Cleaning unconsolidated samples 5.3 Core drying 5.3.1 Oven drying 5.3.2 Critical Point Drying (CPD) 5.3.3 Humidity controlled drying 5.4 Review of some contractor preparation procedures 5.5 Literature

86 87 87 88 90 90 91 93 93 94 97 98 101

6.

Basic core analysis 6.1 Porosity and grain density 6.1.1 Bulk volume by buoyancy in mercury 6.1.2 Bulk volume by mercury displacement 6.1.3 Bulk volume by caliper 6.1.4 Pore volume by liquid saturation 6.1.5 Grain density by pycnometer 6.1.6 Grain volume by buoyancy 6.1.7 Grain volume by Boyle's law porosimetry 6.2 Steady- state gas permeability 6.2.1 Air permeability 6.2.2 Probe permeability 6.3 Fluid saturations 6.3.1 Fluid saturations by Dean-Stark extraction 6.3.2 Retort method or summation of fluids 6.4 Literature

102 103 103 104 106 107 108 110 112 114 114 118 120 120 122 123

7.

Porosity and permeability at stress and whole core analysis 7.1 Stressed Porosity 7.1.1 Stressed pore volume by liquid saturation 7.1.2 Stressed pore volume by Boyle's Law porosimetry 7.2 Stressed permeability 7.2.1 Stressed steady-state permeability 7.2.2 Pulse decay permeability

124 125 125 126 127 127 129

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7.3 Whole core analysis 7.3.1 Whole core porosity by Boyle's Law porosimetry 7.3.2 Whole core steady-state gas permeability 7.3.3 Other whole core measurements 7.4 Literature

131 132 133 135 137

8.

Capillary pressure 8.1 Mercury/air capillary pressure 8.1.1 Mercury/air capillary pressure by high pressure injection - Autopore 9200, 9220 8.1.2 Mercury/air capillary pressure by pressure equilibrium 8.1.3 Stressed mercury/air capillary pressure 8.2 Oil/water capillary pressure 8.2.1 Oil/water capillary pressure by centrifuge 8.2.2 Oil/water capillary pressure by pressure equilibrium 8.3 Gas/liquid capillary pressure 8.3.1 Gas/liquid capillary pressure by centrifuge 8.3.2 Gas/liquid capillary pressure by porous plate vessel 8.4 Literature

138 141 142 145 147 149 150 152 154 155 156 157

9.

Electrical properties 9.1 Formation Resistivity Factor, FRF, and cementation exponent, m 9.2 Resistivity index, I, and saturation exponent, n 9.2.1 Resistivity index by pressure equilibrium 9.2.2 Resistivity index by continuous injection 9.2.3 Resistivity index by porous plate vessel 9.2.4 Resistivity index by rapid desaturation 9.3 Cation Exchange Capacity (CEC) and Qv 9.3.1 Qve by membrane potential 9.3.2 Qv by multiple salinity measurements, Co-Cw 9.3.3 CEC by conductometric titration 9.3.4 CEC by absorbed water correlation 9.4 Literature

158 159 161 163 165 168 169 170 171 174 176 178 179

10. Wettability and interfacial tension 10.1 Wettability 10.1.1 Cleaned-state samples 10.1.2 Restored-state samples (aging) 10.1.3 Fresh-state samples 10.1.4 Preserved-state samples 10.1.5 Pressure-retained core samples 10.1.6 Restored state vs native state 10.2 Wettability determination 10.2.1 Amott 10.2.2 United States Bureau of Mines method (USBM) 10.2.3 Other wettability determination methods 10.3 Interfacial tension 10.3.1 Interfacial tension by 'Pendant Drop' 10.3.2 Surface tension by 'du Nouy balance' 10.3.3 Interfacial tension by spinning drop tensiometer 10.4 Literature

180 181 183 184 185 186 186 187 189 190 192 193 194 195 197 199 200

11. Relative permeability 11.1 Steady-state measurement 11.1.1 Relative permeability by steady-state 11.2 Centrifuge measurement 11.2.1 Oil/water relative permeability by centifuge

202 204 204 207 207

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11.2.2 Gas/liquid relative permeability by centrifuge 11.3 Unsteady-state measurement 11.3.1 Oil/water relative permeability by unsteady state displacement 11.3.2 Gas/liquid relative permeability by unsteady-state displacement 11.4 Relative permeability at reservoir conditions 11.4.1 Restored-state (see section 10.1.2) 11.4.2 Native-state (see section 10.1.3, 10.1.4, 10.1.5) 11.5 Literature

211 213 213 216 219 219 219 220

12. Mechanical rock properties 12.1 Compressibility 12.1.1 Uniaxial compaction 12.1.2 Hydrostatic compaction 12.1.3 Oedometer compaction test 12.2 Rock strength parameters 12.2.1 Rock strength by triaxial testing 12.2.2 Brinell Hardness Number (BHN) 12.2.3 Thick-Walled-Cylinder strength test (TWC) 12.2.4 Unconfined Compressive Strength test (UCS) 12.3 Acoustic properties 12.3.1 Acoustic Travel Time (ATT) 12.4 Literature

222 223 224 230 231 232 233 234 236 239 240 240 241

13. Supplementary tests 13.1 Rock analyses 13.1.1 Grain size by laser diffraction 13.1.2 Grain size by sieve analysis 13.1.3 Grain size by image analysis 13.1.4 Source rock analysis 13.1.5 Cap rock/seal analysis 13.2 Fluid analyses 13.2.1 Counter Current Imbibition (CCI) 13.2.2 Oil and gas analyses 13.2.3 Formation water and core water analysis 13.3 Rock-fluid compatibility 13.3.1 Compatibility flood 13.4 Miscellaneous tests 13.4.1 Acid response test 13.4.2 Solvent flushing - for wax removal 13.5 Literature

244 245 247 249 250 251 253 254 254 256 258 260 260 263 263 266 267

Core analysis research activities 14. 14.1 Rock characteristics 14.1.1 Ultrasonic Velocity Cell (UVC) 14.1.2 Acoustic transmission anisotropy 14.1.3 Apparatus for Pore Examination (APEX) 14.1.4 Resistivity 14.2 Fluid flow 14.2.1 Capillary Pressure and Resistivity Index by Continuous Injection, CAPRICI 14.2.2 Relative Permeability at Reservoir Conditions (3-phase), REPARC-3 14.2.3 Critical gas saturation 14.3 Supplementary 14.3.1 Nuclear Magnetic Resonance, NMR 14.4 Literature

268 269 269 271 273 275 277 277 279 281 283 283 287

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APPENDIX 1 Value of Information A1.1 Value of prospect screening A1.2 Value of project optimisation (reducing uncertainty) A1.3 Value of correct core analysis data (Shell EP Laboratories vs contractors).

289 290 293 297

APPENDIX 2 Core screening techniques A2.1 X-Ray Computer Tomography scanning (CT) A2.2 Core gamma ray A2.3 X-ray fluoroscopy A2.4 Coreslab inlarging A2.5 Literature

301 302 306 308 309 311

APPENDIX 3 Petrophysical data from geological analysis 312 A3.1 Microstructure/Petrography 313 A3.1.1 Petrography from Scanning Electron Microscopy (SEM) and Enhanced Image Analysis (IA) 314 A3.1.2 Petrographic image analysis from thin sections 319 A3.2 Mineralogy 321 A3.2.1 X-ray diffraction 322 A3.2.2 Energy Dispersive X-ray analysis (EDX) 323 A3.2.3 Mineralog 324 A3.3 Literature 325 APPENDIX 4 Core analysis on small cores, sidewall samples and cuttings A4.1 Small core samples from slim holes A4.1.1 Analysis of a 13/4" diameter core A4.1.2 Analysis of a 25/8" diameter core A4.1.3 Further slim hole core analysis A4.2 Sidewall samples A4.2.1 Rotary drilled samples A4.2.2 Percussion sidewall samples A4.2.3 Sidewall sample measurement techniques A4.3 Cuttings A4.3.1 Collection/sampling A4.3.2 Measurement techniques used in cuttings analysis A4.4 Literature

326 327 328 329 330 331 332 333 334 335 335 337 339

5 Sponge core analysis APPENDIX A5.1 Oil-Wet sponge analysis A5.1.1 Sponge analysis by gas chromatography A5.1.2 Other oil-wet sponge analysis techniques A5.2 Water-wet sponge analysis A5.3 Literature Appendix 6 Conversion from hydrostatic to uniaxial strain conditions Points Index

340 341 341 342 343 344 345 348 349

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List of Figures (p) denotes photo 2.1 2.2 2.3 2.4

Economic choices for example 1 - prospect screening Economic choices for example 2 - Ekofisk Economic choices for example 3 - project optimisation Economic choices in Opco example

3.1 Flow diagram for core analysis planning 4.1 4.2 4.3 4.4

Recommended flow diagram for basic core analysis Recommended flow diagram for special core analysis (p) Longitudinal CT-scans (tomograms) of a core plug (p) Flow diagram highlighting core analysis data review

5.1 5.2 5.3 5.4 5.5 5.6

Drilling plugs with liquid nitrogen (p) Unconsolidated sample cleaning apparatus at KSEPL (p) A conventional drying oven (p) Illustration of the principle of critical point drying A sample after CPD (p) A sample after air drying (p)

6.1 Bulk volume by buoyancy in mercury at KSEPL (p) 6.2 Pycnometer at KSEPL (p) 6.3 An automated pycnometer (p) 6.4 Grain volume by buoyancy at KSEPL (p) 6.5 Schematic of a typical Boyle's law porosimeter 6.6 A typical Hassler-type core holder 6.7 Capability for permeability anisotropy and air permeability measurements at KSEPL (p) 6.8 Air permeameter at KSEPL (p) 6.9 Schematic of a probe permeameter 6.10 Dean-Stark apparatus at KSEPL (p) 7.1 7.2 7.3 7.4 7.5

Schematic of stressed brine permeability Schematic of pulse decay permeameter Schematic of flow paths in whole core horizontal permeability measurements Schematic of flow paths in whole core vertical permeability measurements Whole core stressed porosity and FRF at CRC

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Capillary pressure curve parameters An Autopore 9220 (p) Penetrometers for an Autopore 9200/9220 Schematic of mercury injection apparatus Schematic of stressed mercury/air capillary pressure apparatus Schematic of coreholder for high-speed centrifuge Schematic of pressure equilibrium cell

9.1 9.2 9.3 9.4

Schematic of formation resistivity factor cell Typical I-Sw relationships Hysteresis in the I-Sw relationship View of the cell for resistivity index by pressure equilibrium method, and oil/water capillary pressure curves (p) 9.5 Schematic of resistivity index by continuous injection 9.6 Multiple resistivity index by continuous injection cells at KSEPL (p) 9.7 Schematic of Qv by membrane potential 9.8 Membrane potential measurement at KSEPL (p) 9.9 Co as a function of Cw for a shaly sandstone 9.10 CEC by conductometric titration at KSEPL (p) 10.1 Wettability concepts 10.2 Initial water saturation on primary and secondary drainage -water-wet system 10.3 Diagram showing the difference between initial water saturation on primary vs secondary drainage 10.4 Amott and USBM wettability indices 10.5 Interfacial tension by pendant-drop apparatus (p) 10.6 De Nuoy balance at KSEPL (p) 11.1 Relative permeability curves 11.2 Effect of wettability on relative permeability 11.3 Schematic of steady-state apparatus at KSEPL 11.4 Schematic of core holder for centrifuge relative permeability measurements 11.5 Interior of centrifuge apparatus for relative permeability at KSEPL (p) 11.6 Comparison of centrifuge and steady-state method (first drainage with n-decane/nitrogen, Berea sandstone) 11.7 Schematic of unsteady-state apparatus at KSEPL (p) 11.8 Comparison of steady-state and unsteady-state (Welge) methods

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12.1 12.2 12.3 12.4

Schematic of first triaxial compaction apparatus at KSEPL Schematic of second triaxial compaction apparatus at KSEPL Radial displacement transducer Typical compaction curve showing axial displacement as a function of pore fluid pressure during uniaxial compaction under pore pressure depletion conditions. 12.5 Brinell Hardness equipment at KSEPL (p) 12.6 Pressure cell for thick-waIled-cylinder (TWC) strength test 12.7 Samples after thick-waIled-cylinder (TWC) testing (p) 12.8 Unconfined Compressive Strength (UCS) at KSEPL 13.1 13.2 13.3 13.4 13.5 13.6 13.7

A typical grain size analysis report Grain size by laser diffraction (p) Sample is immersed in toluene Weight change with time indicates residual saturation Typical residual-initial curve from counter current imbibition measurements Automated compatibility flooding set-up Typical acid response curve

14.1 Schematic of UVC cell at KSEPL 14.2 Acoustic transmission anisotropy 14.3 A representation of APEX data 14.4 Schematic of EMPRESS at KSEPL 14.5 Schematic of CAPRICI 14.6 CAPRICI at KSEPL (p) 14.7 REPARC-3 equipment at KSEPL (p) 14.8 Critical gas saturation experiment at KSEPL (p) 14.9 NMR spectrum from a rock sample 14.10 NMR spectrometer at KSEPL (p)

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A1.1 Economic choices for prospect screening core analysis A1.2 Economic choices for optimisation core analysis A1.3 Economic choices in selecting core analysis laboratory A2.l CT-scanner at KSEPL (p) A2.2 Scanning of core material using CT-scanning A2.3 Natural core gamma ray scanner (p) A2.4 A coreslab image A3.l An SEM secondary electron (SE) image A3.2 An SEM back scattered (BSE) image A3.3 An SEM cathodoluminescence (CL) image A3.4 Quantitative analysis from SEM A3.5 A thin-section image A3.6 Analysis of the thin-section image A4.l Autopore penetrometers used for drill cuttings analysis

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List of Tables 4.1 Information from geological evaluation 4.2 Basic core analysis parameters and their uses 4.3 Information derived from core preparation 5.1 Laboratory comparison for core preparation 5.2 Summary of cost and timing in core preparation 10.1 Definitions of wettability 12.1 Brinell hardness number suggested loading schemes A3.1 Image Analysis Regression Statistics

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Introduction

Core analysis encompasses techniques used to derive formation properties from core material taken from the well-bore. The techniques generally involve measurement on plug samples of the core material. In most cases, the sample should be maintained in or restored to a state that would be representative of the state of the material in the formation and may, for example, necessitate the application of appropriate stresses and/or temperature. In other cases, measurements are made on the matrix material itself without regard to representative state. Measurements range from the simplest determinations of porosity to the most complicated measurement such as three phase relative permeability measurement at reservoir conditions. Core analysis measurements are of interest to a wide range of disciplines in EP from petrophysics, geology and reservoir engineering to drilling, production and exploration. Because core analysis has so many customers, it must be a focus of the integrated efforts of PE teams throughout Shell.

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About this manual

The core analysis manual presents a strategy and plan for obtaining the highest quality data and maximising the value from core analysis measurements. All too often core analysis fails to get the engineering attention that it deserves. Frequently, core analysis planning is done poorly, if at all, and the results of such efforts in terms of data acquired can often be confused and contradictory. Yet core analysis remains an important source of critical information for quantifying reservoir models and calibrating formation evaluation tools like wireline logging. As the construction of reservoir models becomes more sophisticated, the demand on acquiring properly measured formation properties using core analysis becomes that much more important. This manual is about the many facets of core analysis, but the authors have taken the approach that business processes involving core analysis need to be "re-engineered" to reflect the business needs of Shell EP companies in the '90's. Two important business processes begin this manual and they are: •

evaluating economic impact of core analysis and

•

planning a core analysis programme.

Chapters 1 to 4 address economic and planning issues of core analysis. While core analysis can be expensive, the value of core analysis is generally much greater. Obtaining proper value for a given expenditure is key to hydrocarbon resource management. The economics of core analysis is the subject of Chapter 2 and is based on value of information concepts. Several examples are given to allow PE staff to realise the value of their own core analysis projects. Once core analysis economics are assessed, a detailed core analysis programme should be assembled. The subject of Chapter 3 addresses the needs of core analysis planning in an integrated multi-disciplinary environment. As part of the planning process consultation with core analysis experts at SIPM/KSEPL is recommended. Proper planning leads to the delivery of highquality core analysis data for the development of the hydrocarbon resource.

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Chapter 4 discusses in more detail the issues to be addressed in getting started with a core analysis project. Chapter 4 should be used as a guideline for those who are starting afresh with a core analysis project. Every issue mentioned in Chapter 4 merits attention although the critical items deserve the most attention. The remainder of the manual describes the most commonly used core analysis techniques performed today. The methods are included to ensure that PE staff are acquainted with general methodology of core analysis. The method descriptions are aimed to be sufficiently detailed to assist with planning, to allow optimisation of core measurements and to provide a means of ascertaining quality and consistency. Beginning with Chapter 5, a reasonably comprehensive survey of core analysis preparation techniques is given. From Chapter 6 onwards the progression from basic analysis to aspects of special core analysis is presented. Chapter 13 addresses supplementary analyses and chapter 14 presents an overview of research activities that represent a glimpse into the probable future of core analysis activities. By necessity, brevity has been imposed in order to allow the manual to be of reasonable length. Each measurement technique is described by the following scheme: •

principle - brief description of how the measurement is made

•

points - remarks that highlight critical aspects of the measurement. An assessment of every measurement is made whether the technique is recommended, acceptable or not recommended. The not recommended assessment is not to say that the technique always produces incorrect data but that the technique has inherent tendencies which make obtaining reliable data more difficult. General issues such as limitations, advantages and disadvantages are also addressed, including possible data handling issues.

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•

precision/accuracy - an estimate of uncertainty in measurement accuracy. The estimate is either expressed in measurement precision, repeatability or uncertainty in true value of a measured parameter.

•

price/timing/number of samples - is designed to understand approximate costs, how long an experiment can take and an appropriate number of samples balancing cost and time involved. Prices are meant to be approximate and can vary significantly (by up to 40%) between regions depending on market competition and local factors. Timing addresses the length of time a measurement takes which should assist in the scheduling and timing of a core analysis project. Recommended number of samples is the recommended minimum number to ensure reasonable characterisation of a rock type in a core analysis programme. More samples should be considered if the justification through Value of Information shows the measurement value to be very great, as might happen with any special core analysis measurement.

•

peripheral measurements - necessary ancillary measurements which quantify measurement consistency, check quality and assist in data interpretation. Without peripheral measurements, core analysis data are difficult to apply. Peripheral measurements deserve considerable attention and are the key to establishing a quality core analysis programme.

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The Appendices contain information that may be useful relating to CT-scanning and CT-scanning interpretation. While the manual addresses measurements made from samples taken from whole core, core analysis can also be made on other material sources such as sidewall cuttings and drill cuttings. There are many specialised core analysis techniques which are not included in this manual such as coal bed methane analysis. The authors have not attempted to provide an exhaustive manual on core analysis but to address the core analyses used in day-to-day Shell operations. This manual completes a sequence of manuals on core, which are Core Handling, EP 93-2200, and Geological Core Analysis, (in preparation).

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Problems solved by core analysis

Core analysis can be used to answer many questions related to the production of hydrocarbons from the subsurface. Besides providing the opportunity to directly see and describe the rock formations of interest, core analysis also provides: •

Detailed description of geological environment and setting including variation of lithology, rock composition and rock type along the length of the core.

•

Important petrographic information can be obtained from microscopic examination of the core material using techniques such as thin sections, scanning electron microscopy, X-ray diffraction.

•

Non-destructive imaging using the CT-scanner or core gamma scanner.

•

Values of routine petrophysical formation properties as a function of depth: - porosity; - permeability; - grain density; - oil and water saturations.

•

Log interpretation parameter values: - Archies lithologic exponent, m; - Archies saturation exponent, n; - Waxman-Smits parameters, clay conductivity, m* and n*; - Grain and fluid densities.

•

Distribution of fluids within the hydrocarbon column from capillary pressure measurements.

•

Grain size distribution data for engineering application in well completion programmes and for geological application in assessing heterogeneity and depositional environment.

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•

Values of special formation properties for reservoir engineering such as: - wettability; - relative permeability: - effective permeability to oil, - effective permeability to water; - initial water saturation; - residual oil saturation.

•

Values of exploration formation properties: - shear and compressional acoustic velocity; - acoustic impedance.

•

Values of rock mechanical parameters used in production engineering and platform design: - rock strength; - compressibility; - compaction; - waterflood sensitivity.

•

Tests for non-reservoir rock, seal analysis and source rock analysis.

•

Fluid measurements are also important to provide a complete picture of the downhole environment. Brine properties such as composition and conductivity, oil properties such as viscosity, acid and base number and identification of gas/oil using High Pressure Liquid Chromatography (see HPLC manual).

•

Measurement of the interfacial tension measurement between oil and water used in scaling mercury/air capillary pressure curves to oil/water systems.

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SIPM/KSEPL recommendation on core analysis

Core analysis remains one of the critical sources of formation data necessary for proper development planning and field management. Careful multi-disciplinary core analysis planning in the integrated PE environment is necessary for acquisition of high-quality core analysis data, avoiding sub-optimal data acquisition and improving data application. Proper economic analysis, including "Value of Information" concepts, are important in appreciating the role core analysis plays in field development and hydrocarbon resource management. SIPM recommends the application of Shell core analysis technology which has been developed at Shell E&P laboratories world-wide. Accordingly, critical special core analysis measurements should be performed at KSEPL, Rijswijk, where possible, or at a core contractor recommended by SIPM/KSEPL. At the very least, major core analysis programmes should involve SIPM/KSEPL, who will develop and maintain a strategy of core contractor quality assurance. Consultation with SIPM EPD/22 and KSEPL RR/37 (who will act as focal point for KSEPL) is recommended for any core analysis questions including core data interpretation.

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1.4

Availability of other Shell E&P Laboratories for core analysis

1.4.1

Bellaire Technology Center (BTC), Houston, Texas

SIPM has reached an agreement with SOC which allows Bellaire Technology Center (formerly known as Bellaire Research Center) to provide core analysis services for SIPM when mutually convenient. Should KSEPL be unavailable to perform any critical core analysis, it is now possible to arrange, via SIPM, for work to be performed at Bellaire Technology Center, Houston, when facilities there are available. Bellaire Technology Center has a long history of excellence in core analysis and has developed numerous Shell standard techniques over the years. SIPM regards BTC as a source of high quality core analysis data which incorporates Shell technology. Arrangements should be made through EPD/222. Consult with EPD/222 for further information. 1.4.2

Calgary Research Center (CRC), Calgary, Alberta

Calgary Research Center has developed considerable expertise in whole core analysis (see chapter 7). These capabilities can be used for Group whole core analysis when mutually convenient and should be arranged by SIPM EPD/222.

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Quality in core analysis

The organising principle behind this manual is the central issue of quality in core analysis. Quality is a critical issue. How often does a user of core analysis ponder the question:

How valid are these core analysis data? The process of formulating an answer to this question begins with the recognition that core material, by nature, is heterogeneous. This fact should be incorporated into every aspect of the acquisition of core analysis data from inception to final data delivery. Without incorporating quality into the performance of the core analysis project, data quality assessment is very difficult to perform. This manual endeavours to build quality into the process of core analysis measurement through prior planning and making the correct suite of core analysis measurements. These steps are summarised as follows (and more details are provided in the appropriate sections in the manual): •

core analysis planning - much attention is focused on this activity because data assessment is a multi-disciplinary activity. For example, rock sample selection must involve a geologist for proper attention to rock type.

•

sample screening - this step is frequently omitted but all too often core analysis measurements are performed on samples that are unfit for measurement even though they may appear as perfectly formed cylinders while they may contain internal heterogeneities invisible from the outside.

•

peripheral measurements - this manual emphasises measurements that can and should be performed to determine data consistency, to check data quality or to improve data application. Certain parameters are critical in the determination of core analysis quantities. The most important parameter in much of core analysis is the pore volume because it is the fundamental determinant of the porosity and all saturation measurements are normalised to the pore volume. Thus any error in pore volume is translated directly into errors in saturation.

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•

core analysis contractors - much of the core analysis performed for Shell companies is done by contractors. Their results suffer from a high degree of variability in quality. Experience shows that it is important not only to use a reputable contractor laboratory but to use the most reputable personnel within those organisations. It is therefore advisable to pay attention to the individuals performing the core analysis within contractor labs and, where possible, to identify the key personnel who can provide quality data. It is insufficient to only trust the manager or sales representative. In general it is preferable to select a core analysis vendor that is capable of carrying out the bulk of the core analysis programme to reduce handling and transportation that degrades core.

•

old core analysis data - many of the techniques presented in this manual can be applied to the examination of old core analysis data. The quality of old core analysis data is difficult to determine when quality assessment planning has been omitted. But the thinking and planning for a quality core analysis programme can assist in determining how old core analysis data may be assessed. Unfortunately, determining the quality of old core analysis is, at best, uncertain.

•

application of core data - this manual is designed to allow core analysis measurements to be performed in which quality is assured so that core analysis data can be more easily applied. If core analysis is done with proper regard to geological setting, rock typing and sample screening incorporating proper wettability considerations, then the core data should be suitable for application in formation evaluation or reservoir simulation.

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Literature

SIPM EPD/22/3 SIPM Coring and Core Analysis Series Bulletin 1: Core Justification. EP 88-1465, June 1988. Advances in EP research 1990-1 SIRM research brief. The Log Analyst Special Issue - Core Analysis 1991 European Symposia Abstracts - SCA and Formation Evaluation, September-October 1991 van der Grijp KH. and van den Oord R.J. Well-Site Hydrocarbon Differentation using High Performance Liquid Chromatography (HPLC) EP 93-0550. Keelan, D.K., Core analysis for aid in reservoir description JPT November 1982. Maas, J., Boutkan, V., Ligthelm, D., Fit-for-purpose basic reservoir data Production newsletter, February 1993. Skopec, R.A, Recent advances in rock characterization The Log Analyst, May-June 1992, p 270. Tannemaat, R., Core analysis methods EP 59259, BSP, April 1983. Haeringen, A. van, Results of a conventional core analysis contractor comparison exercise. EP 89-0234. Schipper, B.A., Aperen, A.E. van, Looyestijn, W.J., Quality assessment of core analysis procedures of Core Laboratories Aberdeen. EP 90-1886. Schipper, B.A., Aperen, A.E. van, Looyestijn, W.J., Quality assessment of core analysis procedures of Poroperm-Geochem Limited, Chester. EP 90-1901 Schipper, B.A., Hofman, J.P., Quality assessment of core analysis procedures of Corex Services Ltd, Aberdeen. RKTR.93.052, May 1993 (EP 93-1296). Schipper, B.A, Oord, R.J. van den, Adams, S.A., Quality core analysis - essential to our business! Production Newsletter July/August 1992. Schipper, B.A. Quality Assessment of the Core Analysis Services of Simon Petroleum Testing, Aberdeen. RKTR.94.089, May 1994 (EP 94-0974)

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Economics of core analysis

Core analysis projects are subject to the necessity and rigor of economic justification. It is important that each project be judged by its economic impact and not just solely on cost. Careful economic justification generally shows that core analysis projects have a far greater economic value than their cost. By recognising the economic benefits of core analysis, core analysis projects can be developed that are optimised both technically and economically. Such justification applies to all aspects of coring and core analysis and to data acquisition in general. The economics of core analysis is driven largely by its role in reducing uncertainty in formation properties, particularly hydrocarbon volume and hydrocarbon saturation. While accurate hydrocarbon volume determination depends on a number of variables such as geological architecture and reservoir distribution, a critical initial step is the determination of hydrocarbon saturation. Hydrocarbon saturation is mostly obtained from wireline resistivity logs. However, the actual relationship between hydrocarbon saturation and log resistivity is extremely variable, making calibration with core measurements an essential step. One Opco has estimated that an accurate understanding of their resistivity index-saturation (I-Sw) relations is worth at least US $12.5 million annually in effective economic benefit, which is far more than the expenditure on core analysis. Other core analysis parameters are critical to decisions in managing a hydrocarbon resource. For example, sizing waterflood or water handling facilities can depend critically on relative permeability parameters, such as water endpoint relative permeability. Again economic impact studies show the value of the core analysis project usually far exceeds project cost. To determine the economic impact of a core analysis programme, Value of Information (VOI) concepts will be used which are detailed in Appendix 1. A summary of value of information concepts is given in section 2.1 and examples of how value of information is applied are given for a number of cases in section 2.2. Further discussion as to applications of VOI calculations are provided there.

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Value of Information (VOl)

In making a decision whether to gather information, it is possible to determine the economic value of the information itself. Value of Information (VOl) concepts rationalise the decision as an act of choosing between alternatives, each of which have an economic impact. One alternative involves the gathering of the required (core analysis) information and the economic impact is calculated based upon the information provided. The other alternative is the economic impact calculated in the absence of the information. The difference in economic impact between the two alternatives is the value of information. At this point the value of information does not include the cost of the information gathering itself. Economic impact is calculated as Net Present Value (NPV). Once the value of information is calculated, the decision whether to proceed or not is then based on the value of the information versus the cost of the information gathering. If the value of information is larger (see section 2.3 on Justification) than the cost of information gathering, then it is economically justified to obtain the information. The difference between the value of information and the cost of the information gathering is called the Value of Appraisal. For core analysis, the economic alternatives are simply whether to proceed or not with the core analysis project. The fundamental choice of whether to proceed with a core analysis project is addressed in two different ways: • prospect screening where there is very large uncertainty typically associated with exploration appraisal; • project optimisation, where quantifying rock and fluid properties can narrow design criteria in development planning. The basic theory behind the VOl calculation is presented in Appendix 1 (Appendix 1.1 for prospect screening and Appendix 1.2 for optimisation). In the next sections, the VOl nomenclature and a summary of the concepts is presented so that the example presented in section 2.2 can be better understood but the reader is referred to Appendix 1 for complete details.

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VOl Nomenclature

The terms used in VOl calculations in this manual are defined here. NPV

Net Present Value - economic impact of a development is expressed in terms of net present value. (-NPV denotes negative value.)

NPVi

Net Present Value of ith branch

P(high)

Probability of having high reserves; taken to be 0.33 because P(high), P(medium) and P(low) are taken to have equal probability of occurring.

P(low)

Probability of having low reserves; taken to be 0.33.

P(medium)

Probability of having medium reserves; taken to be 0.33.

POCM

Probability of correct measurement in core analysis. Value is very high for Shell E & P laboratories and about 0.75 for core contractor laboratories. (0.75 is a very conservative number based on estimates from Shell core analysis experts, some of whom feel that it is much lower especially for many special core analysis services such as resistivity index, relative permeability and compressibility.)

POS .

Probability of success.

VOA

Value of Appraisal- value of information (VOl) minus the cost of gathering the information.

VOl

Value of Information - value of information itself without any regard to the cost of gathering the information.

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Value of prospect screening - Summary

In prospect screening discussed in Appendix 1.1, the VOl equation shows that information has a high value and that information gathering is economically justified. The justification stems mainly from the fact that expenditure for data acquisition is done to eliminate the possibility of making an unprofitable investment. Data acquisition is done to save on the loss of NPV if the field turns out to have insufficient hydrocarbon reserves. The VOl calculation covers all aspects of data acquisition from seismic data acquisition, wireline logging, production testing and core analysis. The VOl does not distinguish the value of the core analysis by itself and some method must by realised to assign benefit to the core analysis. In fact, the VOl of acquiring data is so high that it is easy to justify core analysis in exploration appraisal situations. Factors that must be known to properly evaluate the VOl for prospect screening are: •

probability of success, POS;

•

the economic impact of the development if reserves are not present, -NPV3, which denotes a loss;

•

a method of assigning the benefit of the VOl calculation to core analysis as part of overall data acquisition.

Using these factors in equation (A1.4) determines VOl for prospect screening.

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Value of project optimisation - Summary

In optimisation discussed in Appendix 1.2, the VOI is calculated to assess the economic impact of reducing uncertainty by performing the core analysis project. The VOI calculation is based on reservoir simulation results which are aimed at determining the NPV impact when the uncertainty in a critical parameter is examined. The sensitivity analysis for this critical parameter is done by using the maximum and minimum parameter values. In optimisation calculations, the total benefit of VOI calculation is due to the core analysis project. A VOI optimisation calculation requires the economic impact of 4 scenarios to be performed usually by reservoir simulation. For a given rock parameter, such as relative permeability, 4 cases are considered as follows: •

high reserves, optimised high with economic impact, NPV1, in this case, the most optimistic scenarios are used which translates into using a high oil relative permeability curve and a low water relative permeability curve and optimistic endpoint saturations;

•

low reserves, optimised low with economic impact, NPV3, in this case, the most pessimistic scenario is used e.g. a low oil relative permeability curve and a high water relative permeability curve and pessimistic endpoint saturations;

•

high reserves, base case with economic impact, NPV 4, is the case where an average case is used which might be using average relative permeability curves with optimistic endpoint saturations;

•

low reserves, base case with economic impact, NPV6, is the case where an average case is used which might be using average relative permeability curves with pessimistic endpoint saturations.

The results of these cases are used in equation (A1.8) to determine VOI for project optimisation. As described in Appendix 1.2, NPV2 and NPV5 do not enter in the calculation of VOI.

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Value of correct core analysis data - Summary

VOI methods can be used to evaluate any economic decision. Section 2.3 describes other aspects of VOI calculations pertinent to core analysis but an important example is the value of correctly measured data. Basing decisions on incorrectly measured data carries risk and this is discussed in Appendix 1.3. It turns out that using incorrect data puts at risk the primary benefit of the development and it is in fact, worse to use incorrect data than to have no data. These rough calculations can assess the risk of inaccurately measured data. Such a calculation requires: •

probability of success, POS;

•

the economic impact of the development case, NPV1;

•

the economic impact of the development if reserves are not proven, NPV3.

Equation (A1.12) is used to determine VOI of correctly measured data. It is not always possible to use KSEPL or another Shell E&P laboratory due to the demands of accessibility, regional preferences or the availability of Shell E&P laboratories. It is nevertheless true that improperly measured data carries a significant and generally underestimated risk.

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Value of information examples as applied to core analysis projects

In this section, a number of VOI examples will be shown to demonstrate how VOI techniques can be applied to justify core analysis projects. Both VOI and VOA are calculated. One of the examples (Example 4 - Section 2.2.4) is an Opco VOI example used recently to justify a core analysis programme. NOTE: For figures in this section, a red shaded rectangle denotes a human decision while a yellow shaded ellipse represents the consequences of measurement, which are various outcomes each with a given probability of occurring. Positive economic impact is given as NPVi. A negative impact is shown as -NPVi.

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Example 1 - Prospect Screening (Unconsolidated Sandstone)

The details of prospect screening are given in Appendix 1.1. Economic options are shown in Figure 2.1. The option of performing core analysis is clearly indicated by "Yes". However, the results of core analysis are to indicate whether or not to proceed with development given with a weighting by the probability of success. Net present value figures for each option are shown on the right hand side which are used to quantify the value of core analysis. Without core analysis, the "No" option, proceeding with development carries the risk of attempting to develop insufficient reserves. Avoiding the loss in an unprofitable development is the value of the core analysis.

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An unconsolidated sandstone play has an estimated probability of success of 0.5. A suite of rock measurements for the evaluation of this play is given in section 3.2.1. The core and core evaluation cost is DFL 5 mIn. The entire data acquisition programme including seismic and well testing is US $15 mIn. Proposed development costs include a platform and facilities at a cost of US $400 mIn. Economic impact if the reserves are inadequate is a loss of US $200 mIn. Here in example 1,

POS NPV3

= 0.5 = - US $200 mIn.

Equation (A1.4) yields

VOl

= US $100 mln

The value of information is US $100 mln and the value of appraisal is obtained by subtracting a cost of US $15 mln to obtain: VOA

= VOI - Cost = US $85 mln

Note that the value of information here reduces the uncertainty to zero i.e. the probability of success is now unity, which is the combined effect of all the data gathered and not just core analysis. The benefit assigned to core analysis, is the amount by which the core analysis increases the probability of success. In prospect screening, core analysis is easily justified because the economic benefits are so large. The reader is urged to consider section 2.3 on other aspects of VOI calculations for core analysis.

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Example 2 - Ekofisk

Ekofisk has experienced surface subsidence which has cost a lot of money for remediation. This problem might have been avoided or its impact reduced had sufficient special core analysis, particularly compaction measurements, been performed to obtain critical data necessary for field development. Hindsight is able to provide the economic impact of the various decisions made in field development. Economic choices are shown in Figure 2.2. The probability of success is estimated at 0.75. Net present value is presented on the right hand side of the figure. Remediation is estimated conservatively at US $500 million.

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A coring and core analysis programme would have cost about US $2 million. But the cost of repairing the Ekofisk structure is about US $500 million. Figure 2.2 summarises the economic choices. POS is estimated as 0.75. Here, in example 2,

POS NPV3

= 0.75 = - US $500 mIn.

Equation (A1.4) yields

VOl

= US $125 mIn.

The value of information is US $125 mln and the value of appraisal is obtained by subtracting a cost of US $2 mln to obtain: VOA

= US $123 mIn.

The value of core analysis is far greater than the cost of the core analysis project. With hindsight, it is reasonable to assign most of the value of acquisition entirely to core analysis. However, in a prospect screening situation, it is not reasonable to do this. Even if the probability of success were 0.90, then the value of information becomes US $50 million and the value of appraisal becomes US $48 million, which indicate significant value in core analysis.

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2.2.3 Example 3 - Project optimisation Much special core analysis is performed for field development where core data allows project optimisation. The details of optimisation economics is given in Appendix 1.2. The economic choices are shown in Figure 2.3. Net present value figures are shown on the right hand side and should be obtained from reservoir engineering computer simulation as well as incorporating costs estimated from production engineering. The value in core analysis lies in being able to ensure that the project is properly sized. Project optimisation occurs because of reduction in uncertainty of a key parameter determined from simulation of the process under study.

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A water-flood development project depends on detailed knowledge of relative permeability and capillary pressure. Reservoir simulation shows that the economic impact for the optimised high reserves case is US $20 mln, for the high reserves but unoptimised is US $10 mln and for the low reserves case optimised is US $8 mln and that for the unoptimised low reserves case is US $3 mIn. Core is to be taken with special precautions for preserving wettability and is to cost about US $200,000 including collection of appropriate fluids, well-site core handling and transportation. The total cost for taking core and performing core analysis is US $0.5 mIn. Equation (A1.8) yields:

VOl

= 0.33 * { 20 + 8 - 10 - 3 } = US $5 mIn.

The value of information calculation here results in a value of information of US $5 mIn. The cost of the core and core analysis programme is US $1 mIn. Therefore, the value of appraisal, VOA, is VOA

= VOI - cost = US $4.5 mIn.

Here the entire value of information benefit can be assigned entirely to the core analysis project.

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Example 4 - An Opco VOl Example

In this example, a well is being drilled. A core analysis, project can quantify the permeability development below the gas-water contact and reduce the uncertainty in predicting aquifer behaviour before the field is put on production. With proper characterisation of the aquifer, the possibility exists that aquifer influx may be limited which would avoid the drilling of an extra well. Without core analysis the drilling of an extra well is necessarily included in the development plan. Net present value figures were supplied from the Opco. Economic choices (simplified) are shown in Figure 2.4.

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The cost of the core analysis project including coring is estimated at DFL 500,000 including DFL 130,000 for core analysis. The core analysis project called for the acquisition of 4 coring runs below the GWC for a total of 72 m. In fact, the original Opco analysis included the option of continuous coring for 150 m which was found to have a slightly lower value of information and is not included here to maintain simplicity. The values of the top branch, Vyes' and bottom branch, Vno' are given by: Vyes Vno

= 0.5 * 0.4 * -12.36 + 0.5 * 0.6 * 12.36 = - 6.18 mln = DFL -12.36 mln VOl

= Vyes - Vno = DFL 6.18 mln

and thus the value of appraisal is obtained by subtracting cost: VOA

= VOI - cost

= DFL 5.68 mIn.

A value of appraisal of DFL 5.68 mln is calculated because of the probability that the drilling of an extra well can be avoided.

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Core analysis aspects of VOl

This section deals with issues that arise in using VOI calculations for core analysis justification. In some ways these issues can be considered consequences or corollaries to the examples shown in the previous section. •

Justification - VOI calculations should show a value of information, VOI, that is many times programme cost, i.e. at least three times. Thus, the appraisal value, VOA, should be at least twice the cost of the project. VOI calculations which show less value than this are not justified economically. This is recommended as a reasonable guide to using VOI calculations for core analysis projects.

•

Need for additional core - examples in section 2.2.1 and 2.2.2 discuss the situation of justifying initial core in an appraisal situation. VOl methods can be used equally well to justify the need for additional core even if there exists core from wells. Perhaps the previous cores were also justified by value of information techniques which indicated large positive value in core analysis. However, if the need for additional core is present then it must be due to some "failure" of previous cores. By "failure" we include the following: - previous cores missed an important target zone; - poor recovery in target zone (perhaps due to poor planning which allowed poor coring techniques and overlooked poor core handling. If the target zone is inherently difficult to core, then you must demonstrate that new insights into the coring process have increased the probability of success); - incomplete planning as to core analysis needs (there now exists previously unanticipated needs for core material such as to measure a critical parameter like compressibility); - insufficient material (not enough material available from previous cores); - poorly preserved core which indicates that the remaining core is unsuitable for measurement.

The justification for additional core carries with it the need to evaluate previous VOI calculations.

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•

What if coring risks the well? If the coring programme carries with it an identifiable risk of failure such as damaging an expensive well, such contingencies can be incorporated into the value of information calculation which is done by adding more branches allowing the possibility of failure. This is similar to the calculation in the Appendix 1.3 which shows the problem of incorrectly measuring core analysis parameters. There, the extra risk is quantified by the parameter POCM, probability of correct measurement. In the same manner, the risk to a well is carried out by quantifying the risk that coring has on the well. Once that risk is quantified, then the VOl calculation will show a diminished value because the risk of losing the well is incorporated. If the VOl calculation is value neutral indicating that coring may be too risky, then additional scenarios can be evaluated such as by coring on by-pass. In coring on bypass, after a target zone has been drilled and logged and identified, the well is sidetracked above the target zone and then cored through the target zone. This technique has been employed in drilling the deepwater Gulf of Mexico turbidites and has the advantage that the coring point is clearly known and the amount of core required is clearly identified.

•

VOl Lookback - it is a good idea to maintain the examples of VOl calculations to ensure that the assumptions made for the VOl calculation were reasonable. VOl calculations assume that the information will be successfully gathered. However, core analysis programmes can fail such as through bad coring practices, bad core handling techniques, or even poor core measurement techniques. In the case of such failures, it is likely that the full VOl was not obtained and this should be reviewed for future VOl calculations.

•

Value and planning - after VOl has shown that the core analysis programme is of significant value, the task at hand is to ensure proper planning to achieve the programme objectives. We hope that recognising the value of a core analysis programme provides inspiration for carrying out the critical aspect of core analysis, namely planning the analysis programme in an integrated PE environment. Planning is the subject of the next two chapters.

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Literature

Demirmen, F., Subsurface Appraisal Justification: The Value of Information June, 1994 EP 94-0585 E&P Economic Guidelines Report EP 93-2150, October, 1993.

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Planning a core analysis programme

Group experience indicates that coring and/or core analysis is usually poorly planned, is left to a late stage, and results in under utilisation and poor application of expensive core material and core data. SIPM recommends core analysis project planning in order that the proper multidisciplinary attention is paid to core analysis. Petrophysics, geology, reservoir engineering and other disciplines have significant input into the development of an effective core analysis programme. The core analysis programme allows for consensus building in the multi-disciplinary environment and assists in the finalisation of programme goals. With proper planning core analysis projects are better able to deliver required data in a timely fashion. Core analysis planning is shown in a flow diagram in Figure 3.1. Within the guidelines established for each Opco, coring and core requirements are defined for the prospect/field with input from each discipline. Once the design of the core analysis programme has reached consensus, the implementation of the programme can then take place. The recommendation for core analysis planning is to follow the outline given in section 3.2. The programme outline covers all items that impact the core analysis programme including the core acquisition itself. The list given in section 3.2 is extensive but is done in such a way as to maximise the information that can be obtained from core analysis and to assist in data interpretation. Experience has shown that all aspects of the core analysis programme can be critically important for subsequent data application. Of course, some items may not be necessary for any given application but it is nevertheless worthwhile to consider the impact each item can have on programme implementation. Each item addressed in the outline represents a separate section in chapter 4, where appropriate detail is found. Chapter 4 aims to present easy options for core analysis planners. Many of the coring and core handling considerations are covered in the "Core Handling Manual", EP 93-2200, but are included here in summary form for completeness.

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Core analysis project planning provides the following benefits: •

maximisation of quality in core analysis measurement through planning and selection of the appropriate measurement suite;

•

obtaining input and consensus from a multidisciplinary EP team so that the majority of the core analysis needs can be anticipated and incorporated and reduce the need for later remeasurement;

•

definition of clear timing constraints in order to properly impact appraisal or field development decisions.

•

optimisation of core analysis programme potentially eliminating the need for future supplementary measurements by clearly defining expectations of the core analysis measurements. This is especially valuable if additional coring can be avoided;

•

roles and responsibilities of each team member within a core analysis project schedule are clearly defined. Timely advice from each team member assists in on-time data delivery.

•

careful core selection and proper core screening increase the likelihood of measurement on the most representative samples;

•

an overall core analysis programme allows the core analysts to appreciate the entire scope of the project and to meet mutually agreed deadlines. Better planning and scheduling usually result;

•

core analysis projects can be more easily justified by using value of information concepts and proper consideration of economic benefits;

•

greater confidence and better utilisation of core analysis data is achieved. Improved application core analysis data in field development and resource management leads to improved field development planning;

•

better project management which includes better continuity during staff changes because expectations and scheduling are clearly noted;

•

easier presentation of core analysis plans and results to partners and other stakeholders in the hydrocarbon resource.

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Planning in an integrated PE team

The multi-disciplinary planning of core analysis produces a better core analysis program with input from each PE discipline. In order to encourage such involvement this section addresses the roles and responsibilities of each PE discipline involved: namely petrophysics, geology and reservoir engineering. Other disciplines such as production technology and exploration functions can also have needs that can be addressed through core analysis. The value of the integrated team approach to core analysis is the synergy that can be obtained when each PE discipline contributes to the planning of the core analysis programme. More details of the requirements of the integrated PE team are given in section 4.2. It has been customary for the petrophysicist and geologist to arrange coring and core analysis programmes. In the integrated PE environment, the petrophysicist remains likely to be the focal point for core handling and core analysis. However, over time it is expected that any member of the multi-disciplinary PE team can be focal point for a core analysis programme with the assistance of this manual.

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3.1.1 Core analysis programme development With the structure as outlined in the next section it is possible to develop core analysis programmes that are agreed to by the PE team relatively quickly. At least one meeting where the integrated team assembles to review and finalise the programme is recommended. However, much of the programme development can be accomplished by discussing relevant aspects with appropriate exploration and PE staff. Important steps in putting together a core analysis programme are as follows: •

appoint the core analysis programme focal point whose responsibility is to develop the core analysis programme - this is usually the petrophysicist;

•

create a trial or "strawman" core analysis programme by inputting as much of outline as possible;

•

review and finalise the core analysis programme with the integrated team. This allows synergy and detailed discussion to take place;

•

programme justification - management review is usually necessary to allow programme implementation;

•

meet with drilling and well-site personnel (preferably at the well-site) just prior to coring to review well-site activities regarding coring, drilling parameters, and well-site core handling and transportation;

•

implement programme. The use of spreadsheets and appropriate software are of considerable aid in tracking the progress of a project and are of great assistance in subsequent project review;

•

review project and core analysis data application.

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The core analysis programme

Scope and objectives of core analysis programme See section 4.1. Summarise measurement objectives of the core analysis programme. Multi-disciplinary considerations See sections 3.1 and 4.2. Responsibilities and required input from petrophysics, geology, reservoir engineering as well as other EP disciplines e.g. drilling should be specified. Core measurements See section 4.3. Summarise the types and number of measurements. Coring considerations and well-site planning See section 4.4. Address coring parameters and operational coring considerations. Consultation with the drilling department is necessary. If core analysis programme involves old core, note any comments that were recorded during original coring operation. Core handling See section 4.5. There are two aspects to consider: At the well-site See section 4.5.1. Note any well-site handling considerations. Upon arrival of core at Laboratory See section 4.5.2. Describe actions to be done immediately at the laboratory such as scanning, photography, slabbing, core description, etc. This facilitates subsequent measurements and minimises core handling and delay.

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Core screening See section 4.6 and Appendix 2. Specify additional procedures for screening the whole core. Core sampling See section 4.7. Specify a method for selecting the most representative samples. Consult with a geologist and reservoir engineer in special core analysis projects. Core sample preparation See section 4.8. Core sample preparation considerations should be specified with special emphasis on cleaning requirements so that core handling can be minimised. Core sample screening for special core analysis See section 4.9. Specify screening measurements and screening criteria to ensure measurement samples are the most representative. Core preservation See section 4.10. Core preservation is important to allow for future work. Fluid measurements See section 4.11. Specify the types of fluid measurements. Fluid handling considerations See section 4.12. In some core analysis programmes, careful consideration must be paid to the fluids used in the core analysis such as relative permeability measurements. This section should also summarise well-site fluid acquisition, transfer methods, transport and fluid preservation.

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Sequencing and scheduling See section 4.13. Summarise the sequence of core measurements, which is important so that data delivery deadlines can be met. Costs See section 4.14. Outline costs as part of justification process. Justification - economic impact - value of informationSee Chapter 2 and section 4.15. A value of information calculation determines economic benefits of the core analysis programme. See chapter 2 for examples. Project reporting See section 4.16 on data reporting formats. Project review See sections 4.17. Include specific details about a project review with appropriate timing which is important for data application.

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An example of a core analysis programme

Scope and objectives of core analysis programme To obtain core data for log calibration and determination of input into reservoir simulation for an unconsolidated deepwater sandstone. Multi-disciplinary considerations Geologist to select facies, describe core and thin sections. Reservoir engineering to provide input as to types of displacement process of interest. Geochemical input into hydrocarbon typing. Coring and core analysis to be coordinated by petrophysics. Drilling to provide advice on mud types and additives and potential coring-bit effects. Petrophysics and reservoir engineering to determine suite of rock and fluid measurements and appropriate value of initial water saturation. Core measurements Basic measurements should be made every foot for porosity, permeability and grain density. 6-10 facies should be selected for special core analysis measurement of capillary pressure, resistivity index, porosity and permeability as a function of stress, relative permeability and compressibility. Coring considerations and well-site planning Conduct organisational meeting at well-site; ensure equipment and supplies are ready: eg core cradle, core cutter, thermometer, dry ice for freezing. Use Christensen's CoreGard RC412 bit, with extended pilot shoe. Coring rate of 10-20 m/hr is recommended. Weighted salt/PHPA/polymer mud is to be used with starch-based fluid loss additive. 30 foot core barrels - occasional 60' core barrels if at end of coring.

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A total of 180' is targeted. Overbalance should be no more than 500 psi. Core should be brought to surface very slowly. Core handling At the well site: Stabilise core by freezing with dry ice. Allow 3-4 hours for core to freeze before cutting or until temperature reaches -50°C. Mark orientation and depths on liner. Cut core into 3 foot sections and prepare for transport. Ensure that core is not bent, flexed, jarred or rotated during handling and laying down. Use core cradle. Ensure transportation arranged. Upon arrival at the lab: Check labelling and orientation. CT-scan each 3 foot section, slab frozen core; describe core. Basic core plugs should be taken every foot. Plugs to be drilled frozen. Photograph with normal and UV light. Preserve 2/3 slab for later use. Core screening Core gamma scan in addition to above steps. Core sampling For special core analysis work, at each facies longer than about 2 feet (60cm) 10 horizontal (with respect to bedding plane) plugs and 6 vertical plugs should be drilled. Each plug should be CTscanned and thin sections taken (ideally one from each end) will assist in guaranteeing uniformity. Core sample preparation Sample cleaning should be done under stress with flow through cleaning using chloroform/methanol. Several pore volumes of tetrahydrofuran should be flown through samples for relative permeability. Relative permeability samples should then be vacuum saturated with brine and then brought to initial water saturation, Swi, and then aged at reservoir temperature for 4 weeks at Swi.

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Core sample screening Special core analysis samples to be screened based on CT -scans and thin sections. Post test analysis should include sieve analysis and thin sections. Core preservation Samples should be preserved for at least 10 years so that unanticipated needs can be addressed. Fluid measurements Brine composition using ion chromatography, inductively coupled plasma and X-ray fluoresence and brine resistivity. Oil measurements should include PVT, gravity, % sulphur, cloud point, acid and base number, and viscosity. Fluid handling considerations Brine and oil samples should be obtained if possible from RFT or MDT samples. The logging tool should be heated to 130°F prior to any fluid transfer. Fluid pressure should be raised to 100 psi above reservoir pressure. During fluid transfer logging tool should be rocked or agitated. Sequencing and scheduling A deadline for preliminary core analysis data has been established for 6 months after core has arrived at the laboratory in order to meet unitisation discussion meetings to be held after 9 months. 3 months has been allowed to perform reservoir simulation to meet planning objectives.

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Costs Core preparation, slabbing, photography, CT-scans etc

US $20k

Basic core analysis (150 samples)

US $15k

Capillary pressure (20 samples)

US $20k

Resistivity index (20 samples)

US $60k

Porosity and permeability vs stress (10 samples)

US $50k

Relative permeability measurements (10 samples)

US $50k

Compressibility measurements (10 samples)

US $50k Total

US $265k

Justification - economic impact - value of information Core analysis project is designed to avoid unprofitable investment by ensuring the presence of commercial hydrocarbons. Project reporting 20 copies of all data (including raw and interpreted) data are required. Project review Preliminary review is recommended after completion of the geological description and prior to selecting samples for SCAL work. Project review scheduled for 6 months after arrival of core.

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Considerations for major lithologies

Specifying the type of core analysis to be done also depends on the lithology to be studied. The major lithologies and related general considerations in a core analysis programme are given as follows: Clean (consolidated) sandstones • Coring is usually straight forward. • All core analysis methods can be applied. • Minimal Qv and CEC analyses are required. • Mineralogy can be limited to special core analysis samples. • Special precautions are not required for plugging or cleaning beyond usual care. • Drying at 105°C is acceptable. • Samples are not usually sensitive to fresh water. Unconsolidated sandstones • Requires special coring bits, core barrels and care in coring considerations (see Core Handling Manual) • Core stabilisation, such as freezing in dry ice, is required for transportation. • Core sample preparation is done at stress by solvent flushing and air drying. • Porosity from pore volume by liquid saturation and grain volume from dry weight and grain density. • Most measurements (including capillary pressure) should be done at stress in a core holder. • Compressibility measurements are usually important. • Core analysis planning is critical. Clay bearing and shaly sands • Coring fluids should not cause clay swelling. • Core handling should be aimed to prevent samples from drying out. • Plug drilling should be done using high salinity brine or refined oil. • Avoid high boiling point solvents during cleaning. • Samples should be dried at 95°C. • Qv and CEC measurements are recommended using membrane potential. • Capillary pressure can be done using mercury/air but air/brine or oil/brine capillary pressures are recommended to determine effects of clay-bound water.

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Resistivity-index vs water saturation curves may need correction for clay-conductivity effects. Rock-fluid compatibility floods may be important. Minerology and clay-typing is recommended.

Carbonates • Coring is usually straight-forward. • Samples often show variability between plugs and heterogeneity within the same plug. • Qv and CEC are usually not required; if required, only membrane potentials should be performed. • Carbonates exhibit variable stress sensitivity. • Compaction measurements may be important because carbonates can exhibit pore collapse at stress. • Not usually fresh water sensitivity. Vuggy carbonates • Coring can be difficult in vuggy carbonates. • Whole core methods may be important in obtaining representative properties. • Bulk volume by mercury should be done with a thin sleeve around the sample to prevent mercury invasion. • A high degree of mud invasion may occur. Low permeability formations • Low permeability samples are sometimes difficult to measure due to equipment limitations. • Core analysis planning is critical because all procedures take significantly more time. • Mercury/air capillary pressure curves should be measured with the Autopore 9220. Fractured reservoirs • Coring is often difficult. • Imaging techniques such as CT -scanning of the whole core can be used to assist in identifying heterogeneous sections. • Sampling may be biased due to fragile nature of the rock. • Whole core measurement may be recommended.

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Evaporites • Care must be exercised in selecting solvents for cleaning. Diatomite • Cleaning can take significantly longer than normal. • Samples typically exhibit very high porosity but low permeability. • Thin section and SEM are important. Coal • Degree of water absorption is critical in measuring producable methane. • Samples should be studied in an "as-received" state as well as oven-dried. Shale • Coring with oil base mud is recommended. • Use an anti-whirl bit • Cores should be cut with a fibreglass inner barrel. • Shale cores should be resin stabilised • Minimise mechanical impact during transportation • Gas-tight laminate bags should be used for storage. • Cut shale plugs with kerosene • Typical measurements can include Brinell Hardness, porosity, bulk density, moisture content, UCS, Vp, Vs and CEC.

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Where to perform the core analysis programme

The consideration of where to perform the core analysis programme, hinges on several issues: •

Programme Scope. Programmes which are predominantly for basic analyses can be done at core analysis contractors. Programmes with an extensive special core analysis component should be done at Shell E&P laboratories or approved core contractors.

•

Quality. To have the highest quality core analysis, it is always preferable to perform critical special core analysis at a Shell E&P laboratory. However, capacity at Shell E&P laboratories can be limited.

•

Regional. It is preferable to perform as much of the core analysis project as possible at the same place to minimise core transportation and core handling.

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Literature

Pink, M.J. Exploration and Appraisal Technology - Maximising Rewards by Integration Shell Selected Paper, January 1993 Van Ditzhuijzen, P. Petrophysics - In Touch With the Reservoir Shell Selected Paper, July 1994

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Core and fluid analysis considerations

This chapter is designed to provide more information in support of planning a core analysis programme as presented in section 3.2. Accordingly, it follows the same outline as presented in section 3.2. Each topic is expanded upon to present relevant considerations so that all aspects of a core analysis programme are included. Fluid analyses are also included here which are particularly important for performing analyses which involve wettability where using representative oil and brine samples are critical. Further information on fluid analyses is provided in Chapter 13.

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Scope of a core analysis programme

Specifying the scope of a core analysis programme is an important first step in planning and defines the measurement objectives of the programme. Proper scope and measurement objectives clarify expectations and allow each team member to understand and support the reasons for the core analysis programme. Moreover, a clearly defined project scope facilitates project approval as well as increases the probability of success. Clearly defined objectives enable the multi-disciplinary team to specify the necessary measurements and deadlines as well as assist the performing group to understand the critical steps that ensure measurement success. The scope of the project is defined by a set of objectives although each objective may entail a large number of measurements. Example measurement objectives are given as follows: •

basic core analysis properties for calibration of wireline logs;

•

capillary pressure and relative permeability of various rock types for input into reservoir simulation;

•

compressibility of a particular rock type or formation for compaction/subsidence predictions;

•

saturation model parameters to evaluate hydrocarbon reserves for a specific formation using resistivity logs;

•

impact of shaliness on conductivity measurements;

•

well injectivity in a particular formation;

•

residual hydrocarbon saturation;

•

impact of gas saturation on residual oil saturation;

•

impact of diagenesis on the hydrocarbon distribution.

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Multi- disciplinary considerations

This section is aimed at summarising the responsibilities and input that can be obtained from each member of an integrated team. It is placed early in programme development to encourage teamwork. 4.2.1

Petrophysics

The petrophysicist has two roles to perform: firstly as core analysis programme focal point and secondly, to co-ordinate petrophysical aspects of core analysis data acquisition. The petrophysicist has the nominal task of organization and implementation of the coring and core analysis programme. It is recommended that the petrophysicist put together a trial core analysis programme, i.e. a “strawman”. By passing the strawman core analysis programme to each PE team member and other disciplines a consensus can be reached. This may require one of more multi- disciplinary team meetings so that the synergy of the integrated team can be used. The petrophysicist must also ensure that the core analysis programme is consistent with other aspects of the petrophysical data acquisition programme such as the wireline log evaluation programme. The logging suite should be a guide to the core analysis programme. Resistivity logging, sonic logging, and density logging can all be calibrated over the cored interval by core analysis. Pay attention to potential mineralogy identification using spectral gamma ray logs, which can be better quantified with calibration from mineralogy obtained from core. The petrophysicist selects core analysis measurements relevant to the purpose of calibrating logs and determining input parameters into log interpretation models. For examples: • basic rock properties – porosity, permeability and fluid saturations; • capillary pressure measurement for saturation calculation; • stressed measurements if the formation is poorly considered or in anyway stress sensitive; • electrical properties for resistivity log interpretation along with cation exchange capacity; • acoustic rock properties for AVO calculations.

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Geology

The core analysis plan should be consistent and be closely interrelated with the geological core analysis plan. Some data are common to both analyses and measurement duplication should be avoided. Geological input is critical to guarantee that measurements are performed on samples that are most representative of the formation, especially for special core analysis. This may involve determining the number of significant rock types and also roughly estimating the reserves that may be contained in each rock type. The combination of rock typing, i.e. facies identification, is part of the process of geological core analysis. Table 4.1 reviews techniques and information typically obtained in geological evaluation. More detail is contained in the manual "Geological Core Analysis" by L. C. van Geuns and J.A. Okkerman (in preparation). Geological input should include some of the following: •

core descriptions;

•

facies analyses which is critical to the sampling for special core analysis measurements;

•

mineral identification (interaction with petrophysicist may ultimately yield mineral identification from logs);

•

investigating diagenesis as well as analysing the structure of the rock fabric (such variations can play an important part in interpreting core analysis data). Thin sections and grain size analyses are important;

•

lithology, depositional characteristics and age of the formations present for geological characterisation of the reservoir.

The geologist makes a preliminary static reservoir model. The ultimate quantification of the reservoir model is accomplished through the interaction of geologist, petrophysicist, reservoir engineer and other disciplines which should determine the goals of the special core analysis programme.

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Technique Macroscopic description • Slabbed core • Plugs/sidewall samples/cuttings

• • • •

Paleomagnetism Fracture analysis by 'goniometer' Visible light photography U.V. photography

Microscopic description • Thin section microscopy •

Scanning Electron Microscopy (SEM) with enhanced image analysis

Compositional analysis • Energy Dispersive X-Rays with SEM • X-Ray Diffraction • Mineralog from Core Laboratories •

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Information • • • • • • • • • • • •

Depositional environment Rock type/gross lithology Net/Gross Bedding/structure Degree of consolidation Grain size/sorting Fossils Hydrocarbon shows Core orientation Fracture orientation Visual record Hydrocarbon shows

• • •

Grain characteristics Porosity indication Microscopic distribution of minerals Quantification of microstructure and porosity

•

• • • •

Natural Gamma Ray Spectroscopy (NGS)

Geochemical analysis

•

Mineralogy (Clay) Mineralogy Mineralogy depth profile and approx. matrix density Quantitative determination of amounts of U, Th, and K. Used in spectral gamma ray log evaluation Chemical analysis of cap and source rock

Table 4.1 Information from geological evaluation

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Reservoir engineering

Reservoir engineering application of core analysis data is in providing input to computer simulation of reservoir performance. The required input is usually focussed on capillary pressure and relative permeability and the experimental conditions that are needed to ensure that the measured data are representative of in-situ conditions, particularly, wettability. However, the reservoir simulation itself should be used to determine the greatest sensitivities in core analysis data and so identify those parameters for which core analysis measurements are critical. This is accomplished by running sensitivities to various input parameters obtained from core analysis using simulation. Sensitivity analyses are performed to investigate the effects of variations in geology and possible recovery process options for reservoir development. Sensitivities might be run on any of the following parameters: •

relative permeability parameters including endpoint saturations and the shape of the relative permeability curve;

•

capillary pressure;

•

critical gas saturation;

•

pore volume compressibility;

•

flooding tests (such as hot water or steam flooding).

While it is unreasonable to run all sensitivities, selective sensitivity analysis can quickly clarify the economic impact of determining core analysis parameters. The output from reservoir simulation is used in the economic justification of the core analysis programme using value of information as discussed in Chapter 2.

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Other disciplines

Many other disciplines are involved in a core analysis programme development: •

Drilling engineering provides advice on drilling parameters and on coring bit and core barrel choices. New coring bits are continually being developed with the latest being low invasion, high density and anti-whirl bits. Selection of core bits is covered in Core Handling Manual, Chapter 2, and more discussion is available from section 4.4. Organisation of a pre-drilling meeting should be done in close cooperation with drilling engineering.

•

Production technology input is sought when core analysis programmes are to be designed to answer questions associated with well injectivity, sand control and rock strength issues pertaining to well-bore integrity, rock mechanical properties for fracture design, sieve analysis for gravel sizing and mineralogy for acid stimulation. An important area is cost estimation involving production technology. Different options frequently require different facilities which have a significant bearing on cost and value of information calculations.

•

Geophysicists should be consulted for input relating to measurements involving acoustic velocity measurements and use of core measurements in calibrating seismic data. The analysis of such samples for mineral constituents that can affect acoustic response often plays an important role.

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4.3

Core measurements

4.3.1

Basic core analysis

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Basic core analysis is carried out to assist in log calibration for formation evaluation such as porosity, density and mineralogy. Basic core analysis data and its uses are summarised in Table 4.2. Basic core analysis consists of the core preparation together with the measurement of the basic petrophysical parameters of atmospheric porosity, air permeability, grain density and fluid saturations for samples taken at regular intervals throughout the cored interval. A sampling rate of one per foot is common.

Parameter

Application

Residual fluid saturations at surface

• • •

Hydrocarbon presence Hydrocarbon type Fluid contacts

Atmospheric Porosity, Ø

• •

Define storage capacity Calibration of wire line density log

• • • •

Basic flow capacity Permeability profile Vertical flow Completion design

Air Permeability, kair: Horizontal (parallel to bedding plane Vertical (perpendicular to bedding plane) Permeability, ka (Klinkenberg corrected)

•

Liquid permeability from gas measurements

Grain Density, ρg

•

Wireline density log calculations (for logØ)

Lithology (from geological analysis, core photos, etc.)

• •

Rock type Rock characteristics

Table 4.2 - Basic core analysis parameters and their uses

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General points regarding basic core analysis are as follows: •

basic core analysis is often referred to as routine core analysis. However, it is sometimes not particularly routine and thus the authors prefer the term "basic" to denote the measurement of basic rock properties;

•

the definition of basic analysis is not rigid and some contractor laboratories include a few of the simpler measurements listed in the next section 4.3.2, Special Core Analysis, such as sieve analysis and cation exchange capacity, in their basic analysis;

•

geological and petrographic evaluations, covered briefly in Appendix 3, are performed both before and during petrophysical/reservoir engineering analysis;

•

basic core analysis is not performed by KSEPL but can be done at BTC;

•

after the initial preparation of core material, contractor laboratories tend to treat basic analysis as a single service with porosity, permeability and grain density measurements offered in one package. KSEPL recommended procedures should be used wherever possible;

•

particular care should be taken over the handling and storage of samples used in basic analysis; undamaged samples can be used in future special analyses which do not require fresh or native state samples.

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Special core analysis

Special core analysis is the term applied to core measurements that are not part of basic core analysis. For example, capillary pressure, relative permeability, compressibility and resistivity index are considered as part of special core analysis. Some measurements are made where the fluid distribution is at equilibrium while others are done under conditions of fluid flow. Special core analysis complements the data from basic core analysis; allowing for more thorough log calibration and reservoir modelling. Special core analysis is carried out to determine the following: •

wireline log evaluation parameters and log response calibrations;

•

refined volumetric calculations and reservoir modelling;

•

rock fluid flow properties for assessment of reservoir productivity, stimulation design and reservoir modelling;

•

rock water retention properties; fluid saturations, pore geometry and structure, and wettability;

•

the mechanical rock properties for the control of fines production and stimulation design;

•

the significance of reservoir compaction as a drive mechanism and to predict surface subsidence and for casing design;

•

rock/fluid interactions for the selection of drilling, completion, workover, stimulation, and injection fluids;

•

the magnitude and distribution of residual oil saturations for reservoir management and improved oil recovery.

Samples should be representative of the various lithologies, porosity and permeability ranges found from basic analysis.

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Typical special core analysis measurements are as follows: •

stressed porosity and permeability;

•

capillary pressure;

•

electrical properties such as resistivity index;

•

wettability and relative permeability;

•

mechanical rock properties such as compressibility;

•

waterflood sensitivity for injectivity and well performance;

•

acid solubility.

Many of these measurements are performed at reservoir conditions necessitating the reproduction of in situ pressures and temperatures.

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Coring considerations and well-site planning

It is worthwhile to understand the impact that the coring process can have on a core. Events that happen during coring can later play a critical role in the interpretation of the measurement results. Such considerations include the type of bit, type of core, drilling mud composition, length and type of core barrel, overbalance, rate at which core should be brought to surface. Proper considerations maximise the amount of core recovered. Core handling at the well-site will be considered in the next section and frequent reference will be made to the "Core Handling Manual", EP 93-2200. • coring bit type In general, low invasion face discharge coring bits are recommended especially for unconsolidated cores. Throat discharge bits are not recommended because they can cause invasion. Eastman Christensen's RC412 and Security DBS CD93 are examples of excellent coring bits with face discharge or modified face discharge with law or minimal invasion characteristics. Check section 2.1.3 of the Core Handling Manual. • type of core There are a number of coring methods such as conventional, sponge or even pressure coring. Most coring is done conventionally. Check section 2.1.4 of the Core Handling Manual. • drilling mud considerations An important consideration for a core analysis programme are the drilling mud components. Mud filtrate can invade the core and make the core behave unexpectedly with regard to desired measurements such as permeability or grain density. In the case of permeability, some drilling mud additives such as certain polymer types can be very difficult to remove from the core and make permeability measurements uncharacteristically low. In the case of grain density, hematite frequently found in mud is difficult to remove leading to significant overestimation of the grain density resulting in high porosity values.

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In general, coring should be performed in such a way as to minimise invasion and with a bland mud, so that if invasion occurs, the rock fabric remains unaltered. A bland mud is one composed of components that do not have high interfacial activity. Components such as xanthum gum biopolymer and other polymeric products should not be present in the mud. Drilling mud additives that are known to be surfactants should be explicitly avoided. This is especially critical in the measurement of capillary pressure, relative permeability and wettability where mud filtrate can cause a change in wettability and deliver results that are not appropriate for input into reservoir simulation. • rate of penetration, weight on bit Excessively high rates of penetration (> 75 ft/hr) and weight on bit (> 30 klbs) should be avoided to minimise core disturbance, • rotary speed Moderate rotary speeds are recommended such as between 60 to 100 rpm. • overbalance control Again, invasion during coring should be minimised and therefore overbalance should be as small as possible. However, safety and environmental guidelines should be reviewed when deciding upon the appropriate overbalance. • core barrel considerations Core barrels for containerised coring can be made of aluminium or fibreglass and can be made up to varying lengths. Either aluminium or fibreglass barrels can be used as long as the material can withstand downhole conditions. The barrel length should be carefully considered especially in the case of unconsolidated samples. The typical barrel length is 30 feet (10 metres) but longer barrels such as 60 feet (20 metres) or even 90 feet (30 metres)

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are possible and can reduce the drilling time necessary for coring. However, core quality can be impacted by having too long a core barrel. For unconsolidated samples, 30 feet core barrel is, in general, recommended. Longer core barrels can be used for more consolidated rock material. • core jamming Review methods of detecting core jamming as it is better to trip out immediately following jam detection than to continue. This is very critical to good recovery in fragile or unconsolidated formations. • bringing core to surface After coring, the core barrel is brought to the surface which involves changing the temperature and pressure of the core material from formation conditions to surface conditions. The more gradual the process the better the core material can adjust to new conditions. This is particularly true for unconsolidated samples and poorly consolidated samples. • laying the core down The process of bringing the core to a horizontal position should be done carefully so that no bending of the core material occurs. Unnecessary bending causes core disturbance which then leads to measurements on disturbed or altered core material resulting in unreliable data.

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Core handling

It is insufficient to only maximise core recovery, but it is important to obtain high quality core. For core analysis to yield correct results, the core material should be damaged as little as possible by careful consideration of each step involved with core handling. There are two periods during coring when there is extensive core handling, namely: •

at the well-site and;

•

upon arrival in the laboratory.

4.5.1

At the well-site

Wellsite handling is covered in "Core Handling Manual" in sections 2.2 and Appendix 1. In general, handling of the core should be done in such a way as to minimise core damage and accomplish the following: •

identify cores in such a way that orientation and depth as is known is clearly and unambiguously marked to the point of redundancy;

•

cut cores into consistent lengths to allow for easier handling;

•

minimise handling steps and avoid hammering to remove the core material;

•

minimise exposure to the elements - the core should not be allowed to dry in any way;

•

minimise core disturbance. Use suitable equipment, for example, some saw blades are better able to cut core material;

•

transport core to the laboratory as soon as is practicable;

•

alert core analysis laboratory that core has been shipped and indicate expected time of arrival;

•

perform core analysis as soon as possible after coring. This improves data reliability and applicability.

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Upon arrival at the Laboratory

Preparation for the receipt of core is advisable to minimise poor laboratory handling which can result in undue delay in core analysis programme scheduling. It can also prevent core damage by preventing improper handling which can happen if inadequate preparation is made for core arrival. Planned activities so that core measurements can be initiated as soon as possible may include: •

inspect core sections; check sequence and mark driller's depth. Determine whether cores should be taken out of any barrels;

•

describe core to provide basis for sampling for special core analysis;

•

depth match with wireline logs;

•

core gamma scan or core spectral gamma scan;

•

slab (usually into 1/3 and 2/3 portions) but this should be carefully considered because some analyses need long plugs taken before slabbing. Consequently, the time of slabbing should be clearly specified;

•

photograph (normal and UV);

•

core imaging such as CT-scanning (can be done before or after slabbing and can be done before or after plugging);

•

other X-ray techniques such as (fluoroscopy, etc).

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Core screening

Additional steps for screening whole core can be specified beyond the scope traditionally defined in section 4.5.2. Additional screening techniques are described in Table 4.3 and in Appendix 2

Technique

Information

Natural Gamma Ray Scan (Core Gamma)

•

Gamma Ray Spectroscopy (Spectral Gamma)

•

Qualitative estimate of U, Th, K concentrations - correlate with spectral gamma ray log.

Gamma Ray Attenuation

• •

Pseudo bulk density profile. Correlation with wireline density log.

Probe Permeametry

•

Pseudo permeability profile (low accuracy).

X-Ray Computer Tomography (CT- Scan)

•

High resolution enhanced images of core material Density profile. Porosity indication. Observation of core recovery and core damage.

X - Ray Fluoroscopy

•

• • • •

Natural radioactivity – pseudo gamma ray profile Correlation with wireline GR log.

Examination of sleeved unconsolidated material.

Main applications of various scanning techniques are to aid in depth matching the core to wireline logs and to estimate the degree of material homogeneity for sample selection. Table 4.3 - Information derived from core screening

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Core sampling

Sample selection for core analysis is crucial to the success of the core analysis programme. Proper sample selection ensures that the data are measured on the most representative samples where the degree of heterogeneity is minimised or at least the degree of heterogeneity can be quantified. Sample selection must be done with regard to the needs of geology, petrophysics, reservoir engineering and other disciplines such as geophysics. Ideally, sampling should result in a statistical representation of the core material. However, that is to be balanced against cost. 4.7.1

Sampling for basic core analysis

Basic core analysis is usually done on a one per foot sampling (or 3 per metre). A quick perusal should be done to check that core competence allows such sampling. If too many plugs fall in regions of poor quality core, it is possible to plug every foot but beginning at a different position perhaps 3 to 6 inches away. In general, emphasis should be paid to the cutting of plugs as close to the one foot spacing as possible without any regard for variations in lithology. Otherwise a bias towards apparently better formation properties may be unwittingly introduced which can lead to improper log calibration. For some cores, where variations occur on about the one foot scale, it is recommended to consider a closer sampling such as 1 sample for every 6 inches (or 1 per 15 cm).

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Sampling for special core analysis

In special core analysis, most attention is paid to determining the relevant rock types upon which measurements are to be made. Samples for special core analysis are usually not taken at regular intervals but are taken so that samples are representative of the appropriate lithology. Perhaps it may mean only 1 or 2 plugs to be cut or as many as 20, but rarely as many as in a basic core analysis programme. The data for special core analysis is then interpreted as to apply to the appropriate formation in quantifying the reservoir model. There are two criteria that must be met when selecting samples for special core analysis namely: •

plug sample should be representative of rock type under consideration;

•

plug sample should be as homogeneous as possible given the prevailing geology.

It is recommended for special core analysis to begin with at least twice as many plugs as you think will be needed for special core analysis measurements. For example, to have 6 relative permeability measurements, at least 12 plugs should be cut to maximise the possibility of selecting the most representative plugs. For consolidated plugs, it is often more efficient to select from the plugs used for basic core analysis measurements. It is most important to take more plugs for any measurement involving fluid flow such as permeability and relative permeability. Static measurements such as capillary pressure are less affected. The larger number of plugs initially taken allows screening to be applied so that representative samples are obtained. For formations that are very heterogeneous, such as some carbonates, it may be necessary to select three (3) times as many plugs as will be needed for measurement. Without a screening process, special core analysis projects run the risk of using plugs that are not suitable for measurement. However, too much sampling may reduce the amount of available core material for other purposes. For very heterogeneous material, whole core measurements should be considered. Again, each lithology should be represented by a number of whole core samples.

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Sampling considerations

•

Proper planning and cross discipline communication of requirements is important for proper sampling and ensuring that the appropriate rock types are included in the core analysis programme.

•

For basic core analysis, emphasis is placed on regular foot by foot (every 30 cm) sampling with little regard for variations in geology.

•

For special core analysis, emphasis is placed on rock type within the formation. It is recommended that twice as many samples as needed for a given measurement be taken for the purpose of maximising representativeness of the samples.

•

CT-scanning (cross-sectional and every inch) is critical to determine locations for plug drilling. Longitudinal CT-scans on each plug after drilling is needed to confirm acceptability of the plug. Without CT-scanning before drilling, rejection rate of plugs can be as high as 90%.

•

Probe permeability measurements can assist in assessing heterogeneity.

•

Depending on the reservoir, a statistically representative data set may require tens of plugs; the laboratory experiments have to be planned efficiently so that such a data set can be obtained.

•

Always work in conjunction with the analysis laboratory on the sampling strategy.

•

Make sure KSEPL recommended drilling/plugging methods are used to minimise damage.

•

For unconsolidated material, sampling and analysis should be done as soon as possible because unconsolidated material is not easy to store long term.

•

Prioritise sample taking; more important analyses usually merit samples from optimum positions.

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Core sample preparation

Having selected samples for screening, the next step is core preparation. Detailing core preparation procedures can minimise mistakes and damage to the core material. Details are given in Chapter 5 on core preparation. Steps in core preparation can be divided into several steps: • plug location identification As noted in section 4.7.1, the selection of plug locations for basic core analysis and special core analysis is based on different philosophies. In basic core analysis the emphasis is on the regular spacing of plugs namely 1 per foot. In special core analysis, the emphasis is on taking plugs that are representative of a particular lithology or rock type. The locations of the plugs should be chosen in cooperation with the geologist, reservoir engineer, petrophysicist and geophysicist. • plug drilling As noted in the next Chapter, the method of drilling plugs should be clearly outlined. • preparation Cleaning, drying, saturation and wetting restoration steps (for relative permeability) are critical to specify before embarking on the core analysis programme. • Whole core samples In the case of vuggy carbonates or very heterogeneous rock, more representative results will be obtained using whole core samples. Whole core analysis is detailed in section 7.3. Slabbing of the required core section is not carried out. Samples are usually taken from each foot of core, have a minimum length of 6 inches (15 cm), and are trimmed into right cylinders. Samples for geological evaluation must be taken before experiments are performed.

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Core sample screening for special core analysis

Sample screening provides an important step in quality control in the core analysis programme for special core analysis measurements. Sample screening is generally only applicable for samples used for special core analysis. Samples used in basic core analysis with quality problems are generally noted and treated as questionable data. As mentioned in the previous section, for any special core analysis measurement plan, at least twice as many plugs are cut as the number used for actual measurement. Thus, the screening process selects the better samples for measurement. Screening consists of a number of measurements aimed at determining basic properties and degree of sample heterogeneity. These measurements are analysed with respect to rock typing and facies identification to provide a clearer picture of the variety of rock types. It occasionally happens that additional plugs must be cut before acceptable samples are obtained. The activities and measurements which are recommended for special core analysis screening are: •

Core description

provides a permanent record of lithological, depositional, structural and diagnetic features of a whole or slabbed core. It provides the basis for routine core analysis sampling, facies analysis and special core analysis studies. •

Thin sections

provide a microscopic view of the rock sample and a general measure of the degree of heterogeneity. Thin section analysis on a number of samples for a given rock type generally will better characterise the formation of interest. It is also important to note the presence of minerals that can affect measurements or the possibility of any core alteration or core damage. Thin section preparation and analysis is a critical component of core screening. More detail about thin sections is given in Appendix 3.

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• Plug photography Photographs of the plugs are recommended. Plug appearance can be used for subsequent interpretation of core data. It is a simple but frequently overlooked step. • Longitudinal plug CT-scanning (2 views) provides a non-invasive and non-destructive view of the internal structure of the rock and provides a measure of core scale heterogeneity. This is done by presenting the density through the plug using two different slices through the sample position 90 degrees apart. CT-scanning is nondestructive and longitudinal scanning is an excellent method of screening for internal heterogeneities not visible from the surface. Figure 4.3 shows typical longitudinal CT-scans, of a plug sample. Variations in colour are due to clay richness and provide a measure of plug quality. Such a plug may be questionable for flow experiments. More detail about CT-scanning is given in Appendix 2. • Porosity, permeability and grain density Porosity, permeability and grain density are used to ensure values from special core analysis are in line with basic core analysis. Sometimes porosity-permeability cross-plots will show the separation of the rock types into recognisable lithologies which are important in identifying and selecting appropriate samples. • Mineralogy Sample mineralogy is useful in quantifying the abundance of unusual minerals. Variations in core analysis data can be related to rock composition. More detail on mineralogy determination is given in Appendix 3.

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• Capillary pressure (on an endpiece) Capillary pressures curves define pore throat distributions which can be used to differentiate rock type. A number of methods of screening capillary pressure curves are used such as the Leverett J function which is one of the most common methods of comparing and contrasting rock types. Each method of rock type classification has merits and any particular one may be more useful than another for a given regional geology. It is advisable to check the manual Capillary Pressure Saturation Height Functions by R. van den Oord and S.J. Adams, EP 93-0001, for a review of methods of using capillary pressure curves in rock typing. More information about screening is given in Appendix 2 and Appendix 3.

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Core preservation

Core preservation is aimed at maintaining core for future use. In any core analysis project, it is very difficult to anticipate every need core analysis should address. This occurs because present needs do not always coincide with future ones and because the demands placed on core analysis may have to be met with core that has been preserved. There are a number of ways of core preservation and these are described in detail in the Core Handling Manual by Okkerman and van Geuns, EP 93-2200. The main types are as follows: • Core freezing Shell has long been a proponent of freezing although freezing of core for preservation has been controversial. Possible effects of freezing include rock damage if water saturation is too high, fracturing if freezing time is not sufficiently slow, salinity variations because of freezing, and alterations to rock fabric because of freeze thaw cycles. It is advisable to cake the core with ice, and to store the frozen core at temperatures below 22°C while minimizing sublimation by ensuring that the frozen core is packaged in appropriate core package materials such as special core wrap, aluminium foil and boxing. Core takes about 3-4 hours to freeze when in contact with dry ice. Water saturation should not be too high less than 60% or at least 10% gas saturation which generally is the case because of the hydrocarbon-bearing formation of interest or when the core is brought to surface. Frozen core is easy to handle and plugs can be easily drilled with liquid nitrogen. CT-scanning can also be done on frozen core. •

Resin stabilisation In many places around the world, dry ice is not available and the opportunity to freeze the core and maintain the core at low temperatures is not possible. Resin stabilisation is an alternative to freezing. Resin stabilisation is done at the well-site, where epoxy resin is introduced between the core and the liner. Once the epoxy sets up, the core is stabilised and can be transported. Unfortunately, it is not always possible to completely fill the annulus with epoxy. Other problems are possible contamination of the core by resin, core invasion by resin and possible safety hazards with use of resin.

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Fluid measurements

4.11.1 Brine measurements There are several types of brine measurements of interest in core analysis: • Obtaining water samples In cases where there is water production, sampling is relatively straightforward. Select a well that has not been worked-over and no additives have been recently used in the well. Water samples should be taken in a plastic container and not a metal one. Water sampling can be difficult if there is no water production. Estimating water composition from core water may be possible, see section 13.2.3. • Brine composition Composition has ramifications because it can playa role in the preservation of the state of minerals in the formation. Abundances of cation and anion types are important. In addition, pH is a very important brine property because it may alter the wettability of the formation. • Brine resistivity Brine resistivity plays a role in all electrical properties measurements. The brine resistivity used in the measurements should duplicate as closely as possible the formation brine resistivity. However, only few measurements are done at reservoir temperature. It is usually thought to be more important to match the brine composition than its resistivity. • Brine-rock compatibility Some consideration should be given to compatibility of brine for flow experiments. Incompatibility results in poor results and unusable data. See section 13.3 for details.

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4.11.2 Oil measurements Oil properties that can play a role in core analysis or are critical information evaluation: •

PVT properties such as bubble point;

•

Gas Oil Ratio - is sometimes necessary for adding hydrocarbon gas to dead crude to make it live. Although usually only methane is added, it is often that methane, ethane and propane are added to obtain a better simulation of live crude properties. Live crude oil is sometimes used in preserved or restored state experiments. Recent work has suggested that it is more important to be at the correct reservoir temperature than the correct gas-oil ratio and that dead crude results are similar to live crude results;

•

API gravity;

•

whole oil analysis for oil quality characterisation;

•

high temperature gas chromatography for hydrocarbon typing;

•

density - necessary for computation of oil volumes and for use in such analyses as oil/water capillary pressure by centrifuge;

•

viscosity at various temperatures- necessary for determining relative permeabilities to oil;

•

acid and base number - useful parameters for characterising wetting tendencies of oil;

•

cloud point and wax deposition rate are important for oil refinery processing considerations;

•

presence of trace elements such as sulphur, nickel, vanadium which are also important in processing considerations.

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Fluid handling considerations

Although this manual is primarily devoted to core analysis, some comment on the handling of fluids is in order because modern special core analysis techniques require proper fluid samples, especially oil samples, to deliver properly measured special core analysis data such as relative permeability. •

Sample oil volumes. Oil volumes can be obtained from formation testing logging tools such as RFT, which may be the only source of oil in new discoveries. Note that before fluid transfer, the tool should be warmed to 55°C as well as pressured to 100 psi greater than formation pressure. Agitating the tool during transfer is important. After as much fluid as possible has been transferred, the tool should be rinsed with chloroform/methanol and the rinses saved. Rinsing should be repeated two to three more times. In remote locations, these procedures may be difficult.

•

Dead oil. Sampling from a well should be done at the wellhead. A well that has not been worked-over recently should be selected and where no additives have been used.

•

Live crude oil. For live crude oils, appropriate volumes of separator gas are required.

•

Required volumes for analysis. It is important that required volumes be obtained. Oil volumes should be sampled as follows:

Analysis

Volume required

Relative permeability at least 300 ml (for both aging and actual measurement; some relative permeability techniques require significantly more oil such as up to 5 litres.) PVT

around 1 liter

geochemical analysis

500 ml.

Approximately 500 ml of brine are required for brine analysis.

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Sequencing and scheduling

The sequencing and scheduling of the core analysis programme allows each team member to know when input is required and when to expect data. The process of sequencing and scheduling is the key to the proper management of a core analysis project. Sequencing is critical to ensure the maximum amount of data can be measured on each plug sample and takes into account the time each step from core preparation to final data reporting should take so that proper time allowance can be made. Some contingency is generally allowed for so that unforeseen circumstances can be incorporated. Scheduling ultimately reduces to the issue of when data can be expected. By recognising data needs and schedules within the larger project, core analysis data should be scheduled to maximise its impact.

4.14

Costs

Costs for the entire coring and core analysis programme can be determined from appropriate price lists. Although KSEPL does not provide prices, this manual does provide an estimate of cost for services described herein. The prices are based on an average of US based and European based prices as of 1994 and may vary by region.

4.15

Economic impact and justification

Project approval should be based on the economic impact of the project and not just on cost alone using Value of Information concepts as discussed in Chapter 2. Core analysis data provides data for decisions used in economic development of hydrocarbon resources. Recognising the balance between cost and impact is the responsibility of the integrated PE team.

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Project reporting

A core analysis programme is not complete until properly documented. Core analysis data are reported in tabular, graphical, image and or digital form. These reports become permanent records of the observations made at the time of coring, core handling, screening, preparation and testing. Any commentary which may assist in the interpretation of the different data forms at the present or in the future should be recorded, e.g.: •

well-site activities should be summarised in a well-site report;

•

a copy of the core analysis programme should be included;

•

all raw data used to generate the final data should be included in the core analysis report;

•

unusual testing circumstances and data anomalies should be clearly noted.

It is important to specify the number of core analysis reports required by the Opco so that appropriate stakeholders (including appropriate central files) receive a copy. Tabular report Tabular report should include all data, positively identified and tabulated in some convenient, but usually spreadsheet, form. Identification comes in two forms: • Wellsite report: well identification; type of well (vertical, deviated, side track, etc); type of core; core recovery; drilling parameters; mud composition; core depths; well-site handling; well-site preservation; core transportation; report timing of activities.

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Core analysis laboratory data: a copy of the complete core analysis programme (see Chapter 3 and Chapter 4); core condition upon arrival at the laboratory; note any variations to core analysis plan; core screening activities; core storage; core disposition; methods and conditions applied (drying, cleaning solvents); results (both raw and calculated data etc.).

The exact presentation of data may be determined between the user and the analyst. Suggested significant figures to be reported are as follows: Porosity values to Grain density values to Saturation values to Pore volumes to Grain volumes to Bulk volumes to Permeability values to Pressure values to Stress values to Resistivity values to Relative permeability values to Compressibility

3 (e.g. 0.203 or 20.3 %) 3 (e.g. 2.65 g/ml) 3 (e.g. 49.9 % pore volume) 4 (e.g. 12.68 ml) 4 (e.g. 20.34 ml) 4 (e.g. 25.78 ml) 3 (e.g. 1.33 mD) 3 (e.g. 75.7 bar) 3 (e.g. 789 bar) 3 (e.g. 25.1 ohm m) 3 (e.g. 0.00123) 2 (e.g. 1.1x10-5/bar)

Graphical report Graphical presentations are often included to provide the user with a pictorial overview of various data. Through the continued advances of computer graphic software an unlimited selection of pictorial formats are readily available including crossplots, histograms, or core data profiles (logs). Specific formats are left to the discretion of individual Opcos. However, some essential recommendations are made below: • Basic core analysis Two graphical figures have been widely accepted and are recommended for inclusion in every basic core analysis report: - Permeability vs Porosity plot - Core Data vs Depth plot.

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• Special core analysis Graphical representation of special core analysis reports is important. Common graphical representation is necessary for the following data: - Porosity (linear) vs stress (linear) - Permeability (logarithmic or linear) vs stress (linear) Capillary pressure curves - Pressure (logarithmic) vs saturation as % pore volume (linear) - Pressure (logarithmic) vs saturation as % bulk volume (logarithmic) Resistivity curves - Resistivity Index (logarithmic) vs water saturation as % PV (log) - Formation resistivity factor (logarithmic) vs porosity as % PV (log) Relative permeability curve - Relative permeability (logarithmic or linear) vs saturation as % of PV(linear) Compaction curve - Axial displacement (linear) vs pore fluid pressure (linear). Image report An important component of current core analysis procedures is the reporting of core and plug screening procedures which specifically include image data such as photographs, thin section images and CT-scans. The ability to cross-check tabular and graphical reports with images is critical to assessing quality of core analysis data and fundamental to the process of project review (see section 4.17). Digital report Most core analysis data are now automatically acquired. Initial (raw) data and calculated (final) data processing and storage, as a result, are being done increasingly on computer systems. A standardized method of data reporting minimises the cost and effort to transfer data between various computer platforms. The exact format of logical data organisation and type of physical storage media (i.e. disk, tape, optical disk, etc.) applied should be agreed between Opco and core contractor. At KSEPL, all data is represented in printable ASCII characters in EXCEL spreadsheet format. The layout is the same as that for the hard copy of both the tabulated and graphical reports. Digital reports should include image files where possible.

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Project review

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A follow-up meeting of the PE team to review core analysis results is very important in order to better apply core analysis data, to maximise impact of core analysis data and to ensure that the needs of the PE team are met. This is shown in diagrammatic form in Figure 4.4. Having completed a series of measurements, data review leads to a much clearer picture of which actual data merit the highest consideration. It is most worthwhile to have the core analysts present at the data review. This could be difficult with problems of distance and time, but perhaps modern technology such as videoconferencing can be of assistance. Even basic core analysis projects, although usually uncomplicated, merit review. The project review process should include: •

review all measurements made on the same plug especially core photography, CT-scanning, thin section, SEM and XRD results which will have a bearing on values measured. The quality of the plug data can be checked, for example, if the sample coincidentally has a higher clay content than normal coupled with an unusual resistivity, etc.;

•

review measurements in the geological context of the formation. Thus the implications of core analysis data can be grasped by examining all measurements on the same facies;

•

determine the quality of the measurements. This is done with the core analysts who performed the work being present;

•

check consistency of related measurements: - pore volumes, and thus porosities, should be checked if a single sample is subject to multiple measurements, - initial water saturations from capillary pressure should be consistent with resistivity-index measurements and relative permeability measurements;

•

obtain input and consensus from the multidisciplinary PE team.

As a consequence of the follow-up review, the best data will have been determined and a consistent picture of the nature of the data will be evident. This will lead to better application of the core analysis data in quantifying reservoir models in the multi-disciplinary team by proving the proper contextual interpretation of the core analysis results.

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Literature

Niko, H., Maas, J.G. Special core analysis as seen from reservoir engineering. Contribution to the PW04 Advanced Reservoir Engineering Workshop, Noordwijkerhout, October 1993 Cuiec, L. The Effect of Drilling Fluids on Rock Surface Properties SPE 15707 Sharma, M.A. and Wunderlich, R.W. The Alterations of Rock Properties due to Interactions with Drilling Fluid Components Worthington, A.E., Gidman, J. and Newman, G.H. Reservoir petrophysics of poorly consolidated rocks 1. Well-site procedures and laboratory methods Transactions of the 28th Annual Logging Symposium London Lamb, C.F. and Ruth, D.W. Laboratory Programme Design for Unconsolidated Heavy Oil Reservoirs: A Case Study SCA 9104 paper presented at the 5th Annual Technical Conference of the SCA. Bateman, R.M. Building a reservoir description team - case study. Paper EE presented at the fifteenth formation evaluation symposium, 1993, May 5-7. Okkerman J.A. and van Geuns L.C. Core Handling Manual EP 93-2200

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Core preparation

The process of core preparation can be divided into three steps •

core plug drilling;

•

core cleaning;

•

core drying.

After selecting plug locations and cutting plugs for analysis, the proper methods of core cleaning set the stage for later measurements. Improper core preparation can impact subsequent data quality. Avoidable errors often occur in these first steps of core analysis so it is advised to be as specific as possible about core preparation steps. This chapter begins with the appropriate considerations for proper drilling of core plugs followed by methods of core cleaning and core drying. After core preparation, the clean dry samples are ready for measurement or for restoration of wettability prior to relative permeability measurement.

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Plug drilling

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Drilling consolidated samples

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Principle Whole core sections are slabbed into two sections typically with thicknesses 1/3 & 2/3 of the original diameter after the optimum slabbing plane is determined through CT-scanning. Plugs are taken from the 2/3 section and can be drilled with either fresh (or tap) water, brine, kerosene, air or liquid nitrogen. Points • Fresh (or tap) water is used for clean sands and carbonates. • Brine is used for cores from high salinity environments. • Kerosene (or petrofree) is used for shales and halite bearing samples. • Air is used for fluid saturation determination studies. • Liquid nitrogen is used for shales and when consolidation is questionable. • For most measurements cylindrical plugs of diameter 2.54 cm and length 2.5 to 5.0 cm should be drilled from the slabbed core using fresh water as a drilling fluid (see also Chapter 10 if wettability must be preserved). • Horizontal plugs should be drilled parallel to the apparent bedding plane while vertical plugs are drilled perpendicular to the apparent bedding plane. Care needs to be taken over the direction of the bedding since fluid flow properties may vary with sample orientation. If horizontal and vertical properties are to be compared the plugs need to be drilled as close to each other as possible. • Samples should preferably be taken from the centre of the core to minimize contamination from drilling mud invasion. • Plugs should be machined into right cylinders; the offcuts (also known as endpieces or trimmings) of this process can be used in analyses which do not require plug samples, such as thin sections, mineralogy, and cation exchange capacity determination (see chapter 9). • Small diameter cores must be plugged before slabbing to ensure plugs of adequate length, see Appendix 4 for more details. Price/timing • < US$25 per plug drilled • Plugging usually takes about 10-15 minutes per plug.

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Drilling unconsolidated samples

Principle Frozen unconsolidated whole core sections are slabbed into two sections typically with thicknesses 1/3 and 2/3 of the original diameter after the optimum slabbing plane is determined through a CT-scanning. Plugs are taken from the 2/3 diameter section. KSEPL recommends the 2/3 diameter core section be frozen in dry ice, if not already frozen, and that a plug be drilled using liquid nitrogen as a coolant (see Figure 5.1). Plug samples should remain frozen prior to measurement.

Points • • • •

Analysis should be performed as quickly as possible to prevent deterioration of the samples. This is particularly true for samples containing high salinity brine. Plugs should be stored at temperatures below -220C. Some contractors take plugs by 'punching' the sample out of the unfrozen core material. This is NOT recommended. Plug samples should be drilled with liquid nitrogen. Points from section 5.1.1 are applicable here.

Price/timing •

< US$25 per plug drilled

•

Plugging usually takes about 10-15 minutes per plug.

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Core cleaning

5.2.1

Cleaning consolidated samples

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Principle Cleaning is accomplished by means of a hot solvent extraction (Soxhlett) technique, in which an azeotropic mixture of methanol and chloroform is heated and diffused into the sample. This should be done below the boiling point of water, to avoid removing any water before the oil. The technique also ensures that salt is not precipitated. Points • •

• •

•

• • •

Certain measurements require samples that have NOT been cleaned; fluid saturations by the Dean-Stark method (section 6.3.1) is one example. Gas-drive solvent extraction (e.g. CO2 saturated toluene extraction where a pressure drop causes the gas to expand and flush the sample) used at some contractor laboratories is considered acceptable, but must not be used for soft rock types such as chalk. Types of solvents include acetone, chloroform/methanol azeotrope, cyclohexane, ethylene chloride, naptha, tetrahydrofuran, toluene, trichloroethylene, xylene. Usual criterion for plug cleanliness is a clean extract (check for fluorescence in solvent). However using a second solvent can remove additional hydrocarbon and is recommended when the first solvent takes more than three or four days to clean the sample. The usual sequence is to begin cleaning with toluene and chloroform/ methanol. If it is found that samples are not sufficiently clean more aggressive solvents are then used such as xylene and tetrahydrofuran. Combinations of solvents such as alternating chloroform/methanol and toluene can be used for samples that are difficult to clean. Tetrahydrofuran is recommended for cleaning to water-wet state prior to restoration of wettability. High boiling point solvents can cause clay dehydration. Naturally occuring halites may be removed by toluene.

Price/timing • < US$25 per plug. • Cleaning by this technique usually takes one week. If this is not sufficient to remove all the oil, an alternative solvent can be applied.

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Cleaning unconsolidated samples

Principle At KSEPL, the frozen sample is mounted in a core holder and a confining stress of 30-50 bar is applied. The sample is allowed to thaw. After thawing, the sample is cleaned by cold solvent flushing with chlorothene and toluene alternately. Points • KSEPL apparatus for cleaning unconsolidated samples is shown in Figure 5.2. • Cleaning in a stress cell prior to a stressed measurement is normally done and eliminates one core handling step. • It may be difficult to ensure that the sample's pore structure is representative of the reservoir. Computer Tomography (CT) scans can be used to recognise core disturbance and core recovery in case of fibreglass or plastic liner contained cores. • Studies have found that if core material is frozen slowly by refrigeration or with dry ice, damage to the microstructure is not induced. • Many core contractors apply a screen capped teflon method (SCTM) to unconsolidated plugs in which a teflon sleeve confines the cylindrical surface while the ends are capped with a wire mesh. Thereafter, for cleaning, drying and measurement the sample is treated as if it were consolidated. The teflon is non-conductive so electrical properties can be investigated. Other contractor labs use heat shrink tubing or lead sleeves. • Further preparation steps are usually: the sample is dried by purging with nitrogen, saturated with a 10 g/l NaCI solution and frozen again. The frozen sample is then placed in the experiment sample holder, subjected to a confining stress and allowed to thaw. The NaCI solution is removed by flushing with methanol. Price/timing • < US$75 per sample • Cleaning can take as long as several weeks depending on oil type.

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Core drying

5.3.1

Oven drying

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Principle The sample should be dried in a vacuum oven. KSEPL advises that samples should be dried at 95°C. Samples may show induced fractures at higher drying temperature. Points • Use an explosion-proof oven. Conventional ovens as shown in Figure 5.3 are acceptable. • Each core sample should be dried until constant weight is obtained. • Drying times may vary substantially. . • Care is critical in handling samples with hydrated materials. In some cases a lower temperature should be used.

Pricing/timing • About US$5 per plug. • Drying is done in batches of up to 100 plugs overnight (at least 16 hours).

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Critical Point Drying (CPD)

Principle The CPD technique prevents the development and advancement of a gas/fluid or fluid/fluid interface within the rock by raising the fluid within the pores above its critical point (see Figure 5.4). The prevention of interface formation is achieved by replacing the oil and brine in the pore space successively by methanol and liquid CO2 through diffusion. CO2 is preferred because its critical point of 32°C and 72 bar is more convenient than other solvents. The gas is vented without an interface being formed. Methanol is used as an intermediate liquid to ensure full miscibility. Points • Diffusion time depends on sample size and permeability and can range from one day to one month. • Temperature and pressure are chosen such that liquid carbon dioxide becomes a gas without a phase change. • Critical point drying preserves the structure of the clays in the pores. It should be used if there are delicate clay minerals, such as fibrous illite, which are sensitive to the conventional oven drying method. If these minerals are damaged in the drying process, the air permeability of the samples is profoundly affected, by up to a factor of 10 or more. Figures 5.5 and 5.6 show the damage which can be caused to delicate clay minerals by conventional oven drying. • The CPD technique can only be used on consolidated material. • CPD is done on fresh cores. • After critical point drying, the sample can be resaturated without the appearance of interfaces by using the critical wetting method; essentially CPD in reverse. • Permeability estimates can be obtained by using a cleaning solvent such as methanol which avoids using brine. Price/timing • About US$50-100 per plug. • CPD takes about 2 weeks to 2 months, depending on air permeability.

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When the pressure and temperature of the pore fluid are raised above its critical point, the fluid is brought into a supercritical state in which no phase transition exists between gas and liquid. The supercritical fluid can then be removed from the sample without damaging fragile clay minerals.

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Humidity controlled drying

Principle Core contractors employ humidity drying where the sample is heated to 60°C at 40% relative humidity. Because of the low temperature, the drying may take several days. It is claimed this method preserves the water adsorbed on the clays (clay-bound water). Points • This technique is NOT recommended by KSEPL as the resulting 'effective' porosity has no unique relationship with either log-derived effective or total porosity. • Salt is not removed and causes erroneous weights. Salt must be removed by flushing with methanol/water before measurements of total porosity are made. • Small variations in relative humidity can impact porosity measurement of some plugs. Price/timing • < US$25 per sample • Humidity controlled drying usually takes several days.

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Review of some contractor preparation procedures

The following tables are based on recent studies carried out by KSEPL/SIPM on a number of contractor analysis laboratories. The review summarises preparation procedures routinely available. The remark "acceptable" indicates that KSEPL agrees with the procedure offered; it is either similar to that used at KSEPL or expected to yield results of comparable quality. A blank space indicates lack of information. In general, contractor laboratories can offer preparation procedures of acceptable quality as long as recommended procedures are requested and followed. Note: Preparation costs are approximate.

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Literature

Dicker, A.I.M. and Bil, K.J. The influence of core preparation on the effective permeability of tight samples. KSEPL report RKMR 87.041 and RKRS.87.02. Dicker, A.I.M. and Bil, K.J. The influence of drying on the gas permeability of tight samples containing illites. KSEPL report, RKRS.86.11. Blehaut, J.F. The effect of laboratory drying techniques on clay morphology and permeability in Rotliegendes tight gas sandstones. TIGRE RKSR June, 1983 Schipper B.A. A critical review of two common core analysis measurements for reservoir evaluation. EAPG/RMC/SCA Workshop, Vienna, June 6, 1994. Soeder D.J. and Doherty M.G. The effects of laboratory drying techniques on the permeability of tight sandstone core. SPE/DOE 11629. Schipper, B.A, Aperen, A.E. van, Looyestijn, W.J. Quality assessment of core analysis procedures of Core Laboratories Aberdeen. EP 90-1886. Schipper, B.A, Aperen, A.E. van, Looyestijn, W.J. Quality assessment of core analysis procedures of Poroperm-Geochem Limited, Chester. EP 90-1901 Schipper, B.A., Hofman, J.P., Quality assessment of core analysis procedures of Corex Services Ltd, Aberdeen. RKTR.93.052, May 1993 (EP 93-1296). Schipper, B.A, Oord, R.J. van den, Adams, S.A Quality core analysis - essential to our business! Production Newsletter July/August 1992. Schipper, B.A. Quality Assessment of the Core Analysis Services of Simon Petroleum Testing, Aberdeen. RKTR.94.089, May 1994 (EP 94-0974)

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Basic core analysis

The most frequent measurements in core analysis are performed for the determination of basic physical properties. These are porosity, permeability, grain density, water and oil saturations. Simple relationships govern these parameters such as: •

the sum of pore and grain volumes is equal to bulk volume;

•

grain volume is given by the ratio of dry weight to grain density;

•

saturations are water and oil volumes normalised to pore volume.

Sampling for basic core analysis, as discussed in section 4.7.1 is generally foot by foot.

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6.1

Porosity and grain density

6.1.1

Bulk volume by buoyancy in mercury

Principle A clean, dry, consolidated sample is immersed in mercury. The sample weight in mercury is measured and Archimedes principle used to determine bulk volume, see Figure 6.1. Points • KSEPL recommended technique because of simplicity and speed. • Significant error in bulk volume may be introduced if large surface pores are present, e.g. in a vuggy sample. • Errors are minimised by using right cylinders and wrapping them in cling film before the measurement. • For carbonates which are particularly cracked or vuggy, more representative bulk volume measurements may be obtained by whole core or full diameter analysis (see section 7.3). Precision • 0.01 ml. Price/timing • < US$75 per sample. • A single measurement takes a few minutes. Peripheral measurements • Grain and/or pore volume are needed to determine porosity. • Dry weight is needed to determine grain density.

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Bulk volume by mercury displacement

Principle A clean, dry, consolidated sample is immersed in mercury and the volume of displaced mercury is determined by a piston displacement. Points • This is an acceptable technique. • Ensure that there is not a significant head of mercury on the sample during measurement. For this reason, bulk volume by mercury buoyancy is preferred. • Significant error in bulk volume may be introduced if large surface pores are present, e.g. in a vuggy sample. Errors are minimised by using well formed right cylinders and wrapping them in cling film before the measurement. • For carbonates which are particularly cracked or vuggy more representative bulk volume measurements may be obtained by whole core or full diameter analysis (see section 7.3). Precision • 0.01 ml. Price/timing • < US$75. • A single measurement takes a few minutes. Peripheral measurements • Grain and/or pore volume are needed to determine porosity. • Dry weight is needed to determine grain density.

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Bulk volume by caliper

Principle A caliper is used to measure sample dimensions to calculate bulk volume. Points • This is an acceptable technique for regularly shaped samples. • This method is slightly quicker than mercury displacement but is less accurate. • It can be used in cases where large surface pores/vugs are present. Precision • 0.15 ml (which is equivalent to a porosity precision of 1 porosity unit for a 20% porosity sample). Price/timing • < US$50 per sample. • A single measurement takes a few minutes. Peripheral measurements • Grain and/or pore volume are needed to obtain porosity. • Dry weight is needed to determine grain density.

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Pore volume by liquid saturation

Principle The weight of a clean, dry, consolidated sample is measured before the sample is 100% saturated with a fluid, either brine or an organic solvent. The saturated weight is measured and the pore volume is determined from the dry and saturated weights and density of the saturating fluid. Points • This is an acceptable technique although care must be taken to avoid handling errors such as can arise in measuring saturated weight if extraneous fluid drops adhere to the sample surface or if the sample is not fully saturated. • Pore volume is measured directly. • Consolidated samples only. Precision • 0.01 ml (which is equivalent to a porosity precision of 0.2 porosity units for a 20% porosity sample). Price/timing • < US$50 per sample. • A batch of 20 samples usually takes about a day. Peripheral measurements • Bulk volume and/or grain volume are needed to determine porosity and dry weight to determine grain density.

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Grain density by pycnometer

Principle Five to ten grams of clean, dried (unconsolidated or crushed) sample are placed in a pycnometer (which is a small glass flask of known weight accurately calibrated for volume; see Figure 6.2). After weighing, the pycnometer is filled with toluene or kerosene, and the solvent is degassed. The weight of pycnometer, sample, and solvent is then determined at a known temperature. Grain density is calculated from weights, pycnometer volume and solvent density. Points • KSEPL recommended technique for determination of grain density for unconsolidated and consolidated material. The techniques is recommended for its accuracy. • Technique is destructive. • Trimmings (or endpieces) are usually used. • Temperature control is critical. • Automated pycnometers as shown in Figure 6.3 are often used where temperature control is less critical. Precision • 0.002 g/ml. • This technique is used to calibrate other grain density methods. Price/timing • < US$50 per sample. • A batch of up to 20 takes about a day. Peripheral measurements • Dry weight and bulk volume are needed to obtain pore volume and porosity.

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Grain volume by buoyancy

Principle A sample is weighed when 100% saturated with a solvent such as chlorothene or toluene. The saturated sample is immersed in a bath of the same solvent and re-weighed while suspended below the surface of the solvent. Grain volume is calculated from the dry and saturated weights and solvent density according to Archimedes Principle. Points • This is the recommended technique (see Figure 6.4). • Consolidated samples only. • Temperature control is critical. Precision • 0.005 ml (which is equivalent to a porosity precision of 0.1 porosity units for a 20% porosity sample). • Error can occur if sample is not completely saturated. Price/timing • < US$50 per sample. • A batch of 20 usually takes about a day. Peripheral measurements • Bulk volume and dry weight are needed to obtain porosity and grain density.

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Grain volume by Boyle's law porosimetry

Principle A Boyle's law porosimeter determines volumes by the principle of gas expansion. A typical design is shown in Figure 6.5. It consists of two chambers, a reference chamber and a sample chamber of known volume, which can be isolated. Helium gas, at a pre-set initial pressure, is allowed to expand from the reference cell into the evacuated sample cell, which contains the clean, dry sample of unknown grain volume. The final equilibrium pressure is measured and the grain volume can be calculated using Boyle's Law.

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Points • Boyle's Law porosimetry is acceptable but KSEPL recommends that, on a regular basis, either the pycnometer or buoyancy method be performed on a subset of samples so that Boyle's Law technique can be checked or calibrated. • Sufficient time must be taken to reach pressure equilibrium otherwise porosity and grain density can be underestimated particularly for low permeability samples. • The technique is non-destructive for consolidated samples. • Both consolidated and unconsolidated samples can be run. Unconsolidated samples are placed in a cup of known volume Precision • 0.025 (which is equivalent to a porosity precision of 0.5 porosity units for a 20% porosity sample). Price/timing • < US$50 per sample. • A typical measurement takes less than 30 minutes per sample. Peripheral measurements • Bulk volume and dry weight are needed to obtain porosity and grain density.

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6.2

Steady- state gas permeability

6.2.1

Air permeability

Principle A core plug of known length and diameter is loaded into a “Hassler” type core holder (see Figure 6.6 ). The sample is subjected to a low confining stress (of about 15- 20 bar) to prevent gas flow around the plug. Gas (air or nitrogen) is allowed to flow through the sample by applying a pressure differential across the sample. Flow rate and pressure differential are measured and used to determine sample permeability using Darcy’s law, pressure differential, sample dimensions and gas velocity.

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Points • This is an acceptable technique. Liquid permeabilities are preferred but are much more expensive. • Unconsolidated samples can be measured but problems can occur with by-passing if the sample is not sleeved or if insufficient confining pressure applied. Permeabilities of unconsolidated samples are better measured at reservoir stress. • Specify orientation of the core plug; horizontal and vertical permeability can be quite different. If permeability anisotropy is required, vertical and horizontal permeabilities should be measured on samples as near to each other as possible within the same rock type. KSEPL RR/37 has cubical sample capability for permeability anisotropy (see Figure 6.7) Precision • Precision depends upon permeability: 0.01 - 1.0 1 - 50 50 - 2,000 2 - 10

mD mD mD D

accuracy: +20 % accuracy: +10 % accuracy: + 5 % decreasing accuracy with increasing permeability.

Price/timing • < US$100 per sample. • A single measurement takes about 5 minutes.

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Peripheral measurements • Gas viscosity at temperature must be determined. •

Klinkenberg correction. Using gas at low pressure leads to an apparent permeability which is too high because the mean free path of the gas is no longer negligible compared to a typical pore size. Corrected permeability values are obtained by measuring the permeability at a series of different mean pressures and using them in the following equation: kair = k∞ ( 1 + (b/P) ) where

kair k∞ P b

apparent gas permeability (mD) absolute 'Klinkenberg' permeability (mD) mean absolute pressure (bar) Klinkenberg gas slippage correction factor (bar).

Apparent permeability values are, in general, linear in reciprocal mean pressure. Extrapolation to infinite mean pressure determines the theoretical liquid, or Klinkenberg, permeability, k, and the slope is the Klinkenberg gas slippage factor, b. Values for b range from 0.1 for high permeabilities to 10 for permeabilities in the micro-Darcy range. •

Turbulence correction. Fluid acceleration and deceleration in the pore throats and bodies lead to inertial effects, becoming more prominent at higher differential pressures and flow rates. Darcy's equation will no longer describe the flow, as it is valid only for laminar flow. The Forchheimer equation can be used as described below: (∆P/L) = (Qµ/Ak) + βρ (Q/A)2 where

∆P/L Q/A µ/k β ρ

pressure gradient flow velocity reciprocal mobility (viscosity/permeability) coefficient of inertial resistance fluid density.

Setting β = 0 returns Darcy's Law.

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Probe permeability

Principle In probe permeametry, gas flows from the end of a small-diameter tube (or 'probe') that is sealed against the surface of a slabbed or unslabbed core (see Figure 6.9). Gas at a known pressure is delivered from the probe to the sample. The pressure in the probe is measured together with the corresponding volumetric gas flow rate. Gas permeability is determined from calibrations based on pressure and flow rate. Points • This is an acceptable technique as long as sufficient calibration is performed. • The permeability is localised to the region near the seal. • The method is non-destructive. • As the probe only investigates a small volume of rock, the measurement is well suited for investigation of spatial permeability variation in cores. Also directional permeability variation around the circumference of a whole core can be measured. • A permeability range of about 1 to 10,000 mD can be measured. • Data reliability depends heavily on the condition of the core. • Permeability data may reflect effective permeability at partial liquid saturations. Precision • 20% of measured permeability with proper calibration. Price/timing • < US$50 per sample. • Each measurement takes a few minutes. Peripheral measurements • Permeability should be checked against plug values.

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6.3

Fluid saturations

6.3.1

Fluid saturations by Dean-Stark extraction

Principle Dean-Stark extraction relies upon distillation of the water fraction and the solvent extraction of the oil fraction from a sample using the apparatus in Figure 6.10. A virgin sample is weighed and placed in the extractor. Vapour of the boiling solvent distils water from the sample. Solvent and water vapours condense in a reflux-type condenser and are collected in a calibrated trap. Additional extraction is sometimes needed to complete removal of oil and precipitated salts from the sample. After water and oil have been removed, the sample is dried. The oil weight is obtained as the difference between total loss in sample weight and water weight. Oil weight is converted to oil volume using oil density which is measured separately. Points • Dean-Stark is the recommended technique for determining fluid saturations. • Dean-Stark should be done as soon as possible after coring. • Consolidated samples usually remain undamaged and can be used for further testing. • Unconsolidated samples can be used but integrity is difficult to maintain. • Typical solvents are toluene, xylene, chloroform/methanol. • Reported saturations are at atmospheric conditions. • An extra methanol distillation can be used to remove precipitated salt which occurs with samples that contain high salinity brines. • Plugs should be drilled with air and not kerosene. Precision • Water saturation reproducibility is 3 saturation units Price/timing •
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Retort method or summation of fluids

Principle Oil and water fluid saturations are obtained by a high-temperature retorting process in which oil and water contained in a fresh sample of crushed core material are vaporised, condensed and collected in calibrated glassware. The gas saturation is determined on an adjacent, lithologically similar sample by placing it in a mercury pump and measuring the amount of mercury injected with water and oil present. Points • The method is NOT recommended because of high temperature degradation of oil causing oil saturation to be too high. • The method is less accurate than Dean-Stark. • Twin plugs are required. • Porosity and saturation values are determined at the same time. • This method should not be used for samples containing gypsum or montmorillonite as the mineral bound water will be removed by the high temperatures leading to an inaccurate water saturation. • Low permeability samples contain small pore throats and limit mercury penetration which underestimates gas volume. Precision •

Oil saturation Water saturation Porosity

+ 5% (of pore volume) + 5% (of pore volume) + 5 - 10 % of true value

Price/timing • < US$50 per sample. • A batch of 10-20 samples takes about a day. Peripheral measurements • Bulk volume from adjacent sample by buoyancy in mercury or mercury displacement.

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Literature

Schipper, B.A., Oord, R.J. van den, Adams, S.J. Petrophysical core analysis contractors - Procedures and quality assessment. EP 92-1355, July 1992. Dake, L.P. Fundamentals of reservoir engineering. Developments in Petroleum Science 8, Elsevier, 1978. SIPM EPD/22/3 SIPM Coring Series Bulletin 2: Core Analysis EP 89-0105, September 1989. P2.65 course notes KSEPL Contributions Shell Training Centre, Noordwijkerhout, 1992. Looyestijn, W.J. and Schipper, B.A. Improved analysis of sponge core saturation by using gas chromatography 1993 SCA Conference paper no 9305. Schipper B.A. A critical review of two common core analysis measurements for reservoir evaluation. EAPG/RMC/SCA Workshop, Vienna, June 6, 1994. Ruth, D., and Pohjoisrimne, T. The Precision of Grain Volume Porosimeters SCA 9129 presented at the 5th Annual Technical Conference of the SCA, San Antonio.

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Porosity and permeability at stress and whole core analysis

Stressed porosity values are important for reproducing formation porosity, especially for unconsolidated or poorly consolidated samples. The stress dependence of the porosity is determined by compressibility and can be a significant production mechanism. Stressed permeability measurements are critical in determining reservoir flow potential. In particular, the stress dependence of the permeability is important in determining flowrates over the life of a producing hydrocarbon reservoir. Whole core analysis is included in this section because the whole core methods used here predominantly employ stress application.

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7.1 Stressed Porosity 7.1.1 Stressed pore volume by liquid saturation Principle A clean, dried (consolidated) sample is mounted in a stress cell and vacuum saturated at an initial stress. Unconsolidated samples are mounted frozen, allowed to thaw and cleaned at initial stress. The stress is increased in steps and at each step produced brine and change in sample length are determined. The volume of expelled brine is taken to be the change in pore volume. Points • KSEPL, recommended technique. • This is a direct measure of pore volume. • Grain volume is assumed to be unaffected by increasing stress. • Applied stress is usually hydrostatic. • Low permeability plugs require extended evacuation for proper saturation. • Stressed porosity values can be used to calculate isostatic compressibility but more accurate methods of compressibilty measurement are given in Chapter 12. Precision • 0.01 ml in pore volume (which is equivalent to a porosity precision of 0.2 porosity units for a 20% porosity sample). Price/timing /number of samples • About US $500 for porosities measured at 6-8 different stress points. • The method takes 2 to 10 days to complete per sample. • 3-5 samples are recommended per rock type, if possible. Peripheral measurements • Plug resistivity, Ro, is usually measured at the same time. • Longitudinal CT-scans, thin sections and mineralogy assist in data interpretation. • This technique is generally used whenever a stressed pore volume is required prior to a special core analysis measurement such as resistivity index (see Chapter 9) or relative permeability (see Chapter 11). • Samples may not be usable after measurement if they have been exposed to very high stresses.

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Stressed pore volume by Boyle's Law porosimetry

Principle The method here is the same as the Boyle's Law porosimeter method for atmospheric conditions; see section 6.1.7. A clean, dry (consolidated) sample is mounted in a stress cell and Boyle's Law porosimetry is used to determine pore volume. Unconsolidated samples are mounted frozen, thawed and cleaned at initial stress prior to measurement. Points • Boyles Law porosimetry is an acceptable technique. • This is a direct measure of pore volume. • Boyle's Law porosimetry is not normally used to determine the stress dependence of the porosity. • The equipment used at KSEPL for the measurement of mercury/air capillary pressures under stress enables porosity to be measured concurrently under both atmospheric and stressed conditions using a hydrostatic cell/helium porosimeter. Precision • 0.02 ml in pore volume • 0.5% in true value of the porosity. Price/timing/number of samples • < US$100 for a single stress. • Measurement time per samples is about half an hour. • 3-5 samples per rock type are recommended, if possible. Peripheral measurements • Bulk volume is needed to determine porosity. • Usually done at the same time as other measurements such as mercury/air capillary pressure curve.

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Stressed permeability

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Stressed steady-state permeability

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Principle A cleaned, dried sample, with known dimensions, porosity and atmospheric air permeability, is placed in a hydrostatic Hassler-type core holder (see Figure 7.1). If brine permeability is required, the sample is 100% saturated with artificial formation brine. Measurements of pressure difference across the sample, average pore fluid pressure and flow rate are determined at stepwise increments of net isostatic confining pressure. Permeability is calculated and a relationship between confining stress and permeability can be determined.

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Points • KSEPL recommended method for determining (stressed) permeability. • Brine ionic composition should approximate original formation fluid to prevent any reaction with the rock. • Experiments should ensure stable flow rate and pressure drops at each stress. • Consolidated and unconsolidated cylindrical plug samples can be used. • Diameter 2.54 - 3.75 cm and length 3-5 cm can be used. • Maximum effective stress is 400 bar (5,800 psi). Effective stress is the difference between confining stress and average sample pore pressure. • Permeability range: 10 µD - 10 D • When gas is used, gas permeability can be measured concurrently under both atmospheric and stressed conditions. After a number of samples have been measured a relationship between gas permeability at effective in-situ stress and standard gas permeability can be developed. • Prior to measurement, a pilot test should be carried out to determine flow rate, average pore pressure, and average differential pressure for which gas slippage and turbulence effects are negligible (see Section 6.1.7). Precision • About 10-20% of true value. Price/timing/number of samples • About US $1000 for 6-8 stresses. • Experiments may last 2-10 days per sample. • 4-6 samples per rock type are recommended. Peripheral measurements • Samples may not be reusable if they have been exposed to high stresses. • Longitudinal CT-scans, thin sections and mineralogy assist in data interpretation. • Special arrangements must be made if stressed porosity and permeability are required on the same core plug.

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Pulse decay permeability

Principle The apparatus is outlined in Figure 7.2. A clean, dry plug sample is placed in a Hassler type core holder and is subjected to the effective confining stress of the formation. Gas pressure is raised to about 100 bar. A pressure pulse is introduced by increasing the pressure in the upstream vessel and then monitoring the return to equilibrium of the pressure, which is dependent on the permeability of the sample. The method is suitable for measuring gas permeability and the effective permeability to gas in the presence of an immobile liquid phase especially in low permeability rocks.

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Points • Pulse decay permeability is recommended for rock samples with permeabilities below 1 mD. • This method can be used to determine permeabilities in the range from 50 nanodarcies to 100 millidarcies. This technique is very well suited to samples with low permeability and has been used effectively to characterise tight gas reservoirs. • Gas slippage effects are negligible due to the high pore pressure used and therefore Klinkenberg correction is not required. • Pulse decay permeability is not normally used to determine the stress dependence of the permeability. • Required water saturation can be obtained by centrifuge desaturating. • Core Laboratories CMS 300 uses a pulse decay technique. Precision • About 10-20% of true value between 0.01 - 100 mD. • For permeabilities < 0.01 mD, precision is reduced. Price/timing/number of samples • US $500 per sample (single stress). • Measurement time per sample is several minutes to more than a day depending on permeability. • 4-6 samples per rock type. Peripheral measurements • Partial liquid saturation is determined prior to measurement. • Longitudinal CT-scans and thin sections and mineralogy are used to assist in data interpretation. • Capillary pressure curves e.g. mercury/air can be used to validate immobile liquid saturations.

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Whole core analysis

Core analysis for petrophysical and reservoir engineering parameters is usually carried out on 2.54 cm to 3.75 cm diameter cylindrical plugs. However, some core material such as heterogeneous carbonates merit sampling on a larger scale. Whole core analysis aims at obtaining values more representative of the formation, by using sections of whole core that are trimmed to form cylinders. Calgary Research Centre, Calgary, Alberta Calgary Research Centre (CRC), a Shell E&P laboratory is the Group's centre of expertise for whole core analysis. CRC may be used for Group Opco work when capacity is available. Coordination through SIPM EPD/222 is required.

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Whole core porosity by Boyle's Law porosimetry

Principle This technique is essentially a Boyle's law helium porosimeter experiment which measures the pore volume of the sample using isothermal helium expansion. The conventional method is described in section 6.1.7. A cleaned, oven dried sample is placed in a Hassler type core holder and subjected to a confining pressure of 400 psi (28 bar) (Figure 7.5). The core holder is connected to the porosimeter and helium is allowed to expand isothermally into the sample from a reference cell of known volume and initial pressure. Pore volume is calculated from the final pressure of the system using Boyle's law. Points • Boyle's Law porosimetry is an acceptable technique. • This technique directly measures pore volume. • Sufficient time must be allowed for helium to expand into the entire pore space, otherwise porosity may be underestimated particularly for low permeability samples. • Full diameter core samples are trimmed to form right cylinders and, if necessary, can be machined to have diameters of 2, 4, or 7 inches (5, 10 or 18 cm). • Samples can be re-used for further tests. • Whole core samples may take a long time e.g. months, to clean. Precision • Porosity can be repeated to within 0.5 porosity percent. Price/timing • < US$100 per sample. • A single porosity measurement may take up to an hour. Peripheral measurements • Bulk and/or grain volume is needed to complete porosity determination. • Special Core Analysis techniques can be adapted for whole core/full diameter samples. See section 7.3.3.

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Whole core steady-state gas permeability

Principle Both vertical and horizontal permeability to gas of a cleaned dried sample are determined using a permeameter equipped with a Hassler-type core holder. The sample is loaded into a rubber sleeve of the holder and subjected to a typical 20 bar (300 psi) confining stress. Flow regimes used to measure the two permeabilities are shown in Figures 7.3 and 7.4. Vertical permeability is determined by flowing gas through the length of the core. Horizontal permeability is determined by passing gas through opposite quadrants of the cylindrical surface of the sample using an array of permeable screens, which cover opposite quadrants on the surface and are rotated through 90o so that the measurement can be carried out in two perpendicular orientations. Points • This technique is acceptable. Liquid permeabilities are generally preferred. • If there is inadequate sealing between the rubber seal of the core holder and the sample, gas will tend to bypass the sample leading to erroneously high permeabilities. • The higher of the two horizontal permeabilities is sometimes referred to as kmax and the lower as k90. Typically a geometric mean permeability is calculated which is used in porositypermeability relationships and in log calibration for permeability estimation. Precision • Permeability can be repeated to within 10 to 15 percent. Price/timing • About US $100 (including cleaning). • A single measurement takes about 15 minutes. Peripheral measurements • Klinkenberg corrections might be considered but are not usually done in whole core analysis.

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Other whole core measurements

The range of special core analyses that can be done on whole core/full diameter samples is sufficient for most formation evaluation purposes. While special core analysis topics are reviewed in detail in Chapters 9 - 13, it is appropriate to review available whole core services. •

Capillary pressure The technique used here is the pressure equilibrium method. See section 8.1.2 for details.

•

Formation resistivity factor See section 9.1 for details.

•

Resistivity index See section 9.2.1 for details

•

Unsteady-state relative permeability measurements. This technique is usually not suitable for heterogeneous core material which is often the case with whole-core samples. See section 11.3 for details.

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Literature

Dicker, A.I., Smits, R.M.M. A practical approach for determining permeability from laboratory pressure pulse decay measurements. SPE 17578 1988. Gilicz, A Application of the pressure decay technique SPE 22688 1991. Shell Method Series Determination of formation resistivity factor of reservoir rock: Simulated reservoir stress method. SMS 2705-86 Juhasz, I. Conversion of routine air permeability data into stressed brine permeability data. Tenth European Formation Evaluation Symposium, Aberdeen, 1986, paper Y Ostermeier, R.M. Some Issues affecting the properties of Gulf Of Mexico Turbidites SCA 9312 presented at the 1993 SCA conference in Houston.

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Capillary pressure

The manual "Capillary Pressure and Saturation Height Functions" by S.J. Adams and R.J. van den Oord, (report EP 93-0001) contains an extensive discussion and description of capillary pressure measurements and their interpretations. Consequently, this section on capillary pressure highlights aspects of capillary pressure measurement relevant to a comprehensive core analysis programme. The capillary pressure curve is the most common special analysis measurement performed on core plugs. Capillarity is responsible for the distribution of oil and brine in a reservoir and is the first rock property discussed which focusses on two phase behavior of rock samples. Proper measurement of capillarity is critical for accurate determination of hydrocarbon reserves. The most common fluid pairs in measurement of capillary pressure are: •

mercury/air;

•

oil/water;

•

gas/liquid.

Corrections for particular fluid pairs are made based on interfacial tension as well as an estimate of contact angle or wettability, which are required for saturation-height functions. Throughout all measurements of capillary pressure, accuracy of the capillary pressure curve is dependent on the accuracy with which the pore volume is measured. Any error in pore volume is translated immediately into a saturation error in the capillary pressure curve itself. It is recommended as a general procedure in capillary pressure measurements to remeasure the pore volume at the end of an experiment although this is difficult in the case of mercury/air curves.

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Figure 8.1 shows two typical capillary pressure curves: •

Primary drainage - begins with a fully (wetting phase) saturated core. Non-wetting phase is introduced and the sample is driven to initial wetting phase saturation, Swi, This measurement reflects the fluid distribution typically found at the time of discovery.

•

Imbibition - beginning with initial wetting phase saturation, Swi, imbibition describes the process by which wetting phase saturation is increasing till residual non-wetting phase saturation is achieved. An example of this process is waterflooding.

Other processes are also described as follows: •

Secondary drainage - begins at residual non-wetting phase saturation and describes the process by which the wetting phase saturation increases till an initial water saturation is achieved. This saturation may not be the same as Swi obtained on primary drainage depending on wettability, see section 10.1 for further discussion especially Figures 10.1 and 10.2. An example of this process is in movement of the OWC down following gas injection.

•

Secondary imbibition - follows secondary drainage and is similar to imbibition in that the process describes a wetting phase saturation increasing process. An example is when an OWC moves up again after first moving down.

Figure 8.1 also shows two parameters namely the initial wetting phase saturation, Swi, and the entry pressure, Pe, The initial wetting phase saturation, which we shall take as the initial water saturation has other names. It is often referred to as connate water saturation, Swc. Another term that is frequently used is irreducible water saturation. However, irreducible in fact is a relative term depending on the applied capillary pressure. At increasing capillary pressure, Swi, decreases until it reaches zero at infinite capillary pressure. Thus, we prefer to use the term, Swi, for initial water saturation, which is taken to mean the lowest water saturation consistent with the initial capillary pressure.

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Mercury/air capillary pressure

In mercury/air measurements, mercury is the non-wetting fluid and air, or vacuum, is the wetting fluid. Mercury/air experiments are used because they can be done rapidly with many data points measured. This makes mercury/air measurements the most accurate in terms of detailed characterisation of capillarity of rocks. For example, an Autopore 9220 measures as many as 250 points in defining a capillary pressure curve. Mercury/air experiments have the disadvantage that bound water effects are not included. Accordingly, comparisons between mercury/air and oil/water capillary pressure curves will show mercury/air curves achieve a lower wetting phase saturation at the same equivalent capillary pressure. Also, imbibition cycle capillary pressures cannot be reliably measured in the mercury/air system. Note: mercury/air experiments should be the last measurement performed on a sample because mercury is difficult to remove and renders the sample essentially useless for further work.

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Mercury/air capillary pressure by high pressure injection - Autopore 9200, 9220

Principle The Micromeritics Autopore 9200 (recently replaced by model 9220) can measure mercury/air capillary pressure curves up to a pressure of almost 4,000 bar (60,000 psi) (see Figure 8.2). Experiments are performed in two separate chambers. A low pressure chamber acquires data for pressures up to 1. 7 bar (25 psi) and a high pressure chamber acquires data up to 4,000 bar. A clean and dried sample is loaded into a penetrometer (see Figure 8.3), which is placed into the Autopore. Mercury pressure is applied which causes mercury to be displaced from the penetrometer into the sample. The amount of mercury that enters the sample is determined by the capacitance of the penetrometer at a given mercury pressure. Points • This is the recommended technique for mercury/air experiments on consolidated samples. Samples need to be at least friable. Sometimes rocks with only minimal degree of consolidation can yield surprisingly good results, but stressed measurements are recommended for unconsolidated samples. • Blank corrections tend to be small and generally not needed. Blank correction is a volume correction that should be subtracted to account for cell expansion due to an applied mercury pressure. • High mercury pressures attained allow determination of capillary properties of the very tightest cores. However, tight samples with small pore volumes must be carefully closure corrected and even blank corrected. • Some errors can be noticed for samples whose plateau lies at about 25 psi because it corresponds to the transfer of the sample between the low pressure and high pressure systems. This has been minimised in the Autopore 9220. • Samples should have a diameter of 1.5 or 2.54 cm (1") and a length of 2.3 cm (0.9"). Irregular samples can be used down to a minimum volume of 1 mI. • This technique can be used for drill cuttings analysis for porosity and permeability at BTC. Drill cuttings should be at least 50 mg in weight (see Appendix 4.3.2). • Samples are not usable for further measurement. Any other measurements required must be done before mercury intrusion.

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Precision • Intrusion volume precision is better than 0.001 ml or about 0.2% in saturation. Price/timing/number of samples • US $350 per plug. • Can be done in batches of 4 in about a day. • 6-8 samples per rock type. Capillary pressure is used to characterise rock types and thus more samples are recommended to ensure proper rock typing. Peripheral measurements • Accurate pore volume is essential. • Pore volume can be estimated with acceptable accuracy from the mercury intrusion at 4,000 bar. • Autopore estimates bulk volume from which porosity can be determined. • Grain volume is also needed for an accurate porosity estimate. • Thin sections (on an endpiece) are recommended for better data interpretation.

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Mercury/air capillary pressure by pressure equilibrium

Principle A clean, dry sample is mounted and evacuated (see Fig. 8.4). The sample is injected with mercury at stepwise pressure increments. The volume of mercury entering the sample at each pressure step is measured. Points • Acceptable technique but pressure limited to 1,500 - 2,000 psi compared to section 8.1.1. • A blank correction should be made on the system, typically done by running an experiment on a steel cylinder. • Closure corrections (also known as packing corrections) should be applied which eliminates from the capillary pressure curve, the erroneous contribution of space between cell and sample caused by surface irregularity. • Samples are not usable for subsequent measurement.

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Precision • Intrusion volume precision is 0.001 ml or about 0.3% in saturation. Price/timing/number of samples • US $500 per plug. • Experiments usually take about a day per sample. • 6 to 8 samples per lithology or rock type are recommended. Capillary pressure is used to characterise rock types and thus more samples are recommended to ensure proper rock typing. Peripheral measurements • An accurate pore volume determination is essential. • Thin sections are highly recommended in rock typing.

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Stressed mercury/air capillary pressure

Principle Stressed mercury/air measurements can be performed on consolidated and unconsolidated samples by applying hydrostatic (isostatic) stress to the samples before mercury injection (see Figure 8.5). The difference between confining stress and mercury pressure is kept constant at the required net effective stress to ensure that the rock sample is maintained at the proper stress state. The technique is otherwise the same as the pressure equilibrium method. Points • Recommended technique for unconsolidated samples. • A blank correction is important in this experiment. • Closure corrections (also known as packing corrections) should be applied. • Unconsolidated samples are often cleaned in the apparatus before measurement. • The maximum mercury pressure is usually about 2,000 psi (140 bar) although some systems can go to 5,000 psi (350 bar). • Maximum applied stress is about 5,000 psi (350 bar). • Samples are not usable for further measurement. Precision • About 0.2% in saturation. Price/timing/number of samples • About US $750 per plug. • A typical experiment takes at least two days if cleaning is required. • 6-8 samples per rock type are recommended per rock type. Peripheral measurements • A stressed pore volume must be measured either by Boyle's Law or by fluid saturation. Pore volume by fluid saturation has the disadvantage of requiring subsequent cleaning. • Thin sections on endpieces are highly recommended.

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Oil/water capillary pressure

Oil/water capillary pressure curves allow determination of capillary properties which more closely approximate the subsurface environment. Measured pressures more directly relate to subsurface values. In addition, effects of brine associated with clay particles, commonly known as clay-bound water, can be incorporated. Unfortunately, oil/water capillary pressure curves are determined by fewer points compared with mercury/air techniques, because of the much longer time needed to approach equilibrium in oil/water systems as well as a more limited pressure range. An advantage is that both imbibition and drainage can be done using this technique.

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Oil/water capillary pressure by centrifuge

Principle Brine saturated samples (usually in batches up to 6 samples) are spun in a centrifuge at a series of increasing rotational speeds. Rotational speed, which can go as high as 20,000 rpm in an ultracentrifuge, determine the capillary pressure of the system. In a typical configuration (see Fig. 8.6), the centrifugal force causes oil to displace brine from the sample. The volume of brine produced is determined at each speed. For imbihition, experiments. brine displaces, oil and oil production is monitored.

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Points • Recommended technique for oil/water capillary pressure curves. • Data should be extrapolated to infinite time before data analysis methods are applied. • Rotational speeds should be applied for at least 24 hours, otherwise production data cannot be easily extrapolated. • Automated data acquisition systems provide better data. • Production data (average saturation) must be converted to endface saturation data and such analysis can be quite complex. Best data analysis methods are parameter estimation and Forbes technique. • Centrifuges can be either a low speed (up to 5000 rpm) conventional centrifuge or a high speed (up to 20,000 rpm) ultra-centrifuge. The high speed ultra-centrifuge is better suited for tighter samples. • Bond number, preferably not to exceed 10-5 otherwise desaturation effects may occur causing incorrect residual saturations. • Stress can be applied in various configurations of centrifuge experiments. • By changing configuration, brine can displace oil so that an imbibition capillary pressure curve can be measured. • The spontaneous imbibition branch for water-wet samples cannot be obtained when the centrifuge is run on the imbibition cycle. Precision • •

Reproducibility of centrifuge capillary pressure curves has been investigated at KSEPL and was reported to be within 3% saturation. Production volume resolution should be to 0.05 ml, which corresponds to approximately 1% uncertainty in saturation.

Price/timing/number of samples • About US$l,000 per capillary pressure curve is typical. • A batch of up to 6 samples can take about a week to 10 days. • 4-6 samples per rock type are recommended. Peripheral measurements • An accurate pore volume is essential. • Centrifuge capillary pressure curves can be combined with relative permeability measurements using the centrifuge (see Chapter 11). • Thin sections are recommended. • A mercury/air capillary pressure capillary curve is recommended for comparison with primary drainage curves. • If imbibition capillary pressure curves are determined, then an estimate of wettability can be obtained. Representative wettability (aging) should be applied for imbibition experiments.

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Oil/water capillary pressure by pressure equilibrium

Principle In the Pressure Equilibrium technique, the capillary pressure curve is usually obtained as part of a resistivity index versus saturation measurement (see Chapter 9). A clean, dry sample in contact with a capillary diaphragm, is mounted in a stress cell and vacuum saturated with brine (see Figure 8.7). Oil pressure is applied at a specific pressure and the oil volume injected into the rock sample is determined after the system has equilibrated. A number of pressure steps are used (typically 6-10) to define the oil/water capillary pressure curve.

Points • This is an acceptable technique. • Experiment is usually run under stress. • Closure is determined as part of the resistivity measurement.

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Determining whether the sample has equilibrated at a given pressure is difficult. It is recommended that the data be extrapolated to infinite time to ensure meaningful equilibrium results. Data near the entry pressure, i.e. at high water saturation, is generally not well delineated, because so few data points are measured. Fortunately, such data are not needed for closure corrections which is determined by other means.

Precision • Pressure precision is usually very high; saturation uncertainty is about 0.5% PV. Price/timing/number of samples • US $750 per plug sample. • Very slow experiment; can take more than two months to complete. • About 2-4 samples per rock type are recommended. Peripheral measurements • An accurate stressed pore volume measurement is essential. • Usually accompanied by a resistivity index measurement. • A comparison mercury/air capillary pressure measurement is recommended. • Thin sections are highly recommended.

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Gas/liquid capillary pressure

Gas/liquid capillary pressure curves are generally much easier to measure than oil/water capillary pressure curves. The gas used is generally air although sometimes nitrogen is used. Hydrocarbon gas is never used in these measurements. This is not so critical because the wetting state in gas/liquid systems is strongly liquid wetting. On the other hand a variety of liquids are used. Both air/water and air/oil curves are measured. In air/water systems the effect of clay bound water is more clearly seen. Like oil/water curves, gas/liquid capillary pressure curves are determined with fewer points than with mercury/air techniques.

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Gas/liquid capillary pressure by centrifuge

Principle The principle is the same as presented in section 8.2.1. However, in this technique, the centrifugal force causes air to displace liquid. The liquid production is determined at each centrifuge speed. Points • Recommended technique for gas/liquid capillary pressure curves. • Data should be extrapolated to infinite time before data analysis. • Rotational speeds should be applied for at least 24 hours, otherwise data cannot be easily extrapolated. • Production data (average saturation) must be converted to endface saturation data and such analysis can be quite complex. Best data analysis methods are parameter estimation and Forbes technique. • Imbibition curves are generally not measured in gas/liquid systems. Precision • Reproducibility of centrifuge capillary pressure curves has been investigated at KSEPL and was reported to be within 3% saturation. Price/timing/number of samples • US $950 per plug. • A batch of up to 6 samples can take about a week to 10 days. • 4-6 samples per rock type are recommended. Peripheral measurements • An accurate pore volume is essential. • Thin sections are recommended. • A mercury/air capillary pressure curve is recommended for comparison with primary drainage curves.

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Gas/liquid capillary pressure by porous plate vessel

Principle A clean, dry sample is saturated with the wetting phase fluid (brine or oil). The sample is then placed in a batch of 20 or so on a semi-permeable membrane, which is only permeable to the wetting phase. The gas pressure is increased stepwise, forcing gas into the sample. Brine is expelled through the porous plate. After equilibrium has been reached at each pressure step (determined by non-brine production), the sample is removed from the cell and saturation changes are determined gravimetrically. The plugs are again placed in the porous plate vessel and a higher gas pressure is applied. Points • This technique is NOT recommended because of sample alteration caused by frequent handling and uncertain re-attainment of capillary continuity. Other problems also exist such as possible salt precipitation during the experiment. • Samples mounted individually in contact with a porous plate in a sleeved core holder can be used for gas/liquid capillary pressure measurement following guidelines in section 8.2.2.

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Literature

Adams, S.J., Oord, R.J. van den Capillary pressure and saturation-height functions EP 93-0001, January 1993 Anderson, W.G. Wettability literature survey part 4: Effects of wettability on capillary pressure JPT, October 1987 Bemelmans, W.A Automation of the ultracentrifuge KSEPL report, RKMR.87.037. Bil, K.J. The use of footbaths in centrifuge capillary pressure curve measurements EUROCAS, Paris, 14-16 September 1992 Boutkan, V.K Estimating the validity of the continuous injection method for measuring capillary pressure and resistivity index RKRS.92.RPI Dicker, AI.M., Bemelmans, W.A. An improved method for transforming centrifuge liquid production data into drainage capillary pressure curves EP 87-0283 Hassler, G.L., Brunner, E. Measurement of capillary pressure in small core samples Trans., AIME (1945) Vol. 160, 114 Hirasaki, G.J., Rohan, J.A. The effects of core cleaning and ageing with crude oil on capillary pressures and relative permeabilities TIR BRC-2239, EP 91-0633 Hofman, J.P., Scherpenisse, W., Diederix, KM., Hartemink, W. The centrifuge technique for determining drainage capillary pressure curves. EP-51754 Kokkedee, J., Boutkan, V. Towards measurement of capillary pressure, relative permeability at representative wettability Production Newsletter, August 1993 O'Meara, D.J., Hirasaki, G.J., Rohan, J.A. Centrifuge measurements of capillary pressure: Part 1 - outflow boundary conditions SPE Res. Eng., February 1992 Forbes P.L. Simple and accurate methods for converting centrifuge data into drainage and imbibition capillary pressure curves. SCA 9107 presented at the Annual Technical Conference, August 1991 Smits, L.J.M. The relationship between the wettability of reservoir rocks and their capillary pressure and resistivity EP-40211, March 1969

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Electrical properties

The measurement of electrical properties is critical for proper evaluation of resistivity logs. This chapter on electrical properties is divided into three sections: •

brine saturated measurements;

•

measurements of systems with partial brine saturations and;

•

methods for the determination of the cation exchange capacity which is an important parameter in resistivity log interpretation of shaly samples.

It is always recommended to use formation brine or synthetic formation brine in electrical measurements.

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Formation Resistivity Factor, FRF, and cementation exponent, m

Principle A sample is vacuum saturated in a hydrostatic stress cell and brine is flowed through the sample until a stable resistivity value is obtained. Formation resistivity factor, FRF, is the ratio of sample resistivity to brine resistivity. Formation factor, stressed porosity and cementation exponent are determined at stress by measuring change in resistance, sample length and pore volume. Points • This is the only direct method for measuring FRF and m at stress. • Both consolidated and unconsolidated samples can be used. • Isostatic stress conditions are generally used. • In shaly samples, clays can contribute to sample conductivity. The values obtained from shaly samples require a correction for cation exchange capacity (CEC). Methods used for measuring CEC are outlined later in this chapter. The Waxman-Smits model corrects measured resistivity values for the presence of clay. Precision • 2.5% of actual value (i.e. about + 0.05 in cementation exponent, 'm'), Price/timing/number of samples • US$950 per sample. • Each measurement takes approximately 2 days including preparation. • 3-5 samples per rock type is recommended. Peripheral measurements • Brine resistivity, Rw, is measured separately. • An accurate ambient porosity is essential. Stressed porosity is calculated during the experiment. • Qv or CEC for shaly samples. • Two longitudinal CT-scans are important for determining heterogeneity. • Thin sections assist in data interpretation. • Formation factor measurements are always performed at the start of a resistivity index measurement, see section 9.2.

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Resistivity index, I, and saturation exponent, n

Resistivity index, I, is the ratio of the resistivity of a sample, Rt at a water saturation, Sw, to the resistivity of the sample when fully saturated with the same brine, Ro. As water saturation is decreased, the resistivity of the sample increases as hydrocarbon replaces the brine within the pore space of the rock sample. The purpose of resistivity index measurements is to provide the relationship between resistivity index, I, and saturation, Sw, such as shown in Figure 9.2, which can be critical for the interpretation of resistivity logs. This relationship can be often approximated by the Archie equation which is a power law expression and is thus linear on a log-log plot. For more complex systems, the I- Sw relationship may be represented by a curve. The accurate determination of the I- Sw curve and 'n' is very important for quantifying hydrocarbons using resistivity logs.

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In Figure 9.2, the straight line (1) represents the classic Archie equation. For some rock samples different curvatures are found. A downward curving relationship is characteristic of certain types of shaly sandstone, for which the Waxman – Smits equation can be used. Precise knowledge of this curve is essential for correctly calculating hydrocarbon saturation from wireline logs and hence for obtaining an estimate for HCIIP. It is important to realise that hysterisis can occur ion the I-Sw relationship (see Figure 9.3). Generally drainage data (water saturation decreasing) are measured. This is because formations are discovered at initial water saturation at the end of the drainage cycle. In this case, systems are mostly thought to be strongly water-wetting. Imbibition data (wetting fluid phase increasing) do not necessarily plot on the same curve as drainage data, because of the effect of wettability on oil production. When measuring resistivity data on the imbibition cycle, careful attention should be paid to proper wetting state which is discussed in the next chapter.

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Resistivity index by pressure equilibrium

Principle A clean, dry core plug is placed in a Hassler-type pressure cell and vacuum saturated under low confining stress with brine of resistivity and ionic composition similar to formation water. Pore volume is determined. Change in pore volume is determined from measured fluid volume. Brine flushing continues until electrical equilibrium is reached and the resistivity at 100% brine saturation, Ro, and the cementation exponent, 'm', are determined. The experimental set-up is shown in Figure 9.4. Oil (kerosene or toluene) is injected into the sample. For a given injection pressure, sample resistivity and volume of expelled brine are monitored when equilibrium is reached (no more brine production). Measurement is repeated for increasing steps in oil pressure. Points • This is a recommended technique for resistivity index determination. • In addition to resistivity index, this technique can also yield an oil/brine capillary pressure curve. • Imbibition mode can be studied by allowing brine to displace the oil. • Confining stress is necessary for unconsolidated samples. • A curved I-Sw relationship can be caused by a leaking membrane. Precision • Uncertainty in water saturation is 0.5% and uncertainty in n is about 0.05. Price/timing/number of samples • US $2,500 per sample is typical. • About 6 weeks per sample for drainage; 2 - 4 additional weeks for imbibition. • 3-5 samples per rock type. Peripheral measurements • Accurate stressed pore volume is essential. • Qv and CEC required for shaly samples. • Drainage saturation exponents are most frequently measured. Imbibition saturation exponents require wettability and aging considerations. • CT-scans and thin sections help in data interpretation. • Formation factor and cementation exponent are always included.

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Resistivity index by continuous injection

Principle The experimental set up shown in Figure 9.5 is very similar to that used in the equilibrium method outlined in section 9.2.1, but the oil phase (kerosene or toluene) is injected into the sample at a constant slow injection rate. Resistivity of the fully brine saturated sample with brine resistivity and ionic properties similar to the formation fluid, is measured. The drainage cycle is begun with an injection rate chosen so that a pore volume of kerosene would be injected in about 14 days. The pump displacement, resistance across the sample, injection pressure and temperature are monitored continuously during injection. Water saturation is determined continuously from injected/produced brine volumes and the pore volume. Points • This is a recommended technique. • Continuous injection gives a qualitative indication of capillary pressure. However, pressure equilibrium is not reached. X-Ray tomography experiments have indicated that these nonequilibrium fluid distributions have no significant effect on the measured I-Sw curve, provided that the experiment is not carried out in less than two weeks. Research is ongoing at KSEPL to use continuous injection for the determination of capillary pressure curves (see Section 14.2.1). • Studies by KSEPL have found that continuous injection and equilibrium methods yield almost identical resistivity index and saturation exponent results. The continuous injection method however, is considered superior since it provides a densely sampled I-Sw curve corresponding to the 'plateau', or near constant gradient region of a capillary pressure curve and is a lot faster. • Drainage mode only. . • Figure 9.6 shows KSEPL capability for continuous injection. • A curved I -Sw measurement can be caused by a leaking membrane. Precision • Uncertainty in water saturation is 0.5% and uncertainty in 'n' is about 0.05.

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Price/timing/number of samples • US $1,500 per sample is typical. • Measurement time is two weeks per sample but another 2 weeks is needed for sample preparation. • 3-5 samples per rock type. Peripheral measurements • Accurate stressed pore volume is critical. • Qv or CEC required for shaly samples. • CT-scans and thin sections assist in data interpretation. • Formation factor and cementation exponent are always included.

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Resistivity index by porous plate vessel

Principle A clean, dry sample is weighed and brine saturated. The electrical resistance of the sample is measured at ambient conditions. The sample is placed in a pressure cell on a plate permeable to brine, where as many as twenty samples are placed at a time. The samples are desaturated by increasing the air pressure in discrete steps, where each pressure level is maintained for 2-4 days so that equilibrium is reached. The plugs are then removed and resistivity and saturation data are obtained from measurements of the sample resistivity and weight. The process is continued until a pressure of 15 bar is reached. Saturation is determined from the weight loss. Points • This technique is NOT recommended because of sample alteration such as grain loss caused by frequent handling and uncertain reattainment of capillary continuity. Other problems also exist such as salt precipitation during the experiment. The technique is not suitable for unconsolidated samples.

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Resistivity index by rapid desaturation

Principle The resistivity and weight of a brine saturated sample is measured. After desaturation is obtained by displacement of brine with air, sample resistivity and weight are measured, yielding a single data point in the resistivity index- saturation relationship. Brine density must be known. Points • This technique is NOT recommended because a single point is inadequate to characterise the entire curve of resistivity- index vs saturation. Moreover there is no guarantee that the sample is at initial water saturation.

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Cation Exchange Capacity (CEC) and Qv

Samples with clay minerals can have anomalous resistivity behaviour due to additional conductivity created by presence of clay particles, which becomes important in low brine salinity environments. The extra conductivity is characterised by the exchange capacity which arises from the clay structure through cationic substitution. This results in a net negative charge on the clay surface. When in contact with brine, a double layer is formed causing extra conductivity, referred to as the clay conductivity. The exchange capacity is expressed as Cation Exchange Capacity in units of milliequivalents per unit weight of dry rock. Alternatively, the Waxman-Smits equation uses Qv which has the units of milliequivalents per unit pore volume. A number of methods is available to measure CEC and Qv. When measuring cation exchange capacity using membrane potential, the value obtained for Qv is denoted as Qve.

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Qve by membrane potential

Principle An electrical potential is generated when two brines of different salinity are brought into contact. When a shaly sample is positioned at the interface, the electrical potential increases. The magnitude of the increase is directly related to Qve. The experimental scheme is shown in Figure 9.7. Points • Recommended technique; available from KSEPL and BTC. • Non-destructive measurement which properly incorporates effects of clay distribution within the sample. • Plug samples should have a diameter of 2.54 cm and a length of 1-4 cm. • Both consolidated and unconsolidated samples can be used. • A stress of 7 bar is applied to prevent leakage around the sample. • Thomas salinities (1.288m: 0.096m) are generally used for which the relationship between measured potential and Qve has been determined. • At KSEPL, salinities of 0.192m: 0.096m are used. • Samples should have a reasonably uniform clay distribution which can be checked with CTscanning. • Measurements can be unreliable for very high values of Qve i.e. Qve > 5 milliequivalents per ml pore space. Precision • Repeatability is estimated at 0.05 in Qve. Price/timing/number of samples • US $300 - $400 is typical. • A measurement takes about 1 hour for a 20 mD sample and up to a day for tighter samples. • 6-8 samples over a range of Qve values can provide a reasonable trend. Peripheral measurements • Sample porosity and permeability should be known. • Longitudinal CT-scans, thin sections and mineralogy help with interpretation. • Membrane potential should be measured for each I-Sw curve. • Membrane potential should also be done when other CEC methods are used.

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Qv by multiple salinity measurements, Co-Cw

Principle The conductivity of a brine-saturated rock sample, Co is measured at different brine salinities of known conductivity, Cw. Four brines are usually used, starting with the lowest salinity and at each salinity the sample is flooded with brine until the conductivity has reached equilibrium. The quantity, BQv, the clay conductivity in the Waxman-Smits model, is determined from a plot of Co versus Cw (see Figure 9.9). The clay corrected formation resistivity factor, F*, is determined by fitting a straight line of slope 1/F* through the high salinity data. Clay conductivity is obtained from the difference between F*Co and Cw.

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Points • Technique is acceptable, but care needs to be taken to ensure brine equilibrium. • The technique is non-destructive. • Beginning experiments with low salinities appears to decrease the time to achieve electrical equilibrium. • Both consolidated and unconsolidated samples can be used. • Plugs of diameter 2.54 cm and length 3-5 cm are preferred. • The experiment is carried out at room temperature and with a net isostatic confining stress up to 400 bar. • Waxman-Smits, Bmax = 3.83 meq/mole, value is needed to determine Qv. • Typical brines used are 25 g/l, 50 g/l, 100 g/l and 200 g/l. Precision • Repeatability is estimated at 0.1 in Qv due to the need for extrapolation. Price/timing/number of samples • US $2,000 - $3,000 per sample. • The method is very time consuming - it can take weeks for a sample to reach equilibrium. It is therefore recommended that its use should be limited to cases where the clay distribution within the reservoir and the sample is not uniform and where salinity variation will not alter the claymorphology. • 3-5 samples per rock type is adequate. Peripheral measurements • Membrane potential Qv measurement is recommended. • Porosity and permeability should be measured. • Longitudinal CT-scans, thin sections and mineralogy aid interpretation.

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CEC by conductometric titration

Principle The sample, usually a clean end piece, is crushed and weighed. The exchangeable cations are exchanged using a suitable leaching solution and are quantified by conductometric titration, which involves titrating the solution while monitoring the conductivity which displays a rapid increase after the correct titre has been reached. Points • This is an acceptable technique commonly used by KSEPL and BTC. • The test is destructive. Plug endpieces are ideal to use as they are more than 1 cm in length. • The procedure is simple and easy to perform. • Extreme crushing or powderisation will lead to overestimates of CEC. Ideally, rock sample should be just disaggregated. • Other titration methods of determining CEC are done, such as using ammonium acetate, but these are not preferred by KSEPL. • This is the usual contractor procedure. Precision Repeatability is about 0.03 in CEC (milliequivalents per 100 gram dry rock). Price/timing/number of samples • US$250 per sample • Measurements usually take about 2-3 days and are done in batches of about 10. • 3-5 samples per rock type. More samples are required if a trend is to be established, such as with porosity. Peripheral measurements • Accurate pore volume is required. • Is routinely done for every I-Sw sample at KSEPL.

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CEC by absorbed water correlation

Principle The measurement is based on an assumption that there exists a relationship between clay surface area, which is measured by water absorption, and the cation exchange capacity of the sample. The sample is dried at 40% relative humidity and 60°C to leave a few layers of absorbed water on the clay surface. After weighing, the sample is dried completely at 105°C and the measured weight loss gives the amount of absorbed water. This is then correlated with CEC, obtained by using one of the other methods. Points • The technique is NOT recommended because it relies on uncertain correlation and calibration by other techniques.

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Literature

Waxman, M.H., Smits, L.J.M. Electrical conductivities in oil bearing shaly sands AIME Transactions 243 1968 pp. 107-122. Waxman, M.H., Thomas, E.C. Electric conductivities in shaly sands JPT, 1974, pp. 213-225. Archie, G.E. The electrical resistivity as an aid in determining some reservoir characteristics. Trans. Am. Inst. Min. Metall. Engrs., 146, pp. 54-62, 1942. Yuan, H.H. and Diederix K.M. The role of membrane potential measurements in shaly sand evaluation. The Log Analyst, vol 30, 415-423, 1989. Waal, J.A. de, Smits, RM.M., Graaf, J.D. de and Schipper, B.A. Measurement and evaluation of resistivity index curves SPWLA Conference Denver 1989, paper II. Shell Method Series Determination of formation resistivity factor of reservoir rock: Simulated reservoir stress method. SMS 2705-86 Anderson, W.G. Wettability literature survey part 3 - The effects of wettability on the electrical properties of porous media. Journal of petroleum technology 1986, pp. 1371-1378. Waal, J.A. de The influence of clay distribution on shaly sand conductivity. KSEPL report RKRS.87.09. Wang, Z., Hirsche, W.K, Sedgwick, G.E. Electrical and petrophysical properties of carbonate rocks. SPE 22661, October 1991 Worthington, A.E. Errors in the laboratory measurement of the formation resistivity factor. SPWLA, 16th annual logging symposium 1975, paper D. Worthington, P.F., Evans, R.J., Klein, J.D., Walls, .J.D., White, G. SCA guidlines for sample preparation and porosity measurement of electrical resistivity samples. Part 3: The mechanics of electrical resistivity measurements on rock samples. The Log Analyst, March/April 1990, pp. 64-67.

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Wettability and interfacial tension

In understanding the behaviour of oil and water in rocks, the issue of wettability is important. Until now we have concentrated predominantly on the behaviour of samples that have been cleaned and dried to a condition that is presumed to be water-wet. Definitions of wetness are given in the next section, but it is sufficient to say that water-wetness expresses a preference for the sample to imbibe only water. Core analysis experiments from basic analyses, capillary pressure and resistivity index have focused on the use of cleaned samples. This is acceptable as long as we are considering the behaviour of samples on primary drainage (see Figure 8.1) and the interest is directed towards the initial water saturation. However, when considering the behaviour of oil and water on the water saturation increasing cycle, reservoir wettability is the determining factor of flow behaviour. Wettability is important because of its impact on the proper measurement of imbibition cycle properties, particularly relative permeability. This chapter focuses on issues associated with proper measurement of relative permeability namely: •

wettability and;

•

interfacial tension.

Interfacial tension is used here primarily as a means of screening the suitability of any crude oil sample for core analysis experiments.

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Wettability

Reservoir wettability expresses the preference of a rock sample for a given fluid type and determines the flow behaviour of oil and water upon production. Core measurements, such as relative permeability, carried out on the imbibition cycle (water saturation increasing) must be performed with the correct wettability. Wettability is usually defined by the angle (conventionally measured through the wetting phase) made at an oil/water interface in contact with a solid surface. Typical definitions of water wet, oil wet and neutral wet are given in Table 10.1 and shown in Figure 10.1. water wet neutral wet oil wet

0° 70° 110°

< < <

θ θ θ

< < <

70° 110° 180°

Table 10.1 - Wettability definition In practice, a water-wet sample would show a preference for water by showing the ability to imbibe water. Similarly an oil-wet rock would show a preference for oil by showing the ability to imbibe oil. A neutral-wet rock would imbibe neither. Beyond this simple description of wettability lies a much more complex wettability of reservoir rocks. In reservoirs, the combination of variable rock composition, rough and complex pore and surface morphology as well as complex mixtures of hydrocarbon type and brine composition, make reservoir wettability even more complicated. The current view is that reservoirs, in particular sandstone reservoirs, often exhibit mixed wettability, where parts of the pore space occupied by oil become oil wet after prolonged contact between oil and rock fabric while the smaller pores filled only with brine remain water wet. Mixed wetting systems can exhibit characteristics of being both oil wet and water wet. One such test is the degree of spontaneous imbibition to brine which is an indication of water-wetness. Mixed wet systems can exhibit spontaneous imbibition to both brine and oil. While wettability remains a subject of continued research, there are now recommended procedures which improve the determination of critical reservoir parameters under appropriate measurement conditions.

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Wettability of core samples may change during handling. For example cleaned samples may be more water wet than in-situ. This chapter addresses the types of sample preparation necessary to conduct measurements at appropriate wetting conditions i.e. fresh state, restored state and cleaned state. Fundamental to considerations about measurement at proper wetting conditions is the comparison of results between different wetting states. SIPM/KSEPL recommends core measurements made at two different wetting states such as stored state vs cleaned state or fresh state vs restored state to estimate the impact of wettability.

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10.1.1 Cleaned-state samples Cleaned state samples refer to those samples that have been cleaned such as by procedures as specified in Chapter 5. The majority of core analysis is done on samples in the cleaned-state such as porosity and permeability. For special core analysis, such as capillary pressure and resistivity index where properties are often measured on water-saturation decreasing cycles (primary drainage), cleaned-state cores are considered acceptable. On measurements where the imbibition cycle is important such as relative permeability, some observations must be made on cleaned-state cores: •

Dean-Stark cleaning possibly increases oil wetness because of exposure of water-wet surfaces to hydrocarbon solvent during cleaning may cause the surfaces to become more oil wet. Thus, the assumption that cleaned-state core are water-wet may not be true.

•

Steps to render cleaned-state samples water-wet have been developed at Shell. One method is to expose samples (particularly sandstones) to tetrahydrofuran. Otherwise, alternating solvents such as chloroform/methanol and xylene can help make a sample more water-wet. Pyridine has also been shown to be effective in making samples water-wet.

•

Making samples water-wet is important for two reasons: - samples cleaned to water-wet allow restoration to proceed with more confidence in duplicating reservoir wettability (for relative permeability measurements); - measurements with cleaned-state samples have a better basis of comparison.

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10.1.2 Restored-state samples (aging) Restored state samples are samples that have first been cleaned and then are exposed to reservoir crude oil at initial water saturation for at least 4 weeks at reservoir temperature and pressure with the intention of reestablishing reservoir wettability. This is referred to as aging the sample. Aging steps can be outlined as follows: •

Extensive cleaning to remove all compounds from the rock surface and to produce a waterwet state.

•

100 % saturation with formation brine.

•

Flooding with (dead) reservoir crude to initial water saturation which is accomplished through application of appropriate capillary pressure.

•

'Aging' by leaving the sample in contact with these fluids for at least 4 weeks at reservoir temperature and pressure at initial water saturation. A period other than 4 weeks may be recommended following specific research (see Chapter 14.2.1).

•

Possible replacement of the aging fluids by refined oil and synthetic brine to be used in the experiment. This is done if the crude oil is particularly difficult to handle. However, checks must be made to establish compatibility between refined oil and crude oil.

•

There is no guarantee that reservoir wettability is restored.

•

Fresh-state and restored state data may be different because fresh-state samples can have trapped water saturation upon return to initial water saturation while the restored state samples have a lower and more representative initial water saturation (see Figure 10.3).

The Use of Live vs Dead Crudes Crude oil used should be sampled from producing wells upstream from any chemical or heater treaters. This is known as 'dead crude'. Some analyses should be performed with 'live crude'. This is oil which has either been sampled from down hole or has been recombined with gas. In general, it has been found that unless the gas-oil ratio is particularly high that dead crude oil appears to be adequate for aging.

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10.1.3 Fresh-state samples Fresh-state samples refer to samples where precautions have been taken to maintain the in-situ wettability as much as possible and where core analysis measurements are done as soon as possible after the core has reached the surface. Reservoir wettability is preserved by paying careful attention to the drilling fluid used in the coring process. For example, drilling with oil-based drilling fluid or even crude oil has been known as a method for preserving wettability. Fresh-state coring is usually done with bland water-based muds where surfactants are excluded, and that have minimal effect on core wettability. Fresh-state samples are not cleaned or dried before experiments. While wettability preservation is difficult, the following guidelines can be used: •

Drilling muds with surfactants or pH differing significantly from the formation fluids must be avoided.

•

Recommended coring fluids: - synthetic formation brine; - formation crude oil; - water based mud with minimum additives; - possibly non-invading gel mud.

•

Oil based drilling muds may require environmental considerations.

•

Minimise exposure of consolidated core to air and drying after coring by performing the following well site procedures: - immersing the core sections in deoxygenated formation or synthetic brine and placing in glass-lined steel or plastic tubing which is then sealed; - OR wrapping the core sections in polyethylene or polyvinylidene film and then in aluminium foil. The wrapped core is then coated in paraffin wax or a plastic seal.

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10.1.4 Preserved-state samples Preserved-state samples are essentially the same as fresh-state samples but have been stored for a period of time. Consequently, some attention should be paid to the method of preservation and the period of storage. In many cases, if the core has been stored for longer than a few months, core wettability is likely not to be in the same state as when it first reached the surface due to drying or additional core alteration. 10.1.5 Pressure-retained core samples Pressure coring has the advantage that the pressure of the reservoir fluids is retained and that changes to the core material are minimised. When pressure coring is performed in combination with bland drilling muds then the cores are most likely to be maintained in a state that best approximates reservoir wettability. However, pressure coring is very expensive and safe practices have to be clearly specified.

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10.1.6 Restored state vs native state For the remainder of this manual, we shall not distinguish between fresh-state, preservedstate cores and pressure-retained cores. We refer to them collectively as 'native-state' cores. SIPM and KSEPL recommend restored-state special core analysis for the following reasons: • An important parameter in core analysis is the appropriate initial water saturation, Swi. Restored-state samples achieve Swi values that are commensurate with field values because both systems have achieved initial water saturations under similar, i.e. water-wet conditions. •

Native-state cores are generally cored with water-based mud so that some imbibition has taken place resulting in a lower oil saturation. However, in order to restore the sample to an initial water saturation, native state samples are generally flooded with oil. However, performing such tests now drive the sample to an initial water saturation from a secondary drainage cycle as opposed to the restored state cycle which achieves initial water saturation under primary drainage. Secondary drainage processes in mixed-wet systems frequently result in trapped water saturation which can be as much as 10-15% of the pore volume. This is shown in Figures 10.2 and 10.3. While it has been thought that agreement between results from restored state and native state tests should be expected, careful consideration shows that only in situations that are strongly waterwet would such an agreement be acceptable. In mixed wet cases, the difference in initial water saturations on primary versus secondary drainage cycles can be as large as 10-15%. This is essentially the observation of hysteresis in capillary pressure phenomena.

•

It remains important to pay careful attention to drilling parameters and drilling mud composition when cutting core for use in wettability and relative permeability studies even though restored-state techniques are used. This is to minimise any damage to the core material during coring.

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Wettability determination

Whenever water/oil relative permeability or any other imbibition cycle water/oil measurements are made, such as imbibition water/oil capillary pressure and imbibition cycle resistivity index measurements, it is advisable to determine the wettability of the system. There are a number of methods for measuring wettability from contact angle determination to capillary pressure methods. The two most common wettability measurements are Amott and USBM methods.

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10.2.1 Amott Principle A wetting fluid will tend to spontaneously imbibe into a sample of core material displacing a nonwetting fluid. The Amott wettability index is calculated as the ratio of the volume of fluid displaced by spontaneous imbibition (line 2 in Figure 10.4), to the total volume displaced by both spontaneous and forced imbibition (line p-s). The ratio of displaced brine volumes is the 'displacement by oil ratio', and that of oil volumes the 'displacement by brine ratio'. Together, the two ratios give a measure of sample wettability as follows: water-wet oil-wet neutral-wet

oil ratio 0 1 0

water ratio 1 0 0

Points • Acceptable technique for wettability determination. • Technique is suitable for measuring wettability in strongly water wet or strongly oil wet conditions and is not particularly sensitive at neutral wetting. • Values generally lie between 0 and 1 and it is the combination of the two ratios that provide insight into the wetting state. • Mixed wet samples have both ratios positive. Precision • Indicative only. Price/timing/number of samples • US $l,000 -US $1,500 per sample. • The recommended imbibition time is 2-3 weeks. If imbibition is stopped after a short period of time the measured displaced volumes are too small, producing wettability ratios that may be too small. • Either one Amott or one USBM for each fresh-state or restored-state measurement. Peripheral measurements •

Amott tests are usually done in support of other measurements such as relative permeability.

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10.2.2 United States Bureau of Mines method (USBM) Principle A core sample is driven to initial water saturation by centrifugation under oil (line 1 in Figure 10.4). Centrifugation under brine is then carried out with speeds increasing stepwise to a capillary pressure of 10 psi. Brine displaces oil from the sample and at each capillary pressure step, the oil volume displaced is used to calculate average brine saturation. The sample is then placed in oil and centrifuged. Capillary pressures and average oil saturations are measured to a drainage capillary pressure of 10 psi. The wettability index, W, is defined as the logarithm of the ratio of the area under the oil drive (A1; secondary drainage) capillary pressure curve to the area under the brine drive curve (A2). A positive W value indicates water-wetting while a negative value indicates oil-wetting and a value of W near zero indicates neutral wetting. The larger the absolute value, the greater the wetting preference. Points • Acceptable technique for wettability determination. • USBM is more sensitive near neutral wettability than Amott. • A combined Amott/USBM measurement can be carried out which determines the saturation changes which occur due to spontaneous imbibition at zero capillary pressure together with the capillary curve data. Both the Amott and the USBM indices are calculated. • By including the forced imbibition aspects of the USBM method a new wettability index has been introduced called the HL index. Precision • Indicative only Price/timing/number of samples • US$1,000-US$1,500 per sample. • This method is relatively rapid, taking 3 days for 4 - 8 plugs. • Either one USBM or one Amott measurement for each fresh-state or restored -state measurement. Peripheral measurements • On a number of samples the wettability should be determined for native state, cleaned and restored state samples.

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10.2.3 Other wettability determination methods The techniques described here for wettability determination are generally qualitative. • CAPRICI This is a measurement which is currently under research and is discussed at length in section 14.2.1. • Relative permeability curves Because relative permeability curves are dependent on sample wettability various aspects of the relative permeability curve such as cross-over point, end point relative permeability to water are indicative for wettability, see Chapter 11 for further discussion. However, relative permeability measurements are not normally performed as a wettability determination method. • Contact angle measurements In simple systems, contact angle is a direct measure of wettability, as shown in Table 10.1. However, in rock systems surfaces are difficult to obtain because of a lack of a smooth surface. Variations using rock surfaces such as Wilhelmy plate, which determines the force exerted by a rock sample as it moves through an oil/water interface, is a method of determining the effective contact angle. • Imbibition tests One aspect of a strongly wet system is the ability to imbibe the wetting phase. Thus, if a preserved core sample strongly imbibes brine, then the sample can be inferred to be water-wet. If the imbibition rate is weak then the sample could be between water-wet and neutrally wet. Imbibition tests can be quantified by the rate of imbibition. Imbibition test can be done either by adding a drop of brine to the surface of a core plug and monitoring the size of the drop with time or by immersing in brine and monitoring the produced oil.

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Interfacial tension

Interfacial tensions (IFT) are discussed here primarily as a means of quantifying the suitability of crude oil in core analysis measurements. If an IFT value is obtained that is unreasonably low, e.g. below 20 dynes/cm, then the use of the crude oil in aging and core analysis measurements would be suspect because of sample contamination with surfactant. Interfacial tension measurements are also necessary for the determination of saturation-height functions from capillary pressure curves. Capillary pressure measurements are often carried out using different fluids and under different wetting conditions than those in the reservoir. Conversions, therefore, correct for differences in wettability and interfacial (surface) tensions. Much uncertainty exists in the conversion with respect to wettability since the wetting conditions within the core samples are very sensitive to the samples' history: the techniques used in their acquisition, handling, storage, etc. Lack of knowledge of interfacial tension in the reservoir increases the uncertainty. Order of magnitude values for reservoir interfacial tensions are quoted in typical text books and Shell references, but existing interfacial tension data is quite diverse, especially values for oil/water situations where an accurate value for an 'average crude' cannot be given. Also, interfacial tensions for mixtures cannot be reliably predicted at this time. It is recommended that the influence of uncertainties in the correction factors on the desired results be checked; however, the need for accurate values increases with decreasing reservoir quality. Studies by Buck and Thomeer suggest that, for low quality reservoir rock, inadequate knowledge of the oil/water interfacial tension can significantly affect saturation, and therefore HCIIP estimations obtained from capillary pressure curves. Experimental techniques aim to reduce uncertainty by measuring the interfacial tension on reservoir fluids at reservoir temperatures and pressures. Certain precautions need to be taken to ensure valid results: • A bottom hole fluid sample is preferred early in field life, where the pressure remains above the bubble-point pressure. • Fluid samples contaminated with non-reservoir fluids should be avoided. • The crude sample should not be exposed to air. • Parameters such as API gravity and surfactant content are required. • The apparatus must be clean and its reactivity and wetting state known.

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10.3.1 Interfacial tension by 'Pendant Drop' Principle A drop of fluid in equilibrium is introduced into the surrounding fluid. The drop is imaged and its shape is used to determine the interfacial tension. Figure 10.5 shows a pendant drop apparatus. Points • This is the recommended technique. • Elevated temperatures and pressures can be used. • KSEPL has implemented an improved data analysis method in which the whole contour of the drop is used, together with the fluid densities, to calculate interfacial tension. • This technique can be used to monitor the change of interfacial tension with time which indicates the presence of surfactants. • Oil and brine should be equilibrated with each other at the appropriate temperature prior to measurement. • Oil quality measurements can be done at room temperature on dead crude. Precision •

The accuracy of this technique is 2% in interfacial tension.

Price/timeliness • Typically US$1,000. • Typical contractor turnaround time for this experiment is 8 weeks. Peripheral measurements • Accurate fluid densities are needed. • Usually part of PVT measurements, e.g. gas-oil ratio is needed when IFT measurements are performed on live crude. • Appropriate capillary pressure curves.

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10.3.2 Surface tension by 'du Nouy balance' Principle A du Nouy balance is used to determine the surface tension. The reservoir fluid is placed on a balance and a circular wire, of known circumference is slowly lifted out of the body of the liquid. The maximum force required to balance the surface forces (due to the two surface films in contact with the ring) is measured either by the stretch of a delicate spring, the twist of a tension wire or by movement of the balance. Figure 10.6 shows a typical du Nouy balance. Points • The technique is acceptable. • Stable temperature is important. • Surface contamination can be a problem. • Generally at room conditions. Precision • Estimated 5% in surface tension. Price/timeliness • Moderate; US$400 • A measurement takes about 1-2 hours. Peripheral measurements • Used to determine quality of core analysis measurements involving wettability. • Appropriate capillary pressure curves.

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10.3.3 Interfacial tension by spinning drop tensiometer Principle A long oil or gas droplet which is spinning in a horizontal tube filled with a more dense fluid is imaged and its diameter measured. Interfacial tension is calculated from the angular rotational speed and density difference. Points • This is an acceptable technique. • Very low interfacial tension can be measured quickly allowing collection of large data sets. • Density difference must be accurately known. Precision • 5% in interfacial tension. Price/timeliness • Moderate; typically US$500 for room conditions. • A typical measurement takes 1-2 hours. Peripheral measurements • Used to determine quality of core analysis measurements involving wettability. . • Appropriate capillary pressure curves.

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Literature

Anderson, W.G. Wettability literature survey part 1: Rock / oil / brine interactions and the effect of core handling on wettability. JPT Oct. '86. Jia, D., Buckley, J.S., Morrow, N.R Alteration of Wettability by Drilling Mud Filtrates. SCA 9408 paper presented at the International Symposium of the Society of Core Analysts, September, 1994 Wunderlich, R.W. Obtaining Samples with Preserved Wettability in Interfacial Phenomena in Oil Recovery, NR. Morrow ed Marcel Dekker, Inc New York City, 1990, pp 289-318. Anderson, W.G. Wettability literature survey part 2: Wettability measurement. JPT. November, 1986. Longeron, D., Hammervold, W.L., and Skjaeveland, S.M. Water/oil Capillary Pressure and Wettability Measurements using Micropore Membrane Techniques SCA 9426 paper presented at the International Symposium of the Society of Core Analysts, September, 1994. Schipper, B.A., Aperen, A.E. van, Looyestijn, W.J. Quality assessment of core analysis procedures of G.A.P.S Geological Consultants, London. EP 90-2172. Amott, E. Observations relating to the wettability of porous rock. Petroleum transactions of AIME 1959. Donaldson et al. US Bureau of Mines (USBM) Oklahoma Wettability determination and its effect on recovery efficiency. SPEJ, March 1969. Buck, A.L., Thomeer, J.H.M. In-situ interphase tension between reservoir fluids: a review. BRC 21-85, EP06-2778. Weg, P.B. van der Computer automated interfacial tension determination with the spinning drop. KSEPL, RKRS.92.RP.1. Roest, J.A., Keir, C.A, Niko, H. Measurement of residual oil - A state of the art review. EP 65259, Feb. '86. Harrison, D A review of field procedures for preserving wettability, laboratory techniques for the measuring

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wettability and methods for reversing wettability. CRC, EP 86-1023. Kortekaas, T.F.M., Poelgeest, F. van Liberation of solution gas during pressure depletion of virgin and watered out oil reservoirs. SPE paper 19693, October 1989 Morrow, N.R Wettability and its effect on oil recovery. JPT Dec. '90. Reed, M.G., Liversey, A.K., Bauldreay, J.M., Hughes, V.B. An improved method for determining interfacial tensions and contact angles using image analysis. TNRS.92.07. Smits, R.M.M., Shannon, B.G. Interfacial tension measurement capabilities in PSSL. BRS-P 7-86. Narahara, G.M., and Blackshear, T.H., Jr. Effects of Using Live versus Dead Crude Oils on Unsteady-state Water/oil Relative Permeabilities. SCA 9326 presented at the seventh Annual Technical Conference of the SCA in Houston, August 1993. Argaud, M.J. Predicting the Interfacial Tension of Brine / Gas (or Condensate) Systems. in Advances in Core Evaluation III Reservoir Management. Worthington and Chardiere Riviere eds. Gordon and Breach 1993. Adams S.J. and van den Oord R.J. Capillary Pressure and Saturation-Height Functions EP 93-0001, January 1993 Cuiec, L. Study of Problems related to the Restoration of the Natural State of Core Samples. Journal of Canadian Petroleum Technology, Oct/Dec 1977.

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Relative permeability

Relative permeability is one of the most important reservoir characteristics measured in the laboratory since it describes multiphase flow in a porous medium and is used in the prediction of reservoir performance and ultimate fluid recoveries. Data obtained (from both imbibition and drainage cycles) are itemised as follows and shown in Figure 11.1: -

oil relative permeability, kro as a function of Sw;

-

water relative permeability, krw as a function of Sw;

-

relative permeability ratio kw/ko (effective permeability to water/effective permeability to oil) as a function of Sw;

-

initial water saturation, Swi, (otherwise known as connate water saturation, Swc,);

-

residual oil saturation, Sor,

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The type of data depends on the recovery process under consideration. As discussed in the previous chapter, wettability has a strong influence on relative permeability curves. Figure 11.2 shows the impact of water-wetness versus mixed wetness has on relative permeability curves. The changes can be more dramatic for individual reservoirs. Mixed-wet systems show high water productivity which is sometimes accompanied by lower residual oil saturations. For oil-wet systems the oil relative permeability curve is even more suppressed. Thus measuring relative permeabilities at the right wettability is important. This is also highlighted in section 11.4.

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Steady-state measurement

11.1.1 Relative permeability by steady-state Principle In the steady-state method, two immiscible fluids are injected simultaneously at constant rates into a core plug at a given fractional flow ratio. Measurements are made at each fractional flow until steady-state conditions are reached. A number of different fractional flows are used from 100% oil flow to 100% brine flow. Pressure drop, saturation and flow rates are monitored. A schematic of the method is shown in Figure 11.3. Points • Recommended technique especially in the mid saturation range. • The steady-state technique can be used for any two phase immiscible system. For the oil/water system, a typical sequence is primary drainage cycle, imbibition cycle, and secondary drainage cycle. • Establishment of Swi on primary drainage is necessary. Imbibition (water saturation increasing) should be done after aging to restore wettability. • Steady-state relative permeability measurements are most valid at the higher relative permeability values. At low relative permeability values, centrifuge techniques are more accurate and are recommended. • Accurate fluid saturation determination is critical. Methods include X ray, microwave or gamma ray attenuation. • Samples are limited to air permeabilities greater than I mD. • End-point saturations should be checked by Dean-Stark extraction. • Absolute brine permeability should be performed to check brine compatibility. • Steady-state measurements can be done at reservoir conditions (see section 14.2 on research aspects of relative permeability at reservoir conditions.) Some contractors offer steady-state service at reservoir temperatures. • A problem with steady-state experiments is the long exposure of the rock sample to flowing fluids which can cause the sample to be damaged over time such as through fines migration. • Gas/iquid systems require the gas phase to be humidified and the fluid phase to be gas saturated. • Relative permeability data should be shown on semi-logarithmic plots.

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Points (continued) • Remarks on contractor service: - contractor procedures which involve removing the sample and determining saturations using gravimetric or volumetric material balance are NOT recommended; - contractor laboratory methods often place the sample with a mixing head upstream and a production end plug downstream in a rubber sleeve and mounted in a Hassler type hydrostatic core holder which can be pressurised to in-situ stress levels. The Core Laboratories method using a specially designed hydrostatic core holder and Xray attenuation (SMAX) to monitor saturation profiles is considered acceptable; - the applied flow conditions must be reported; - end-point saturations should be checked by Dean-Stark extraction.

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Precision • Saturation can be determined within 3% (in saturation units). • Sor cannot be determined with high precision within a reasonable measurement time using steady-state methods. Price/timing/number of samples • Typical costs are US$3,000- US$4,000 per cycle. • Experiments take 1-3 weeks depending on automation per sample. • 2-3 samples per rock type are recommended. At least 6 samples should be prepared for the screening process to select the proper plugs for measurement. Peripheral measurements • Wetting state of the sample should be determined; see section 10.2. • Accurate pore volume measurement is important. • An oil/water interfacial tension as a function of time is recommended to determine whether the crude oil (if used) has been contaminated. • Two longitudinal CT-scans should be done as part of screening and should be used to check sample quality. Cross-sectional CT-scans can also provide indications of heterogeneity. • Thin sections and mineralogy are recommended for data quality and to aid data interpretation. • A capillary pressure measurement on the same sample is highly recommended.

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Centrifuge measurement

11.2.1 Oil/water relative permeability by centifuge Principle Samples are placed in centrifuge core holders (see Figure 11.4). During centrifugation at a single speed, the invading phase (usually brine in the imbibition mode) displaces oil. Produced oil volumes as a function of time are determined. Relative permeability curves are determined using standard methods such as Hagoort's analysis but the preferred technique is from history matching the centrifuge production using computer simulation of flow behavior. A typical centrifuge is shown in Figure 11.5. Points • Recommended technique especially near endpoint saturations. • The method allows both drainage and imbibition modes to be studied for both consolidated and unconsolidated core material. • Oil relative permeability curve is determined on the imbibition cycle and the brine relative permeability curve is determined on the drainage cycle. Both curves cannot be obtained on the same cycle. • Capillary pressure must be measured; preferrably on the same sample. • Centrifuge displacement is gravity-stable; no viscous fingering occurs. • Relative permeabilities can be measured to very small values (< 0.0001). The centrifuge is the best technique for determining endpoint saturations such as Sor. • Samples are limited to air permeabilities greater than 1 mD. • For samples that are somewhat water-wet, the speed at which the relative permeability experiment should be conducted can be determined by a multi-speed centrifuge experiment to determine the imbibition cycle capillary pressure curve. The optimum speed should not be so high that the capillary forces are overcome (i.e. Bond numbers should be less than 10-5). • Relative permeability data should be shown on semi-logarithmic plots. • A limited capability of applying stress to cores is available which allows unconsolidated samples to be run. • The centrifuge takes time to reach a given speed; oil production versus time data should therefore be corrected for time delay. Because initial oil production may be high, high initial data acquisition rates should be used.

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Points (continued) • It is highly recommended to use computer simulation to derive relative permeability curves by history matching the production data. • Volume resolution of at least 0.05 ml is recommended. • Note that no data are obtained during spontaneous imbibition. • Figure 11.6 shows comparison of centrifuge and steady-state measurements. Note that the centrifuge data achieves very low values. Precision • Saturation can be determined within 3% (in saturation units). • Uncertainty in relative permeabilty is estimated to be about 50%. Price/timing/number of samples • US $3,000- US $4,000 which includes a capillary pressure measurement and both oil and water relative permeability curves. • A typical experiment takes about a month excluding an aging time of 4 weeks. • 4-6 samples are recommended per rock type. Experiments are usually done in batches of 3-6 depending on centifuge and centrifuge holder. Peripheral measurements • Steady-state oil/water relative permeability curves are recommended as a check of the centrifuge data especially in the mid-range saturation region. • An accurate pore volume determination is important. • An oil/water interfacial tension as a function of time is recommended to determine whether the crude oil (if used) has been contaminated. • Two longitudinal CT -scans should be done as part of screening and should be used to check sample quality. Extra plugs must be prepared for the screening process before deciding on the best samples for measurement. • Thin sections and mineralogy are highly recommended for data quality and data interpretation.

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11.2.2 Gas/liquid relative permeability by centrifuge Principle A liquid saturated plug is placed in an air-filled core holder and centrifuged at constant speed. Production is measured as a function of time and the fluid relative permeability curve is determined from the production data. Points • Acceptable technique for water relative permeability curves. • Many of the points in section 11.2.1 apply here. • Close attention should be paid to data application. Centrifuge data are good for drainage experiments where liquid is displaced by gas. The centrifuge provides the liquid phase relative permeability. • The centrifuge is recommended for determination of endpoint saturations. • Only the drainage mode can be studied and only the liquid relative permeability is obtained. • Three phase experiments are possible with gas/oil systems at initial water saturation. It is important to verify that the oil behaves in the same way in the core experiment as it does in the field i.e. if the oil is the spreading phase in the reservoir then a spreading oil must be used in the core measurement. (A spreading phase, typically oil, in a three phase system preferentially spreads between the other two phases.) Alternatively a sample of reservoir oil can be used. More details about three phase systems are discussed in section 14.2.2. • The analytical relative permeability calculation assumes infinite gas mobility. A simple empirical correction is applied to the saturations to account for the finite mobility of the invading phase. This correction must be applied when the oil/gas viscosity ratio becomes lower than 150. A low mobility contrast causes a saturation shock-front to develop; that part of the curve corresponding to the highest liquid saturations will not be valid. Precision • Saturation can be determined within 3% (in saturation units). • Uncertainty in relative permeability is estimated to be about 50%.

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Price/timing/number of samples • US $3,000 - US $3,500 which includes a capillary pressure measurement. • The method takes about 2 weeks. • 4-6 samples per rock type are recommended. Peripheral measurements • Accurate pore volume determination is critical. • A gas/liquid surface tension measurement is recommended to determine (crude) oil quality. • Two longitudinal CT-scans should be done as part of screening and should be used to check sample quality. Extra plugs must be prepared for the screening process before deciding on the best samples for measurement. • Thin sections and mineralogy are highly recommended for data quality and data interpretation.

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Unsteady-state measurement

11.3.1 Oil/water relative permeability by unsteady state displacement Principle The unsteady state method involves brine displacement of oil from initial water saturation, Swi. A core plug is placed in a core holder as shown in Figure 11.7 and subjected to an appropriate isostatic stress, The sample is 100% saturated with artificial formation water and the absolute water permeability, kw, determined. Initial water saturation is usually established by oil flooding until brine production ceases; the effective oil permeability, kocw, is determined at Swi. Artificial formation water is injected at a constant rate of around 0.5 ml/min. An equilibrium situation is not reached. The relative volumes of produced and injected fluids are monitored together with the pressure difference across the plug keeping injection rate constant. When no more oil is produced, the effective permeability to water, kwor, at residual oil saturation, Sor, is determined. Points • This method is NOT RECOMMENDED by SIPW/KSEPL. In particular, the water relative permeability curve is considered unreliable because of the complex combination of (a deliberately chosen) unfavourable mobility ratio which may lead to viscous fingering and relatively high displacement rates needed to suppress the capillary end effect. Moreover, unsteady state relative permeabilities are very sensitive to the presence of sample heterogeneities. • Reaching initial water saturation by flooding is difficult. It is preferable to achieve initial water saturation by centrifugation. • This method is used widely in the oil industry by both contractor laboratories and other oil companies because it is rapid but the data obtained are more difficult to interpret. • The Welge method and Buckley-Leverett frontal advance equations for non-capillary fluid displacement are used to calculate the relative permeability ratio. Standard interpretation techniques such as the JBN-method are used to determine individual relative permeabilities.

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Points (continued) • Displacement procedures do not always guarantee a representative initial water saturation. Centrifuge methods can more easily attain lower and more representative water saturations. • Samples are limited to absolute air permeability values greater than 1mD. • Interpretation is best by history matching the production performance using computer simulation incorporating effects of capillary pressure. • Unsteady-state methods do not properly reach residual oil saturation, Sor, because of the long displacement times needed. If Sor numbers are critical then the recommended technique is the centrifuge. • Both consolidated and unconsolidated core material can be used; diameters between 2.54 and 3.75 cm with a minimum plug length of 4 cm. • Only the data points measured after water breakthrough can be used to calculate relative permeability curves. To ensure a sufficiently wide enough saturation range, a high fluid mobility ratio is used which gives early breakthrough. However, this may lead to viscous fingering problems. • Two common assumptions in the analytical data analysis are: ignoring capillary pressure end effects and a constant pressure differential across the plug. Capillary end effects can be reduced by using a sufficiently large pressure gradient, i.e. injecting at high rates; care should then be taken to avoid sample damage. Experiments can be carried out at a constant rate and monitoring pressure drop or at constant pressure and monitoring rate. Precision • Saturation precision is about 1-2% (saturation units). However, uncertainty in relative permeability is estimated to be higher than 50% in the mid-saturation range and increases as endpoints are approached. Price/timing/number of samples • US $2,500 per plug is typical. • The technique takes about 4 days. • 3-5 samples per rock type. At least 6 samples should be prepared for screening.

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Peripheral measurements • The wetting state should be determined see section 10.2. • Steady-state measurements on a subset of the same samples should be done to check data quality and consistency. • Accurate determination of pore volume is essential. • A capillary pressure curve on the same sample is highly recommended. • Interfacial tension measurements are needed along with oil characterisation for mobility determination. • Two longitudinal CT -scans should be done as part of screening and should be used to check sample quality. Cross-sectional CT-scans are also useful in assessment of plug suitability for measurement. • Thin sections, mineralogy and grain size distribution (for sandstones) assist in data interpretation.

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11.3.2 Gas/liquid relative permeability by unsteady-state displacement Principle Unsteady-state displacement method is used to determine gas/liquid relative permeability curves under drainage mode. Either artificial formation water or oil (at initial water saturation if required) can be used. The method is similar to that outlined above. Gas is injected into a brine saturated sample plug which is subjected to an effective isostatic confining stress. Displacement is carried out at a constant pressure differential and production of liquid and gas is measured as a function of time. Both gas and liquid relative permeability curves are calculated as a function of liquid saturation, as derived from fractional flows, saturation and pressure gradient defined at the outflow end of the plug. Points • This technique is NOT RECOMMENDED. Under certain conditions such as gravity stable displacement, acceptable results may be obtained. • Many of the points in section 11.3.1 apply here. • Close attention should be paid to whether data are required in the drainage or imbibition modes. This requires an understanding of the reservoir recovery process, such as gas cap expansion which causes gas to displace oil, gas displacement by water which necessitates determination of endpoint saturations and waterflooding after solution gas drive. Specific three phase systems such as gas displacing oil at initial water saturation can be studied. Here, the various issues such as the impact of residual gas saturation on residual oil saturation can be studied although this is best done with the centrifuge. • Drainage curves can only be calculated after gas breakthrough. • Saturation profile at the outflow end of the plug is affected by capillary end-effects. The gas/oil data should be corrected for this in the history match using computer simulation. • The Welge method assumes incompressible fluids. Gas compressibility should be minimised by using high average pressures (by applying a ~20 bar back pressure) and small pressure differentials across the plug. • High gas rates may introduce turbulence. The results should be corrected for such inertial effects (section 6.2.1).

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Points (continued) • Care should be taken to ensure use of humidified gas during gas displacement of water experiments. • The absolute water permeability should be measured to determine the sensitivity to brine if a compatibility test has not been carried out. • Flow conditions applied for the end point permeabilities should be reported. Precision •

Saturation precision is about 1-2% (saturation units). However, uncertainty in relative permeability is estimated to be 50% in the mid saturation range and increases as endpoints are approached.

Price/timing/number of samples • • •

US $2,500 per plug is typical. The method takes about 4 days. 3-5 samples per rock type are recommended.

Peripheral measurements • Centrifuge measurements on a subset of samples should be used to check data quality. • Accurate pore volume determination is essential. • Two longitudinal CT-scans should be done as part of screening and should be used to check sample quality. Cross-sectional CT-scans are also useful in assessing plug suitability. • A gas/liquid capillary pressure on the same sample is highly recommended. • Thin sections, mineralogy and grain size distribution (for sandstones) assist in data interpretation.

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Relative permeability at reservoir conditions

It is best to have relative permeability measurements performed at wetting conditions identical with reservoir wettability. An extensive discussion is given in Chapter 10. It is critical to measure the interfacial tension of the crude oil/water system to ensure that oil sample is not contaminated. Use of contaminated oils results in unusable relative permeability data. Besides cleaned-state cores, two types of cores can be used for experiments at reservoir conditions: 11.4.1 Restored-state (see section 10.1.2) Principle Cores are first cleaned and dried. The sample is brine saturated, brought to an initial water saturation on primary drainage (usually with a centrifuge) and allowed to age at reservoir temperature and pressure for a period of at least 4 weeks (1 month). Any changes in wettability are deemed to have been completed in 4 weeks. Points • This is the recommended method for steady-state and centrifuge techniques. • Samples should be screened for measurement allowing proper rock characterisation prior to measurement. 11.4.2 Native-state (see section 10.1.3, 10.1.4, 10.1.5) Principle Native-state plugs (which include fresh-state, preserved-state and pressure-retained core) are cut and mounted in an experiment without cleaning. Samples are flooded with oil to initial water saturation. However, this represents a secondary drainage process and may yield higher water saturations than in the reservoir due to water trapping in mixed-wet cores. Points • This is NOT recommended because native state cores are difficult to screen for appropriate rock type, permeability, porosity and homogeneity.

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Literature

Heaviside, J. Measurement of relative permeability. Interfacial phenomena in petroleum recovery. Marcel-Dekker Inc. NY '90 pp.377-411. Niko, H. Measurement and application of relative permeabilities: A state of the art review. KSEPL, Report RKRS.88.06, June 1988. Johnson, E.F., Bossler, D.P., Naumann, V.O. Calculation of relative permeability from displacement experiments. Pet. Trans. AIME, V 216, p370, 1959. Niko, H., Maas, J.G. Special Core Analysis as seen from Reservoir Engineering. Contribution to the PW04 Advanced Reservoir Engineering Workshop Noordwijkerhout, October, 1993 Anderson, W.G. Wettability literature survey part 5: The effects of wettability on relative permeability. JPT. Nov. '87. Anderson, W.G. Wettability literature survey part 6: The effects ofwettability on waterflooding. JPT. Dec. '87. Heaviside, J., Brown, C.E., Gamble. I.J.A. Relative permeability for intermediate wettability reservoirs. SPE 16968 1987 Heaviside, J., Black, C.J.J. Fundamentals of relative permeability: Experimental considerations. SPE 12173 1983 , Hove, A., Ringen, J.K., Read, P.A. Visualisation of laboratory corefloods with the aid of computerised tomography of X-rays. SPE Reservoir Engineering (May 1987) 148-154. Lund, T.B. Relative permeabilities measured on core plugs from the Ekofisk area chalk. EP 86-0277. Mundis, C.J. Cano Limon core damage study: Vol. 3: Relative permeability tests EP 87 -2094. Prast, H.J., Coenen, J.G.C., Spijker, A. The effect of small scale heterogeneities on relative permeability measurements. KSEPL report RKRS.87.04.

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Potter, G., and Lyle, G. Measuring Unsteady-State Gas Displacing Liquid Relative Permeability of High Permeability Samples. SCA 9419 paper presented at the International Symposium of the Society of Core Analysts, Stavanger, Norway, September 12-14, 1994. Jia, D., Buckley, J., and Morrow, N. Alteration of Wettability by Drilling Mud Filtrates. SCA 9408 paper presented at the International Symposium of the Society of Core Analysts, Stavanger, Norway, September 12-14, 1994.

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Mechanical rock properties

Measurements of mechanical rock properties are important because of their impact upon production and well-bore behaviour. This chapter addresses three areas of mechanical rock properties: •

compressibility;

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rock strength;

•

acoustic properties.

These analyses are important for the following: •

estimation of reservoir compaction caused by hydrocarbon production;

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borehole stability analysis;

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prediction of sand production;

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prediction of acid etched channel behaviour during production;

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prediction of fractures in naturally fractured reservoirs;

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applications of acoustic properties for calibration of seismic data.

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Compressibility

Hydrocarbon bearing formations experience an effective compressive stress due to the difference between overburden pressure and fluid pressure within the pore space. The production of hydrocarbons results in pore fluid pressure reduction thereby increasing effective stress, which can lead to reservoir compaction and surface or seabed subsidence above the reservoir. The determination of the dependence of formation properties on effective stress is therefore important. Reservoir compressibility can only be quantified by performing experiments on core material to measure compressibility (also referred to as compaction coefficients) under representative stress conditions. Ideally, these tests should be carried out under in-situ fluid saturations and temperatures. The most important parameter is the uniaxial compressibility of the reservoir rock, Cm (bar -1), which is defined as the relative reduction in length per unit increase in effective axial stress. Radial deformation must be zero and the rate of loading constant. Laboratory measurements are applied in the prediction of reservoir compaction by making several assumptions, including the possible dependence of Cm on loading rate and stress path, minimal core damage, and initial reservoir stress state. Theoretical compaction models, representative experimental procedures and the application of experimental results to compaction prediction are currently being researched by the Rock Characteristics group at KSEPL, RR/37.

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12.1.1 Uniaxial compaction Principle After being saturated with artificial formation brine, a sample is placed in an impermeable elastomer sleeve and mounted in a pressure cell (see Figures 12.1 and 12.2). Axial stress, radial stress and pore fluid pressure are then brought to the assumed pre-production reservoir condition (normally to be specified by the Opco). The sample is then subjected to a uniformly increasing effective axial stress normally by depleting the pore pressure while keeping the total axial stress constant. This simulates reservoir production with constant overburden weight. Effective radial stress is changed by simultaneously changing the confining pressure applied on the elastomer sleeve. Changes in sample dimensions and changes in radial stress, axial stress, and pore fluid pressure are measured. Radial strain is continually monitored (see Figure 12.3) during compaction and a feedback mechanism automatically adjusts the radial pressure so that the radial strain remains zero and uniaxial conditions remain. Points • Vertical compaction can be simulated in two ways: Pore pressure reduction, with prestressing (Recommended technique). The sample is brought to in-situ effective stress levels by increasing radial and axial stresses. During loading, radial deformation is permitted. A pore pressure equal to initial reservoir pore pressure is simultaneously applied. Creep effects are accounted for by waiting 15-20 hours. Axial effective stress on the sample is increased by decreasing pore fluid pressure while keeping total axial stress constant. Zero radial strain is maintained. Typical results are shown in Figure 12.4 where axial displacement is plotted against pore fluid pressure. The uniaxial compaction coefficient is calculated from the slope over the relevant effective stress range. Drained, with prestressing (Acceptable technique). The sample is brought to in-situ effective stress levels by increasing axial and radial stresses. During loading, radial deformation is permitted. The pore pressure is maintained at atmospheric pressure. After leaving the sample for about 15 - 20 hours to account for any creep effects, axial stress is increased further under uniaxial conditions (zero radial strain) and Cm is determined.

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Points (continued) • Drained experiments are used when the axial fluid permeability is too low to achieve pore pressure equilibrium over the duration of the compaction experiment (5-8 hours). • Uniaxial compaction test requires true vertical plugs. • A typical loading rate is 50 bar/hour. • Poisson's ratio can be calculated from the change in total radial stress per unit change in total axial stress during uniaxial compaction under drained conditions, provided the sample compacts elastically. • Unconsolidated samples are mounted frozen. • Pore pressure reduction is the preferred technique. Reservoir depletion may cause a slight expansion of rock grains which partially counteracts the compaction due to the increase in effective axial stress. Determination of Cm by reducing pore fluid pressure will therefore produce a more representative value. Because compaction data is so important, SIPM strongly recommends that all compaction measurements be carried out at KSEPL or in BTC. • Application of measured compaction coefficients in reservoir modelling should account for the difference in loading rates between laboratory measurement and reservoir conditions. For relatively strong sandstones, (Cm < 10-5/bar) the influence of loading rate on compressibility is probably small (<10%). However, for relatively weak sandstones (Cm > 2 x 10-5/bar), the compressibility measured in the laboratory may be lower than during the actual reservoir depletion. Consult with RR/37. • Cm is determined as a function of porosity, stress and depth. • Carbonate reservoirs can exhibit pore collapse which require special attention. Consult with RR/37. • At the conclusion of the experiment, sample dimensions are measured after all stresses have been released to determine the amount of permanent (inelastic) deformation. • For the first triaxial compaction apparatus shown in Figure 12.1, the limits on axial stress, radial stress and pore pressure are 960 bar, 930 bar and 900 bar respectively. • For the second triaxial compaction apparatus shown in Figure 12.2, the limits on axial stress, radial stress and pore pressure are 900 bar, 440 bar and 500 bar respectively. • The magnitude of creep is invariant with loading rate if equal pressure steps are used.

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Precision • 10% in Cm but representativeness is important. Price/timing/number of samples • About US $1,000 - US $3,000 per sample. • The experiment takes about 1-2 days per sample. • 10 samples per rock type are recommended to provide proper statistical coverage. Screening on 20 samples should be done if possible to obtain the best 10 samples. Because the uniaxial compressibility may depend on porosity, it is recommended to select samples that span the porosity range of the rock type being studied. Peripheral measurements • CT scans should be carried out on both whole core and individual plugs before measurements are made so that homogeneity and bedding plane orientation can be investigated. • Initial atmospheric porosity is determined. • Vertical and horizontal permeability can be measured during compaction. • CT -scans, thin section analysis and mineralogy assist in quality assessment and data interpretation. For sandstones, grain size analysis is also valuable.

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12.1.2 Hydrostatic compaction Principle Hydrostatic compressibility measurements at KSEPL are made using a technique which simultaneously measures porosity and formation resistivity factor under stressed conditions. This method is described in section 9.1. Dedicated hydrostatic rock compressibility measurements are carried out on brine saturated vertical core plugs. Sample dimensions are measured and pore volume determined. Samples are placed in a sleeve and mounted in a core holder. Confining pressure is increased to in-situ levels, and changes in pore volume are monitored by measurement of the volume of fluid produced from the compacting sample. Volumetric strain per unit increase in hydrostatic stress yields the volumetric compressibility. Points • Volumetric compressibility can be converted to uniaxial conditions. • Hydrostatic measurements are easier than uniaxial ones although Cm values will not be as representative as those obtained from uniaxial techniques. • For prediction of reservoir compaction and subsidence (additional) uniaxial measurements are required. • Conversion of hydrostatic measurements to uniaxial conditions are discussed in Appendix 6. Precision • 10% in Cm assuming sample compacts elastically. Price/timing/number of samples • US $500 - US $1,000 per sample. • A typical sample can be done in 2 days including preparation. • 10 samples per rock type. Peripheral measurements • Formation resistivity factor and porosity are determined as a function of stress and depth. • CT-scans should be carried out on both whole core and individual plugs before measurements are made so that homogeneity and bedding plane orientation can be investigated. • CT-scans, thin sections and mineralogy assist in quality assessment and data interpretation. For sandstones, grain size analysis is also valuable.

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12.1.3 Oedometer compaction test Principle A saturated cylindrical core sample is placed in a thick walled steel cylinder. An axial stress is then applied. The rigid cell wall is supposed to prevent lateral strain in the sample and thereby approximate uniaxial strain conditions. Axial strain is measured as a function of axial stress. Points • This measurement is NOT RECOMMENDED because radial deformation is not fully prevented and friction occurs between sample and cell.

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Rock strength parameters

The mechanical strength of reservoir rock can be related to a number of parameters which can be measured in the laboratory. Knowledge of rock strength is required in such studies as borehole stability, sand production, prediction of in-situ stress directions or fracture behaviour.

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12.2.1 Rock strength by triaxial testing Principle A sample is placed in a rubber sleeve (usually in "as received" condition) and mounted in a high pressure cell. Equal radial and axial stresses are applied to a certain predetermined value, which is usually the assumed initial in-situ stress. The sample is then axially loaded until failure while keeping the radial stress constant. Tests are carried out at different values of radial stress and the measured values of radial and axial stress at sample collapse determine a material failure envelope, which gives shear effective stress ((axial stress - radial stress)/2) as a function of normal effective stress ((axial stress + radial stress)/2). Points • Recommended technique in rock strength measurement. • Young's modulus and Poisson's ratio are used in wellbore stability analysis and fracture design and can also be used to construct empirical relationships predicting strength as a function of depth or porosity or lithology. Youngs modulus can be obtained from the axial strain per unit increase in axial stress at constant radial stress. Poisson's ratio is defined as the radial extension strain per unit axial compaction strain. However, care must be used in applying these values, which are based on the theory of (linear) poro-elasticity, since real reservoir rock with a porosity greater than 15% often show appreciable (>30%) permanent (inelastic) strain. • True triaxial tests should be performed on cubical samples where a different stress can be loaded in each principal direction. Tests on cylindrical samples are more properly referred to as biaxial tests. Precision • 20% in Poisson's ratio and 10% in Young's modulus. Price/timing/number of samples • US $2,000-US $3,000 per sample. • A typical experiment takes 2 days per sample. • 10 samples per rock type. Peripheral measurements • Longitudinal CT scans should be carried out on both whole core and individual plugs so that homogeneity can be investigated. • Thin sections and mineralogy assist in quality assessment and data interpretation. For sandstones, grain size analysis is also valuable.

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12.2.2 Brinell Hardness Number (BHN) Principle A load is applied to a stainless steel ball, typically 5 or 10 mm in diameter, resting on the surface of the slabbed core or plug. At a selected location on the slab surface, three measurements of indentation depth at a given load are taken a fixed distance of at least 7 mm apart. The BHN is calculated as an average of the three measurements. Points • Recommended technique for hardness measurement. • Both consolidated and friable slabbed cores can be used. Consolidated samples of diameter 2.5 cm can be used but some core damage occurs. • The method is rapid and thus provides a quick survey of rock homogeneity along the core. The measurement at KSEPL is automated. • In order to provide a basis of consistency in BHN measurements SIPM advises adoption of the following loading scheme:

Precision • 25% in BHN is typical; individual measurements have an accuracy of 5%. Price/timing/number of samples • < US$50 per measurement location. • Each measurement takes about 5-10 minutes. • Usually done at one sample per foot. Peripheral measurements • Usually done at the same time as basic core analysis. • Thick-waIled-cylinder, unconfined compressive strength and acoustic properties are also measured.

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12.2.3 Thick-Walled-Cylinder strength test (TWC) Principle A 5 cm long cylindrical sample, with a 8-9 mm hole drilled along the cylinder axis, is enclosed in a rubber sleeve and placed in a high pressure hydrostatic cell shown in Figure 12.6. A continually increasing axial and radial stress (max. 1500 bar) is applied to the sample at a loading rate of 25 bar/minute. The thick walled cylinder (TWC) strength is defined to be the pressure at which sample collapse occurs. Points • Recommended technique for strength tests. • Test is destructive; see Figure 12.7. • The sample is typically run at initial water saturation, Swi, of 20-30% which is achieved by drying. Sometimes used in an "as-received" condition. • Samples should be perpendicular to the core axis to simulate perforation. • Typically triplet sets of samples are required for peripheral measurements. • An initial failure estimate can be determined by observation (endoscope). • A common criterion used in the prediction of sand production states that sand production will occur when the effective vertical stress in the vicinity of the wellbore exceeds 1.07 times the TWC. • It is possible to use the acoustic wireline log as a "rock strength" log by means of a correlation between the TWC values and the acoustic travel times of P and S waves. • TWC testing is unique to the Shell group. KSEPL is the only provider. Precision • Repeatability of TWC measurements is 10%. Price/timing/number of samples • About US$100 per measurement. • A measurement takes about 1-2 hours excluding preparation time. • About 10-15 (triplet) samples per rock type.

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Peripheral measurements • Basic rock and acoustic properties ace usually measured on one triplet sample and unconfined-compressive strength is usually measured on the remaining triplet sample. • BHN measurements are usually done on the whole core prior to TWC measurements.

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12.2.4 Unconfined Compressive Strength test (UCS) Principle A 5 cm long cylindrical sample is subjected to an axial load (max 5000 kgf) until failure. Failure stress is recorded. The apparatus is shown in Figure 12.8. Points • Recommended technique • Test is destructive. • Consolidated plugs of diameter of 2.5 - 5 cm can be used. • Samples are usually run at Swi or occasionally 'as-received'. • Triplet samples are usually required for peripheral measurements. • Formation brine salinity should be known. • Horizontal samples should be used. • Data should be combined with TWC; see section 12.2.3 Precision • Accuracy of the failure pressure is usually 1%. Price/timing/number of samples • About US $100 per sample. • A single measurement takes about an hour. • 10 - 15 samples per rock type. Peripheral measurements • Basic rock and acoustic properties are usually measured on one triplet sample and TWC is usually measured on the remaining triplet sample. • BHN on slabbed surface is usually done prior to UCS measurements.

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Acoustic properties

12.3.1 Acoustic Travel Time (ATT) Principle A core plug is placed in a high pressure triaxial core holder and loaded with a fixed axial to radial stress ratio of 3:1 to simulate in-situ stress condition (max 500 bar). Ultrasonic compressional and shear waves are generated by a piezoelectric crystal at one end of the plug and first arrival travel times are measured at the other end. Sample length decrease is recorded. Points • Recommended technique for acoustic travel time. • Dry or partially brine saturated consolidated or unconsolidated plug samples can be used, but more representative travel times will be obtained if reservoir saturation conditions are maintained. • The plugs should be 2.5 cm in diameter up to 5 cm long and should be drilled along the core axis. • Porosity at a particular effective vertical stress can be estimated by assuming zero radial strain. • New ATT equipment at KSEPL applies isostatic stress up to 1,000 bar and pore fluid pressure up to 200 bar. • Samples should not be reused if they have been exposed to high stress. • Air in the pore space will reduce velocities. A correction can be made on data from dry core material but saturated measurements are preferred. • Porosity is calculated at the effective vertical stress assuming incompressible grains and neglecting lateral deformation. Precision • Repeatability of travel time at constant stress is 5%. Price/timing/number of samples • About US$500 for six stresses. • Half a day for six stresses per sample. • About 10 samples are recommended per rock type. Peripheral measurements • The atmospheric porosity and bulk density of the sample is determined at KSEPL, if not already known, together with the sample dimensions before acoustic measurements.

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Literature

Compaction/strength of quartz-rich sandstone Dunn, D.E., LaFountain, L.J. and Jackson, RE. Porosity dependence and mechanism for brittle fracture in sandstones. J. Geophys. Res. 78, 2403-2417.,1973 Farquhar, R.A., Smart, B.D.G., Crawford, B.R, Todd, AC. & Tweedie, J.A. Mechanical properties anlysis: The key to understanding petrophysical properties stress sensitivity. 1993 SCA Conference paper Number 9321. Farquhar, RA, Smart, B.G.D. & Crawford, B.R Porosity-strength correlation: failure criteria from porosity logs. SPWLA 34th Annual Logging Symposium, June 13-16, 1993. Geertsma, J. Land subsidence above compacting oil and gas reservoirs. JPT, p. 734-744. Presented as paper SPE 3730 at the SPE-AIME European Spring Meeting held in Amsterdam May 16-18 1972., 1973 Hasselt, J.Ph. Reservoir compaction and surface subsidence resulting from oil and gas production. A review of theoretical and experimental research approaches. Geologie en Mijnbouw 71,107-118.,1992 Kooten, J.F.C. Core compaction study for the Groningen field: Status report by September 1988. RKGR. 89.091., 1989 Martin, J.C. and Serdengecti, S. Subsidence over oil and gas fields. Geol. Soc. Am. Reviews in Engng Geol. 6, 23-34., 1984 Morita, N., Gray, KE., Fariz, AAS. and Jogi, P.N. Rock property changes during reservoir compaction. Society of Petroleum Engineers (Formation Evaluation), p. 197-205., 1992 Plumb, RA Influence of composition and texture on the failure properties of clastic rocks. SPE/lSRM paper 28096, presented at the EUROCK Conference, Delft, August 29-31, p. 1320., 1994 Schutjens, P.M.T.M. & De Ruig, H. An experimental investigation into the compaction behaviour of Brent and Statfjord reservoir rock, Brent field, UK. RKTR.92.010., 1992 Schutjens, P.M.T.M. & De Ruig, H. An experimental investigation into the compaction behaviour of core material from well Mukhaizna-5 (Oman). RKTR.93.057.,1992 Schutjens, P.M.T.M. & De Ruig, H. An experimental investigation into the compaction behaviour of core material from well Ritterdam6 (Rotterdam field, onshore The Netherlands). RKTR.93.076., 1993

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Schutjens, P.M.T.M., De Ruig, H., Sayers, C.M., Van Munster, J.G. & Whitworth, J.L. Compressibility measurement and acoustic characterisation of quartz-rich consolidated reservoir rock (Brent Field, North Sea). SPE/ISRM paper 28096, presented at the EUROCK Conference, Delft, August 29-311994, p. 557-571., 1994 Scott, T.E. and Nielsen, K.C. The effect of porosity on the brittle-ductile transition in sandstones. J. Geophys. Res. 96, 405-414., 1991 Teeuw, D. Laboratory measurement of compaction properties of Groningen reservoir rock. Verhandelingen Kon. Ned. Geol. Mijnbouwk.Gen. Volume 28, p. 19-32., 1973 Veeken, C.A.M., Hertogh, G.M.M., Hydendaal, H.G.C. & Meulen, J.T. van der. Groningen sand failure study. Status report Part 2. Rock stress and rock strength in Groningen / Annerveen fields. RKGR. 89. 201., 1989 Vernik, L, Bruno, M. & Bovberg, C. Empirical relations between compressive strength and porosity of siliciclastic rocks. Int. J. Rock. Mech.Sci. & Geomech. Abstr. Vol. 30, N 7, p. 677-680., 1993 Compaction/strength of carbonate/chalks Blanton, T.L. Deformation of chalk under confining pressure and pore pressure. Paper EUR41, presented at the European Offshore Petroleum Conference, London 1978. Ditzhuijzen, P.J.D. Van & De Waal, J.A. Reservoir compaction and surface subsidence in the Central Luconia gas bearing carbonates, Offshore Sarawak, East Malaysia. Paper 12400, presented at the Offsore SE Asia Conference, Singapore, February 1984. Graaf, J.D. de & Schmidt, E.J. Compaction study on core samples from wells Central Luconia F23-107 and F23-107ST, Sarawak. RKOR.84.023, 1984 Johnson, J.P., Rhett, D.W. & Siemers, W.T. Rock mechanics of the Ekofisk reservoir in the evaluation of subsidence. J. Petro Tech. July 1989, p. 717 - 722., 1989 Kooten, J.F.C. van. Compaction measurements on core samples from wells NW D-2, NWD-3, NWD-5, NF-l and UISE-l in the North field, Khuf reservoir, Qatar. RKER. 87.193, 1987 Martin, J.C. & Serdengecti, S. Subsidence over oil and gas fields. Geol. Soc. Am. Reviews in Engng Geol. 6, 23-34., 1984 Ruddy, I., Andersen, M.A., Pattillo, P.D., Bishlawl, M., & Foged, N. Rock compressibility, compaction and subsidence in a high porosity chalk reservoir: A case study of Valhall field. J. Petr. Tech. July, p 741-746., 1989 Smits, RM.M., Waal, J.A. de, & Kooten, J.F.C. van. Prediction of abrupt reservoir compaction and surface subsidence due to pore collapse in carbonates.

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SPE 15642. paper presented at the 61st Annual Technical Conference and Exhibition in New Orleans, 1986. Teufel, L.W., Rhett, D.W. & Farrell, H.E. Effect of reservoir depletion and pore pressure drawdown on in situ stress and deformation in the Ekofisk field, North Sea. In: Roegiers (ed). Rock Mechanics as a Multidisciplinary Science. Balkema, Rotterdam., p. 63, 1991 Compaction/strength of loose aggregates (sands) Chilingar, G.V., Yen, T.F., Rieke III, H.H. & Fertl, W.H. Compressibilities of sands and clays. Proc. US Dept. of Energy. Subsidence due to fluid withdrawals. Symposium Checotah, Oklahoma 82-11-14-17. August 1983. Ostermeier, RM., Offner, K.M., Hopkins, D.S. & Bowen, G.E. Stress cycling and creep scouting of turbidite sands. BRC 84-90. December 1990. Ostermeier, R.M., Some Core Analysis Issues related to Deep Water Gulf of Mexico Turbidites. SCA 9315 paper presented at the 7th Annual Technical Conference of the SCA in Houston, August, 1993. Pittman, E.D. & Larese, R.E. Compaction of lithic sands: Experimental results and applications. Am. Assoc. of Petroleum Geologists V. 75, N 8, p. 1279-1299., 1991 Schutjens, P.M.T.M. Experimental compaction of quartz sand at low effective stress and temperature conditions. Jl. of Geological Soc. London. Vol. 148.,p. 527-539., 1991 Schutjens, P.M.T.M. & De Ruig. H. An experimental investigation into the compaction behaviour of core material from well B13-3 (NAM, offshore The Netherlands). RKTR 93.082., 1993 Acoustics Marion, D.P. & Pellerin, F.M. Acoustis measurements on cores as a tool for calibration and quantitative interpretation of sonic logs. SPE 25018, 1992. Shafer, J. 1991. Measurement of pore compressibility characteristics in rock exhibiting pore collapse and volumetric creep. SCA 9124. Paper presented at the 5th Annual Technical Conference of the SCA in San Antonio, August 1991 Vernik, L.. Predicting lithology and transport properties from acoustic velocities based on petrophysical classification of siliciclastics. Geophysics Vol 59, N 3, p. 420-427, 1994 Vernik, L.. Petrophysical classification of siliciclastics for lithology and porosity prediction from seismic velocities. AAPG Bull. 76, p. 1295-1309, 1992

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Supplementary tests

Both basic and special core analysis measurements require details of rock and fluid properties that ensure data quality and enhance data applicability. This chapter addresses those analyses which are fundamental to the understanding of core analysis data. The chapter is divided into three main areas: •

rock analyses such as grain size, seal and source rock analyses;

•

fluid analyses;

•

rock-fluid compatibility.

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Rock analyses

Grain size analysis is an important supplement to core analysis measurements. Grain size analysis which applies generally only to sandstones describes the distribution of grain sizes. The distribution is important in characterising the rock sample and in assessing the quality of the core sample. Grain size analysis is used in a number of applications such as: • petrophysical evaluation in determining controls on log parameters; •

permeability prediction;

•

sedimentological description including sand heterogeneity and depositional environment;

•

well completion programs in friable and unconsolidated sediments.

Grain size sorting parameters Once grain size distribution has been determined, it is typical to apply a sorting method. Sorting is one of the most diagnostic textural features of sediments. A typical grain size report is shown in Figure 13.1. Three common sorting coefficients are Folk, Trask and Moment measures.

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13.1.1 Grain size by laser diffraction Principle A small sample (1-5 grams) is disaggregated and dispersed in a carrier fluid which can be oil or water based. The carrier fluid is agitated. A laser beam is projected through the dispersed sample and the diffracted light patterns are analysed. The angle through which the incident light is scattered is inversely proportional to particle size and the intensity is directly proportional to number of particles. Points • Recommended technique • Laser technique was introduced in about 1989 and has replaced the traditional sieve analysis technique. • Laser technique covers a greater range of particle sizes than sieve analysis and is faster, more reliable and more accurate. • Very little sample is required. • Coarse sand fraction (sizes greater than 0.5 mm) can not be determined. Coarse sand fraction should be determined separately by pre-sieving using techniques described below. • Data is very reproducible. Precision • Uncertainty estimated at about 0.5 weight percent for each size fraction. Price/timing • About US$70 per sample • Several minutes per sample is typical. Peripheral measurements • Grain size analysis is a measurement in support of basic properties of porosity and permeability. • Permeability correlations are often built up for predicting permeability from grain size distributions and sorting coefficients derived therefrom. • Grain size analyses are used to confirm that no changes in rock fabric have occurred during testing. For example, if fines have developed then these can be detected from laser sieve analysis. • Grain size analysis should be done on every sample involved in special core analysis.

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13.1.2 Grain size by sieve analysis Principle A clean, dried sample of known weight (about 100 grams) is disaggregated and mechanically vibrated to pass through a series of sieves of progressively smaller mesh size. The partial weights retained on individual screens are used to determine the grain size distribution. Points • Acceptable technique. • The majority of grain size analyses has been done in this fashion. • Samples can be mechanically shaken or vibrated using acoustic energy. • Sieve analysis can also be performed by suspension in a carrier fluid which is agitated through the screens. • Sample weight should be known to 0.01 g. • Data is reported in weight percent retained on each screen. • Avoid fine loss during handling and overcrushing. • Method is suitable for grain sizes over 0.044 millimetre. • Clay fraction is usually removed by wet wasting on the 325 mesh screen which prevents particle aggregation. Precision • Uncertainty is 0.5 percent for each screen. Price/timing • Less than US$100 per sample. • It usually takes about an hour to determine grain size. Peripheral measurements • Grain size analysis should be done on every sample involved in special core analysis.

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13.1.3 Grain size by image analysis Principle A thin section is made which is used in an image analysis system which incorporates a petrographic microscope. Points • Acceptable technique but needs calibration with another technique. • This method has been described as a method of choice for consolidated rocks because of the difficulty in disaggregating consolidated samples. • Typically 200-300 grains are used in the determination of distribution. • Data may be biased to grains of smaller size partly because the imaging is done in 2 dimensions. • Data is calculated on a volume distribution basis. • Instead of thin section analysis another technique is to spread grains on a glass slide so that few are touching. About 200-500 grains are required. Precision • Uncertainty is 0.5 percent for each mesh size. Price/timing • Cheap; typically less than US$300 per sample. • The method can be time-consuming if non-automated methods are used. Automated methods generally take 5-15 minutes. Peripheral measurements • Grain size analysis by another method is recommended for calibration.

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13.1.4 Source rock analysis Principle Source rock analysis is obtained from the Applied Geochemistry section at KSEPL, RR/26. KSEPL Report, RKTR.94.0001, contains more details regarding their analyses portfolio and prices. Source rock analysis can include, but is not limited to, the following analyses: • source rock indication before and after extraction; • organic carbon determination; • source rock yield and type of organic matter; • incident light microscopy; • vitrinite reflectance measurements; • activation energy measurements; • pyrolysis gas chromatography. Points • Include sample particulars (as is known) such as: country, well/outcrop, drilling operator, type of sample (cuttings, cores, SWS, tool-samples, outcrops/surface samples, etc), depth of sample or sample number, casing depth, stratigraphy, temperature data, type of drilling mud and mud additives • 30 grams of sample (dry, free of drilling mud) are adequate • do not crush sample • washing or rinsing samples to remove drilling mud and salt is acceptable; indicate if sample was been washed or not • dry samples at temperatures not higher than 600C • rock samples should be packed preferably in KSEPL's 'Special bags for geochemical samples' (two sizes available 10x15 cm and 19x29 cm). • forward samples to: KSEPL (RR/26) Volmerlaan 6 2288GD Rijswijk (Z.H.) The Netherlands.

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Precision • depends on analysis; contact KSEPL RR/26 Price/timing • From US $15 - 150 per sample. • Source rock analysis usually takes about 1-2 months. High priority samples can be turned around in 1-2 weeks. Peripheral measurements • Usually done in combination with or support of other measurements.

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13.1.5 Cap rock/seal analysis Principle A fresh core plug is 100% saturated with formation brine, placed in hydrostatic cell and subjected to confining stress. Brine is flushed through the sample and the permeability monitored until steady-state conditions are reached, which determines the absolute brine permeability. Sample resistivity should be measured also. Gas or oil is then introduced on to the surface of the rock and the upstream pressure incrementally increased. The threshold pressure is identified when there is a significant increase in the flow rate (or a change in sample resistivity is seen). Points • Good cap rock should have a liquid permeability of the order 10-6 mD. • Threshold pressures are normally above 1000 psi (70 bar). • Resistivity is usually a much more sensitive indicator of oil or gas entry than flow, but a uniform brine salinity must be present in the rock. • Unconsolidated samples must have oil/water measurements at the proper confining stress. • Preserved core that has not been allowed to dry out must be used for this measurement. Precision •

Entry pressure accuracy can be very high. However, data applicability depends on sample representativeness.

Price/timing/number of samples • US$2,000 per sample is typical. • This is a very slow experiment and can take more than a month. • 2-3 samples per seal type are recommended. The more samples done the better the characterisation of the seal. Peripheral measurements • Capillary pressure measurements should also be made which can be mercury/air for consolidated rocks. • CT -scans assist in data interpretation. • Thin section and mineralogy can be important for data interpretation.

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Fluid analyses

13.2.1 Counter Current Imbibition (CCI) Principle A clean, dry sample plug is weighed, evacuated and then saturated with toluene. Toluene is allowed to evaporate until an initial wetting saturation of 25% is reached. The sample is then immersed in a toluene bath (see Figure 13.3) and its immersed weight measured as a function of time (see Figure 13.4). Toluene imbibes into the sample while air escapes, i.e. through counter current imbibition. Residual air saturation is determined. The process is repeated for initial toluene saturations of 50%, 75% and actual reservoir irreducible water saturation if known. A curve of residual saturation against initial saturation is then determined as shown in Figure 13.5. Points • Residual air saturation, which is an analogue of the residual oil saturation, is determined from the plot of air saturation against time. Imbibition behaviour is followed by diffusion which is indicated by a change in slope. This defines the residual gas saturation. • Calculated saturations are valid only if the reservoir is water wet. • In tight samples, some depression of the gas saturation is seen because of gas compression due to capillary pressure. • Other wetting fluids can be used such as brine. • Irregularly shaped samples can be used in this technique. Precision • Saturation uncertainty is about 2% (in saturation units). Price/timing • About US$300 per sample. • The experiment takes about a day. Experiments are done in batches. Peripheral measurements • Bulk and grain volumes of the sample are required. • Other methods of determining residual oil saturations such as by flow experiments should be performed to check estimates obtained from the CCI technique.

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13.2.2 Oil and gas analyses Principle Oil and gas analyses are obtained from the Applied Geochemistry section at KSEPL, RR/26. Oil and gas analyses include, but are not limited to, the following: . • determination of API gravity; • gas chromatography; • sulphur, nickel, vanadium contents; • asphaltene determination; • C12/C13 isotope determination; • mass spectrometry; • compositional analysis up to C7; • viscosity and pour point; • free hydrocarbon analysis (heads pace gas analysis); • carbon isotope; • biomarker analysis; • trace element analysis; • organic sulphur; • multi-dimensional gas chromatography. Points • Preferably 1 litre from a single reservoir production test after clean-up period is required. Production test samples are preferred over DST. RFT samples are least preferred. The minimum volume is 50 ml for a complete programme. • Oil samples can be stored in KSEPL's oil sample collection (at no charge). • Oil samples should be stored in preferably clean glass bottles sealed with aluminium foil under a screw cap. Tin cans are also suitable but plastic bottles are to be avoided. • Oil samples should be free of water which can be done by centrifugation. • Gas samples should be transported in mercury-free, special steel cylinders, which are UNapproved or D.O.T. (U.S.) approved. • KSEPL has developed an aluminium container to facilitate air transportation of oil samples (refer to RR/26).

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Precision • depends on analysis; contact KSEPL RR/26. Price/timing • Prices range from US$15 -250. Advanced chromatography can cost more. • Oil and gas analyses usually take 2-3 months depending on workload. High priority samples can be turned around in 1-2 weeks. Peripheral measurements •

Usually done in combination with or support of other measurements.

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13.2.3 Formation water and core water analysis Principle Formation water and core water analysis are needed to establish proper brine resistivity and brine composition parameters. Formation water is obtained using well-bore sampling methods such as a repeat formation tester. Core water can be recovered by using a number of techniques. Brine analysis includes but is not limited to: • cation and anion composition; • brine resistivity; • brine density; • pH; • solids. Techniques used for brine analysis include: • ion chromatography; • inductively coupled plasma; • X-ray fluorescene; • atomic absorption spectroscopy; • mass spectroscopy. Points • Methods for core water recovery include: - immiscible fluid displacement; - centrifugation. • Cores must be handled carefully to avoid drying. • Variations in brine compositional analysis depend strongly on the laboratory used. SIPM recommends that occasional synthetic brines be sent for analysis to ensure proper compositional and resistivity determination. • Brine composition should obey electro neutrality principle; anion and cation concentration should agree.

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Precision • depends on analysis. Price/timing • Prices are variable depending on analysis. • Brine analyses can be turned around in 1-2 weeks. Peripheral measurements • Usually done in combination with or support of other measurements.

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Rock-fluid compatibility

13.3.1 Compatibility flood Principle A core sample, which has been cleaned so that oil and gas phases have been completely removed, is mounted in a Hassler-type core holder and subjected to isostatic stress. After vacuum saturation with artificial particle-free formation brine, the sample is flooded with brines of different salinities (starting off with a high salinity and then reducing it). Brine permeability is monitored. The brine flooding apparatus is shown in Figure 13.6. The same formation water is pumped into the sample while pressure differential and brine volumetric flow rate are continuously monitored to establish the base absolute brine permeability. The core sample is flooded by different brines and the resulting brine permeability is monitored. Injection of further brine is initiated after back flushing with the previous one. Reversal of flow is carried out to investigate movement of any fines which may have been liberated by the artificial formation water. The presence of mobile fines can often be seen from the erratic pressure trace caused by pore throat blockage and subsequent clearing. Also upon flow reversal, a dramatic increase in permeability is generally seen. Any permeability changes are attributed either to interaction between ions in the brine with clay minerals in the rock sample or to the mobilisation of fines. Points • Recommended especially for ensuring proper flow tests. • The test is required when artificial formation water is to be used in core analysis and is also used to help predict the effect of water injection in secondary recovery. • Montmorillonite is most likely to swell due to incompatible fluids and kaolinite is most likely to migrate. The stabilisation of these clay minerals can be investigated by flushing selected samples with CaCl2, MgCl2, or KCI solutions before flushing with the required brine solution. • The whole permeability range should be covered, as different permeabilities can show different sensitivities. The greatest sensitivity is shown by low permeability samples.

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Points (continued) • Both consolidated and unconsolidated core samples can be investigated. • Samples are of plug type; 2.5 cm diameter and 2 - 4 cm in length. • A sample of original formation water may be required; its composition (and resistivity) needs to be determined. • Mobile fines can be caused by improper core preparation procedures. • Realistic flow rates should be used • Remarks on contractor procedures: - The KSEPL procedure should be followed as closely as possible. - Contractors tend to split up liquid permeability tests into three separate experiments: specific permeability to a single liquid, effective permeability to oil at connate water saturation, and permeability versus throughput. - The test can be carried out using a constant flow rate or a constant pressure difference across the sample. The injection rate can be varied to investigate rock-fluid interactions. Longer term flow effects should be investigated via a permeability versus throughput test. - If cumulative volume throughput of a single flowing fluid is measured and permeability measurements are made at set time intervals until equilibrium is reached, then permeability is obtained as a function of fluid throughput. Precision • 20-40% of true value which is less than normal permeability determination. Price/timing • On quotation from vendor • Experiments can take months. Peripheral measurements • At KSEPL, porosity, grain density and absolute permeability to air are measured selected samples.

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Miscellaneous tests

13.4.1 Acid response test Principle A clean, dry plug is placed in a hydrostatic cell and brine saturated. Brine permeability is established using (synthetic) formation brine. The system is attached to an acid permeameter. Acid flushing is then initiated, consisting of a preflush, a main flush (consisting of the chosen acid mix) and an overflush with a compatible brine e.g. 3% HCI or 3% NH4CI to determine the final fluid porosity. All are carried out under conditions that simulate injection. During the flushes, permeability is determined continuously. Reversal of the flow direction by backflushing and recycling the partially spent acid will simulate reaction conditions at the outer boundary of the treated zone. Results are presented on a crossplot of the ratio of the permeabilities before and after the acid flood versus the cumulative acid volume per height of the treated zone (Fig. 13.7). Points • All acid flushes should be carried out at borehole temperatures. • Samples should be taken parallel to the bedding planes. • Viscosity of the test fluids should be determined at borehole temperature. • Core acid flushing tests can be carried out on both cleaned samples and on samples which have been artificially impaired with brines or muds. • At KSEPL, tests are carried out on cylindrical samples having a maximum length of 14 cm and a diameter of 2.54 cm. • Artificial impairment can be used to investigate potentially less damaging drilling/workover/completion fluids. Core Laboratories conduct static tests which investigate the interaction between the formation rock/fluid and mud filtrate, completion fluids and acid systems. Core Laboratories can also simulate drilling induced damage and assess the permeability reduction involved. • A full acid test involves a number of stages: - determination of the mineral composition of the formation rock; - determination of the optimum acid composition; - core plug flushing experiments with selected formulations; - evaluation of field trials.

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Precision • These measurements have a precision of 5-10 % of measured value but have low accuracy. A significant increase in permeability should be observed. Price/timing/number of samples • About US$1,500 per sample is typical. • Each test takes about 2 days. • 3-5 samples per rock type is recommended. Peripheral measurements • Porosity and Brinell hardness number should be measured before and after the core flushing test. • Conventional air permeability. • SEM images, CT-scanning should be done on the core. • X-ray fluorescence and atomic absorption should be performed on the effluent.

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13.4.2 Solvent flushing - for wax removal Principle A kerosene-saturated sample is flushed with kerosene at reservoir temperature to determine initial oil permeability. After a crude oil pre-flush at reservoir temperature, flow is stopped and temperature is lowered to a level expected to cause wax deposition. The pre-flush continues with crude oil at this temperature and wax is deposited. Permeability reduction caused by this impairment is determined by using kerosene at the same temperature without attempting to remove the impairment. After the crude oil pre-flush, a dissolving flush is carried out at this temperature in an attempt to remove the impairment. An after-flush of kerosene is carried out to determine final liquid permeability. Points • Samples of formation fluids are required and their properties determined i.e. the wax content of the crude with its cloud point and the composition of the formation water. The composition of the crude and its cloud point will indicate whether wax, and possibly other solid compounds, will precipitate out during operations. • Solvent flushing tests can be run at the same time as other core flushing analysis such as the acid response test; a full damage analysis can be done which aims to identify sources of damage, to identify less damaging fluids for future use and to optimise damage removal procedures. • Removal of wax should be investigated with wax solvent, crude oil at reservoir temperature, and toluene. Precision • These measurements have a precision of 5-10 % of measured value but have low accuracy. A significant increase in permeability should be observed. Price/timing • About US$1,500 per sample is typical. • Each test takes about 2 days. Peripheral measurements • Oil properties such as cloud point should be determined. • Knowledge of brine composition is important.

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Literature

Vischer, G.S. Grain Size Distributions and Depositional Processes Journal of Sed Petrology Vol 39, p 1074-1106, 1969 Komar, P.D. and Cui, B., The Analysis of Grain Size Measurements by Sieving and Settling Tube Techniques Jour of Sed. Petrology, Vol 54, 613-614, 1972 Griffin, T.G., Extended Range of Particle Size Distribution using Laser Diffraction Technology: A New Perspective SCA 9126, paper presented at the Fifth Annual Technical Conference of the Society of Core Analysts, August 1991. Section Applied Geochemistry, RR/26 Price List and Sample Requirements Standard Geochemical Analysis Scheme. KSEPL Report, RKTR.94.0001. Blumer, D.J., Cano Limon core damage study: Vol. 1: Rock-water interactions. EP 87.2094. Eigner, M.R.P., Kantorowicz, J.D., Mattern, R.B., Stadt, M.E. van de, The effect of rock fluid interaction on sea water permeability of core samples from Cormorant CA30, U.K., North Sea. EP 86-1046. Nitters, G., ldenfication and removal of impairment problems in the Rabi field, Shell Gabon. EP 89-1212. Nitters, G., Sedee, W.I.M., Acid response tests on core samples from well Tazerka-3 and simulated gravel packs, Shell Tunirex. EP 87-0343. Nitters, G., Kouwenhoven, A.P., Oedai, S., Trompert, R.A., Optimisation of acid recipes for Southern North Sea gas wells, Shell Expro, A progress report. EP 89-0850.

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Core analysis research activities

The (special) core analysis techniques described in the previous chapters deliver accurate results within the described limitations. Nevertheless, there is continuous development to enhance the measurement of core properties. KSEPL and BTC are constantly developing more efficient ways of making accurate core analysis measurements. Existing measurement techniques can always be improved to extend measurement range or to yield additional information. In this way, capillary pressure measurement was extended to yield pore trapping information (Apparatus for Pore Examination), and the Continuous Injection equipment for measuring resistivity index curves was extended to enable measurements under simulated in situ conditions (EMPRESS). New physical measurement techniques developed outside the oil industry are also being investigated for suitability for oil field purposes. For examples, CT scanning, Scanning Electron Microscopy and Nuclear Magnetic Resonance techniques have been picked up by the oil industry. CT-scanning and SEM, for example, have become routine methods in core analysis. In this chapter, new developments at the forefront of core analysis are described briefly. None of the techniques are currently available for standard (cat. 8) Opco measurements. Consequently, the format as applied to the description of the techniques is not used. Most of these techniques can be used in a limited degree in specific (cat. 6/7) research studies for Opcos. The techniques described below fall under the following headings: •

rock characteristics;

•

fluid flow;

•

supplementary.

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Rock characteristics

14.1.1 Ultrasonic Velocity Cell (UVC) KSEPL RR/37 is investigating, together with Geophysics (RR/34) and Geology (RR/21/28), the influence of petrophysical properties, anisotropy and lithology on acoustic (compressional and shear) velocities under various stress and pore fill conditions. An Ultrasonic Velocity Cell (UVC) has been constructed which allows such measurements as well as simultaneous (static) deformation to be determined. The set-up has the additional advantage over the hydrostatic ATT (acoustic transit time) measurement that radial and axial stresses can be varied independently. The UVC will be used initially for research purposes and may eventually become available as a service. The experimental set-up is shown in figure 14.1. The UVC uses cylindrical samples of 1.5 inches (3.76 cm) or 1 inch (2.54 cm) and 1.2 inches (3 cm) and 2.4 inches (6 cm).

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14.1.2 Acoustic transmission anisotropy In a vertically oriented cylindrical core sample the variation in ultrasonic wave velocity is used to detect the presence of anisotropic microcrack orientation and infer the direction of the principle insitu stress. Ultrasonic P-wave velocity along the diameter of the sample is measured at ambient conditions by rotating the sample between two spring loaded ultrasonic transducers. A cube is then cut from this plug and placed in a triaxial loading apparatus. Equal normal loads are applied perpendicular to the cube faces in a stepwise manner until the cube shows signs of failing. Ultra-sonic wave velocity measurements are made along each of the principle stress directions after each pressure increment. A reduction in velocity anisotropy is indicative that the anisotropy measured at ambient conditions is due to core damage caused by releasing in-situ stress. Two assumptions are made: 1) any microcracks formed during the stress release experienced on bringing the core to surface will cause ultrasonic wave velocity anisotropy; these cracks will close when the sample is restressed. 2) most microcracks are believed to form perpendicular to the direction of maximum horizontal stress release. The direction of minimum wave velocity will lie along the direction of maximum horizontal in-situ stress. This technique uses a full size, vertical plug sample of diameter 7.5 cm and length 10 cm.

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14.1.3 Apparatus for Pore Examination (APEX) APEX (Apparatus for Pore Examination) is a special capillary pressure measurement which was developed in the early eighties by BTC. Instead of using the conventional pressure controlled injection of mercury, mercury is injected at a slow constant rate of about 1-2 nl per sec. Pressure is monitored continuously and reveals fluctuations which arise as mercury spontaneously redistributes. The redistribution is known as a "Haynes jump" and occurs because mercury can occupy configurations of lower energy by movement of part of the mercury from pore throats to pore bodies. The increase in radius of curvature of the mercury is revealed as a drop in mercury pressure. Hence, APEX gives information on the pore neck and pore body distributions of a rock sample. These distributions are useful in studying many attributes of rock samples. For example, porescale heterogeneity is revealed by the pore body and pore throat distribution. APEX measurements deliver the total capillary pressure curve which can be partitioned into two parts namely the pore body capillary pressure curve and the pore throat capillary pressure curve. It turns out that the pore throat capillary pressure curve is directly related to the secondary drainage capillary pressure curve in a strongly wetting system i.e. the initial water saturation of the primary and secondary drainage cycles are the same. Similarly, the pore body capillary pressure curve is related to the residual-initial curve for a pore sample. Another way of obtaining residual-initial curve is described in section 13.2.1. It has been shown that APEX and counter current imbibition results deliver essentially the same results on twin plugs. Thus, APEX is especially useful in revealing how much non-wetting fluid can be trapped, i.e. for residual oil studies. It is possible to obtain a number of petrophysical parameters such as determining permeability, formation resistivity factor and cementation exponent, 'm', from APEX measurements using model calculations because these parameters depend directly on pore-scale properties of rocks. APEX is currently only available at BTC.

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14.1.4 Resistivity Enhanced Measurement Procedure for Resistivity Experiments at Sub surface conditions (EMPRESS) In the existing Resistivity Index by Continuous Injection equipment (see section 9.2.2), the I-Sw curve is measured by injecting kerosene at room temperature, and at a relatively low confining stress (70 bar) and a pore pressure up to 9 bar. In the past few years, attempts to develop RlMARC (Resistivity Index Measurement At Reservoir Conditions) equipment to measure the I -Sw curve at reservoir temperature and pressure conditions, using live (reservoir) crude oil proved difficult. Consequently, a variation of RlMARC called HTP (High Pressure and Temperature) Continuous Injection equipment was built, which could handle high temperature and pressure, but no live crude, which worked fine. Therefore, RIMARC has been replaced by modified HTP equipment, called EMPRESS (Enhanced Measurement Procedure for Resistivity Experiments at Sub-Surface conditions). EMPRESS is currently being used for a systematic investigation of high pressure and temperature effects using "dead" crude (i.e. not containing gas) on well defined outcrop material and reservoir rock obtained from interested Opcos. EMPRESS measurements can be made using dead crude, at temperatures up to 150°C, with confining stress up to 400 bar and pore fluid pressures up to 55 bar. A possible subsequent extension of the EMPRESS equipment would be to handle live crude (oil recombined with gas). Depending on the importance of the effects found it will be decided whether EMPRESS will be offered to Opcos as a standard service.

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14.2 Fluid flow 14.2.1 Capillary Pressure and Resistivity Index by Continuous Injection, CAPRICI The CAPRICI method has been designed by KSEPL RR/44. CAPRICI determines primary drainage, imbibition and secondary drainage oil-brine capillary pressure curves together with I-Sw curves in a single suite of measurements at reservoir conditions. Research is being carried out using the CAPRICI apparatus to study wettability changes which occur due to aging samples under reservoir conditions using dead and live crude. The principal aim is to establish pragmatic procedures in a continuous injection experiment. A secondary objective is to use CAPRIC! to collect relevant information on wettability and aging from a wide range of rock/crude systems. By generating a database, it is expected that correlations can be established that may help in reducing the effort required for aging experiments. A schematic of the experimental set-up is shown in Figure 14.5 and a picture of CAPRICI is shown in Figure 14.6. A core plug is placed between an oil-wet membrane, which allows only oil to pass, and a water-wet membrane, which allows only brine to pass. Oil or water is injected continuously at low rates such as 0.1 ml/day. At this low rate, capillary forces dominate viscous forces and the saturation profile may be homogeneous over the core. The directly measured pressure difference across the core can then be taken to be the capillary pressure. The average saturation within the core is determined from the produced fluid volumes and resistivity is simultaneously measured. Reservoir conditions can be imposed. In principle, capillary pressure and relative permeability of the displaced phase can be determined simultaneously. This is possible by using numerical simulation to determine the balance between capillary pressure forces and viscous forces for different saturations and flow rates. Viscous force can be related to relative permeability. Capillary pressure and relative permeability curves obtained agree well with those obtained using conventional steady state and centrifuge techniques. By judicious choice of flow rates (initially high, later very low when approaching residual saturations), the experiment can be done relatively quickly with curves being generated within ten days.

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14.2.2 Relative Permeability at Reservoir Conditions (3-phase), REPARC-3 This equipment has been designed by KSEPL RR/44 to study 3-phase flow phenomena at reservoir conditions (max 150°C and 500 bar). Unsteady-state and end-point relative permeability experiments can be conducted and the apparatus is being extended to facilitate steady-state experiments. A picture of REPARC-3 is shown in Figure 14.7. All equipment, except the pumps, is housed in a thermostatic cabinet. Produced phases are collected under pressure, to avoid a back-pressure regulator system. Both the production collection vessel and the injection -storage vessels are equipped with calibrated endoscopes to measure injected and produced volumes in-situ. A specially designed light-weight core holder is used that allows fast connecting and disconnecting for mass-balance checks by weighing during the experiments. Phase densities can be monitored by a high precision densitometer that has also been installed in the cabinet. A capillary has been included to facilitate in-situ viscosity measurements. Several differential pressure gauges with different sensitivities have been mounted to measure the pressure drop during flooding. The equipment is used for research on the effects of aging on relative permeabilities, capillary pressure and residual oil and gas saturations, complementary to CAPRICI related research. As with CAPRICI, the experiments are analysed with numerical modelling.

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14.2.3 Critical gas saturation Two critical gas saturation set-ups are available at KSEPL to study the development of the critical gas saturation in a solution gas drive. Upon pressure depletion of an oil-field through the bubble point, solution gas will be liberated. Initially, gas will be trapped by capillary forces and, thus, immobile. When pressure depletion continues, more gas will be liberated while at the same time the already liberated gas will expand. At a particular gas saturation, referred to as the critical gas saturation, the individually trapped gas bubbles will connect and gas can move through the reservoir. For reservoir management, the critical gas saturation is the primary parameter necessary to predict the onset of a significantly increased producing GOR. Another application of the equipment is for the study of the remobilisation of trapped gas. During flooding of a primary or secondary gas cap or during depletion of gas reservoirs with an active aquifer, gas can be trapped. Upon pressure depletion, later in the field's life, trapped gas will expand and form a continuous, mobile phase. A picture of a critical gas saturation set-up is shown in Figure 14.8. All equipment is housed in a thermostatic cabinet. Critical Gas 1 can be operated with gas-oil or gas-water systems at max 45°C and 100 bar. The equipment basically consists of a Hassler type core holder connected to one pump system for fluid injection and another system for fluid withdrawal to simulate depletion. The pressure decline rate is computer programmable. Saturations are determined both through mass balance and by gamma-ray absorption. Critical Gas 2 is designed for experimentation at reservoir conditions of temperature (150°C) and pressure (500 bar) for live crude oil. A main issue in critical gas work is scaling the results obtained in relatively small core plugs at relatively high pressure decline rates to the dimensions of the field using pressure decline rates about two orders of magnitude slower than in the laboratory.

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Supplementary

14.3.1 Nuclear Magnetic Resonance, NMR Nuclear Magnetic Resonance (NMR) techniques have been used extensively in many branches of science and industry. In petrophysics, NMR techniques are rapidly evolving, both in logging and in core analysis. The wireline NMR tool, 'Magnetic Resonance Image Log' (MRIL) has recently been developed and is increasingly used. Companion core analysis measurements are performed in the laboratory using NMR spectrometers. In both wireline and laboratory applications, detailed characterisation of pore size distributions and properties of fluid/solid interfaces such as information on various porosity systems, permeability, wettability, clay bound water and related properties can be obtained. In an NMR spectrometer, the relaxation behaviour of hydrogen proton spins in a plug sample can be measured by subjecting the sample to a series of RF (about 1 MHz) pulses. The excitation and relaxation take place in a static magnetic field. The frequency of the RF pulses is tuned to induce transitions between energy levels of the nuclear spins, which is different for all nuclei. The relaxation of the hydrogen proton spins is governed by its interaction with its local environment which is dominated by interactions with the pore walls. Measured relaxation times (called T1, the spin-lattice or longitudinal relaxation rate, and T2, the spin-spin or transverse relaxation rate, dependent on the type of relaxation mechanism) thus give information on pore sizes, on movable fluid and bound water layers. Measurement of T1 and T2 require different pulse sequences. Normally, T2 is used because it can be determined faster. T1 and T2 contain similar information and henceforth we shall only refer to T2. As there are many pore sizes, a whole range of T2 values will be measured, giving rise to a measured T2 spectrum (histogram) related to the pore size distribution. The shape of this spectrum and the absolute amplitudes are the basic information obtained from the measurement. By applying a gradient in the static magnetic field, diffusion of the excited protons can also be measured. Since diffusion of oil and water are different, this gives additional information, e.g. on hydrocarbon saturation.

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• Porosity The amplitude of the NMR signal is proportional to the concentration of hydrogen nuclei in the sample and thus can be used to measure porosity. NMR signals that originate from hydrogen in the rock matrix or clay bound water decay much faster than that in the pore-space and are not seen by the detector coil; the measurement is therefore unaffected by the rock matrix. Hence, it is lithology independent. The overall amplitude of the signal extrapolated to t=0 determines porosity. The accuracy of the measurement depends upon how quickly the first data point is measured after the equilibrium magnetisation is disturbed. • Pore-size distribution NMR relaxation times are faster when a liquid occupies the pores of a rock than for a bulk fluid. T2 is short for hydrogen nuclei in solids or in water molecules bound to rock surfaces(∼ 1ms) but long in bulk fluids (∼several seconds). The effect of the grain surface in the relaxation process offers a link between T2 and pore size. The relaxation time for all hydrogen nucleii is decreased in water-wet rocks because non-relaxed water molecules will tend to diffuse to the pore-wall. The decrease is proportional to the surface-to-volume ratio of the pore which is a measure of pore size. Hence the measurement of T2 and the subsequent deconvolution provides a means of determining pore size distribution of the rock sample. For oil-wet rocks, the roles of water and oil are reversed and for mixed wettability systems, the wetting mechanism will affect whether the pore size distribution can be determined from T2. • Permeability At KSEPL, many NMR measurements have been made on samples from different fields and geological environments. It has been concluded from this data that the prediction of permeability from porosity can be greatly improved by incorporating the average pore size as represented by the T2 distribution. A general correlation determined for sandstones can predict permeabilities within a factor of ten while local correlations have been used to predict permeability to within a factor of three. Such correlations can be used to determine permeability from the response of the NMR logging tool.

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• Movable fluid By ignoring the NMR signal originating from small pores in water-wet rock, the movable fluid volume is determined. This volume available to contain hydrocarbons is directly related to irreducible water saturation and is referred to as the free fluid index. The remaining volume can be related to capillary bound and clay bound water. • Residual oil saturation Residual oil saturation after waterflood in a water-wet sample can be measured directly. The water in the sample is replaced by a solution containing paramagnetic ions, which accelerate relaxation of hydrogen nuclei so that the only measured signal originates from the residual oil. If oil is the non-wetting phase the decay will be unaffected by pore size and the amplitude of the signal extrapolated back to t=0 corresponds directly to the residual oil. Under favourable conditions, NMR diffusion methods may be used to determine the (residual) oil saturation, without using paramagnetic ions. • Fluid diffusion coefficient If a magnetic field gradient is applied to the sample, the T2 relaxation time is affected by molecular diffusion. Diffusion can be monitored because the spinning nuclei are moving through a changing background magnetic field. From diffusion coefficients, viscosity ratios can be obtained. The use of this measurement for the logging tool allows differentiation of oil and gas. • Wettability Wettability determination by NMR is an area of active research. Because the fundamental mechanism of NMR relies on surface relaxation, the idea that NMR can differentiate between oilwet and water-wet behaviour seems clear. However, more research is required to elucidate the mechanism. • NMR imaging Imaging can provide the above measurements together with 2- or 3 dimensional mapping of the nuclei under investigation. This is achieved by creating a magnetic gradient, through the bulk sample, along the axis on which the spatial differentiation of the spin population is required. The frequency shift exerted upon each nucleus will be directly proportional to its position on the gradient axis. Higher gradients provide greater frequency shifts and greater spatial resolution.

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Literature

Yuan, H.H. and Swanson, B.F., Resolving Pore Space Characteristics by Rate Controlled Porosimetry SPE Formation Evaluation, Volume 4, Number 1, pp 17-24,1989. Yuan, H.H. Pore-Scale Heterogeneity from Mercury Porosimetry Data SPE 19617 paper presented at the 1989 SPE Annual Technical Conference and Exhibition San Antonio, October 8-11. Yuan, H.H. Advances in APEX Technology SCA 9004, paper presented at the fourth Annual Technical Conference of the SCA, 1990. Kokkedee, J.A., Boutkan, V.K., and Oedai, S., Capillary pressure and relative permeability by continuous injection - Experiments with CAPRIC!. RKGR.93.139. Kokkedee,J., Boutkan, V.K., Towards measurement of capillary pressure and relative permeability at representative wettability Proceedings of the Seventh European lOR Symposium- Moscow, Oct 27-29,1993 Boutkan, V.K., and Oedai, S., Residual oil and gas saturations of core samples from well BB-18, Brent field RKGR.92.142. Scherpenisse, W. and Snoei, G., Experimental investigation of the variation in critical gas saturation with pressure decline rate with model fluids. RKGR.93.078. Berg, F.G. van den, Installation of a proton NMR spectrometer at KSEPL for core analysis. KSEPL report RKGR.86.068. Berg, F.G. van den, Looyestijn, W.J., Nuclear magnetic resonance on core samples from the Cormorant field, in relation to permeability and to NML logs. KSEPL report RKOR.85.043. Coates, G.R., Peveraro, R.C.A., Hardwick, A., Roberts, D., The magnetic resonance imaging log characterised by comparison with petrophysical properties and laboratory core data. SPE 22723, October 1991. Hyde, T.C., Network modelling of porous media for the prediction of permeability from nuclear magnetic resonance. KSEPL report RKMR.88.027, September 1988 RKRS.88.01.

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Hyde, T.C., Permeability predictions from nuclear magnetic resonance measurements on core samples KSEPL Report RKRS.87.01. Hyde, T.C., Permeability correlations with porosity and nuclear magnetic resonance T1 data for brine saturated core samples. KSEPL Report RKRS.87 .07. Kenyon, W.E., Nuclear magnetic resonance as a petrophysical measurement Nuclear geophysics. Vol. 6. No.2. pp. 153-171. 1992. NMR Logging - The New Measurement EP 94-1525, November 1994. Looyestijn, W.J., Nuclear magnetic resonance logging; A state of the art review. EP 91-1824, August 1991. Miller, M.N., Paltiel, Z., Gillen, M.E., Granot, J., Bouton, J.C., Spin echo magnetic resonance logging: Porosity and free fluid index determination. SPE 20561, September 1990. Nesbitt, G.J., Datema, K.P., Maas, J.G., Groot, A. de, Applicability of nuclear magnetic resonance techniques in the characterisation of permeability and wettability of core plug materials. EP 91-1828, December 1989. Sandor, R.K.J., van Ditzhuijzen, P.J.D., NMR logging: The New Measurement EP 94- 1525

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APPENDIX 1 Value of Information Value of Information concepts, which are summarised in chapter 2, are detailed in this Appendix. Three types of value of information cases are examined: •

Value of Prospect Screening,

•

Value of Project Optimisation and

•

Value of Correctly Measured Data.

NOTE: For figures in this section, a red shaded rectangle denotes a human decision while a yellow shaded ellipse represents the consequences of measurement, which are various outcomes each with a given probability of occurring. Positive economic impact is given as NPVi. A negative impact is shown as - NPVi.

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A1.1 Value of prospect screening Prospect screening, earlier known as exploration appraisal, is the most common reason for core analysis projects. During exploration appraisal, the uncertainty of the presence of commercial hydrocarbons is expressed by the term, probability of success, POS. As data acquisition occurs, new information is incorporated into the reservoir model and uncertainty is decreased. Many core analysis projects which are used as part of the entire formation evaluation scheme have resulted in proving the presence of commercial hydrocarbon reserves. However, core analysis projects have also shown the absence of commercial hydrocarbons, which has a positive economic benefit of avoiding unprofitable investment. In both situations, the economic benefit of performing the core analysis project can be very large. A VOl analysis begins by examining the decision tree shown in Figure A1.1

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where POS is the probability of success, NPV1 is the economic benefit of sufficient hydrocarbon reserves, which is the same whether core analysis is done or not, NPV2 is the economic benefit from no development (essentially negligible) because of insufficient hydrocarbon reserves and NPV3 is the loss of income due to development but having insufficient hydrocarbon reserves. The VOl of the situation shown in Figure A1.1 is the difference in value between the top branch and the bottom branch. The top branch represents the case for performing the core analysis project before taking a development decision. The bottom branch is the alternative choice of proceeding with development without core analysis information. The value of the top branch, Vyes, is given as follows: Vyes

= POS * NPV1 + (1-POS) * NPV2

(A1.1)

Since NPV2 is negligible because of no development, equation (A1.1) becomes Vyes

= POS * NPV1

(A1.2)

Note here that the probability of success should actually increase if the core analysis programme is successful. Accordingly, the POS in equation (A1.2) ought to be larger than any POS used in the bottom branch. Consequently, by using POS unchanged, equation (A1.2) underestimates the value of the top branch, which will result in the VOl being underestimated. The value of the bottom branch, Vno, is expressed as follows: Vno

= POS * NPV1 + (1 - POS) * (-NPV3).

(A1.3)

The VOl for prospect screening is given as VOl

= Vyes - Vno = (1 - POS) * NPV3.

(A1.4)

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Note that if the probability of success is unity, i.e. no risk of failure, then the VOl is zero because there is no economic impact and thus there would be no need for any additional information. Alternatively, the larger the possibility of failure, the more advisable it may be to proceed with core analysis. This of course depends on the type of risks involved. For example, coring may impose a risk on the well which thus introduces a modification to the VOl calculation. Equation (A1.4) shows that the justification of core analysis in prospect screening is directly related to the avoidance of an uneconomic development and avoiding the loss given as NPV3. While equation (A1.4) expresses the VOl for prospect screening, the VOl is applied to all data acquisition collectively. The core analysis project may get no credit for the VOl benefit. Nevertheless, the VOl calculation can be used to determine the level of data acquisition expenditure. The value of the core analysis project should then be assessed in terms of the appropriate uncertainties that need to be addressed. Alternatively, the value of information should be discounted to obtain a basis of comparison for the core analysis project. Although this is not a straight forward step, in prospect screening, VOl results are typically large, which makes acquisition of the relevant data critical. VOl concepts only provide the value of the information and do not include the cost of acquiring the information. The Value of Appraisal, VOA, is the difference between VOl and cost of acquiring the data. In summary, for prospect screening options, the economic impact of core analysis is justified by the avoidance of unprofitable investments. In general, development entails large investments and economic impact of core analysis accordingly very large and the justification to proceed with core analysis is very clear. An example is shown in section 2.2.1 for a prospect screening situation.

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A1.2 Value of project optimisation (reducing uncertainty) VOl concepts can also be applied to the justification of core analysis projects that are implemented to evaluate field development options. The main focus is in uncertainty reduction. The decision tree in optimisation is different from exploration appraisal. In effect, the VOl calculation is aimed at determining the economic impact of a given range of uncertainty. Clearly, if uncertainty, even though large has little economic impact then reducing uncertainty has little economic benefit. It is only in those cases where reducing uncertainty has significant economic benefit that core analysis projects are justified. In order to carry out a VOl calculation for optimisation, it is important to know the economic impact of uncertainty in a particular rock property. Such a rock property may be relative permeability, e.g. end-point saturations, or compressibility. In order to determine economic benefit, reservoir simulation is necessary over the range of uncertainty in rock property. By using different values of input parameters, reservoir simulation is able to determine economic benefit of reducing uncertainty. Computer reservoir simulations are sensitivity studies of variations in particular rock properties and are used to develop the relationship between economic impact (NPV) to given variation in rock properties. By using sensitivities within reservoir simulation and deriving economic impact, it is possible to calculate the VOl in optimisation. As before, the Value of Project Optimisation calculation begins by showing the economic alternatives. The base case, which is the choice of NOT proceeding with core analysis, involves applying a single development scenario within a wide range of uncertainty. The base case shows that the single development plan will miss the upside potential if more reserves are in place or loses economic benefit if there are less reserves than thought. The other alternative is proceeding with the core analysis project. The core analysis project is designed to reduce uncertainty in the rock properties associated with development option and the extra information allows optimisation of the development options. Higher economic impact is realised when more reserves are present and more cost-effective development takes place if less reserves are present than thought. Figure A1.2 summarises the decision tree associated with optimisation.

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where P(high), P(med) and P(low) are probabilities of given outcomes, NPV1 is the economic impact if development is optimised for high reserves, NPV2 is the economic impact if development is optimised for medium reserves, NPV3 is the economic impact if development is optimised for low reserves, NPV 4 is the economic impact when high reserves are developed when medium reserves are assumed (base development scenario) NPV5 is the economic impact when medium reserves are developed and medium reserves are assumed (base development scenario) and NPV6 is the economic impact when low reserves are developed when medium reserves are assumed (base development scenario).

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The value of information is the difference in value between the upper branch and the lower branch (base case), given as Vyes and Vno respectively: Vyes

= P(high)*NPV1 + P(med)*NPV2 + P(low)*NPV3

(A1.5)

Vno

= P(high)*NPV4 + P(med)*NPV5 + P(low)*NPV6

(Al.6)

The VOl for optimisation is VOl = Vyes - Vno = P(high) * {NPV1 - NPV4} + P(med) * {NPV2 - NPV5} + P(low) * {NPV3 - NPV6}

(A1.7)

In allocating the probabilities associated with high, medium and low reserves, the range of reserves should be chosen so that P(high), P(medium) and P(low) are equal and thereby equal to 0.33. Note that outcomes 2 and 5 are essentially equal and cancel in equation (A1.7), which simplifies to VOl

= 0.33 * {NPV1 + NPV3 - NPV4 - NPV6}

(A1.8)

VOl is positive because NPV1 is greater than NPV4 and NPV3 is greater than NPV6. The exact magnitude of VOl is dependent upon the reservoir simulation results. Note that only four options need be calculated from reservoir simulation to be able to calculate VOl. Here, the economic benefit from VOl optimisation is entirely due to the core analysis project because the only variable is variation in rock property. On the other hand, cost of the reservoir simulations must be included and although the costs do not appear in the VOl result, the costs impact the VOA result. Accordingly, the reservoir simulations should be as simple as possible but maintain the essential physics of the reservoir mechanism.

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In summary, the optimisation problem is reduced to determining the economic impact of 4 situations, which are quantified by reservoir simulation: NPV1 = economic impact if reserves are high and development is optimised for high reserves NPV3 = economic impact if reserves are low and development is optimised for low reserves NPV4 = economic impact if reserves are high but development assumes medium reserves NPV6 = economic impact if reserves are low but development assumes medium reserves. The actual outcomes for NPV2 and NPV5 are not needed because they cancel in the VOl calculation.

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A1.3 Value of correct core analysis data (Shell EP Laboratories vs contractors). Value of information techniques are able to determine the economic impact of performing core analysis results incorrectly. By this, the authors mean the application of incorrect procedures that deliver incorrect data. As a direct corollary to VOl, the value of incorrect data can be calculated because basing decisions on incorrectly measured data has a significant negative economic impact! In one recent example, a contractor laboratory incorrectly measured relative permeability curves on which the size of water-handling facilities were based. The water relative permeability curve results were two orders of magnitude higher than remeasurements at a Shell EP laboratory. As a consequence, many millions of dollars were spent on water handling facilities that were not needed! In a North Sea example, core analysis data from a commercial laboratory would have indicated insufficient hydrocarbons for development. Subsequent remeasurement by KSEPL of resistivity index led to evaluation of commercial volumes of hydrocarbons and that without remeasurement an economic opportunity would have been missed, which was estimated to be about US$30 million. These examples do not imply that core analysis contractors cannot make special core analysis measurements. However, a cursory review of core analysis history at vendor laboratories and the number of requests for remeasurements indicate that contractors fail to provide quality data in a significant proportion of cases. It is very conservatively estimated at about 25%. In other words, in one quarter of cases do core contractors provide incorrect data upon which it is ill-advised to base any decisions. Part of this is also because of unclear expectations of the core analysis contractor and proper planning and communication can do much to reduce the failure rate. Let us make this clearer by examining the decision tree, shown in Figure A1.3, that calculates the economic impact of wrongly measured data. Here, the economic choice is the choice of which laboratory to use for the core analysis project, either a Shell EP Laboratory, say KSEPL, or a commercial contractor laboratory. The central issue is the fact that contractor laboratories have a higher failure rate in special core analysis projects and that the failure rate at Shell EP Laboratories is far lower, in comparison, and negligible with respect to the VOl calculation.

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where POS is the probability of success, POCM is the probability of correct measurement = 3/4, NPV1 is the economic impact of the project, NPV2 is the economic impact of no development (negligible) and NPV3 is the economic impact of basing information on wrongly measured data which results in non-optimal development or perhaps even no development. In either case, a significant negative economic impact is realised.

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(There is a chance that the core analysis laboratories can make an incorrect measurement resulting in the false appearance of commercial hydrocarbons. This situation is rarely encountered and is therefore omitted from the calculation. If it were to be included then it would only make the economic impact of performing measurements at KSEPL even greater. Note it is possible to construe the construction of unneeded water handling facilities as a result of this sort of problem but the authors prefer to regard this example as non-optimal development.) In Figure A1.3, the value of performing the core analysis at a Shell EP Laboratory is the difference in value between the upper and lower branches. The value of the upper branch, VEPLab, is given as follows: V EPLab

= POS * NPV1 + (1- POS) * NPV2 = POS * NPV1

(Al.9)

since the economic impact of no development is negligible. The value of the lower branch is given by, V ConLab, V ConLab

= POS * {POCM*NPV1)+ (1-POCM)*( -NPV3)} + (1-POS) * NPV2 = POCM * POS * NPV1 + (1-POCM) * POS * (-NPV3)

(A1.10)

If as stated above the probability of measurement success is just 3/4 for a commercial contractor then, V ConLab, becomes V ConLab

= 0.75 * POS * NPV1 - 0.25 * POS * NPV3

(A1.11)

Thus the value of performing measurements at Shell EP Laboratories is just, the difference between V EPLab and V ConLab: VOl

= VEPLab - V ConLab = 0.25 * {POS * (NPV1 + NPV3)}

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The value of correctly measuring data results in a significantly large economic impact which results from an identified risk of failure at a contractor laboratory. It therefore pays to have the best data acquisition possible in any project because the value of the total project, NPV1, is at risk in direct proportion to the possibility of measurement inaccuracy. In other words, it is far worse to use wrongly measured data than it is to have insufficient data!! Computing the value of non-optimal development, NPV3, is difficult. It is easy to ignore the risk of measurement inaccuracy but it is every bit as important as selecting the right core analysis measurements in the first place.

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APPENDIX 2 Core screening techniques In this Appendix, we describe techniques used in the screening of whole core such as were described in section 4.6. In this Appendix, more detail is given on CT -scanning and information on traditional screening techniques of core gamma ray and X-ray fluoroscopy are given. Note that CT-scanning can also be used in core sample screening for special core analysis as discussed in section 4.9.

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A2.1 X-Ray Computer Tomography scanning (CT) Principle A typical CT scanner is shown in Figure A2.1. Core material is placed in the X-ray beam and the attenuation of the X-ray beam caused by the core material is measured at different angular positions around the core. The X-ray attenuation data are reconstructed into a cross-sectional image of the core revealing the variations in density of the core material. The resolution depends on X-ray beam width and the resolution of the reconstruction. A typical image is composed of 512x512 pixels and can be colour enhanced with computer processing as shown in Figure A2.2. Points • CT -scanning is recommended for all aspects of core analysis. • Typical X-ray beam widths are between 2 and 8 mm depending on CT scanner. • Two planes can be investigated; - a tomogram shows the cross sectional density distribution in a selected plane perpendicular to the core axis. Tomograms are normally done every inch along whole core and provide an excellent characterisation of the homogeneity of the core. This is especially useful prior to cutting samples for measurement. - a topogram shows the density profile along the axis of the core. Topograms can be reconstructed from repeated tomograms along a whole core. Topograms, also referred to as longitudinal CT -scans, can be done on core plugs. These are very useful on plugs that have already been drilled to ascertain plug homogeneity. Topograms should be done on every plug sample used in special core analysis. • CT -scanning is fast and non-destructive. • CT -scanning can be done on frozen core as well as core that remains within an aluminium core barrel. This is important for unconsolidated core. • X-ray attenuation is directly related to bulk density and thus information can be obtained on porosity distribution which requires an assumption on grain density. • A CT number of 2,200 for fused quartz is used as a calibration standard. Water has a CT number of 0 and air has a CT-number of 1000. CT-scanners should be calibrated at least once per day. • CT-scanners operate optimally after a warm-up period of at least an hour.

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Points (continued) • Factors affecting reliability of CT values include instrument drift, scanning energy, beam filtering, sample size and shape, and artefacts that including beam hardening. • Presentation of CT-images should include a clear definition of CT-number range and legend; a reference scan indicating the calibration standard is recommended. A CT-number distribution should also be displayed as shown in Figure 4.3 in section 4.9 as this can be used to better identify degree of homogeneity. • Most CT-scanners can scan at two different energies which can be used to determine density and atomic number. Alternatively, dual energy scanning can be used to determine density of an unknown material. • CT facilities are available at KSEPL, BTC and various core contractors. • Applications: - Quality control in all aspects of core analysis. - Generation of a topographic density log with the same resolution as the wireline density for core/log depth matching. - Identification of laminations, lithology changes, fracture,orientations, bioturbations and other inhomogeneities. Fine details are revealed which are not visible on the surface. Topograms can be compared directly with normal/UV light photographs of the slabbed core. - Identification of drilling fluid invasion and induced damage. - Selection of preferred orientation for core slabbing. - Selection of plug sample locations. - Determination of in-situ fluid saturation profiles in core flood experiments, which require careful calibration of the CT-scanner.

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A2.2 Core gamma ray Principle Naturally-occurring radioactivity along the length of whole core is recorded to produce a core gamma ray log. The core log can be compared with the wireline gamma ray log to adjust core to wireline log depth. Apart from a total gamma ray log, a spectral gamma ray log can be made by recording the radioactivity in energy windows corresponding with the radiation energy of potassium, uranium and thorium. A typical core gamma scanner is shown in Figure A2.3. Points • Core gamma ray measurements are acceptable. • CT scanning is preferred because of the additional data that are obtained. • Zones where core has been lost can be identified. • An indication of rock type such as sand versus shale can be given. • Unconsolidated material can be logged through the liner. • The core-log correlation enables an accurate definition of depth shifts. • The survey can be done before or after slabbing/plugging. • Spectral gamma ray core logs are acceptable but for qualitative purposes only. Because calibration is heavily affected by deviations in core diameter, background radiation, and presence of sleeve on the core, large (systematic) errors may occur. However, pattern correlations with spectral gamma ray logs are often present. The identification of some minerals is assisted and the results used in the interpretation of borehole spectral gamma ray logs. • This is the main scanning technique used by contractors if not equipped with a CT scanning facility. Total and spectral gamma logs are available at Core Laboratories, GAPS, and Poroperm-Geochem.

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A2.3 X-ray fluoroscopy Principle A core is moved across an X-ray source and the beam, attenuated by the core, impinges on a fluorescent screen, is intensified and recorded by a video camera. The captured image can be viewed on a monitor, recorded on a cassette and converted to digital format. The output from this technique is a continuous image along the length of the core. Points • X-ray fluoroscopy is acceptable but is considered an inferior alternative to CT -scanning. • The method is used by Core Laboratories to examine unconsolidated core material while it is still in its core liner so to minimise core damage. • The technique is rapid. • The main application is similar to that of CT scanning, i.e. aid in slabbing orientation and representative sample selection.

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A2.4 Coreslab inlarging Coreslabs and coreslab photographs can be scanned by a high resolution colour camera. From the digitised images, thin-bed features like dip, thickness and continuity of layers, sand/shale ratio and net pay can be extracted. The extraction of features is currently based on colour and the combined analysis of white light and UV images. The analysis currently available can be especially be useful in the case of laminated formations, for instance, when a more accurate estimation of saturation is required. Figure A2.4 presents a scanned core section with the results of the analysis which can now be obtained.

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A2.5 Literature Vinegar, H.J., X-Ray CT and NMR imaging of rocks. JPT March ‘86 pp. 257-259. Wellington, S.L., Vinegar, H.J., X-ray computer tomography. JPT, 1987, pp. 885-898. Hunt, P.K., Engler, P., Bajsarowicz, C., Computerised tomography as a core analysis tool: Applications, instrument evaluation and image improvement. JPT Sept. '88. pp. 1203-1210. Deijl, B.M. van, Berg, F.G. van den, Natural gamma ray spectroscopy on core material. KSEPL report RKRS.88.06, June 1988. Georgi, D.T., Phillips, C., Hardman, R., Applications of digital core image analysis to thin-bed evaluation. 1992 SCA conference paper no. 9206. Nicholls, C.I., Heaviside, J., Gamma ray absorption techniques improve analysis of core displacement tests. SPE 14421 Sept. '85. Oord, R.J. van den, Evaluation of contractor measurements of total gamma ray activity as well as of potassium, thorium, and uranium in cores and logs. KSEPL report RKMR.89.019., RKRS.89.08.

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APPENDIX 3 Petrophysical data from geological analysis Detailed geological information is obtainable from core material as discussed in section 4.2.2 and is fully discussed in the companion manual "Geological Core Analysis", EP 93-2300. The main purposes of geological core analysis are to characterise and to enhance the geological model of the reservoir. However, geological information is also important for many aspects of core analysis particularly through core screening and in the application of core analysis data in quantifying the geological model. Petrophysical data from geological analysis is focused on two aspects: •

petrography - petrographic information is used to relate core analysis data to rock type;

•

mineralogy - the compositional analysis can be important in the interpretation of core analysis data. Mineralogy is recommended for all samples used in special core analysis as described in section 4.7.

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A3.1 Microstructure/Petrography Geological information is used in the interpretation of petrophysical and reservoir engineering parameters obtained from dedicated core analysis techniques and can provide a check on the validity and representativeness of core plugs. The majority of techniques used to determine geological parameters from core material are carried out separately from the analysis for petrophysical and reservoir engineering data, but some can be used to investigate rock-pore characteristics and porosity. Petrography, the microscopic visualisation, description and classification of rocks and minerals, is particularly important in core analysis. There are two scales of examination of rock samples from a microscopic viewpoint, namely scanning electron microscopy and thin sections. Scanning electron microscopy is used on the grain scale to identify possible microscopic effects on core analysis. Thin sections are usually made by preparing thin slices of core material which can be dyed to highlight the makeup of the rock such as key minerals and pore space. Thin sections can also be prepared under stress which is important for unconsolidated rock samples.

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A3.1.1 Petrography from Scanning Electron Microscopy (SEM) and Enhanced Image Analysis (IA) In Scanning Electron Microscopy, images are formed by scanning the surface of a rock sample with a focused electron beam. The various detection modes allow different images to be generated from the same area each with different analytical properties. The rock samples can be pieces of core, sidewall samples or even cuttings. Note that in the case of cuttings, depth matching can be problematic. The combination of SEM with EDX (Energy dispersive X-ray analysis) allows determination of elemental composition, leading to detailed characterisation of lithology/mineralogy. •

Secondary electron (SE) mode:

This is the most established application of the SEM. The SE-mode can show surface structure up to nm-scale. At KSEPL, SE-mode is primarily used to observe clay morphology and distribution in the pore space. Figure A3.1 shows an example of an SE image. •

Backscattered electron (BSE) mode:

In this mode, flat, polished samples produce images in which the contrast is related to atomic number. On reservoir rock samples, pore space (containing epoxy) appears as dark regions, quartz and calcite/dolomite as grey and heavy minerals as white. It is this mode which is used for estimation of porosity, permeability and formation factor, next to an indication of capillary behaviour based on network modelling. Estimations of porosity, permeability and formation resistivity factor are obtained by regression based on correlations with plug measured values on sandstone samples. Table A3.1 below shows the statistical properties of the data set used for this estimation on regressions derived from image analysis on a number of thin section samples.

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Figure A3.2 presents the results of BSE analysis on an image. With respect to the estimation of capillary behaviour based on IA data the procedure is as follows: Firstly, the microstructural information obtained from the samples is compared with microstructural information from the reference (in-house) data set for which mercury/air capillary pressure curves have been measured. Secondly, if samples with sufficient resemblance are found, simulated capillary pressure curves are generated (by network modelling) for both the sample data and reference data and compared. Thirdly, this is fitted against the measured mercury/air capillary pressure curves resulting in an estimated capillary pressure curve for the sample data. •

Cathodoluminescence mode (CL):

Again, polished samples are used. In this mode visible light, induced by the electrons, is detected by a photo-multiplier. In addition to imaging in BSE mode, CL enables different generations of a particular authigenic mineral to be distinguished. For example in sandstones, CL allows determination of the phases and proportion of quartz overgrowth, and visualisation of deformation features like healed cracks. The combination of BSE/CL and image analysis enables quantification of these features, providing valuable information for the reconstruction of diagenetic and structural processes impacting reservoir quality. Figure A3.3 shows such a CL image next to the BSE image from the same place on the sample. •

Energy dispersive X-ray analysis (EDX)

Where the SEM enables surface structure and atomic density distribution to be examined, the EDX allows elemental composition to be determined and the distribution of elements to be visualised. The X-ray photons, induced by electrons, are analysed in terms of energy. As each element has its own specific energy bands, elements can be recognised from their energy spectrum. A spectrum with associated quantitative analysis is presented in Figure A3.4. The ease of operation of the system makes it of interest for Opcos with specific problems where SEM/EDX might help reducing uncertainty in reservoir evaluations. The SEM service is available from RR/36.

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Points • SEM/IA can provide the most help in those cases where additional microstructural evaluation might reduce uncertainty in the context of other evaluation techniques, e.g. log evaluation, core description. SEM/IA is most effective if the expertise at KSEPL is combined with the expertise of the problem owner. Interaction between problem owner and KSEPL staff can reduce analysis time substantially and therefore cuts costs. • SE analysis is qualitative in nature. Samples for SE analysis can have a minimum size of 3 x 3 x 3 mm. Sidewall samples and cuttings can be used. Sample preparation takes place at KSEPL. • BSE analysis requires larger sample size, preferably offcuts from plug samples. BSE analysis allows quantitative assessment of porosity, permeability, formation factor and mineralogy. Sample preparation takes place at KSEPL. • SEM/SE/BSE analysis, thin section analysis and coreslab analysis are available at KSEPL and these services are regarded as standard. • Results of the analyses are presented in EXCEL format data files and images in standardised TIFF, which are PC-compatible. • Because of the formalisation of the analyses and the ease of operation of equipment, Opco staff can carry out the analyses themselves to gain maximum benefit.

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A3.1.2 Petrographic image analysis from thin sections Principle The procedures as developed for SEM/BSE analysis on impregnated, polished rock samples were extended to the analysis of thin sections. Instead of the SEM, a high resolution colour camera attached to a petrographic microscope provides the images for this analysis. In thin sections, pore space, clays/cements and grains can be recognised by their colour. For instance, porosity can be recognised by blue dyed epoxy, filling the pore space. The procedure to estimate porosity and permeability is based on correlation with IA parameters obtained from the pore space, clays and grains seen in the images. Next to porosity and permeability, clay content and 2D grain parameters (diameter, sorting, roundness, angularity) can be obtained as well. Note that this analysis is available for sandstones only; quantitative analysis of carbonate samples is currently under investigation. Figures A3.5 and A3.6 show an example of a digitised colour image and its processed counterpart ready for analysis. The thin section service is available from RR/36. Points • This analysis can be carried out by Core Laboratories, which claim to determine petrophysical indices of porosity, permeability, capillary pressures and formation factor from core material, sidewall samples, and drill cuttings, based in independently obtained correlations.

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A3.2 Mineralogy Compositional studies identify and quantify the minerals within the rock sample and are used in conjunction with petrographic studies. There are a number of ways of accomplishing mineral identification: •

X-ray diffraction;

•

from EDX associated with SEM;

•

'Mineralog' from Core Laboratories.

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A3.2.1 X-ray diffraction Principle The X-ray diffraction (XRD) pattern obtained when a powered sample is irradiated with X-rays is specific to the minerals present. The relative abundance of these minerals is determined in a semi-quantitative way from the heights and the widths of peaks in the measured 'diffractogram'. Points • XRD is the recommended technique for mineralogical quantification. • Interpretation of diffractograms can be subjective. • Submitting samples to a second laboratory is recommended occasionally. • It is recommended to submit reference samples to check the accuracy of XRD measurements. • SEM/EDX/IMP methods should also be used to assist in determining mineralogical distribution.

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A3.2.2 Energy Dispersive X-ray analysis (EDX) Principle X-rays emitted by a rock sample in response to bombardment by an electron beam have wavelengths that are characteristic of the constituent elements in the sample. The EDX system at KSEPL can be used to detect the X-ray energy distribution and thus determine the mineralogy. Only elements with an atomic weight above 11 will be detected and if a sample with an irregular surface is used the measurement will be only qualitative. Points • This is an acceptable technique. • SEM/EDX has the advantage that mineral morphology can be examined in the SEM image. • XRD numbers assist in the quantification of mineralogy from SEM.

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A3.2.3 Mineralog Principle Infrared spectroscopic techniques are used to identify common sandstone and carbonate minerals in core, sidewall, and drill cutting samples. Points • Mineralog is an acceptable technique but should be calibrated especially in new exploration areas. • The Perkin - Elmer Fourier Transform I.R. Spectrophotometer (Model 1720X) is in use at Core Laboratories facility in Aberdeen. • Because Mineralog is reasonably inexpensive, it can provide a depth plot of mineralogy by measuring samples on a foot by foot basis. An estimate of grain density for log calibration is provided. • The accuracy of Mineralog has been checked against calibrated samples. The results of this survey showed that the weight per cent values of the total clay and the other minerals which can be individually measured by Mineralog were accurate to within 5 wt%, as advertised. However, two problems were found with the Mineralog analysis. Firstly, it was found to be poor at identifying clay minerals in the test samples. Secondly, the detection limits for chlorite, illite, K-feldspar and pyrite were found to be larger than 5%. • Care must be taken when identifying pyrite and certain clay minerals. Comparison with XRD methods is recommended. • Mineralog can be used for applications where the identification of individual clay minerals is not critical and where the detection limits and quoted accuracy of the analysis are acceptable.

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A3.3 Literature Fens, T.W., The scanning electron microscopy / X-ray analysis facility at KSEPL. Review of principles and applications. KSEPL report, RKGR.88.013. Harville D.G. and Freeman, D.L., The Benefits and Application of Rapid Mineral Analysis Provided by Fourier Transform Infra red Spectroscopy. SPE 18120 paper presented at the 63rd Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Houston, Tx, October 1988.

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APPENDIX 4 Core analysis on small cores, sidewall samples and cuttings Continuous slim hole core analysis, coupled with slim hole drilling technology, provides significant value for hydrocarbon evaluation, reserves and well productivity. Large amounts of core are produced at slim hole wells, using wireline retrieval techniques. This requires a re-thinking of the core evaluation strategies used in the past. It is sometimes impractical and undesirable to transport large amounts of core to a laboratory for analysis. It is better to analyse the core in the field while it is still fresh, saving core transportation costs and allowing rapid decisions to be made, based on core data. Although full diameter conventional coring is a valuable process, it does have uncertainties such as precisely identifying the coring point. For example, even during in-field drilling, many promising intervals are missed because of unanticipated changes in stratigraphy. Once an interval has been bypassed, however, sidewall coring devices are available for retrieval of samples. Useful information for the evaluation of wells drilled by the rotary system can be obtained from the analysis of cuttings removed from the mudstream. Normally, cuttings are removed from the mudstream in order to maintain good mud-properties and hole-conditions.

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A4.1 Small core samples from slim holes The methods used to evaluate slim hole wells and the resultant slim hole cores are essentially similar to those used to evaluate conventional cores. Variations in the methods of evaluation are due to smaller hole size and core size obtained from the slim hole approach. In general, the evaluation of a specific section drilled using slim hole techniques may be marginally inferior, because of the small hole and core size, to that from an equivalent section cored in a larger diameter well. However the acquisition of continuous core from the slim hole well provides for a more complete overall evaluation of the section drilled when compared with a conventional well with only spot cores. Core sizes obtained from slim hole coring range from 17/8" to 3 11/32". Cores with diameters of 13/4" and 25/8" are standard in slim hole coring. Because of the large quantities of core a realistic evaluation of the well must be achieved without unnecessary detail being produced. Detailed work can be carried out at the laboratory on the core when the main zones of interest have been identified.

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A4.1.1 Analysis of a 13/4" diameter core This size core can pose particular problems for special core analysis. Plugs with a diameter of 1" (2.54 cm) and a length of 11/4" (3.2 cm) are usually cut for all analyses. Points • Vertical plugs will not be at the same depth as horizontal plugs; matching horizontal to vertical properties may therefore be difficult. • In the case of high angle bedding it may be that the quality of the plug samples are such that they cannot be used in fluid flow analysis tests. • Smaller sample size increases the uncertainties in many core analysis techniques where accurate pore volume is required. • The higher possibility of invasion from drilling fluid on smaller diameter cores may impact results from analyses such as Dean-Stark. • 1" (2.54 cm) diameter plugs that are shorter than an inch (2.5 cm) will in general require fabrication of special test measurement cells. • Probe permeametry measurements (see section 6.2.2) offer a facility for semi-quantitative permeability measurement and reservoir definition. Results should be calibrated against several plug measurements.

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A4.1.2 Analysis of a 25/8" diameter core Normal routine analysis can be carried out on 25/8" cores. Horizontal and vertical plugs with diameter 1" (2.54 cm) and length 11/2" (3.8 cm), for use in routine analysis techniques, can be taken before slabbing using the conventional methods. Points • Basic analysis is not difficult on this size core. Special core analysis may prove difficult if long core plugs are required. • Vertical plugs will not be at the same depth as the horizontal plugs; matching horizontal to vertical properties may therefore be difficult. • Trim ends can be used for further analysis, i.e. in CEC, SEM/XRD. • Due to the higher possibility of invasion from drilling fluid, the value of Dean-Stark analysis to determine water or oil saturation may be reduced. • The normal procedures can be used to determine porosity, grain density, and permeability. • Full diameter core analysis can be performed, for example on 3" long whole core pieces at one foot intervals. Most test work, including special core analysis, should be possible on whole core samples. This may require fabrication of a suitable whole core cell. • Current procedures for slabbing involve cutting the whole core sections into two equal sections, where one section is encased in resin. • A probe permeameter can be used to determine a pseudo-permeability profile on either whole core or slabbed core.

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A4.1.3 Further slim hole core analysis The upsurge in slim hole, continuous coring within the oil industry spurred core analysis contractors to develop onsite quantitative analysis capability to process large amounts of core in near-real-time. This ruggedized, mobile core characterisation modules are configured to "Continuous Core Logging". This is a production-line analysis at the well-site where whole core sections are placed on a conveyor belt and undergo consecutive video imaging, GR measurements, UV photography, NMR, and seismic velocity measurement. Properties such as grain density, porosity, fluid saturations are measured routinely at the well site. This system of analysis for petrophysical information is being developed by a number of contractors and the acquisition/evaluation of such data is still a subject of research.

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A4.2 Sidewall samples Sidewall samples are small cores drilled, or recovered from projectiles fired into the wall of the drill hole. Sidewall samples can be extremely useful in geological and petrophysical interpretation to determine specific rock properties, but offer less information than conventional cores due to the restricted sample size, possible sample damage and uncertain depth registration. They can also be used by production engineering to evaluate production effects at the well bore such as scale buildup and acid treatment effects. Sidewall samples are valuable for many applications, but cannot replace conventional coring. Conventional coring provides a continuous rock sample. Sidewall samples represent individual locations. It is often difficult to determine exact depth of origin or obtain representative samples of the dominant lithologies in the reservoir. The biggest advantage of sidewall samples over conventional core is the ability to obtain samples from an interval after drilling through it.

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A4.2.1 Rotary drilled samples Wireline rotary coring tools are generally designed to retrieve up to 30 plugs with 15/16" (2.4 cm) diameter. The tool consists of a downhole motor and a coring bit on a retractable arm, and a storage tube for the cored material. With the aid of the rotary coring tool, selective core plugs can be taken from intervals of interest to aid in the interpretation of petrophysical, geological, and production characteristics. Points • This technique is recommended over percussion sidewall samples. • The plug diameters are limited and a bit smaller than the standard one inch which can make analysis problematic. • Usable in hard formations. • Rotary drilled samples can be more economical than conventional coring. • Poor hole conditions result in poor sample recovery.

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A4.2.2 Percussion sidewall samples Sidewall samples can also be obtained by sampling the formation by explosively driving a cylinder into the formation. These are called percussion sidewall samples and are often severely damaged in the plug acquisition process. Only those petrophysical evaluation techniques which can be performed using crushed material yield reliable results. The samples are useful for biostratigraphic dating but petrographic study is difficult as a result of the extensive microfracturing or shattered nature of the material, which sometimes occurs with percussion sidewall samples. Points • Not recommended for hard formations • The sample is often too small for analytical purposes using standard core holders. • The impact can severely alter the physical properties of the sample.

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A4.2.3 Sidewall sample measurement techniques Suitable sidewall samples can be analysed at KSEPL using techniques similar to those used for conventional core analysis. The following parameters can be obtained: • Grain density on crushed material • Cation exchange capacity (CEC) • Element analysis by X-Ray diffraction (using crushed material) • Dominant grain size • Porosity • Permeability • Capillary pressure curve (mercury/air by Autopore 9220) Points • Routine measurements can be carried out quickly and easily; most of the basic methods used can be performed at the wellsite. • The dominant grain size is estimated using thin section microscopy. The combination of this grain size with the sorting can provide a qualitative estimate of permeability for nonargillaceous clastics. • Porosity, permeability, and capillary pressure measurements require that the samples be undisturbed. Drilled sidewall cores are preferred, for both consolidated and unconsolidated sandstone formations, over those taken with a bullet percussion type core sampling tool. Such plugs rarely yield true in-situ values; hard formations tend to yield porosity and permeability values which are too high due to fracturing and unconsolidated material may yield low values due to compaction. • Most petrophysical measurements are difficult or impossible due to poor sample geometry.

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A4.3 Cuttings A4.3.1 Collection/sampling Drill cuttings are washed up the well bore with the returning mud-flow and are collected by sampling the material from the shaker screens at predetermined intervals. Rock samples offer the most direct source of information available to geologists and petrophysicists, but drill cuttings tend to get neglected as such a source. The reasons for this neglect arise from difficulties involved in the depth control of the collected samples which limit the confidence placed in the subsequent interpretation. Also new drill bits, such as the PDC bit, produce very small cuttings that prohibit reasonable analysis. Cuttings analysis should not be seen as an alternative to coring, since rock material may be substantially altered by the drilling process. Points • The sampling intervals are determined by calculating the uphole time of the mud returns from each drilled depth using parameters such as pump rate, volume per stroke, hole volume, etc. The uphole time must be corrected for the lag time for cuttings drilled at each depth relative to the mud returns from that same depth. Depth matching the samples to their stratigraphic position is complicated by variations in this sample lag time. • Simultaneously generated cuttings will arrive at the surface at different times due to the differential velocity of various sizes and shapes of cuttings within the mud. • A mix of cuttings from various depths can be generated due to well bore cave-ins. • Fine cuttings, which are difficult to remove at surface, re-enter the wellbore and are recirculated. • Care should be taken to ensure that cuttings are collected systematically. Biased sample sets can be generated if this is not done.

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Points (continued) • Cuttings collection can be automated and SIPM has had experience with the ACS-200 system of Core Laboratories. For each metre of rock drilled, roughly 10 cm of cuttings are collected. The quantity of samples can be varied by changing the equipment pump rate and altering the proportion of the return mud being sampled. This equipment has been designed to perform the following functions: - Continuously sample the entire drilling interval. - Preserve the complete sequence of cuttings both for on-site evaluation and for future laboratory tests. - Collect the samples before the solids control equipment so that the mixing of the cuttings that occurs within the shale shaker is avoided. - Preserve cuttings in the range 44 µm- 5 mm. - Work with all types of mud, including viscous muds or those with high gel strengths. • In preliminary trials at NAM Beerta-1 exploration well, the pseudo gamma ray log measured on size-fractionated samples showed excellent agreement with wire line logs across much of the reservoir. • Initial results suggest that cuttings with sizes less than 125 µm travel to the surface at the same speed as the drilling mud. Proper collection and analysis of these small size samples will reduce the detrimental effect of sample lag time, the spread of cuttings, and the recirculated solids.

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A4.3.2 Measurement techniques used in cuttings analysis Petrophysical properties can be measured on drill cuttings as long as the cuttings are reasonably large (greater than 25mg). Points • The recommended technique for porosity and permeability is by capillary pressure determination using an Autopore 9200/9220 using a special small penetrometers shown in Figure A4.1. Porosity is determined from the closure corrected capillary pressure curve and the permeability is determined by correlation. BTC has this capability. • Although permeability/porosity from cuttings is technically feasible if the chips are large enough, the results will only be representative if the chips originate from a fairly thick, homogeneous and well consolidated formation. • Cuttings have a tendency to sample the lower porosity parts (i.e. tighter rock) of the formation. • A useful permeability estimate can be obtained from small fragments, particularly when a number of particles from a specific interval are examined. • When cuttings from unconsolidated samples are sieved, cuttings that are suitable for porosity/permeability measurements may be obtained, but the representativeness of these samples is questionable and should not be used to characterise the formation as a whole. • Drill cuttings can be used in analyses that do not require intact samples such as CEC, grain density, XRD. • With SEM, detailed information can be obtained on the pore and matrix structure with the sample. Good qualitative information is also obtained on the mineralogical composition and the clay type and distribution. • For well-site hydrocarbon differentiation on cuttings, the reader is referred to the manual "Well site Hydrocarbon Differentiation using High Performance Liquid Chromatography" by K.H. van der Gijp and R.J. van den Oord, EP 93-0550.

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A4.4 Literature Adams, S., Nicholson, P., The 'automated cuttings sampler’ Production newsletter, May 1992. Baaren, J.P. van, Clastic reservoir rocks. Permeability estimates from side wall samples and cuttings. KSEPL report RKGR. 0002.75. Bush, D.C., Freeman, D.L., Drill cuttings porosity, grain density and permeability by direct laboratory measurements and their reliability. SPWLA 27th Annual Logging Symposium, June 9-13, 1986. Georgi, D.T., Harville. D.G., Robertson, H.A., Advances in cuttings collection and analysis. SPWLA 34th annual Logging Symposium, June 13-16, 1993. Gijp, K.H. van der, Oord, R.J. van den, Wellsite hydrocarbon differentiation using high performance liquid chromatography (HPLC). EP 93-0550, May 1993. Prins; M., Reservoir rock characteristics from drill cuttings and sidewall samples. EP 90-2108, April 1990.

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APPENDIX 5 Sponge core analysis Sponge coring is a modification of the conventional coring technique. In sponge coring, a sponge lining in the inner core barrel is used to catch any fluid that is expelled from the core when it is brought to surface. Although the amount of fluid in the sponge may be small in such cases, it may still contribute to a couple of saturation percent difference and should be determined with sufficient precision. There are two types of sponge analysis: •

oil-wet sponge analysis for determining oil saturation;

•

water-wet sponge analysis for determining water saturation.

In oil-wet sponge analysis, as the pore pressure drops below the oil's bubble point, gas bubbles evolve and expand. These bubbles can displace otherwise immobile oil. By adding the amount of oil captured in the sponge to the amount left in the core, one obtains more representative values of oil saturation. Sponge coring finds its main application in in-situ Sor determination in flooded reservoirs. The sponge is saturated with brine prior to going into the well. If the objective is to capture any water escaping the core as it is brought to the surface a waterwet sponge sleeve is used. The water wet-sponge is saturated with dry mineral oil prior to coring.

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A5.1 Oil-Wet sponge analysis A5.1.1 Sponge analysis by gas chromatography PrincipIe Oil is extracted from the sponge by standard extraction technique (see section 6.3). The amount of oil in the extraction fluid is measured by using gas chromatography. The system is calibrated on a selected number of peaks, e.g. the series of normal alkanes C10 -C19, using known solutions of the field crude in the extraction fluid (toluene). Components that are dissolved in the extraction fluid also yield chromatographic peaks, but these do not coincide with any peak of the normal alkanes selected. Points • The technique is acceptable. • The sum of peak areas for a selected range of compounds C10 -C19 correlate excellently with the concentration of (dead) crude in solution. Thus determination does not require full spectrum of hydrocarbon components. • The volume expansion factor, B0 of the oil must be known to convert the volume of determined oil to in-situ live oil. • The method is insensitive to the presence of solids in the sponge. • Any extraction fluid which does not dissolve sponge can be used. Suitable solvents generally require careful handling because of flammability, toxicity and environmental sensitivity.

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A5.1.2 Other oil-wet sponge analysis techniques Principle The sponge is cut into 1 foot (30 cm) lengths and extracted with a suitable solvent such as Freon11 or tetrachloroethylene. Various techniques can be used to determine oil volume. Points • These are acceptable techniques. • When Freon-11 is used, oil removed is determined gravimetrically by allowing freon to evaporate. Many countries prohibit or severely restrict the use of freon. In the US, freon is not allowed to be vented to atmosphere so that a freon collection system must be used. • Proton NMR spectroscopy can be used to determine the amount of oil when an aprotic solvent (a solvent without protons) is used. • Instead of NMR spectroscopy, visible spectrometry, UV fluorescence spectrometry or IR spectroscopy can be used.

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A5.2 Water-wet sponge analysis Water-wet sponge analysis can be done by Dean-Stark extraction using toluene to determine water volume. Points • Water-wet sponge is very hygroscopic and care must be taken to prevent absorption of moisture from the atmosphere. • This technique is used with oil-based mud for the determination of initial water saturation. • The sponge is saturated with mineral oil initially.

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A5.3 Literature Looyestijn, W.J., Schipper, B.A., Determination of oil saturations in sponge coring by gas chromatography. 1993 SCA Conference paper no. 9305. DiFoggio, R. ,Calkin, C.L., Ellington, W.E. and Setser, G.G., Improved method for extraction and quantification of hydrocarbon content of sponge core liners. 1990 SCA Conference paper no. 9019. Vinegar, H.J. and Tutunjian, P.N., Analytical Methods and Apparatus for measuring the oil content of sponge core. US patent number 4,866,983, September 19, 1989

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Appendix 6 Conversion from hydrostatic to uniaxial strain conditions Petrophysical properties such as stressed porosity, stressed permeability, formation resistivity factor, and resistivity-index measurements are usually measured in a cell where hydrostatic stress is applied, i.e. horizontal and vertical stress are the same. In the reservoir, the horizontal stress is different from (and generally lower than) the vertical stress. During depletion, the horizontal stress changes such that no radial deformation occurs during the vertical compaction process. This is called uniaxial strain. Hence, to obtain measurements that better represent reservoir conditions, hydrostatic laboratory measurements have to be converted to uniaxial strain reservoir conditions. This conversion can only be made if the following assumptions hold: • • • •

the rock should behave linearly elastic over the whole stress range of interest. the rock should be homogeneous and isotropic. the difference in stress regime should not cause a difference in pore shape deformation. grain compressibility can be ignored.

The important consideration in the conversion procedure is the stress regime. Suppose the total vertical (overburden) stress is sv. Rock deformation is governed by changes in the effective stress, which is the total stress minus the pore fluid pressure. During depletion, the vertical effective stress increases because the pore pressure decreases while the total overburden weight does not change. Before depletion, the initial vertical effective stress, Sv,e,i and the initial pore pressure, pi, are related as follows: Sv,e,i = sv - pi

(A6.1)

Default gradient values are: overburden fluid initial vertical effective stress

= 0.23 bar/meter = 0.10 bar/meter = 0.13 bar/meter.

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During depletion, the vertical effective stress after the reservoir pressure has dropped by ∆P is thus: sv,e = s v - P i + ∆P

(A6.2)

The horizontal stress in the reservoir will change during depletion such that the reservoir does not deform horizontally. According to linear poro-elasticity theory, the horizontal effective stress at uniaxial strain conditions, s h,e ,is related to the vertical effective stress, S v,e according to: s h,e = (n /(1-n ))s v,e

(A6.3)

where v = Poisson's ratio (which lies between 0 and 0.5 and for sandstones is generally between 0.1- 0.3). The mean effective stress, s e, a ve, acting on the reservoir is the average of the vertical and the two (perpendicular) horizontal effective stresses: s e, a ve = (sve +2she)/3 = (((1+n )/(1-n ))/3)s v,e

(A6.4)

Because strain is assumed to relate linearly to stress, it follows from equation (A6.4) that the uniaxial compressibility cm (measured in a laboratory experiment in which radial deformation is kept zero) is related to the hydrostatic (bulk) compressibility cb (measured in a laboratory experiment in which horizontal and vertical stresses are taken equal) according to: cm = (((1+n )/(1-n ))/3) cb

(A6.5)

where it has been assumed that the hydrostatic experiment is performed at a confining stress in which vertical and horizontal stresses are all equal to the vertical effective stress (while in a uniaxial experiment the horizontal effective stresses are lower than the vertical effective stress (eq. (A6.3)).

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From the above, procedures can be derived to convert petrophysical properties obtained from hydrostatic laboratory measurements to properties that would have been obtained under uniaxial strain conditions at equivalent reservoir stress conditions, provided that above-mentioned assumptions hold. Suppose lab measurements were performed at hydrostatic conditions over a certain hydrostatic stress regime. There are two methods to convert this measurement to true (uniaxial) strain reservoir conditions. •

Conversion of stress regime

The stress regime encountered during depletion (i.e. under uniaxial strain conditions) is given by (A6.2) and (A6.3) and the mean stress encountered by the reservoir is given by (A6.4), where the vertical effective stress increases from its initial value to the final value (at depletion) according to (A6.2). Hence, if the calculated isostatic stresses (corresponding to different values of ∆p) are actually given in the laboratory tables (or can be obtained from these by interpolation), no conversion is needed: the petrophysical parameters can be obtained from the laboratory tables under the hydrostatic stress values as calculated from (A6.4) and (A6.2). This is the most accurate procedure. It is also the only one that can be applied for properties other than porosity, like FRF, permeability, capillary pressure etc. •

Conversion of volumes

For porosity, equation (A6.5) can be used. Assuming negligible grain compressibility, both the bulk and the pore volume change as follows: under hydrostatic conditions: ∆V p = ∆V b = cb V b shydr

(A6.6)

where shydr = applied hydrostatic stress. under uniaxial conditions: ∆Vp = ∆Vb = cm Vb ∆P

(A6.7)

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Hence, using the appropriate values for ∆P, the hydrostatically measured pore and bulk volumes at hydrostatic stresses can be calculated back to uniaxial conditions, using eq. (A6.5). For instance, porosity at uniaxial conditions at the appropriate value of the vertical effective stress is equal to: ϕ = (Vp - a ∆Vp )/(Vb - a ∆Vp )

(A6.8)

where a =(((1+n )/(1-n ))/3). Such calculated values will normally be given in the laboratory tables. Equation (A6.8) can be applied to correct porosity measured hydrostatically to uniaxial strain conditions, provided that the hydrostatic stress at which the measurement was made is equal to the vertical effective stress for which the uniaxial strain calculation is desired.

Points •

The quartz grain compressibility is 2.6x10-6 bar-1, and if the bulk compressibility approaches this value (e.g. for low porosity (hard) rock), KSEPL should be consulted to apply a more complicated correction procedure, and/or to perform additional triaxial tests.

•

Standardly n = 0.3 is taken, leading to a = 0.62. However, for consolidated materials it is better to take values of n between 0.1 and 0.2, leading to values of a between 0.40 and 0.50. If no value of the Poisson ratio is known from other sources, performing the calculations for such a range will give an indication of the thus caused inaccuracy of the conversion.

•

If the above assumptions do not hold, it is much better to perform measurements in a triaxial cell, where different horizontal and vertical stresses can be applied.

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Index absorbed water 178 acetone 90 acid flood 263 acid permeameter 263 acid response curve 265 acid response test 263 acoustic properties 240 acoustic transmission anisotropy 271 additional core 28 aging 279 aging steps 184 air 87 air permeability 114 ammonium acetate 176 Amott 190, 192 Amott wettability index 190 Apparatus for Pore Examination (APEX) Archie equation 161 Archies lithologic exponent,m 5, 159 Archies saturation exponent, n 6,161 Archimedes Principle 110, 103 backscattered electron (BSE) 312 basic core analysis 55, 102 Bellaire Technology Center (BTC) BHN 234 bland mud 61 blank corrections 142 Bmax 175 bound water 141 Boyle's law 112, 126, 132 brine 87 brine analysis 258 brine composition 76, 258 brine permeability 127,260 brine measurements 76 brine resistivity 159, 165, 258

273

9

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brine-rock compatibility 76 Brinell Hardness Number 234 bringing core to surface 63 Buckley-Leverett 213 bulk volume 102,103, 104, 106 buoyancy 110 buoyancy in mercury 103 Calgary Research Center (CRC) 9,131 calibrating log 50 caliper 106 cap rock 253 capillary end effects 214 capillary pressure (on an endpiece) 73 capillary pressure 53, 138 capillary pressure curves 165 CAPRICI 193, 277 carbonates 44 cathodoluminescence mode 317 cation exchange capacity 87, 159, 170 CEC 163, 166, 171, 176, 178 cementation exponent 159, 163, 166 centrifuge capillary pressure curves 151 centrifuge core holders 207 centrifuge experiment 207 change in pore volume 125 chloroform/methanol 40,120 chloroform/methanol azeotrope 90 clay 159 clay bearing and shalf sands 43 clay bound water 154 clay conductivity 6, 174 clay minerals 170,260 clay-bound water 97, 149 clean (consolidated) sandstones 43 cleaned state 182 cleaned-state samples 183 cleaning unconsolidated samples 91 closure corrections 145

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Co-Cw 174 coal 45 commercial hydrocarbons 290 compatibility flood 260 compositional analysis 52 compressibility 125,223 computer simulation 24 conductometric titration 176 confining stress 127, 133 connate water saturation, Swc 202 contact angle 138, 193 continuous injection 165 contractor analysis laboratories 98 contractor laboratory 297 core analysis contractors 11 core analysis laboratory data 81 core analysis planning 2, 10, 32 core analysis programme 49, 50 core analysis programme focal point 50 core analysis project 291 core barrel considerations 62 core cleaning 86, 90 core description 36, 71 core drying 86,93 core freezing 75 core gamma ray 306 core gamma scan 65 core gamma scanner 6, 306 core handling 36,40, 64 core j amming 63 core plug drilling 86 core preparation 70,86 core preservation 37,41, 75 core sample preparation 37,40,70 core sample screening 41 core sample screening for special core analysis 37 core sampIing 67 core screening 37, 66 core screening techniques 301

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core water analysis 258 coreslab imaging 310 coring bits 61 coring considerations 61 coring methods 61 coring on by-pass 29 coring rate 39 costs 38, 79 counter current imbibition 254, 255 critical gas saturation 281 critical point drying 94 crude oil 184 CT scanner 6,302 CT images 72, 304 CT scanning 65,72,87,302 cubical sample 116 curved I-Sw relationship 163,165 cuttings 238, 338, 340 cyclohexane 90 Darcy's law 114 dead crude 184 dead oil 78 Dean-Stark 90, 120, 204 degree of heterogeneity 67 diatomite 45 digital report 82 drainage 162 drainage cycle 204, 207 drilling 1,36, 39 drilling engineering 54 drilling mud 61 dry weight 107 du Nouy balance 197 economic benefit 2, 79, 293 economics 13 EDX 314,315, 323 effective permeability 118, 129, 202

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effective porosity Ekofisk 22 electrical equilibrium 163 electrical properties 158 Empress 275 energy dispersive X-ray analysis 315, 323 ethylene chloride 90 evaporites 45 exploration 1 exploration appraisal 290 exploration functions 34 failure stress 239 fluid analyses 254 fluid flow 277 fluid handling considerations 37,41, 78 fluid measurements 37,41,76 fluid saturations 120 fluoroscopy, etc. 65. Forbes technique 151 Forchheimer equation 117 formation brine 158 formation evaluation 55 formation resistivity factor, FRF 159, 166 formation water 258 fractured reservoirs 44 free fluid index 285 freezing of core 75 fresh 87 fresh state 182, 187, 192 fresh-state samples 184 fresh-state samples 185 friable 142 gamma ray attenuation 66 gamma ray spectroscopy 66 gas analyses 256, gas chromatography 344 gas slippage 117, 128

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gas/liquid capillary pressure 154, 155, 156 gas/liquid relative permeability 211, 216 gel mud 185 geochemical analysis 52 geological analysis 312 geological core analysis plan 51 geological environment 6 geological input 51 geologist 39 geology 1, 34, 36, 51 geophysicists 54 grain density 6, 72, 108 grain size 247, 249, 250 grain size analysis 246 grain size distribution 249 grain size sorting parameters 245 grain volume 102, 110, 112, 143 graphical report 81 halites 90 Hassler type core holder 114, 132, 133 helium porosimeter 126, 132 hematite 61 heterogeneous core material 135 high quality core 64 high salinity brines 120 horizontal and vertical permeability 116 horizontal permeability 133 hot solvent extraction 90 HTP 275 hydrocarbon reserves 290 hydrocarbon saturation 13 hydrocarbon volume 13 hydrogen nuclei 284 hydrostatic 230 hydrostatic to uniaxial conversion 348 I-Sw 161, 165, 275 IA parameters 319

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image analysis 250,314 image report 82 imbibition 139, 162, 180, 181 imbibition cycle 182, 204, 207 imbibition tests 193 impairment 266 increase in permeability 260 infrared spectroscopic techniques 324 initial saturation 254 initial water saturation, Swi 40, 184,187, 192, 202, 213 injection pressure 165 integrated team 50 interfacial tension (1FT) 194, 138, 180, 194, 195, 199 invasion 229 justification 28, 42, 79 kerosene 87 Klinkenberg correction 117, 130 laboratory arrival 66 laminated formations 309 laser diffraction 247 laying the core down 63 liquid nitrogen 87 liquid saturation 107, 125 lithology 6, 43 live crude 184 live crude oil 78 log calibration 55 log interpretation models 50 longitudinal CT-scan 72 longitudinal relaxation rate 283 low permeability formations 43 m at stress 159 macroscopic description 52 maximum horizontal stress 271 mechanical rock properties 222

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membrane 277 membrane potential 171 mercury 103 mercury displacement 104 mercury/air 141,145, 147 microcracks 271 microscopic description 52 microstructure 313 mineralogy 72, 87, 312, 321, 324 mixed wettability 181 mobilisation of fines 49, 260 movable fluid 285 mud filtrate 61 multi-disciplinary 36, 50, 84 multiple salinity 174 naphtha 90 native-state 187, 219 natural gamma ray scan 66 NMR 283 NPV 15 NPVi 15 objectives 36 oedometer 231 oil 6 oil analyses 256 oil measurements 77 oil properties 77 oil relative permeability, kro 202 oil sample collection 256 oil samples 78 oil-wet 181 oil-wet membrane 277 oil-wet sponge analysis 340 oil/water capillary pressure 149, 150, 152 oil/water interface 181 oil/water relative permeability 213 old core 36

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overbalance control 62 P(high) 15 P(low) 15 P(medium) 15 packing corrections 145 parameter estimation 151 particle size 247 PDC bit 335 PE team, 84 pendant drop apparatus 195 percussion 333 peripheral measurements 4, 10 permeability 6, 72 284 permeability anisotropy 115, 116 permeability reduction 266 permeameter 133 petrographic image analysis 319 petrography 312, 313, 314 petrophysics 1, 34, 36, 39, 50 photography 36 planning 34 plug drilling 70, 87 pIug Iocations 70 plug photography 72 POCM 15 points 3 poor quality core 67 pore body 273 pore throat 273 pore volume 10, 107, 126, 138, 163 pore-scale 271 pore-size distribution 284 porosimetry 112 porosity 1, 6, 72, 103, 284 porous plate 168 porous plate vessel 156 POS 15

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precision 4 preserved-state 187 preserved-state samples 186 pressure coring 186 pressure equilibrium 163 price 4 primary 204 primary drainage 139,188 principle 3 probability of success 292 probe permeameter 66, 118, 329 problems 6 production 1 production engineering 24 production technology 5, 34, 54 project optimisation 14, 17, 24, 293 project reporting 38, 80 project review 38,83 prospect screening 14, 16, 20, 290 pulse decay permeameter 129 pulse decay technique 130 PVT properties 77 pycnometer 108 quali ty 46 Qv 159,163,166,170,174 Qve 171, 176 rapid desaturation 169 rates of penetration 62 raw data 80 receipt of core 65 relative humidity 178 relative permeability 54, 193,202, 204,207 relative permeability at reservoir conditions 219, representative data 69 representative plugs 68 reservoir conditions 1, 275, 277 reservoir engineering 1, 34, 36, 39, 53

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reservoir simulation 25, 53 residual oil saturation, Sor 202, 213, 285 residual saturation 254 resin stabilisation 75 resistance across the sample 165 resistivity index 13, 161, 163, 165, 168, 169 resistivity logs 158, 161 resistivity of a sample 161 restoration 183 restored state 182, 192, 219, retort method 122 review measurements 84 rock analyses 245 rock characteristics 269 rock composition 6 rock fabric 61 rock fluid compatibility 260 rock homogeneity 234 rock strength 232,233 rock type 6, 52, 68,69 rotary drilled samples 332 rotary speed 62 sample cleaning 92 sample heterogeneity 71 sample screening 10, 71 sample selection 67, 68 sampling considerations 69 sampling rate 55 saturation profiles 205 saturation-height functions 138 scanning 36 scanning electron microscopy (SEM) 314 scanning electron microscopy 6, 314 scheduling 79 scope 36, 49 screen capped teflon method (SCTM) 91 seal analysis 253 secondary drainage 139, 187, 188, 204

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secondary imbibition 139 selecting Core Analysis Laboratory 298 selecting samples 68 sensitivity analyses 53 sequencing 79 sequencing and scheduling 38,41,79 shale 45 shaly samples 158 shaly sands, 43 sidewall sampIes 326, 331 sieve analysis 249 significant figures 81 slabbing 36 slim hole core analysis 327, 330 solvent flushing 266 sorting coefficients 245 source rock analysis 251 special core analysis 58, 82 spinning drop tensiometer 199 sponge analysis 341, 343 sponge core analysis 58,340,341, 342 steady-state 204 steady-state gas permeability 114, 133 steady-state permeability 127 stressed permeability 124, 127 stressed pore volume 126,147 stressed porosity 124, 125, 159 summation of fluids 122 surface tension (IFT) 194, 197 Swi 40 synthetic formation brine 158 tabular report 80 tetrahydrofuran 40,90 thick-waIled-cylinder strength test 234 thin section samples 314 thin sections 6, 71, 87, 319 thin sections 71, 143 thin-bed features 308

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Thomas salinities 171 three phase relative permeability 1 toluene 90, 120 tomogram 301 topogram 301 total porosity 97 transverse relaxation rate 283 triaxial loading apparatus 271 trichloroethylene 90 turbulence correction 117 turbulence effects 128 ultrasonic P-wave velocity 271 ultrasonic velocity cell 269 unconfined compressive strength test 239 unconsolidated samples 142 unconsolidated sandstones 20, 43 uniaxial compaction 224 United States Bureau of Mines method (USBM) 192 unsteady state displacement 213, 216 USBM 189, 190, 192 Value of Appraisal (VOA) 14,292 Value of Information (VOl) 13, 14,289 vertical permeability 133 viscous fingering 207 VOl examples 19 vuggy carbonates 43 vuggy sample 104 water 6, 87 water based mud 185 water relative permeability, krw 202 water samples 76 water saturation, Sw 261 water-wet 277 water-wet conditions 187 water-wet sponge analysis 340 wax removal 266

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Waxman-Smits 6, 159,162, 170, 174 weight on bit 62 Welge method 213 well-site planning 36,64 well site handling 64 wettability 138, 180, 181, 286 wettability definition 181 wettability determination 189 whole core analysis 131 whole core permeability 133 whole core porosity 132 whole core samples 70 whole core sections 87 X-ray attenuation 205, 302 X-ray fluoroscopy 6, 309, 322 XRD 322 xylene 90, 120

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