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Imperial College Lectures In Petroleum Engineering, The - Volume 3: Topics In Reservoir Management [Kõva köide]

(Kuwait Oil Company), (Petroleum Consulting And Training), (Imperial College London, Uk), (Imperial College London, Uk), (Imperial College London, Uk)
  • Formaat: Hardback, 268 pages
  • Ilmumisaeg: 24-Oct-2017
  • Kirjastus: World Scientific Europe Ltd
  • ISBN-10: 1786342847
  • ISBN-13: 9781786342843
Teised raamatud teemal:
Imperial College Lectures In Petroleum Engineering, The - Volume 3: Topics In Reservoir ManagementSuurem pilt
  • Formaat: Hardback, 268 pages
  • Ilmumisaeg: 24-Oct-2017
  • Kirjastus: World Scientific Europe Ltd
  • ISBN-10: 1786342847
  • ISBN-13: 9781786342843
Teised raamatud teemal:
Püsilink: https://www.kriso.ee/db/9781786342843.html
Märksõnad:
This book covers several aspects of reservoir management, from initial analysis to enhanced recovery methods, simulation, and history matching. Split into four parts, part one provides readers with an introduction to the physical properties of reservoir rocks. Part two provides an introduction to enhanced recovery methods used for conventional oil production. Part three shows how numerical methods can be used to simulate the behaviour of oil and gas reservoirs. Finally, part four looks at history matching of reservoirs through the building of numerical models using past data, in order to provide best practice for future reservoir development and management.Written as the third volume in the Imperial College Lectures in Petroleum Engineering, and based on lectures that have been given in the world-renowned Imperial College Masters Course in Petroleum Engineering, Topics in Reservoir Management provides the basic information needed for students and practitioners of petroleum engineering and petroleum geoscience.
Preface v
About the Authors vii
Chapter 1 Introduction to Rock Properties 1(46)
Robert W. Zimmerman
1.1 Introduction
1(1)
1.2 Porosity and Saturation
2(5)
1.2.1 Definition of Porosity
2(2)
1.2.2 Heterogeneity and "Representative Elementary Volume"
4(2)
1.2.3 Saturation
6(1)
1.3 Permeability and Darcy's Law
7(11)
1.3.1 Darcy's Law
7(4)
1.3.2 Units of Permeability
11(1)
1.3.3 Relationship between Permeability and Pore Size
12(2)
1.3.4 Permeability of Layered Rocks
14(3)
1.3.5 Permeability Heterogeneity
17(1)
1.4 Surface Tension, Wettability and Capillarity
18(14)
1.4.1 Surface Tension
18(3)
1.4.2 Capillary Pressure
21(1)
1.4.3 Contact Angles
22(3)
1.4.4 Capillary Rise
25(2)
1.4.5 Oil-Water Transition Zone
27(3)
1.4.6 Leverett J-Function
30(2)
1.5 Two-Phase Flow and Relative Permeability
32(3)
1.5.1 Concept of Relative Permeability
32(2)
1.5.2 Irreducible Saturations
34(1)
1.6 Electrical Resistivity
35(6)
1.7 Fluid and Pore Compressibility
41(3)
1.7.1 Fluid Compressibility
41(1)
1.7.2 Pore Compressibility
42(2)
References
44(1)
Questions
45(2)
Chapter 2 Introduction to Enhanced Recovery Processes for Conventional Oil Production 47(62)
Samuel C. Krevor
Ann H. Muggeridge
2.1 Introduction: Definition, Techniques and the Global Role of EOR
47(6)
2.1.1 The Aims of this Module
47(1)
2.1.2 Definitions and Techniques
48(2)
2.1.3 The Role of EOR in Current and Future Global Oil Production
50(3)
2.2 Enhancing the Recovery Factor
53(14)
2.2.1 The Recovery Factor
53(2)
2.2.2 Limits on Microscopic Displacement Efficiency
55(4)
2.2.3 Limits on Macroscopic Displacement Efficiency
59(8)
2.3 Gas Injection
67(25)
2.3.1 Phase Equilibrium for Gas Drives
68(11)
2.3.2 Transport in Two-Phase Multi-Component Systems
79(6)
2.3.2.1 Review of the Buckley-Leverett solution
80(2)
2.3.2.2 Two-component, two-phase displacement
82(3)
2.3.3 Fractional Flow Theory and Water Alternating Gas Injection
85(5)
2.3.4 Three-Phase Flow
90(2)
2.3.4.1 Fractional flow theory applied to three-phase flow
90(1)
2.3.4.2 Models for three-phase relative permeability
91(1)
2.4 Chemical EOR: Polymers and Low Salinity Flooding
92(8)
2.4.1 Polymer Flooding
93(4)
2.4.2 Low Salinity Water Flooding
97(3)
2.5 Practical Considerations
100(4)
References
104(5)
Chapter 3 Numerical Simulation 109(100)
Dave Waldren
3.1 Reservoir Models
109(5)
3.1.1 Introduction
109(1)
3.1.2 Physical Models
110(2)
3.1.2.1 Analogue models
110(1)
3.1.2.2 Comprehensive models
111(1)
3.1.2.3 Elemental models
111(1)
3.1.3 Mathematical Models
112(1)
3.1.4 Numerical Models
112(1)
3.1.5 Models as Comparative Tools
113(1)
3.2 Equations and Terminology
114(17)
3.2.1 Mass Conservation
114(1)
3.2.2 Darcy's Law
115(2)
3.2.3 Diffusivity Equation
117(2)
3.2.4 Finite Difference
119(2)
3.2.5 Implicit and Explicit Formulation
121(4)
3.2.6 Dispersion and Weighting
125(1)
3.2.7 Nonlinearity and Outer Iterations
126(1)
3.2.8 Linear Solvers
127(4)
3.3 Buckley-Leverett Displacement
131(3)
3.4 Reservoir Models
134(3)
3.4.1 Model Components
134(1)
3.4.1.1 Reservoir description
134(1)
3.4.1.2 Initialisation
134(1)
3.4.1.3 Model control
134(1)
3.4.1.4 Production data
135(1)
3.4.1.5 Output
135(1)
3.4.2 Model Types
135(2)
3.4.2.1 Cross-sectional models
136(1)
3.4.2.2 Sector models
136(1)
3.4.2.3 Cylindrical single well models
137(1)
3.4.2.4 Full field models
137(1)
3.5 Grid Systems
137(10)
3.5.1 Cartesian Systems
139(1)
3.5.2 Cylindrical Systems
140(1)
3.5.3 Stream Line Grids
141(1)
3.5.4 Special Connections
142(2)
3.5.5 Corner Point Representation
144(1)
3.5.6 Local Grid Refinement
144(1)
3.5.7 Unstructured Grids
145(1)
3.5.8 Surface Constraints
146(1)
3.5.9 Non-Orthogonality
147(1)
3.6 Rock Properties
147(14)
3.6.1 Core Data
148(9)
3.6.1.1 Routine core analysis
148(2)
3.6.1.2 Geocellular up-scaling
150(1)
3.6.1.3 Special core analysis
150(7)
3.6.2 Log Data
157(3)
3.6.3 Test Data
160(1)
3.7 Model Relative Permeability
161(13)
3.7.1 Data Manipulation
161(4)
3.7.2 Three-Phase Relative Permeability
165(1)
3.7.3 Vertical Equilibrium
166(2)
3.7.4 Pseudo Relative Permeability
168(5)
3.7.5 Well Pseudo Relative Permeability
173(1)
3.7.6 Summary
174(1)
3.8 Model Capillary Pressure
174(5)
3.8.1 Manipulation of Capillary Pressure
176(2)
3.8.2 Vertical Equilibrium
178(1)
3.8.3 Summary
179(1)
3.9 Fluid Properties and Experiments
179(11)
3.9.1 Single Component Properties
180(1)
3.9.2 Properties of Mixtures
180(2)
3.9.3 Hydrocarbon Types
182(1)
3.9.4 Definitions
183(3)
3.9.5 Experiments
186(4)
3.9.5.1 Constant composition expansion
186(1)
3.9.5.2 Differential liberation
186(4)
3.9.5.3 Constant volume depletion
190(1)
3.9.5.4 Separator tests
190(1)
3.10 Model Fluid Properties
190(7)
3.10.1 Black Oil Fluid Properties
190(3)
3.10.2 Data Manipulation
193(3)
3.10.3 Spatial Variations
196(1)
3.10.3.1 Variable bubble point
197(1)
3.10.3.2 Variable Api gravity
197(1)
3.11 Aquifer Treatment
197(4)
3.11.1 Hurst Van Everdingen
198(1)
3.11.2 Carter Tracy
199(1)
3.11.3 Fetkovitch
199(1)
3.11.4 Numerical Aquifer
200(1)
3.12 Model Well and Production Data
201(8)
3.12.1 Well Inflow
201(2)
3.12.2 Production Control Data
203(2)
3.12.2.1 Targets
203(1)
3.12.2.2 Constraints
204(1)
3.12.2.3 Actions
205(1)
3.12.3 Practical Considerations
205(6)
3.12.3.1 History match
205(1)
3.12.3.2 Prediction
206(3)
Chapter 4 History Matching 209(36)
Deryck Bond
4.1 Introduction
209(2)
4.2 Context of the History Match Study
211(4)
4.2.1 The Business Context of the Study
211(1)
4.2.2 Relation to Reservoir Development/Management
212(1)
4.2.3 The Work Flow Context of the Study
213(2)
4.3 Static and Dynamic Data/Static and Dynamic Models
215(2)
4.3.1 Static and Dynamic Data
215(1)
4.3.2 Dynamic Data and the Static Model
216(1)
4.4 Issues Related to Reservoir Simulation/Up-Scaling
217(2)
4.4.1 Issues Related to Grid Size/Numerical Resolution
217(1)
4.4.2 Issues Related to Representation Rate Variation With Time
217(1)
4.4.3 Issues Related to Representation of Well In-Flow in the Simulator
218(1)
4.5 Details of a "Conventional" Deterministic History Match Study
219(24)
4.5.1 Preparatory Work-Definition of Aims
219(1)
4.5.2 Data Review/Well Histories
219(2)
4.5.3 Preparatory Work-Data Acquisition Opportunities
221(1)
4.5.4 Preparatory Work-"Classical" Reservoir Engineering Calculations/Part Field Models
221(1)
4.5.5 Review of the Simulation Model (and Geological Model)
222(1)
4.5.6 Outline of Approach to Matching the Model
223(1)
4.5.7 How Well Should We Aim to Match Data?
224(2)
4.5.8 Assessing the "Goodness" of a Match
226(1)
4.5.9 Well Controls During the History Match
227(2)
4.5.10 Initial Simulation Runs
229(1)
4.5.11 Review of Scope for Changing Model Input Parameters
230(1)
4.5.12 Sensitivity Study
231(1)
4.5.13 The History Matching Process
232(1)
4.5.14 Matching Pressure
233(3)
4.5.14.1 Pressure match example
234(2)
4.5.15 Matching Fluid Movement
236(2)
4.5.16 Matching Water Movement-Example 1
238(2)
4.5.17 Matching Water Movement-Example 2
240(1)
4.5.18 Matching Water Movement-Example 3
241(1)
4.5.19 Matching Well Pressures/Detailed Well Performance
242(1)
4.5.20 The Transition to Prediction
243(1)
4.6 Automatic and Computer-Assisted History Matching/Multiple Matches
243(1)
4.7 Conclusions 243
References
244(1)
Index 245