Petroleum Society Monograph 1- Determination of Oil and Gas Reserves

Determination of Oil and Gas Reserves Petroleum Society Monograph No.1

THE PETROLEUM SOCIETY OF THE CANADIAN INSTITUTE OF MINING, METALLURGY AND PETROLEUM

Determination of Oil and Gas Reserves Petroleum Society Monograph No.1

© 1994 by The Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum, Calgary Section. All rights reserved. First edition published 1994. Printed in Canada. 10 9 8 7 6 5 4 3 2 Permission is granted for individuals to make single copies for their personal use in research, study, or teaching and to use figures, tables and short quotes from this monograph for republication in scientific books and journals. There is no charge for any of these uses. The publisher requests that the source be cited appropriately.

Canadian Cataloguing in Publication Data Main entry under title: Determination of oil and gas reserves.

(Petroleum Society monograph; no. I) Includes bibliographical references and index. ISBN 0-9697990-0-4 I. Petroleum reserves. I. Petroleum Society of CIM. II. Series. TN871.D47 1994 622'.1828 C94-910092-7

Edited by Virginia MacKay. Cover design by Guy Parsons. Typesetting and graphic design by lA. (Sandy) Irvine, By Design Services. Printed and bound in Canada by D.W. Friesen Ltd., Altona, ME.

CONTENTS

Figures

xiv

Tables

xvii

Foreword

xix

Preface

xxi

Acknowledgements Authors

xxiii .'

xxiv

PART ONE: DEFINITIONS AND GUIDELINES FOR CLASSIFICATION OF OIL AND GAS RESERVES 1.

OVERVIEW OF PART ONE

3

2.

DEFINITIONS 2.1 Introduction 2.2 Resources 2.2.1 Discovered Resources or Initial Volumes in Place 2.2.2 Undiscovered Resources or Future Initial Volumes in Place 2.3 Remaining Reserves 2.3.1 Remaining Proved Reserves 2.3.2 Probable Reserves 2.3.3 Possible Reserves 2.3.4 Development and Production Status 2.4 Cumulative Production 2.4.1 Sales 2.4.2 Inventory 2.5 Reserves Ownership 2.6 Specified Economic Conditions 2.7 Reporting of Reserves Estimates 2.7.1 Risk-Weighting of Reserves Estimates 2.7.2 Aggregation of Reserves Estimates 2.7.3 Barrels of Oil Equivalent

4 4 4 5 5 5 5 5 5 6 7 7 7 7 8 8 8 8 9

3.

GUIDELINES FOR ESTIMATION OF OIL AND GAS RESERVES 3.1 Introduction 3.2 Methods ofCaiculating Reserves 3.2.1 Deterministic Procedure 3.2.2 Probabilistic Procedure 3.3 Guidelines for Specific Methods 3.3.1 Volumetric Method 3.3.2 Material Balance Method 3.3.3 Decline Curve Analysis 3.3.4 Reservoir Simulation Method 3.3.5 Reserves from Improved Recovery Projects 3.3.6 Related Products

10 10 10 10 II 12 12 17 18 22 22 22 v

PART TWO: DETERMINATION OF IN-PLACE RESOURCES 4.

5.

vi

OVERVIEWOF PART TWO 4.1 Introduction 4.2 Resource Estimates 4.2.1 Volumetric Estimates 4.2.2 Material Balance Estimates 4.3 Procedures for EstimatingIn-Place Resources 4.4 Sources and Reliability of Data 4.5 Interrelationship of Parameters 4.6 Uses of Resource Estimates 4.7 Backgroundand Experience of Evaluators ESTIMATION OF VOLUMES OF HYDROCARBONS IN PLACE 5.1 Reservoir Area and Volume 5.1.1 Introduction 5.1.2 Acquisition of Data 5.1.3 Data Analysis 5.1.4 Mapping 5.1.5 Refinementof Volumetric Estimates 5.2 Thickness 5.2.1 Introduction 5.2.2 Defining Net Pay 5.2.3 Data Acquisition Programs 5.2.4 Data Interpretation 5.2.5 Factors Affecting Data Quality 5.3 Permeability 5.3.1 Introduction 5.3.2 Permeabilityfrom Core 5.3.3 Relative Permeability Measurement 5.4 Porosity 5.4.1 Introduction 5.4.2 Sources and Acquisition of Data 5.4.3 Analysis of Data 5.4.4 Factors Affecting Data Quality 5.5 Hydrocarbon Saturation 5.5.1 Introduction 5.5.2 Saturation Determination From Core 5.5.3 Saturation Determination From Logs 5.5.4 Flow Test Procedures for Gas and Oil Saturation 5.5.5 Factors Affecting Data Quality 5.6 Testing and Sampling 5.6.1 Introduction 5.6.2 DrillstemTests 5.6.3 Production Tests 5.6.4 Sampling 5.7 Reservoir Temperature 5.7.1 Introduction 5.7.2 Data Sources 5.7.3 Data Analysis 5.7.4 Data Analysis on a Regional Basis

27 27 27

27 30 30 31 31 31 34 35 35 35 35 36 38 43 44 44 45 46 48 49 53 53 53 54 55 55 55 58 63 65 65 65 69 70 72

75 75 75 75 77 81 81 81 82 82

5.8

5.9

5.10

5.11

5.7.5 Data Quality Reservoir Pressure 5.8.1 Introduction 5.8.2 Data Sources 5.8.3 Data Analysis Gas Formation Volume Factor 5.9.1 Introduction 5.9.2 Ideal Gas Law 5.9.3 Gas Compressibility Factor 5.9.4 Sour Gas 5.9.5 Derivation of Gas Formation Volume Factor Oil Formation Volume Factor 5.10.1 Introduction 5.10.2 Data Sources 5.10.3 Data Acquisition 5.10.4 Data Analysis 5.10.5 Data Adjustment 5.10.6 Summary Quality and Reliabilityof Data and Results 5.11.1 Introduction 5.11.2 Permeabilityfrom Cores 5.11.3 Porosity from Cores 5.11.4 Saturations from Cores 5.11.5 Effective Porous Zone and Net Pay from Cores 5.11.6 Porosity from Well Logs 5.11.7 Water Saturations from Well Logs '" 5.11.8 Effective Porous Zone and Net Pay from Well Logs 5.11.9 Drillstem Tests 5.11.10 Production Tests 5.11.11 Reservoir Fluid Samples 5.11.12 Reservoir Temperature 5.11.13 Reservoir Pressure 5.11.14 GasCompressibilityFactor 5.11.15 Formation Volume Factor 5.11.16 Material Balance 5.11.17 Interrelationships

'"

'"

85 86 86 86 86 91 91 91 91 92 94 96 96 96 96 96 98 100 101 101 101 101 102 102 103 103 103 104 104 104 104 104 105 105 105 105

6.

PROBABILITYANALYSIS FOR ESTIMATES OF HYDROCARBONS IN PLACE 6.1 Introduction 6.2 Warren Method Theory 6.3 Application 6.4 Typical Situation: Conventional Gas

106 106 107 108 110

7.

MATERIAL BALANCE DETERMINATION OF HYDROCARBONS IN PLACE 120 7.1 Introduction 120 7.2 Underlying Assumptions 120 121 7.3 Explanation of Terms 7.4 General Material Balance Equation .......................•.............. 122 7.5 Special Cases of the Material Balance Equation 122 7.5.1 Undersaturated Oil Reservoirs 122 7.5.2 Saturated Oil Reservoirs 123 7.5.3 Gas Reservoirs 123 vii

7.6 7.7

7.8 7.9

Limitations of Material Balance Methods Supplemental Calculations 7.7.1 Gas Caps and Aquifers 7.7.2 Water Influx Measurements 7.7.3 Analytical Water Influx Models Multiple Unknown Material Balance Situations Computer Solutions

123 124 124 124 124 125 127

PART THREE: ESTIMATION OF RECOVERY FACTORS AND FORECASTING OF RECOVERABLE HYDROCARBONS 8.

OVERVIEW OF PART THREE 8.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 8.2 Purpose of Depletion Strategy 8.3 Techniques for Reserves and Production Forecasting

131 131 131 132

9.

NATURAL DEPLETION MECHANISMS FOR OIL RESERVOIRS 9.1 Introduction 9.1.1 Fluid Expansion 9.1.2 Solution Gas Drive 9.1.3 WaterDrive 9.1.4 Gas Cap Drive , 9.1.5 Compaction Drive 9.1.6 CombinationDrive 9.2 Forecasting of Recoverable Oil 9.2.1 Solution Gas Drive 9.2.2 Water Drive 9.2.3 Gas Cap Drive 9.2.4 CombinationDrive 9.3 Factors Affecting Oil Recovery 9.3.1 Production Rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.3.2 Oil Quality 9.3.3 Reservoir Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 9.3.4 Reservoir Geometry 9.3.5 Effects of Economic Limit

133 133 133 133 134 134 134 135 135 137 137 140 140 140 140 141 141 141 142

10. DEPLETION MECHANISMS FOR NATURAL GAS RESERVOIRS 10.1 Introduction 10.2 Characteristics of Natural Gas 10.3 Definition of Reservoir Types from Phase Diagrams 10.4 Gas Recovery 10.5 Gas Reserves 10.5.1 Nonassociated Gas Reserves Determination .. , 10.5.2 Solution Gas Reserves Determination 10.5.3 Associated Gas Reserves Determination 10.6 Pipeline Gas Reserves 10.7 Reserves of Related Products 10.7.1 Natural Gas Liquids 10.7.2 Sulphur 10.8 Gas Deliverability Forecasting 10.9 Well Spacing 10.10 Cycling of Gas Condensate Reservoirswith Dry Gas viii

145 145 145 146 147 148 148 150 150 150 151 151 151 151 152 152

10.11 Secondary Recovery of Gas 10.12 EnhancedGasRecovery

153 153

II. ENHANCED RECOVERY BY WATERFLOODING 11.1 Introduction 11.2 Displacement Process 11.2.1 Mobility Ratio 11.2.2 Interfacial Tension 11.2.3 Fractional Flow 11.3 Types of Waterfloods 11.4 Analysis Methods and When to Apply Them 11.4.1 Pool Discovery 11.4.2 Delineated Pool: Immature Depletion 11.4.3 Post-Injection Startup 11.4.4 Post-Watertlood Response 11.4.5 Mature Watertlood U.s Volumetric Analysis 11.5.1 Overview of Method 11.5.2 Parameters and Factors Affecting Analysis 11.5.3 Reliability of Results 11.6 Decline Performance Analysis 11.6.1 Overview of Method 11.6.2 Factors Affecting Analysis 11.6.3 Reliability of Results 11.7 Comparison to Analogous Pools 11.7.1 Overview of Method 11.7.2 Procedure and Factors Affecting Analysis 11.7.3 Reliability of Results 11.8 Analytical Performance Prediction 11.8.1 Overview of Methods 11.8.2 Reliability of Results 11.9 Numerical Simulation 11.9.1 Overview of Method 11.9.2 Parameters and Factors Affecting Analysis 11.9.3 Reliability of Results 11.10 Waterflooding Variations 11.10.1 Naturally Fractured Reservoirs 11.10.2 Polymer Flooding 11.10.3 Micellar Flooding 11.11 Statistical Watertlood Analysis Survey 11.11.1 Overview of Database 11.11.2 Discussion of Results

154 154 154 154 154 155 156 156 157 157 158 158 158 158 158 158 162 162 162 162 163 163 163 163 164 164 164 164 166 166 166 166 167 167 168 168 168 168 168

12. ENHANCED RECOVERY BY HYDROCARBON MISCIBLE FLOODING 12.1 Introduction 12.2 Types of Hydrocarbon Miscible Floods 12.2.1 Vertical Miscible Floods 12.2.2 Horizontal Miscible Floods 12.3 Methods of Achieving Miscibility 12.3.1 First-Contact Miscible Process 12.3.2 MUltiple-Contact Miscible Process 12.3.3 Vapourizing Multiple-Contact Miscibility

171 171 171 171 172 172 172 172 173 ix

12.4

12.5

12.6

x

Experimental Methods to Determine Miscibility 12.4.1 P-X Diagram 12.4.2 Multi-Contact Ternary Diagram 12.4,3 Slim Tube Test 12.4.4 Rising Bubble Apparatus Screening and Feasibility Studies 12.5.1 Volumetric Method 12.5.2 Break-Through Ratio Method 12.5.3 Geological Model 12.5.4 Simulation Studies 12.5.5 Estimation of Uncertainties 12.5.6 Determination of Solvent and Chase Gas Slug Size 12.5.7 Field Performance of Miscible Floods Classification of Miscible Hydrocarbon Reserves 12.6.1 Possible Reserves 12.6.2 Probable Reserves 12.6,3 Proved Reserves

173 173 174 174 174 174 175 177 177 177 178 178 179 179 179 180 180

13. ENHANCED RECOVERY BY IMMISCIBLE GAS INJECTION 13.1 Introduction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 13.2 Types of Floods 13,3 Performance Prediction 13.3.1 External Injection Schemes 13,3.2 Dispersed Gas Injection Schemes

183 183 183 184 185 185

14. ENHANCED RECOVERY BY THERMAL STIMULATION 14.1 Introduction 14.2 Cyclic Steam Stimulation 14.2.1 Process Variation 14.2.2 Field Examples 14.2.3 Recovery Mechanisms 14.2.4 Design Considerations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 14.3 Steam Flooding . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. 14.3.1 Process Variation 14,3.2 Design Considerations 14.4 Causes of Failure for Cyclic Steam Stimulation and Steam Flood Processes 14.5 Forecasting Models 14.5.1 Marx and Langenheim Model 14.5.2 Myhill and Stegeimeier Model 14.5,3. Vogel Model 14.5.4 ButierModel 14.6 In Situ Combustion Processes 14.6.1 Recovery Mechanisms 14.6.2 Process Variations 14.6.3 Design Considerations 14.6.4 Causes of Failure , , 14.7 Electromagnetic Heating

187 187 187 187 188 188 188 189 189 189 190 191 191 193 194 194 194 195 195 195 196 196

15. ENHANCED RECOVERY BY CARBON DIOXIDE FLOODING 15.1 Introduction , 15.2 Process Review , 15.3 Recovery Mechanisms

200 200 200 201

15.4

15.5 15.6

Design Considerations 15.4.1 Phase Behaviour 15.4.2 Displacement Efficiency 15.4.3 Volumetric Sweep Efficiency 15.4.4 Slug Sizing Reserve Evaluation Field Applications

201 201 201 202 202 202 203

16. RESERVES ESTIMATION FOR HORIZONTAL WELLS 16.1 Introduction 16.2 Reserves Determination Techniques 16.2.1 Performance Projection 16.2.2 Volumetric Method 16.2.3 Role of Heterogeneities ; 16.2.4 Importance of Channelling in Reserves Performance 16.2.5 Recovery Factors 16.3 Determination of Reserves 16.3.1 Determination of Reserves Parameters 16.3.2 Key Elements 16.3.3 Steps Involved in Reserves Determinations

205 205 206 206 209 209 209 210 211 211 211 211

17. NUMERICAL SIMULATION 17.1 Introduction 17.2 Types of Reservoir Simulators 17.3 Mathematical Formulation 17.4 Anatomy of Reservoir Simulation 17.5 Data Requirements 17.5.1 ReservoirGeometry 17.5.2 Rock and Fluid Properties 17.5.3 ProductionandWellData 17.6 Reservoir Model Grid Design 17.7 Reservoir Model Initialization 17.8 Model Sensitivity Analysis 17.9 History Matching 17.10 Forecasting Reservoir Performance 17.11 Use and Misuse of Reservoir Simulation 17.12 Summary

214 214 214 215 216 216 216 216 216 217 218 218 219 219 220 220

18. DECLINE CURVE METHODS 18.1 Introduction 18.2 Source and Accuracy of Production Data 18.3 Terminology 18.4 Single-Well vs. Aggregated-WellMethods 18.5 Decline Curve Methods for a Single Well 18.5.1 Exponential Decline 18.5.2 Hyperbolic Decline 18.5.3 Harmonic Decline 18.5.4 Dimensionless Solutions and Type-Curve Matching 18.6 Decline Curve Methods for a Group of Wells 18.6.1 Statistical Method 18.6.2 Theoretical Methods 18.7 Summary

222 222 222 223 223 224 225 226 229 230 231 231 234 235 Xl

19. RECOVERY FACTOR STATISTICS , 19.1 Introduction 19.2 Data Source and Reliability 19.3 Conventional Crude Oil 19.3.1 Natural or Primary Drive Mechanisms 19.3.2 Oil Recovery Factor Distributions 19.3.3 Average Recovery Factors 19.3.4 Pool Size 19.3.5 Fluid Type: Light and Medium vs. Heavy 19.3.6 Lithology: Clastics vs. Carbonates 19.3.7 Geological Period 19.3.8 Geological Play 19.3.9 Recovery vs, Common Reservoir Parameters 19.4 Conventional Gas 19.5 Using Recovery Factor Statistics

"

237 237 237 238 238 239 240 240 241 242 243 '" . 243 247 247 249

PART FOUR: PRICES, ECONOMICS, AND MARKETS

xii

20. OVERVIEW OF PART FOUR

253

21. CASH FLOW ANALySIS 21.1 Introduction 21.2 Mineral Rights Ownership 21.3 Principal Sources and Uses of Cash 21.4 Royalties and Mineral Tax 21.5 Federal Corporate Income Tax 21.6 Financial Statements 21.7 Finance and Economic Considerations

254 254 254 255 257 261 263 264

22. UNCERTAINTY AND RISK IN RESERVES EVALUATION 22.1 Introduction 22.2 Concepts 22.2.1 Definition of Risk and Uncertainty 22.2.2 Describing Uncertainty 22.2.3 Areas of Uncertainty 22.2.4 Causes of Uncertainty 22.2.5 Magnitude of Uncertainty 22.2.6 Use of Uncertainty 22.3 Estimation of Uncertainty 22.3.1· Parameters to be Estimated 22.3.2 Empirical Classification 22.3.3 Quantifying Subjective Estimates 22.3.4 Quantitative Estimation 22.4 Methods of Analysis 22.4.1 Carrying Out a Stochastic Evaluation 22.4.2 Decision Matrices 22.4.3 Decision Trees 22.4.4 Probabilistic Simulation 22.5 Evaluation of Undeveloped Lands

266 266 266 266 266 266 268 271 271 273 273 273 274 274 275 275 276 277 277 278

23. THE REGULATORY ENVIRONMENT 23.1 Introduction 23.2 Resource Assessments 23.3 Mineral Ownership 23.4 Economic Development Policies 23.5 Conservation Controls 23.5.1 Field Development and Production Conservation 23.5.2 Consumer Demand Conservation 23.6 Development, Operating, and Environmental Regulations 23.7 Domestic Supply Assurance 23.8 Fiscal Policies 23.9 Business Regulations 23.10 International Policies

281 281 281 282 282 283 283 283 283 284 285 285 285

24. CRUDE OIL MARKETS 24.1 Introduction 24.2 Transportation Network 24.3 Major Markets 24.4 North American Pricing 24.5 Price Risk Management 24.5.1 Futures 24.5.2 Options 24.5.3 Swaps 24.6 Outlook and Challenges

287 287 288 290 291 294 294 295 295 295

25. NATURAL GAS MARKETS 25.1 Introduction 25.2 The Market Environment 25.2.1 Review of Pre-Deregulation Era 25.2.2 Review of Current Era 25.2.3 Preview of Future Era 25.3 Market Mechanisms and Market Forces 25.3.1 Market Types and Market Mechanisms 25.3.2 Market Demand Forces 25.3.3 Production Forecasting 25.4 The Role of Reserves 25.5 Conclusions

297 297 297 297 298 300 300 300 302 304 304 305

26. USES OF RESERVES EVALUATIONS 26.1 Introduction 26.2 Users of Reserves Volumes and Production Forecasts 26.2.1 Producers 26.2.2 Transporters 26.2.3 Governments 26.2.4 Gas Marketers 26.2.5 Other Users 26.3 Developing Values from Reserves Estimates 26.3.1 Profitability Indices 26.3.2 Incremental Economics 26.3.3 Acceleration Projects 26.4 Uses of the Values Derived from Reserves Estimates 26.4.1 Valuing Oil and Gas Companies

306 306 306 306 306 306 307 307 307 307 310 310 311 311

xiii

26.4.2 26.4.3 26.4.4 26.4.5 26.4.6 26.4.7 26.4.8 26.4.9 26.4.10

Sale of ResourceProperties Evaluation of UnexploredLands and ExplorationWells Lending and Borrowing Auditing Evaluations Securities Reporting Accounting Requirements EstablishingFinding and Replacement Costs Estimating Barrels of Oil Equivalent EstimatingNet-Back Calculations

312 313 314 314 315 316 317 318 320

Biographies ofAuthors

32i

Acronyms

329

Glossary

333

Bibliography

345

Author index

349

Subject index

353

FIGURES 2.1-1 2.1-2 2.5-1 3.3-1 3.3-2 3.3-3 3.3-4 3.3-5 3.3-6 3.3-7 3.3-8 3.3-9 3.3-10 3.3-11 5.1-1 5.1-2 5.1-3 5.1-4 5.2-1 5.2-2 5.2-3 5.2-4 5.2-5 5.4-1 5.4-2 5.4-3

xiv

Resources Reserves Reserves Ownership Single Well Oil Pool with Good Geological Control Conventional Gas Pool, Zero Limit of Net Pay Map Conventional Gas Pool, Zero Limit of Net Pay Map with Individual Well Assignments Conventional Gas Pool, Zero Limit of Net Pay Map with Area of Proved Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. Conventional Gas Pool, Zero Limit of Net Pay Map with Area of Proved Plus ProbableReserves Material Balance (Gas Reservoir) Material Balance (Scattered Data) Material Balance (ReservoirDrive and Depletion Mechanism) Decline Curve, Proved Reserves ., Decline Curve, Cumulative Gas Production Decline Curve, Cumulative Oil Production Pressure-Depth Plot for Free Water Level Determination Cross Contouring Series of Related Maps (zero edge from seismic, computer-contoured) (ZYCOR Software) Examples of Mechanical and Interpretive Mapping Reservoir IntervalTerminology Air Permeabilityvs. Porosity Flow Chart for a Core Analysis Program Hydrocarbon Fluid ContactIdentification from Pressure Gradients Sand Unit Shape Diagram Porosity of Cubic-Packed Spheres Typical Core Analysis Report Porosity vs. Horizontal Permeability

4

6 7 13 14

15 15 16 18 19 19 20 21 21 38 40 41 42 44 46 47 49 51 55 59 60

5.4-4 5.4-5 5.4-6 5.4-7 5.4-8 5.4-9 5.5-1 5.5-2 5.5-3 5.5-4 5.5-5 5.5-6 5.6-1 5.6-2 5.7-1 5.7-2 5.7-3 5.7-4 5.8-1 5.8-2 5.8-3 5.8-4 5.9-1 5.10-1 6.3-1 6.4-1 6.4-2 6.4-3 6.4-4 6.4-5 7.7-1 7.7-2 9.1-1 9.1-2 9.1-3 9.2-1 9.3-1 9.3-2 9.3-3 9.3-4 10.2-1 10.2-2 10.3-1 10.3-2 10.5-1 10.5-2 10.8-1 10.8-2

Core Analysis Report: Analytical Summary Sheet Porosityfrom Formation Density Log Porosityfrom Sonic Log Neutron PorosityEquivalence Curves Porosityand Lithology Determination from Neutron-Density Log Impact of Clay on Log and Core Measurements Porosityvs. Formation Factor Formation Resistivity Index Air Brine Capillary Pressure Test Log Interpretation Flow Chart Dual Water Model Shaly Sand Interpretation Process DrillstemTest Tool (UnsetPosition) DrillstemTest Tool (Set Position) : Representative Homer Plots from Wellsin the Utah-Wyoming Thrust Belt Relief Map for Southern Alberta ContourPlot of Spreadfor BHTValues in Southern Alberta Examples of Temperature vs. Depth Plots from Two Areas in Southern Alberta Static Gradient Pressure vs. Time Homer Plot PorosityVolume Map Compressibility Factors for Natural Gases Comparison of Formation Volume Factor by Differential and Flash Liberation Estimation of Reef Volume Typical Situation: Gas Pool Map Conversion of Base Area to Average Pool Area Typical Situation: Gas-in-Place Distribution Typical Situation: Reserve Distribution Typical Situation: Discounted Net Profit Before Investment StraightLine Plot for Oil Zone and Gas Cap Case StraightLine Plot for Oil Zone and Water Influx Case SolutionGas DriveReservoir Comparison of Solution Gas Drive and Water Drive Reservoirs Gas Cap Drive Reservoir Recommended Methods for the Stages of Exploitation Relationship Between Production Rate and Reserves Relationship Between Well Spacing and Abandonment Pressure Optimum Well Spacing Effectsof FacilityConstraints on Economic Limit Classification of Gas Based on Source in Reservoir Occurrence of Oil and Gas Pressure-Temperature Phase Diagram of a Reservoir Fluid Phase Diagram of a Cap Gas and Oil Zone Fluid Plot ofP/Z vs. Cumulative Gas Production Effect of Water Drive on Pressure Decline Back Pressure Plot Gas Deliverability Plot

60 61 61 62 62 64 67 68 70 71 72 73 76 ; 76 83 83 83 84 87 87 88 89 93 96 110

III 113 116 118 119

126 127 133 134 135 135 141 143 143 143 145 146 147 147 150 150 152 152

xv

11.2-1 11.2-2 11.3-1 11.3-2 11.3-3 11.5-1 12.3-1 12.3-2 12.3-3 12.5-1 13.2-1 14.5-1 14.5-2 16.2-1 17.2-1 17.3-1 17.6-1 17.6-2 17.6-3 17.6-4 18.3-1 18.3-2 18.5-1 18.5-2 18.5-3 18.5-4 18.5-5 18.5-6 18.6-1 18.6-2 18.6-3 18.6-4 18.6-5 19.3-1 19.3-2 19.3-3 19.3-4 19.3-5 19.3-6 19.3-7 19.3-8 19.3-9 19.3-10 19.3-11 19.3-12 19.3-13 19.3-14 xvi

Effect of Oil Viscosity on Fractional Flow Curve, Strongly Water-Wet Rock Effect of Oil Viscosity on Fractional Flow Curve, Strongly Oil-Wet Rock Cross Section for Vertical Waterflood Plan View for Horizontal Waterflood Flood Patterns for Horizontal Flood Schemes Effect of Mobility Ratio on Oil Production for the Five-Spot Pattern Pseudo-Ternary Diagram Indicating First-Contact Miscibility Development of Multiple-Contact Miscibility Condensing Process . . . . . . Development of Multiple-Contact Miscibility Vapourizing Process Reserves Distribution Gas Injection Types of Analytical Gravity Drainage Models Thermal Efficiency of Steam Zone as a Function of the Dimensionless Time Parameter Schematic of Horizontal and Vertical Well Drainage Areas Schematic Diagram of Matrix-Fracture Connectivity Mass Balance on Reservoir Element 2D Areal Model 2D Vertical Model 2D Radial Model .......................................... 3D Model Reservoir Performance Chart Production Performance Chart Exponential Decline Chart Decline Curve Analysis Chart Relating Production Rate to Time Decline Curve Analysis Chart Relating Production Rate to Cumulative Production Hyperbolic Curve Overlay Production Performance Graphs Composite of Analytical and Empirical Type Curves Production Performance Graph Rate-Cumulative Production Graph Distribution of Well Rates, Pembina Cardium Pool Rate-Ratio-Cumulative Graph, Pembina Cardium POOl Production Performance Graphs, Pembina Cardium Pool Oil Pools Distribution of Primary Oil Recovery Factors Large Mature Oil Pools Light and Medium Oil Pools Heavy Oil Pools Clastic Oil Pools Carbonate Oil Pools Upper Cretaceous Oil Pools Lower Cretaceous Oil Pools Jurassic Oil Pools Triassic Oil Pools Permian Oil Pools Mississippian Oil Pools Upper Devonian Oil Pools

155 155 156 156 157 159 172 173 173 178 184 192 193 208 215 215 217 217 217 218 224 224 226 227 227 228 229 230 232 232 233 234 234 239 240 241 241 242 242 242 243 243 244 244 244 244 245

19.3-15 19.3-16(a) 19.3-16(b) 19.3-17(a) 19.3-17(b) 19.3-18(a) 19.3-18(b) 19.3-19 19.3-20 22.2-1 22.2-2 22.2-3 22.2-4 22.2-5 24.2-1 24.2-2 24.4-1 24.4-2 25.3-1 25.3-2 25.3-3

Middle Devonian Oil Pools Oil Recovery vs. Porosity Porosity Distribution Oil Recovery vs. Net Pay Net Pay Distribution Oil Recovery vs. Water Saturation Water Saturation Distribution Gas Pools (Producing) Large Gas Pools (Producing) Risk and Uncertainty Level of Uncertainty in Reserves Estimates during the Life of a Producing Property The Effect of Error and Bias on a Reserve Estimate Expectation Curves: Comparison of Results Expectation Curve: Reconciliation of Different Views of Hydrocarbon Volumes and Values Major Alberta Pipeline Systems Major Crude Oil Pipelines and Refining Areas NYMEX WTI Prices at Cushing Alberta Crude Oil Pricing, Chicago Market (July 1992) Commercial and Regulatory Mechanisms for Ex-Alberta Markets Gas Marketing Options Reserves Connection to Markets

245 247 247 248 248 248 248 249 249 267 269 270 271 272 288 289 293 293 301 302 303

TABLES 4.2-1 4.4-1 5.4-1 5.5-1 5.10-1 5.10-2 5.10-3 6.1-1 6.4-1 6.4-2 6.4-3 6.4-4 6.4-5 6.4-6 7.2-1 7.2-2 9.2-1 9.2-2 10.7-1 11.8-1 11.11-1

In-Place Volumes of Related Products Sources of Data Comparison of Techniques of Determining Porosity Wettability and Interfacial Tension Pressure Volume Relations Separator Tests of Reservoir Fluid Sample Differential Vapourization In-Place Volumetric Estimation Techniques Gas-in-Place Distribution for Most Likely Area of384 Hectares Gas-in-Place Distribution for Most Likely Area of 576 Hectares Gas-in-Place Distribution for Most Likely Area of 704 Hectares Gas-in-Place Distribution for Most Likely Area of 576 Hectares, Variable Temperature and Gas Deviation Factor Reserve Distribution for Most Likely Area of 576 Hectares Discounted Net Profit Before Investment Distribution for Most Likely Area of 576 Hectares ReservoirVoidage Terms Reservoir Expansion Terms Recommended Reserves Forecasting Methods Decline Analysis Plots Used after Water Break-through Recoveries of Related Products Classification of 33 Waterflood Prediction Methods Summary of Recovery Factors: A Sampling of Western Canadian Waterfloods

30 32 56 69 98 99 99 107 114 115 115 117 118 119 121 122 136 139 151 165 169 xvii

7

11.11-2 13.3-1 18.5-1 18.6-1 19.2-1 19.3-1 19.3-2 19.3-3 19.3-4 21.4-1 21.4-2 21.4-3 21.5-1 24.3-1 26.4-1

XV1l1

Reserve Analysis Technique Distribution . . . . . . . . . . . . . . . . . . . . . . . . .. Recommended Performance Prediction Methods DeclineCurve Equations Statistical Parameters for Pembina Cardium Pool Public Data Available for Reserve Studies Primary Oil Recovery by DriveMechanism AverageOil Recoveries Recovery Factors for Upper Devonian Zones Recovery Factors for Geological Plays in WesternCanada Summaryof AlbertaNatural Gas Royalty Changes Summaryof Equations for Basic Royalty Summaryof AlbertaCrude Oil RoyaltyRate Changes Cash Flow and Income Tax Summary Importers of Canadian HeavyCrude Conversion Rates

169 185 225 233 237 238 241 245 246 258 259 259 262 292 318

FOREWORD

The estimating and reporting of reserves of oil and gas and related substances are of fundamental importance to the oil and gas industry. Reserves estimates form the basis for most development and operational decisions and are of critical importance in financing and other commercial arrangements that allow oil and gas developments to proceed in an orderly and efficient manner. Reserves estimates also playa key part in relevant planning and policy decisions by governments and others. The role of reserves estimates in operational, financial and policy decisions emphasizes the need for the estimates to be as accurate and current as possible. The use ofconsistent terminology and estimation procedures is also essential. This monograph, Determination ofOil and Gas Reserves, has been developed to assist in achieving the objectives of accuracy and consistency in estimating reserves. The idea ofdeveloping such a monographwas conceivedby Dr. Roberto Aguilera who, as Chairman of the Reserves Monograph Advisory Committee,has co-ordinatedthe preparation of the document. The project was sponsored by the Calgary Section of the Petroleum Society ofthe Canadian Institute of Mining, Metallurgy and Petroleum. The first organizational meeting of the committee took place in the spring of 1990. Since that time, members of the committee, on their own and with the support of their employers, have contributed substantial time and expertise to the project and enlisted the help of many industry experts in the preparation and critique of specific chapters. The objective was to develop a reference that would be of substantial value to geologists, engineers and other technical persons involved in estimating reserves, as well as to others who use such estimatesfor particular purposes. With the publication ofthe monograph in the spring of 1994, the committee will have achieved that objective. A total of over fifty people have been involved in the planning, the writing and review of the chapters, the drafting of figures, and the editing and preparation of the final copy for the printing of the monograph. All those involved in estimatingoil and gas reserves, or who use such estimates, owe them a vote of thanks. I am confident that the monograph will become a standard reference for all practitioners of the science of estimating oil and gas reserves. It will also serve as an excellent training tool for persons who have only a basic understanding of reserves estimation methods and who wish to advance their knowledge of the subject. G. 1. DeSorcy, P.Eng. Calgary, January 1994

xix

7

PREFACE

The estimation of reserves of oil, gas, and related substances has been a hot topic since the very beginning of the oil industry. Over the ensuing years, the concept of reserves has meant different things to different people within this industry, with each evaluator, oil and gas company, financial agency, securities commission, and government department using its own version of the definitions. The monograph represents our effort to find definitions and guidelines for the classification of reserves that will be acceptable to all ofthese users. When the concept of this monograph was first discussed, we wrestled with the question: "Should we ask one or two professionals to prepare the whole monograph or should we ask a variety of specialists to contribute to it?" In the end we concluded that we would not find one or two people with expertise in all the topics concerned with oil and gas reserves, so we should use a number of knowledgeable authors. We ended up with forty contributing authors and a group of reviewers who helped to polish the thirty-seven topics covered in the twenty-six chapters ofthe monograph. The topics have fallen into four major divisions that we have called "parts" in the monograph. Part One presents the definitions and guidelines for the classification of oil and gas reserves. These have been prepared by the Standing Committee on Reserves Definitions of the Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum. Part Two discusses the volumetric and material balance methods for estimating volumes of oil and gas in place, various sources of data, and the interpretation of the data. Part Two also deals with probabilistic methods for estimating the volumes of oil and gas contained in reservoirs, in addition to the more common deterministic methods. Part Three considers the estimation of recovery factors for oil and gas reservoirs, with particular emphasis on volumes recoverable by enhanced recovery methods. Secondary and tertiary recovery methods are discussed, as well as primary methods and the use of horizontal wells. Part Three also addresses decline curve analysis and reservoir modelling by numerical simulation. Part Four covers the other factors that must be considered in estimating reserves: cash flow analysis, the assessment of uncertainty, the role of markets, and potential regulatory impacts that must be recognized by evaluators. Part Four ends with a discussion of the uses that are made of reserves estimates. This part proved to be very challenging to write as the diverse nature of the applications of recovery estimates in economic evaluations led to some animated discussions between the engineering and financial groups. But in the end, I think we put together some information that will be useful to all the professionals who deal with economic evaluations.

(cont'd)

xxi

z

For simplicity, the nomenclature and units of measurement are defined following each equation. We have used the metric system (SI), with Imperial units shown as well in some cases. Following the text, we have included brief biographies of the authors and several lists for the convenience of readers: Acronyms, Glossary, Bibliography, Author Index, and Subject Index. It is our sincere hope that this monograph, Determination of Oil and Gas Reserves, will help to simplify and standardize the science and art of estimating oil and gas reserves throughout the world.

Roberto Aguilera, P. Eng. Calgary, January 1994

xxii

ACKNOWLEDGEMENTS

Associated with the publication of the monograph was the time-consuming and challenging task of co-ordinating the material produced by forty authors with forty different backgrounds and forty different writing styles. The Reserves Monograph Advisory Committee did a superb job ofco-ordinating the four parts of the monograph. As Chairman, I wish to thank the members of the committee for the many hours they devoted to planning the work, meeting with the authors, and reviewing the drafts. The following are the members of the committee with their company affiliations. We are grateful to the employers for supporting the members in this endeavour. N. Guy Berndtsson Keith D. Brown CAS. (Charlie) Bulmer R.V. (Bob) Etcheverry John Hewitt R. V. (Bob) Lang W.V. (Bill) Mandolidis Michael E. McCormack r. Glenn Robinson Roberto Aguilera, Chairman

Energy Resources Conservation Board Royal Bank of Canada Sproule Associates Limited CN Exploration Inc. Martin Petroleum and Associates Energy Consultant Saskatchewan Oil and Gas Corp. Fractical Solutions Inc. Sproule Associates Limited Servipetrol Ltd.

The work on the monograph involved authors and reviewers with backgrounds in government regulations, banks, stock brokers, securities commissions, consultants, the University of Calgary, and major, mid- and small-sized exploration and production companies. On the following pages are listed the names and company affiliations of the authors of the various chapters and sections of the monograph. These are the people who supplied the "meat" of the document through many volunteer hours of labour-writing, revising, and consulting with others-on the material they were responsible for. In addition, we would like to thank the Petroleum Society ofCIM, Canadian Well Logging Society, Society of Petroleum Engineers, Society of Professional Well Log Analysts, American Association of Petroleum Geologists, and Alberta Energy Resources Conservation Board, as well as Western Atlas International Inc., Schlumberger, Gulf Publishing Co., PanCanadian Petroleum Ltd., Chevron Canada Resources, and PennWell Publishing Co. for permission to use material from their publications. We also express our gratitude to all of the various authors and organizations that have published material on reserves estimation and thereby added to the body of knowledge on this subject. Virginia MacKay, P.Eng., the professional editor for this monograph, undertook the daunting task of editing the material written by the forty different authors and assembling it all into one coherent document. She was assisted very conscientiously by lA. (Sandy) Irvine, P.Geol., who entered the text and figures on the computer. Together they prepared the camera-ready copy for the printer. Mike McCormack checked the nomenclature throughout the monograph and also contributed to the compilation ofthe Subject Index. Our sincere thanks to Virginia, Sandy, Mike, and all the authors, reviewers and co-ordinators for their dedication to the quality of the monograph. Roberto Aguilera, P. Eng. Calgary, January 1994 XXlll

7

AUTHORS

Part One Standing Committee on Reserves Definitions GJ. (Gerry) DeSorcy Energy Consultant

Chairman

George A. Warne Energy Consultant

Secretary

R. V. (Bob) Lang Energy Consultant

Co-ordinator

J. Glenn Robinson Sproule Associates Limited

Co-ordinator

Barry R. Ashton Ashton Jenkins and Associates Ltd. Graham R. Campbell National Energy Board David R. Collyer Shell Canada Limited John Drury Consultant (Ontario Securities Commission) W.O. (Bill) Robertson Price Waterhouse David W. Tutt Bank of Montreal

Note: All committee members contributed to the writing of Part One.

xxiv

AUTHORS (cant'd)

Part Two N. Guy Berndtsson Energy Resources Conservation Board

Co-ordinator

CAS. (Charlie) Bulmer Sproule Associates Limited

Co-ordinator

Brent Austin PanCanadian Petroleum Limited

Co-Author of Sections 5.2, 5.3,5.4,5.5

Robin G. Bertram Talisman Energy Inc.

Co-Author of Section 5.6 and Author of Sections 5.8, 5.9

Mike J. Brusset Brusset Consultants Ltd.

Co-Author of Section 5.6 and Author of Section 5.11

Merlin B. (Mel) Field Consultant

Author of Chapter 7

J.D. (Joe) Giegerich Chevron Canada Resources

Author of Sections 5.7, 5.10

DJ. (Dave) Hemphill Shell Canada Limited

Author of Section 5.1

Craig F. Lamb Lonach Consulting Ltd.

Co-Author of Sections 5.2, 5.3, 5.4, 5.5

Raymond A. Mireault Gulf Canada Resources Limited

Author of Chapter 6

xxv R

AUTHORS (cont'd)

Part Three

XXVI

R.V. (Bob) Etcheverry CN Exploration Inc.

Co-ordinator and Author of Sections 8.1, 8.2

John M. Hewitt Martin Petroleum & Associates

Co-ordinator and Author of Section 8.3

Soheil Asgarpour Gulf Canada Resources Limited

Author of Chapter 12

Anthony D. Au Servipetrol Ltd.

Author of Chapter 17

Keith M. Braaten Coles Gilbert Associates Ltd.

Co-Author of Chapter II

RonM. Fish Imperial Oil Limited, Resources Division

Author of Chapter 13

Mam Chand Gupta GM International Oil and Gas Consulting Corp

Author of Chapter 10

William E. Kerr Joss Energy

Co-Author of Chapter 15

Gobi Kular Advanced Petroleum Technologies

Co-Author of Chapter 14

Dana B. Laustsen Coles Gilbert Associates Ltd.

Co-Author of Chapter II

Margaret Nielsen Petro-Canada

Co-Author of Chapter 9

David C. Poon Consultant, D.C. Poon Consulting Inc.

Co-Author of Chapter 14

Ross A. Purvis Energy Resources Conservation Board

Author of Chapter 18

Darlene A. Sheldon Petro-Canada

Co-Author of Chapter 9

Phillip M. Sigmund BRTR Petroleum Consultants Ltd.

Co-Author of Chapter 15

Ashok K. Singhal Petroleum Recovery Institute

Author of Chapter 16

Andy Warren Energy Resources Conservation Board

Author of Chapter 19

AUTHORS (cont'd)

Part Four Keith D. Brown Royal Bank of Canada

Co-ordinator and Authorof Chapters20, 21

Janusz Bielecki National Energy Board

Authorof Chapter 24

Noel A. Cleland Sproule Associates Limited

Author of Chapter 26

David C. Elliott Geosgil Consulting

Author of Chapter 22

Harold R. Keushnig Energy Resources Conservation Board

Authorof Chapter 23

Tim J. Reimer Pan-Alberta Gas Ltd.

Author of Chapter 25

xxvii

PART ONE DEFINITIONS AND GUIDELINES FOR CLASSIFICATION OF OIL AND GAS RESERVES

7

Chapter 1

OVERVIEW OF PART ONE

There are almost as many definitions for reserves of oil and gas and related substances as there are evaluators, oil and gas companies, financial agencies, securities commissions, and government departments. Each uses its own version of the definitions for its own purposes. In addition, because of today's unstable economic conditions in the oil and gas industry, the lower quality of the reservoirs being discovered, and the new recovery methods being developed, it is becoming increasingly difficult to estimate the reserves that will be produced. All ofthese factors have made it imperative to develop a universal set of definitions for reserves that will meet the needs of all users. Part One of the monograph contains the definitions of key terms, the system of reserves classification, and guidelines to illustrate the application ofthe definitions and the classification system. The task of writing the definitions was undertaken by the Standing Committee on Reserves Definitions ofthe Petroleum Society of the Canadian Institute of Mining, Metallurgy and Petroleum, and Part One of the monograph has been published as a separate document comprising the committee's 1993 report. The committee includes representatives of oil and gas companies, geological and petroleum engineering consulting firms, Canadian industry associations, financial and accounting organizations, regulatory agencies, and government. The definitions ofkey terms and reserves classifications presented in Chapter 2 are similar to those currently in use by the oil and gas industry, particularly in North America. They have been reviewed by users in the industry and representatives from regulatory agencies, government departments, industry associations, and technical and professional organizations. Chapter 3 presents the guidelines that illustrate the application of the definitions and the classification system. These are intended to complement the detailed guidelines on reserves estimation methods and procedures that follow in subsequent chapters of the monograph.

The Standing Committee believes that the recommended definitions and guidelines are suitable for use with respect to all types of oil and gas and related substances, including offshore reserves and oil sands. Although those segments of the industry have used somewhat different terms and definitions, the principles reflected in the definitions recommended here are applicable. The fundamental principle is that those quantities that are known to exist and to be economically recoverable are reserves. The total quantities, whether or not they have been discovered, are resources. Reserves and resources are further categorized depending on the level of certainty that they will be recovered.

It is the view of the Standing Committee that current reserves estimation methods and categories, in general, match the recommended definitions and guidelines. The committee, therefore, does not expect that major changes to reserves estimates would result from adoption of the definitions, although it recognizes that for some specific reserves estimates (generally for small pools) changes could be significant. The committee hopes that, over time, reserves evaluators will increasingly conform to the recommendations presented in this monograph and thus contribute to the overall quality and consistency of reserves estimates. The Standing Committee received assistance from many individuals and organizations in the form of comments as it formulated the definitions and guidelines. The committee will continue to communicate with interested parties to ensure that its intent with respect to the recommended definitions is fully understood. The committee welcomes comments on its recommendations as well as any other aspects of reserves definitions and their application. Since comments are being sought from those that use the recommendations, it is reasonable to expect that the definitions may change with time. If they do, the revisions will be available from the Petroleum Society.

3

?

Chapter 2

DEFINITIONS

2.1

INTRODUCTION

The terminology recommended for the classification of estimated quantities ofoil and gas and related substances, at a particular time, is presented in Figures 2.1-1 and 2.1-2. Each term is defined in this chapter. Figure 2.1-1 and its related definitions set the framework for Figure 2.1-2 and its related definitions. The major classifications identified in this chapter are resources, remaining reserves, and cumulative production, each of which can be further divided into

Figure 2.1-1

4

Resources

sub-classifications. Reserves ownership is also discussed in this chapter.

2.2

RESOURCES

Resources are the total quantities of oil and gas and related substances that are estimated, at a particular time, to be contained in, or that have been produced from, known accumulations, plus those estimated quantities in accumulations yet to be discovered.

-I DEFINITIONS

2.2.1

Discovered Resources or Initial Volumes in Place

Discovered resources, which may also be referred to as initial volumes in place (Figure 2.1-1), are those quantities of oil and gas and related substances that are estimated, at a particular time, to be initially contained in known accumulations that have been penetrated by a wellbore. They comprise those quantities that are recoverable from known accumulations and those that will remain in known accumulations, based on known technology under specified economic conditions that are generally accepted as being a reasonable outlook for the future.

Initial Reserves

Future Initial Reserves Future initial reserves are those quantities of oil and gas and related substances that are estimated, at a particular time, to be recoverable from accumulations yet to be discovered by known technology under specified economic conditions that are generally accepted as being a reasonable outlook for the future.

Future Unrecoverable Volumes Future unrecoverable volumes are those quantities of oil and gas and related substances that are estimated, at a particular time, to remain in accumulations yet to be discovered because they are not recoverable by known technology under specified economic conditions that are generally accepted as being a reasonable outlook for the future.

Initial reserves are those quantities of oil and gas and related substances that are estimated, at a particular time, to be recoverable from known accumulations. They include cumulative production plus those quantities that are estimated to be recoverable in the future by known technology under specified economic conditions that are generally accepted as being a reasonable outlook for the future. (Figure 2.1-2 shows how initial reserves are classified.)

Remaining reserves (Figure 2.1-2) are estimated quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, by known technology under specified economic conditions that are generally accepted as being a reasonable outlook for the future.

Unrecoverable Volumes

2.3.1

Unrecoverable volumes (Figure 2.1-1) are those quantities of oil and gas and related substances that are estimated, at a particular time, to remain in known accumulations because they are not recoverable by known technology under specified economic conditions that are generally accepted as being a reasonable outlook for the future.

Remainingproved reserves are those remaining reserves that can be estimated with a high degree of certainty, which for purposes ofreserves classification means that there is generally an 80 percent or greater probability that at least the estimated quantity will be recovered. These reserves may be divided into proved developed and proved undeveloped to identify the status of development. The proved developed may be further divided into producing and nonproducing categories.

Unrecoverable volumes may be further divided into currently uneconomic volumes, which are those quantities that are currently estimated to be technically recoverable, but that are not economically recoverable under the specified economic conditions, and residual unrecoverable volumes, which are those quantities that are unrecoverable by known technologies.

2.2.2

Undiscovered Resources or Future Initial Volumes in Place

Undiscovered resources, which may also be referred to as future initial volumes in place (Figure 2.1-1), are those in-place quantities of oil and gas and related substances that are estimated, at a particular time, to exist in accumulations yet to be discovered.

2.3

2.3.2

REMAINING RESERVES

Remaining Proved Reserves

Probable Reserves

Probable reserves are those remaining reserves that are less certain to be recovered than proved reserves, which for purposes of reserves classification means that generally there is a 40 to 80 percent probability that the estimated quantity will be recovered. Both the estimated quantity and the risk-weighted portion reflecting the respective probability should be reported. These reserves can be divided into probable developed and probable undeveloped to identify the status of development.

2.3.3

Possible Reserves

Possible reserves are those remaining reserves that are less certain to be recovered than probable reserves, which for purposes of reserves classification means that

5

7

DETERMINATION OFOIL AND GAS RESERVES

generally there is a 10 to 40 percent probability that the estimated quantity will be recovered. Both the estimated quantity and the risk-weighted portion reflecting the probability should be reported. These reserves can be divided into possible developed and possible undeveloped to identify the status of development.

2.3.4

Development and Production Status

Each of the three reserves classifications, remaining proved, probable and possible, may be divided into developed and undeveloped categories (Figure 2.1-2). The developed category for proved reserves is often divided into producing and nonproducing.

Developed Reserves Developed reserves are those reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure to put the reserves on production (i.e., when compared to the cost of drilling a well).

Developed Producing Reserves Developed producing reserves are those reserves that are expected to be recovered from completion intervals

Figure 2.1-2

6

Reserves

open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date ofresumption of production must be known with reasonable certainty. Developed Nonproducing Reserves Developed nonproducing reserves are those reserves that either have not been on production, or have previously been on production, but are shut in, and the date of resumption of production is unknown.

Undeveloped Reserves Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (i.e., when compared to the cost of drilling a well) is required to render them capable of production.

In multi-well pools, it may be appropriate to allocate the total reserves for the pool between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed nonproducing. This allocation should be based on the evaluator's assessment as to the reserves that will be recovered from specific wells, the facilities

DEFINITIONS

and completion intervals in the pool, and their respective development and production status.

2.4

CUMULATIVE PRODUCTION

Cumulative production (Figure 2.1-2) comprises those marketable quantities of oil and gas and related substances that have been recovered to date from known accumulations.

2.4.1

Sales

Sales are produced quantities of oil and gas and related substances that have been sold to date.

2.4.2

Inventory

Inventory consists of quantities of oil and gas and related substances that have been produced and are available for future use.

2.5

RESERVES OWNERSHIP

The terminology that is recommended for reporting the ownership of quantities of oil and gas and related substances is presented in Figure 2.5-1. The terms are defined as follows:

Gross remaining reserves are the total remaining reserves associated with the property in which an owner has an interest. Company* gross remaining reserves are the company's lessor royalty, overriding royalty and working interest share ofthe gross remaining reserves, before deduction of any Crown, freehold, and overriding royalties payable to others. Company* net remaining reserves are the company's lessor royalty, overriding royalty, and working interest

Other Owner Interest Reserves

• Lessor Royalty Interests Payable Overriding Royalty Interests Payable

Figure 2.5-1

Reserves Ownership

* The word "Company"may be replaced by moresuitable adjectives to better depictthe ownership of reserves, e.g., ABC Oil and Gas, 9367 LimitedPartnership, John Doe, etc.

7

7

DETERMINATION OFOIL AND GAS RESERVES

share of the gross remaining reserves, less all Crown, freehold, and overriding royalties payable to others.

2.6

SPECIFIED ECONOMIC CONDITIONS

In order for oil and gas and related substances to be classified as reserves, they must be economic to recover at specified economic conditions. The estimator should use, as the specified economic conditions, a price forecast and other economic parameters that are generally accepted as being a reasonable outlook for the future. The revenue, appropriately discounted, must be sufficient to cover the future capital and operating costs that would be required to produce, process, and transport the products to the marketplace. A more detailed discussion of discounting future cash flow is presented in Chapter 21, Cash Flow Analysis, and in Chapter 26,

Uses ofReservesEvaluations. Ifrequired by securities commissions or other agencies, current prices and costs may also be used. In either case, the economic conditions used in the evaluations should be clearly stated. Occasionally, the estimator also may wish to determine the impact of higher or lower price forecasts on estimates of reserves as compared to the most reasonable forecast. These cases (current, higher or lower prices) should not be reported as the most reasonable reserves estimates, but should be identified as sensitivity cases with the assumptions clearly stated. They illustrate the impact of different specified economic conditions on estimates of reserves.

2.7 2.7.1

REPORTING OF RESERVES ESTIMATES Risk-Weighting of Reserves Estimates

Remaining proved reserves, as defined in Section 2.3.1, are those reserves for which there is an 80 percent or greater probability that at least the estimated quantity will be recovered. In instances where additional reserves are estimated in the probable and possible categories, both the estimated quantity and the adjusted (riskweighted) portion should be reported, particularly when the estimates are being aggregated. Proper statistical procedures may be used to derive the expected or risk-weighted reserves from the data. In the deterministic procedure, the best estimate of each parameter is used in the calculation of reserves. The probabilistic procedure quantifies the uncertainty in the resource estimate by using the evaluator's opinion to describe the range of values that could possibly occur

8

for each variable.' If a deterministic procedure is being used and a probabilistic determination is not available, the following equality is recommended to approximate the expected reserves: expected = (proved ) + (p x probable) + (p x Possible) reserves reserves b reserves S reserves where Pb

probability of recovering the probable reserves (80-40%) P, = probability of recovering the possible reserves (40- I0%) =

For individual pools, the amount for the expected or risk-weighted reserves provides the evaluator's best judgement as to the quantity that will be recovered from the pool. The probability used to adjust the estimated quantity for a specific pool should be that considered by the evaluator to be appropriate for the particular circumstance, taking into account the available geological, geophysical and engineering data. It is likely, however, that the quantity actually recovered from a specific pool will be more or less than the risk-weighted estimate. If the number ofpools for which estimates ofreserves are being prepared is sufficiently large, then the sum of the expected reserves should be the evaluator's best judgement as to the total quantity that will be recovered from all the pools. According to the ranges specified in these definitions, the risk-weighting should result in an average risk-weighting of 60 percent for probable reserves (the mid-point ofthe 80 to 40 percent probability range) and 25 percent for possible reserves (the mid-point of the 40 to 10 percent probability range). When the value of the risk-weighted reserves is being determined, the unrisked reserves must be used in the economic analysis. Risk for both the reserves and values should only be applied after the economic forecasts have been completed using total costs to develop the unrisked reserves.

2.7.2

Aggregation of Reserves Estimates

Traditionally, when deterministic approaches are being used, the aggregation of a series of reserves estimates will have been made using the arithmetic method. However, with the increase in the use of statistical methods in reserves determination, the arithmetic method of aggregation may not always be appropriate. Although

• Theseprocedures are described in more detailin Section 4.3.

DEFINITIONS

use of a statistical method of aggregation may be better for reserves estimates, the method of aggregation may be dictated by regulators, auditors or management. Thus, when aggregating a series of reserves estimates, the evaluator should state whether the method of aggregation is arithmetic or statistical. If a statistical method is used, the evaluator should state how it is done. If the proved reserves, which represent an 80 percent confidence level, are summed arithmetically, the total reserves will represent a confidence level that is much higher than would be achieved if the proved reserves were totalled using a probabilistic approach of all the entities and an 80 percent confidence level. Conversely, . the proved plus probable reserves and the proved plus probable plus possible reserves will be overstated when summed arithmetically using a deterministic as compared to a probabilistic procedure. On the other hand, the sum of the expected reserves, as defined in the preceding sections, should be the same as the deterministic (using arithmetic methods) and the probabilistic procedures. This relationship is extremely important in summing reserves, and therefore it is recommended that risk-weighted reserves be used in the aggregation of reserves. In any event, the evaluator should state whether the method of aggregation is arithmetic or probabilistic.

2.7.3

Barrels of Oil Equivalent

From time to time, it may be desirable to report reserves ofoil, gas and related substances in common units. This

is generally done by converting reserves that are not oil to barrels of oil equivalent (BOE). The conversion can be made using either an energy equivalence or a relative value procedure, depending upon the purpose of the conversion. The energy equivalence is only relevant at the burner tip and, since the value in the marketplace is different for various types of reserves and the costs to move the various types from wellhead to the end-user vary considerably, the value of the reserves at the wellhead (or in the ground) is only somewhat indirectly related to energy content. Consequently, for making value-based comparisons, the conversion should be based on the relative values of the gas and related substances compared to the values of oil reserves at the field level. The conversions to BOE are usually made to barrels of "light" oil equivalent. Since medium and heavy oil have values much lower than light oil, it may be desirable that the medium and heavy oil reserves be converted to BOE of light oil as well as converting the gas and related product reserves, to better indicate their real value. Some companies may prefer to convert their reserves using gas as the common unit. The procedure would be similar, except that the converted reserves would be quoted as thousand cubic feet of gas equivalent. It is important, when reserves are reported in BOE or gas equivalent, that the method used and the respective conversion rates be disclosed. A more detailed description ofthe procedure is presented in Chapter 26, Uses ofReserves Evaluations.

9

Chapter 3

GUIDELINES FOR ESTIMATION OF OIL AND GAS RESERVES

3.1

INTRODUCTION

The quantification and classification of estimates of reserves are, by nature, rather subjective processes. Estimates of reserves are developed under conditions of uncertainty, and their reliability and classification are directly related to the quality of the data available, as well as to the competence and integrity of the individual responsible for preparing the estimates. The purpose of this chapter is to elaborate on the classification of estimates ofreserves derived using the two primary reserves determination procedures: deterministic and probabilistic. The categories of proved, probable, and possible have for some time provided a basis for differentiating estimates of reserves to reflect the probability of recovery considered appropriate by the estimator. Stated in another way, the assignment ofthe estimate ofreserves to the three categories has provided a qualitative measure of the probability that a particular estimate of reserves will, in fact, be realized. However, for some time there has been discussion as to whether a more rigorous approach should be adopted to describe the degree of probability associated with the specific reserves categories. Some observers view the use ofterms such as "high degree of certainty" to describe reserves classification categories as too subjective, and believe a definitive statistical probability of recovery would give users more confidence in utilizing- the estimates of reserves provided for each of the categories. For this reason, consideration has been given to a means to further quantify the degree of probability associated with each of the categories. The probability ranges adopted by the Standing Committee on Reserves Definitions for the definitions ofproved, probable, and possible reserves are intended to more explicitly quantify the probability of recovery associated with each of the reserves categories, both on an absolute and on a relative basis. The ranges provide an assessment that is more quantitative in nature than some prior definitions.

10

The use of probabilities to assist in the categorization ofreserves does not eliminate subjectivity from the process. It remains incumbent on the evaluator to ensure that the basis for the estimate of reserves and the category to which the estimate is assigned are clearly reported. The guidelines and examples given are intended to assist in this regard. The reserves classifications and associated probability ranges are applicable to estimates of reserves derived using either deterministic or probabilistic (stochastic) calculation procedures.

3.2

METHODS OF CALCULATING RESERVES

3.2.1

Deterministic Procedure

The deterministic procedure is the most commonly used method ofreserves estimation in Canada. Ifthe true values of all parameters used in any calculation were known, a true or deterministic value could be calculated. However, due to the uncertainties in the geological, engineering and economic data, for the purposes of reserves estimation using the deterministic procedure, the "best estimate" ofeach parameter is used in the calculation of reserves for each specific case. As a result, the probability distribution of the input parameters is generally not formally considered in the classification of reserves calculated using this method. Estimates ofreserves calculated using the deterministic procedure should be assigned to the proved, probable, and possible categories based on the probabilities inherent in the estimates. The assignment ofthe estimates of reserves to the respective classification categories should be consistent with the prescribed ranges ofprobability, taking into account factors such as the stage in the producing life ofthe reservoir, the amount and quality of geological and engineering data available, the availability of suitable analogous reservoirs and, perhaps most importantly, the evaluator'sjudgement as to the uncertainty inherent in the estimate.

GUIDELINES FOR ESTIMATIONOF OIL AND GAS RESERVES

The assignment of reserves estimates to the respective categories using the deterministic procedure normally uses one of two approaches. In the first, the evaluator develops a "best estimate" of reserves for each of the categories, using consistent parameters. Using this methodology, the evaluator effectively establishes a range of estimates of reserves, with the proved estimate based on parameters for which a high probability can be attributed, and additional estimates of probable and possible reserves based on parameters for which there is a lesser probability of occurrence. The effect of this is to progressively increase the estimated quantity as it is moved from the proved to probable to possible categories, with the overall range of estimates dependent upon the uncertainty inherent in the specific parameters upon which the estimates are based. In the second approach, a single estimate of reserves is derived for the pool and then allocated to the respective reserve categories based on an assessment of the portions of the estimate that would satisfy the probability ranges for each of the reserves categories. In making this determination, the evaluator must make a subjectivejudgement as to the uncertainty inherent in the single estimate and, therefore, the extent to which it can be allocated to the proved rather than the probable or possible category. As already noted, where probable or possible reserves have been estimated in addition to proved reserves, they should be adjusted (risk-weighted) and added to the proved reserves to result in the expected reserves. In summary, using the deterministic procedure, estimates of reserves are calculated and assigned to the proved, probable, and possible categories using primarily subjective criteria, the overall basis being that the assigned quantities satisfy the probabilities established for each of the categories. It is incumbent on the evaluators to provide the supporting rationale for the categorization of the reserves estimates.

3.2.2

Probabilistic Procedure

The probabilistic or stochastic procedure is less commonly used in Canada. It is more suitable for circumstances where the uncertainty is high, such as for reservoirs in the early stages of development, frontier areas, or areas where new technology is being applied. As the level of uncertainty increases, it is generally agreed that the probabilistic procedure becomes more relevant and the deterministic less reliable. Rapidly expanding computer applications also facilitate the use of the probabilistic procedure.

This method uses the statistical analysis of data. Relative frequency curves established for each variable describe the range of possible values for each, as well as the probabilities that these values will occur. After frequency distribution curves have been established for each variable to be used in a reserves classification, the Monte Carlo (described in Section 22.4.4) or a similar method is used to estimate a value for reserves. A single sample of each variable is taken randomly from each probability distribution and used to calculate a single value of the dependent variable. This procedure is repeated a large number of times to ultimately create a frequency distribution curve that describes the range of estimates of reserves and the probabilities of achieving particular estimates. Once the measures of central tendency (the mean or arithmetic average, the mode or "most likely" value, and the median or "middle" value) and the dispersion (range, standard deviation, and percentiles), have been determined using this technique, estimates of reserves may be assigned to each of the proved, probable, and possible categories. The assignment of the estimates of reserves to the respective categories should be consistent with the probabilities outlined in the reserves definitions, proved reserves being those with an 80 percent or greater probability, and probable and possible reserves having lower probabilities. The relative cumulative frequency distribution curves may be used as the basis for the assignment of estimated quantities to the reserves categories. Again, the evaluator must clearly describe the supporting rationale for the categorization ofestimates ofreserves. Like the estimates derived using the deterministic procedure, the probable and possible reserves should be adjusted (risk-weighted). Since the probabilities have been established through the probabilistic process, they should be used to adjust the respective estimates. It should be noted that the probability associated with the estimate of reserves for a pool should increase as the pool is developed and produced over a period of time. As the overall probability of recovery increases, the estimate of the proportion of reserves considered to be proved is likely to increase, with a diminishing proportion in the probable and possible categories. The objective of the evaluator should be to minimize the extent to which it is necessary to reduce estimates of proved reserves over the life of a pool for reasons other than production, although there may be circumstances (i.e., a significant price decline) where such reductions are necessary.

11

,

DETERMINATION OFOIL AND GAS RESERVES

3.3

GUIDELINES FOR SPECIFIC METHODS

The guidelines and examples that follow are designed to provide guidance for evaluators on the calculation of proved, probable and possible reserves, using the following methods for determining reserves: • Volumetric • Material balance • Decline curve analysis • Reservoir simulation This section also deals with the calculation of reserves of natural gas liquids (NGLs) and sulphur. It must be emphasized that the guidelines touch on some key factors related to reserves estimation, but are not all-inclusive. In the final analysis, the calculation and categorization of reserves depend upon the judgement ofthe evaluator as to the probability of recovery of the reserves of oil and gas. It is intended that the guidelines will lead to more uniform practices of reserves calculation in each category, and thus to reserves estimates that will be more comparable and consistent throughout the industry, the financial community, and the government agencies that use them.

3.3.1

Volumetric Method

The volumetric method is the most commonly used approach to estimating reserves in the early stages of production from an oil or gas field. As more data become available, the estimate may be refined, sometimes through the use of other reserves estimation methods. Often the volumetric estimates are useful for comparison with other methods. The volumetric method is used by employing the standard reserves equation with the appropriate choice of parameters. For various parameters in the equation, the guidelines provide suggestions for choosing the appropriate value, according to the category of reserves being calculated. Pool Area

The parameter that often has the greatest variability in the reserves equation is the area chosen to represent the areal extent of the pool. Thus, the choice of the value for the area plays a particularly important role in computing reserves in each category.

Single-Well Pools

For single-well pools, the area must be consistent with the reserves category, recognizing the geological and engineering information with respect to the single wellbore and the geological and other information available for single-well pools in similar formations. In the case of an isolated gas well with little or no geological control, it is a frequent practice to assign reserves to one section,* a frequently used regulatory spacing for gas wells. However, one section should only be .assigned as proved reserves if a review of similar wells in the same or a similar formation has satisfied the evaluator that such an area can be assigned 'with a probability of 80 percent or more. If the review of similar wells shows that a smaller area, such as one halfsection or even one eighth-section, can be expected to have a high degree of probability, this reduced area should be used for proved reserves. On the other hand, in situations such as a blanker sandstone, the review of similar wells may justify the assignment of more than one section if it can be demonstrated with high probability that the well will drain reserves associated with the larger area. In the event that an evaluator is reasonably confident that gas would be recovered from an area, say one section, but not with a high enough probability for the reserves to totally qualify as proved, then some lesser area for which there is a high probability, say one halfsection, should be assigned as the proved area. The remaining half-section ofthe normal spacing unit might then be assigned to the probable or possible category, depending on the degree ofprobability that such reserves would be recovered. For single oil wells, the area assigned would generally be less than for gas wells because the flow characteristics for oil result in smaller drainage areas. A typical practice is to assign proved reserves to areas ranging from one quarter-section for light crude oils to one sixteenth-section or less for heavy crude oils. Such assignments should be made only when a review of similar wells demonstrates that such reserves can be expected with a probability of 80 percent or more. The process used to assign areas to single oil wells should otherwise be similar to that for gas wells, with an assignment that reflects the probability that the area can be drained at the level required for each reserves classification.

*One section = 259 hectares, 640 acres,or 1 square mile.

12

z

GUIDELINES FOR ESTIMATION OF OIL AND GAS RESERVES

In certain cases such as sheet sandstones, even though only one well has penetrated gas or oil, information may be available, as a result of knowledge about nearby abandonments and the regional geology, that justifies the preparation of an isopach map. This situation is illustrated for an oil pool in Figure 3.3-1, which shows the zero pay limit. If the probability of a one quartersection pool is very high, based on a study of similar pools in the area, then the one quarter-section containing the well could be assigned as proved reserves. The remaining three quarter-section parcels offsetting the well, and within the zero limits ofthe isopach map, could also be assigned reserves as additional proved or probable or possible depending on the degree of probability that the oil will be recovered. These reserves, however, should be in the undeveloped category. The assigrunent of reserves for single gas wells with considerable geological control can be handled in a manner similar to that detailed for the oil well in Figure 3.3-1, except that the estimated drainage area for gas will usually be larger, depending on the available geological and other data. An area larger than the assigned area determined as described may be used

I

------------

\ -, --

Figure 3.3-1

0

t-...

Multi-Well Pools

In multi-well pools, the area between wells should be considered to contain proved reserves if the areas assigned on a single-well basis overlap or are separated by a very small area, or if material balance calculations or production data and pressure response clearly demonstrate that the wells are in the same pool. There will, however, be many situations where such conclusive information is not available and the evaluators must use their judgement, based on geological and other data, regarding the areal extent and the assignment of additional reserves to adjacent areas. For wells that are in separate pools, the preceding methodology for assigning reserves for single-wellpools should be followed. If more than one well can be included in a pool, the type of procedure described in the following example might be used. Example

Figure 3.3-2 shows the zero pay limits for a multi-well conventional gas pool. It is important to emphasize that

",--

-- L-0

depending on information on pressure, drillstem test results, and seismic data.

\

0

-~---~-~-~--

•

WELL LEGEND

o

Location

--

Abandoned 011

* •

--

)

Gas

[7 1 mi 1 km

Single Well Oil Pool with Good Geological Control

13

DETERMINATION OF OIL AND GASRESERVES

RANGE 36

~

/

31

-.

V

1/

\

/

\

Figure 3.3-2

~

6

/

1/

31

~

f-

WELL LEGEND

0 1

36

-