Practice of Reservoir Engineering

Foreword to the revised edition vii Preface ix In Memoriam xiii Nomenclature xxi Introduction to Reservoir Engineering 1(28) Activities in reservoir engineering 1(3) Observations 1(1) Assumptions 2(1) Calculations 3(1) Development decisions 4(1) Basic themes of the text 4(7) Simplicity 4(1) What works and what does not --- and why? 5(1) Analytical methods 6(1) Offshore versus onshore developments 7(4) The role of reservoir engineers 11(6) Technical responsibilities of reservoir engineers 17(9) Appraisal 18(1) End of appraisal 19(1) Development 19(7) The physical principles of reservoir engineering 26(3) References 28(1) The Appraisal of Oil and Gas Fields 29(44) Introduction 29(1) Pressure-volume-temperature fluid properties for oil 29(15) Basic PVT parameters 29(4) Sampling reservoir fluids 33(4) Laboratory experiments 37(3) Comparison of laboratory and field PVT data 40(3) PVT for volatile oil systems 43(1) Calculation of the stock tank oil initially in place 44(1) Field unitization/equity determination 45(5) Oil initially in place (OIIP) 46(1) Stock tank oil initially in place (STOIIP) 47(1) Recoverable reserves 48(1) Movable oil 49(1) Calculation of gas initially in place (GIIP) 50(1) Pressure-depth plotting 51(7) Gas field appraisal 53(5) Application of the repeat formation tester 58(5) Pulse testing using the repeat formation tester 63(3) Appraisal well testing 66(4) Extended well testing 70(3) References 72(1) Material Balance Applied to Oilfields 73(64) Introduction 73(1) Derivation of the cumulative material balance for oil reservoirs 74(4) Left-hand side (underground withdrawal --- rb) 75(1) Right-hand side (expansion plus water influx) 75(3) Necessary conditions for application of material balance 78(3) Solving the material balance (knowns and unknowns) 81(1) Comparison between material balance and numerical simulation modelling 82(3) The opening move in applying material balance 85(1) Volumetric depletion fields 86(24) Depletion above the bubble point 86(1) Material balance applied to an understurated volatile olifield 87(5) Identification of the drive mechanism and calculation of the STOIIP for a depletion type reservoir 92(6) Depletion below the bubble point (solution gas drive) 98(8) Application of the Muskat material balance in history matching and prediction of solution gas drive 106(4) Water influx calculations 110(7) Carter-Tracy water influx calculations 110(1) Aquifer ``fitting'' using the method of Havlena-Odeh 111(1) History matching using the Carter-Tracy aquifer model and the ``fitting'' technique of Havlena and Odeh 112(4) History matching with numerical simulation models 116(1) Gascap drive 117(7) Application of material balance to the early production performance of a gascap drive field 119(5) Compaction drive 124(9) Compaction drive 128(5) Conclusion 133(4) References 134(3) Oilwell Testing 137(174) Introduction 137(1) Essential observations in well testing 138(7) Rate, pressure, time 138(1) Core/log data 139(2) RFT, pressure-depth profiles 141(1) Geological model 142(1) Drive mechanism 142(1) PVT fluid properties 143(1) Well completion 143(1) Equipment 143(1) Tests in neighbouring wells 144(1) Well testing literature 145(2) The purpose of well testing 147(7) Appraisal well testing 147(5) Development well testing 152(2) Basic, radial flow equation 154(5) Radial diffusivity equation 154(2) Investigation of the validity of linearizing the basic radial flow equation by the method of deletion of terms 156(3) Constant terminal rate solution of the radial diffusivity equation 159(9) Bounded reservoir conditions 161(4) Steady-state condition 165(3) The transient constant terminal rate solution of the radial diffusivity equation 168(8) Difficulties in application of the constant terminal rate solution of the radial diffusivity equation 176(1) Superposition of CTR solutions 177(3) Single-rate drawdown test 180(3) Inspection of the flowing pressure 181(1) Time derivative of drawdown pressures 182(1) Pressure buildup testing (general description) 183(2) Miller, Dyes, Hutchinson (MDH) pressure buildup analysis 185(5) Horner pressure buildup analysis 190(6) Some practical aspects of appraisal well testing 196(9) Determination of the initial pressure 196(1) Afterflow 196(3) Pressure buildup test: infinite acting reservoir 199(6) Practical difficulties associated with Horner analysis 205(7) Flowing time/superposition 206(4) The meaning of p* 210(2) The influence of fault geometries on pressure buildups in appraisal well testing 212(18) General description 212(1) Single fault 213(4) Pressure buildup test: single fault analysis 217(6) Some general considerations in defining fault positions 223(5) Definition of more complex fault geometries 228(2) Application of the exponential integral 230(5) Example: interference between oilfields 231(4) Pressure support during appraisal well testing 235(18) Pressure buildup performance 236(2) Dimensionless pressure-radius of investigation 238(2) Miller, Dyes, Hutchinson interpretation 240(1) Horner interpretation 241(4) Variable skin factor (well clean-up) 245(1) Pressure buildup test: steady-state flow condition 246(7) Well testing in developed fields 253(26) Pressure buildup analysis method of Horner-MBH for bounded reservoir systems 254(4) Pressure buildup analysis method of MDH-Dietz for bounded reservoir systems 258(2) Buildup analysis for systems with constant pressure or mixed boundary conditions 260(4) Example well test 264(7) Practical difficulties in testing development wells 271(2) Relationship between wellbore and numerical simulation grid block pressures 273(2) Afterflow 275(1) Extended well testing 275(2) Radius of investigation 277(2) Multi-rate flow testing 279(11) Two-rate flow testing 280(4) Example well test 284(4) Selective inflow performance (SIP) testing 288(2) Log-log type curves 290(9) Conventional type-curve interpretation 290(4) Time derivative type curves 294(2) Practical aspects 296(3) Conclusions 299(12) The elusive straight line 299(1) Saving money in well testing 300(4) Identification of the correct early straight line 304(3) References 307(4) Waterdrive 311(162) Introduction 311(1) Planning a waterflood 312(12) Purpose 312(3) Permeability 315(1) Oil viscosity 316(1) Oil volatility 317(3) Overpressures 320(3) Reservoir depth 323(1) Engineering design of waterdrive projects 324(12) Production plateau rate 324(2) Number of production/injection wells 326(1) Surface production/injection facilities 327(3) Topsides facilities design for an offshore waterdrive field 330(6) The basic theory of waterdrive in one dimension 336(30) Rock relative permeabilities 337(2) Mobility ratio 339(2) Fractional flow 341(4) The Buckley-Leverett displacement theory 345(3) Welge displacement efficiency calculations 348(7) Input of rock relative permeabilities to numerical simulation and analytical reservoir models 355(7) Laboratory experiments 362(4) The description of waterdrive in heterogeneous reservoir sections 366(7) Reservoir heterogeneity 366(3) Recipe for evaluating vertical sweep efficiency in heterogeneous reservoirs 369(4) Waterdrive under segregated flow conditions (vertical equilibrium) 373(32) Basic description 373(2) Data requirements and interpretation for input to the generation of pseudo-relative permeabilities 375(9) Catering for the presence of edge water in VE flooding 384(2) VE displacement in a homogeneous acting reservoir 386(2) Water-oil displacement under the vertical equilibrium condition 388(10) The influence of distinctive permeability distributions on the vertical sweep efficiency for the VE-flooding condition 398(7) Waterdrive in sections across which there is a total lack of pressure equilibrium 405(22) Reservoir environment 405(4) Data requirements and interpretation for input in the generation of pseudo-relative permeabilities 409(2) Stiles method 411(2) Dykstra-Parsons method 413(3) Well workovers 416(1) History matching and prediction of a waterdrive field performance using the method of Stiles 416(7) Dykstra-Parsons displacement calculations 423(4) The numerical simulation of waterdrive 427(9) Purpose 427(2) Generation of pseudo-relative permeabilities using cross-sectional simulation modelling 429(6) Areal numerical simulation modelling 435(1) The examination of waterdrive performance 436(22) Starting point 440(1) Natural waterdrive 441(1) Prediction 442(1) Perturbations in the fractional flow 443(1) Example---North Sea Waterdrive Field 443(5) Example---the East Texas Field 448(6) The influence of operational activity 454(3) Comment 457(1) Difficult waterdrive fields 458(15) Field A 458(5) Field B 463(6) The overall management of waterdrive fields 469(1) References 470(3) Gas Reservoir Engineering 473(64) Introduction 473(1) PVT requirements for gas-condensate systems 473(8) Equation of state 475(1) Surface/reservoir volume relationships 476(1) Constant volume depletion (CVD) experiments 477(2) Gas compressibility and viscosity 479(1) Semi-empirical equations of state (EOS) 479(2) Gas field volumetric material balance 481(25) Appropriateness in application 481(2) Havlena-Odeh interpretation 483(2) p/Z-interpretation technique 485(4) Example field 489(11) Gas field development 500(6) The dynamics of the immiscible gas-oil displacement 506(17) Mobility ratio 507(1) Heterogeneity/gravity 508(5) Displacement condition 513(4) Immiscible gas drive in a heterogeneous reservoir under the VE condition 517(6) Dry gas recycling in retrograde gas-condensate reservoirs 523(14) Mobility ratio 524(2) Heterogeneity/gravity 526(3) Vertical sweep efficiency 529(1) Generation of pseudo-relative permeabilities for dry gas recycling 530(5) References 535(2) Subject Index 537