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E-raamat: Enhanced Oil Recovery Field Case Studies

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Edited by (Professor, Bob L. Herd Department of Petroleum Engineering, Texas Tech University, USA)
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  • Ilmumisaeg: 10-Apr-2013
  • Kirjastus: Gulf Professional Publishing
  • Keel: eng
  • ISBN-13: 9780123865465
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Enhanced Oil Recovery Field Case StudiesSuurem pilt
  • Formaat: PDF+DRM
  • Ilmumisaeg: 10-Apr-2013
  • Kirjastus: Gulf Professional Publishing
  • Keel: eng
  • ISBN-13: 9780123865465
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Petroleum engineers mostly from oil and equipment companies draw on the field experience of specialists in enhanced oil recovery as well as from the technical literature and other sources to provide a reference to all aspects of enhanced oil recovery. The topics include polymer flooding practice in Daqing, alkaline flooding, surfactant enhanced oil recovery in carbonate reserves, facility requirements for implementing a chemical enhanced oil recovery project, the use of microorganisms to enhance oil recovery, and the cold production of heavy oil. Annotation ©2013 Book News, Inc., Portland, OR (booknews.com)

Enhanced Oil Recovery Field Case Studies bridges the gap between theory and practice in a range of real-world EOR settings. Areas covered include steam and polymer flooding, use of foam, in situ combustion, microorganisms, "smart water"-based EOR in carbonates and sandstones, and many more.

Oil industry professionals know that the key to a successful enhanced oil recovery project lies in anticipating the differences between plans and the realities found in the field. This book aids that effort, providing valuable case studies from more than 250 EOR pilot and field applications in a variety of oil fields. The case studies cover practical problems, underlying theoretical and modeling methods, operational parameters, solutions and sensitivity studies, and performance optimization strategies, benefitting academicians and oil company practitioners alike.

  • Strikes an ideal balance between theory and practice
  • Focuses on practical problems, underlying theoretical and modeling methods, and operational parameters
  • Designed for technical professionals, covering the fundamental as well as the advanced aspects of EOR

Arvustused

"Petroleum engineers mostly from oil and equipment companies draw on the field experience of specialists in enhanced oil recovery as well as from the technical literature and other sources to provide a reference to all aspects of enhanced oil recovery." --Reference and Research Book News, August 2013

Muu info

The book provides important case studies related to over 250 EOR pilot and field applications in a variety of oil fields.
Preface xix
Contributors xxi
Acknowledgments xxiii
1 Gas Flooding
1(22)
Russell T. Johns
Birol Dindoruk
1.1 What Is Gas Flooding?
1(1)
1.2 Gas Flood Design
2(1)
1.3 Technical and Economic Screening Process
3(2)
1.4 Gas Injection Design and WAG
5(4)
1.5 Phase Behavior
9(3)
1.5.1 Standard (or Basic) PVT Data
9(1)
1.5.2 Swelling Test
9(1)
1.5.3 Slim-Tube Test
10(1)
1.5.4 Multicontact Test
11(1)
1.5.5 Fluid Characterization Using an Equation-of-State
12(1)
1.6 MMP and Displacement Mechanisms
12(4)
1.6.1 Simplified Ternary Representation of Displacement Mechanisms
13(2)
1.6.2 Displacement Mechanisms for Field Gas Floods
15(1)
1.6.3 Determination of MMP
15(1)
1.7 Field Cases
16(5)
1.7.1 Slaughter Estate Unit GO2 Flood
16(1)
1.7.2 Immiscible Weeks Island Gravity Stable CO2 Flood
17(2)
1.7.3 Jay Little Escambia Creek Nitrogen Flood
19(1)
1.7.4 Overview of Field Experience
20(1)
1.8 Concluding Remarks
21(2)
Abbreviations
21(1)
References
22(1)
2 Enhanced Oil Recovery by Using CO2 Foams: Fundamentals and Field Applications
23(40)
S. Lee
S.I. Kam
2.1 Foam Fundamentals
23(11)
2.1.1 Why CO2 Is so Popular in Recent Years?
23(1)
2.1.2 Why CO2 Is of Interest Compared to Other Gases?
24(1)
2.1.3 Why CO2 Is Injected as Foams?
24(1)
2.1.4 Foam in Porous Media: Creation and Coalescence Mechanisms
25(1)
2.1.5 Foam in Porous Media: Three Foam States and Foam Generation
25(2)
2.1.6 Foam in Porous Media: Two Strong-Foam Regimes-High-Quality and Low-Quality Regimes
27(1)
2.1.7 Modeling Foams in Porous Media
28(2)
2.1.8 Foam Injection Methods and Gravity Segregation
30(1)
2.1.9 CO2-Foam Coreflood Experiments
31(1)
2.1.10 Effect of Subsurface Heterogeneity-Limiting Capillary Pressure and Limiting Water Saturation
32(2)
2.1.11 Foam-Oil Interactions
34(1)
2.2 Foam Field Applications
34(11)
2.2.1 The First Foam Field Applications, Siggins Field, Illinois
34(1)
2.2.2 Steam Foam EOR, Midway Sunset Field, California
35(2)
2.2.3 CO2/N2 Foam Injection in Wilmington, California (1984)
37(1)
2.2.4 CO2-Foam Injection in Rock Creek, Virginia (1984-1985)
38(1)
2.2.5 CO2-Foam Injection in Rangely Weber Sand Unit, Colorado (1988-1990)
39(1)
2.2.6 CO2-Foam Injection in North Ward-Estes, Texas (1990-1991)
40(2)
2.2.7 CO2-Foam Injection in the East Vacuum Grayburg/San Andres Unit, New Mexico (1991-1993)
42(1)
2.2.8 CO2-Foam Injection in East Mallet Unit, Texas, and McElmo Creek Unit, Utah (1991-1994)
43(2)
2.3 Typical Field Responses During CO2-Foam Applications
45(7)
2.3.1 Diversion from High- to Low-Permeability Layers
45(1)
2.3.2 Typical Responses from Successful SAG Processes
46(5)
2.3.3 Typical Responses from Successful Surfactant-Gas Coinjection Processes
51(1)
2.4 Conclusions
52(11)
Acknowledgment
53(1)
Appendix-Expression of Gas-Mobility Reduction in the Presence of Foams
53(6)
References
59(4)
3 Polymer Flooding-Fundamentals and Field Cases
63(20)
James J. Sheng
3.1 Polymers Classification
63(1)
3.2 Polymer Solution Viscosity
64(1)
3.2.1 Salinity and Concentration Effects
64(1)
3.2.2 Shear Effect
65(1)
3.2.3 pH Effect
65(1)
3.3 Polymer Flow Behavior in Porous Media
65(5)
3.3.1 Polymer Viscosity in Porous Media
65(2)
3.3.2 Polymer Retention
67(1)
3.3.3 Inaccessible Pore Volume
68(1)
3.3.4 Permeability Reduction
69(1)
3.3.5 Relative Permeabilities in Polymer Flooding
70(1)
3.4 Mechanisms of Polymer Flooding
70(2)
3.5 Polymer Mixing
72(1)
3.6 Screening Criteria
72(1)
3.7 Field Performance and Field Cases 73
3.7.1 Overall Field Performance
73(1)
3.7.2 Polymer Flooding in a Very Heterogeneous Reservoir
74(1)
3.7.3 Polymer Flooding Using High MW and High Concentration Polymer
75(1)
3.7.4 Polymer Flooding in Heavy Oil, Reservoirs
76(1)
3.7.5 Polymer Flooding in the Marmul Field, Omap
77(1)
3.7.6 Polymer Flooding in a Carbonate Reservoir-Vacuum Field, New Mexico
78(1)
3.8 Post-Polymer Conformance Control Using Movable Gel
78(5)
References
80(3)
4 Polymer Flooding Practice in Daqing
83(34)
Dongmei Wang
4.1 Mechanism
83(4)
4.1.1 Mobility Control
83(1)
4.1.2 Profile Modification
84(2)
4.1.3 Microscopic Mechanism
86(1)
4.2 Reservoir Screening
87(4)
4.2.1 Reservoir Type
87(1)
4.2.2 Reservoir Temperature
88(1)
4.2.3 Reservoir Permeability
88(1)
4.2.4 Reservoir Heterogeneity
89(1)
4.2.5 Oil Viscosity
90(1)
4.2.6 Formation Water Salinity
90(1)
4.3 Key Points of Polymer Flood Design
91(11)
4.3.1 Well Pattern Design and Combination of Oil Strata
92(2)
4.3.2 Injection Sequence Options
94(1)
4.3.3 Injection Formulation
95(6)
4.3.4 Individual Production and Injection Rate Allocation
101(1)
4.4 Polymer Flooding Dynamic Performance
102(2)
4.4.1 Stages and Dynamic Behavior of Polymer Flooding Process
102(2)
4.4.2 Problems and Treatments During Different Phases
104(1)
4.5 Surface Facilities
104(3)
4.5.1 Mixing and Injection
105(1)
4.5.2 Produced Water Treatment
106(1)
4.6 A Field Case
107(4)
4.6.1 Well Pattern and Oil Strata Combination
107(1)
4.6.2 Polymer Injection Case Design
108(1)
4.6.3 Polymer Performance Prediction
109(2)
4.6.4 Polymer Performance Evaluation
111(1)
4.7 Conclusions
111(6)
Nomenclature
112(2)
References
114(3)
5 Surfactant-Polymer Flooding
117(26)
James J. Sheng
5.1 Introduction
117(1)
5.2 Surfactants
117(2)
5.2.1 Parameters to Characterize Surfactants
118(1)
5.3 Types of Microemulsions
119(1)
5.4 Phase Behavior Tests
120(1)
5.5 Interfacial Tension
121(1)
5.6 Viscosity of Microemulsion
122(1)
5.7 Capillary Number
122(1)
5.8 Capillary Desaturation Curve
123(1)
5.9 Relative Permeability
123(1)
5.10 Surfactant Retention
124(1)
5.11 SP Interactions
125(1)
5.12 Displacement Mechanisms
126(1)
5.13 Screening Criteria
126(1)
5.14 Field Performance Data
126(1)
5.15 Field Cases
127(16)
5.15.1 Loma Novia Field Low-Tension Waterflooding
127(1)
5.15.2 Wichita County Regular Field Low-Tension Waterflooding
128(2)
5.15.3 El Dorado M/P Pilot
130(2)
5.15.4 Sloss M/P Pilot
132(2)
5.15.5 Torchlight M/P Pilot
134(2)
5.15.6 Delaware-Childers M/P Project
136(1)
5.15.7 Minas SP Project Preparation
136(3)
5.15.8 SP Flooding in the Gudong Field, China
139(2)
References
141(2)
6 Alkaline Flooding
143(26)
James J. Sheng
6.1 Introduction
143(1)
6.2 Comparison of Alkalis Used in Alkaline Flooding
143(1)
6.3 Alkaline Reactions
144(2)
6.3.1 Alkaline Reaction with Crude Oil
144(1)
6.3.2 Alkaline Interaction with Rock
145(1)
6.3.3 Alkaline-Reactions with water
146(1)
6.4 Recovery Mechanisms
146(1)
6.5 Field Injection Data
147(2)
6.6 Application Conditions of Alkaline Flooding
149(2)
6.7 Field Cases
151(14)
6.7.1 Russian Tpexozephoe Field (Abbreviated as Field T)
151(3)
6.7.2 Russian Field (Abbreviated as Field W)
154(1)
6.7.3 Hungarian H Field
155(1)
6.7.4 North Gujarat Oil Field, India
156(1)
6.7.5 Whittier Field in California
157(1)
6.7.6 Torrance Field in California
158(1)
6.7.7 Wilmington Field in California
159(5)
6.7.8 Court Bakken Heavy Oil Reservoir in Saskatchewan, Canada
164(1)
6.8 Conclusions
165(4)
References
165(4)
7 Alkaline-Polymer Flooding
169(10)
James J. Sheng
7.1 Introduction
169(1)
7.2 Interactions Between Alkali and Polymer
169(1)
7.3 Synergy Between Alkali and Polymer
169(2)
7.4 Field AP Applications
171(7)
7.4.1 Almy Sands (Isenhour Unit) in Wyoming, USA
171(1)
7.4.2 Moorcroft West in Wyoming, USA
172(2)
7.4.3 Thompson Creek Field in Wyoming, USA
174(1)
7.4.4 David Lloydminster "A" Pool in Canada
174(2)
7.4.5 Etzikom Field in Alberta, Canada
176(1)
7.4.6 Xing-28 Block, Liaohe Field, China
176(1)
7.4.7 Yangsanmu in China
177(1)
7.5 Concluding Remarks
178(1)
References
178(1)
8 Alkaline-Surfactant Flooding
179(10)
James J. Sheng
8.1 Introduction
179(1)
8.2 Interactions and Synergies Between Alkali and Surfactant
179(5)
8.2.1 Alkaline Salt Effect
179(1)
8.2.2 Effect on Optimum Salinity and Solubilization Ratio
179(1)
8.2.3 Synergy Between Soap and Surfactant to Improve Phase Behavior
180(3)
8.2.4 Effect on IFT
183(1)
8.2.5 Effect on Surfactant Adsorption
183(1)
8.3 Simulated Results of an Alkaline-Surfactant System
184(1)
8.4 Field Cases
185(4)
8.4.1 Big Sinking Field in East Kentucky
186(1)
8.4.2 White Castle Field in Louisiana
186(2)
References
188(1)
9 ASP Fundamentals and Field Cases Outside China
189(14)
James J. Sheng
9.1 Introduction
189(1)
9.2 Synergies and Interactions of ASP
189(1)
9.3 Practical Issues of ASP Flooding
190(2)
9.3.1 Produced Emulsions
190(1)
9.3.2 Chromatographic Separation of Alkali, Surfactant, and Polymer
191(1)
9.3.3 Precipitation and Scale Problems
192(1)
9.4 Amounts of Chemicals Injected in Chinese Field ASP Projects
192(2)
9.5 Overall ASP Field Performance
194(1)
9.6 ASP Examples of Field Pilots and Applications
194(9)
9.6.1 Lawrence Field in Illinois
194(2)
9.6.2 Cambridge Minnelusa Field in Wyoming
196(2)
9.6.3 West Kiehl Field in Wyoming
198(1)
9.6.4 Tanner Field in Wyoming
199(1)
9.6.5 Lagomar LVA-6/9/21 Area in Venezuela
199(1)
References
200(3)
10 ASP Process and Field Results
203(48)
Harry L. Chang
10.1 Introduction
203(1)
10.2 Background
204(3)
10.3 Laboratory Studies and Mechanistic Modeling
207(9)
10.3.1 Laboratory Studies
207(5)
10.3.2 Mechanistic Modeling
212(3)
10.3.3 Other Laboratory Studies and Field Experiments
215(1)
10.4 The Screening Process
216(2)
10.5 Field Applications and Results
218(9)
10.5.1 ASP Flooding in the Daqing Oil Field
221(4)
10.5.2 ASP Flooding in the Shengli Oil Field
225(1)
10.5.3 ASP Flooding in the Karamay Oil Field
225(1)
10.5.4 Other Field Test Results
226(1)
10.6 Interpretation of Field Test Results
227(3)
10.6.1 Assessment of Oil Recovery Efficiency
227(2)
10.6.2 Interpretation of Recovery Mechanisms
229(1)
10.6.3 Process Application
229(1)
10.7 Lessons Learned
230(2)
10.8 Future Outlook and Focus
232(3)
10.9 Conclusions
235(1)
10.10 Recommendation on Field Project Designs
235(16)
Nomenclature and Abbreviations
239(1)
References
240(11)
11 Foams and Their Applications in Enhancing Oil Recovery
251(30)
James J. Sheng
11.1 Introduction
251(1)
11.2 Characteristics of Foam
251(1)
11.3 Foam Stability
252(5)
11.4 Mechanisms of Foam Flooding to Enhance Oil Recovery
257(3)
11.4.1 Foam Formation and Decay
258(2)
11.4.2 Foam Flooding Mechanisms
260(1)
11.5 Foam Flow Behavior
260(2)
11.5.1 Foam Viscosity
260(1)
11.5.2 Relative Permeabilities
261(1)
11.5.3 Mobility Reduction
261(1)
11.5.4 Flow Resistance Factor
262(1)
11.6 Foam Application Modes
262(3)
11.6.1 CO2 Foam
262(1)
11.6.2 Steam-Foam
263(1)
11.6.3 Foam Injection in Gas Miscible Flooding
264(1)
11.6.4 Gas Coning Blocking Foam
264(1)
11.6.5 Enhanced Foam Flooding
264(1)
11.6.6 Foams for Well Stimulation
264(1)
11.7 Factors That Need to Be Considered in Designing Foam Flooding Applications
265(2)
11.7.1 Screening Criteria
265(1)
11.7.2 Surfactants
265(1)
11.7.3 Injection Mode
266(1)
11.8 Results of Field Application Survey
267(1)
11.8.1 Locations of Conducted Foam Projects
267(1)
11.8.2 Applicable Reservoir and Process Parameters
267(1)
11.8.3 Injection Mode
268(1)
11.8.4 Gas Used in Foam
268(1)
11.9 Individual Field Applications
268(13)
11.9.1 Single Well Polymer-Enhanced Foam Flooding Test
268(3)
11.9.2 Nitrogen Foam Flooding in a Heavy Oil Reservoir After Steam and Waterflooding
271(2)
11.9.3 Snorre Foam-Assisted-Water-Alternating-Gas Project
273(3)
References
276(5)
12 Surfactant Enhanced Oil Recovery in Carbonate Reservoirs
281(20)
James J. Sheng
12.1 Introduction
281(1)
12.2 Problems in Carbonate Reservoirs
282(1)
12.3 Models of Wettability Alteration Using Surfactants
283(3)
12.4 Upscaling
286(3)
12.5 Oil Recovery Mechanisms in Carbonates Using Chemicals
289(2)
12.6 Chemicals Used in Carbonate EOR
291(1)
12.7 Chemical EOR Projects in Carbonate Reservoirs
292(4)
12.7.1 The Mauddud Carbonate in Bahrain
292(1)
12.7.2 The Yates Field in Texas
293(1)
12.7.3 The Cottonwood Creek Field in Wyoming
294(1)
12.7.4 The Baturaja Formation in the Semoga Field in Indonesia
294(1)
12.7.5 Cretaceous Upper Edwards Reservoir (Central Texas)
295(1)
12.8 Concluding Remarks
296(5)
Nomenclature
296(1)
References
297(4)
13 Water-Based EOR in Carbonates and Sandstones: New Chemical Understanding of the EOR Potential Using "Smart Water"
301(36)
Tor Austad
13.1 Introduction
301(5)
13.1.1 Wetting in Carbonates
302(2)
13.1.2 Wetting in Sandstones
304(1)
13.1.3 Smart Water Flooding
304(2)
13.2 "Smart Water" in Carbonates
306(14)
13.2.1 Introduction
306(1)
13.2.2 Reactive Potential Determining Ions
307(5)
13.2.3 Suggested Mechanism for Wettability Modification
312(1)
13.2.4 Optimization of Injected Water
312(3)
13.2.5 Viscous Flood Versus Spontaneous Imbibitions
315(1)
13.2.6 Environmental Effects
315(1)
13.2.7 Smart Water in Limestone
316(1)
13.2.8 Condition for Low Salinity EOR Effects in Limestone
317(3)
13.3 "Smart Water" in Sandstones
320(6)
13.3.1 Introduction
320(1)
13.3.2 Conditions for Low Salinity Effects
320(1)
13.3.3 Suggested Low Salinity Mechanisms
320(1)
13.3.4 Improved Chemical Understanding of the Mechanism
321(1)
13.3.5 Chemical Verification of the Low Salinity Mechanism
321(5)
13.4 Field Examples and EOR Possibilities
326(6)
13.4.1 Carbonates
326(2)
13.4.2 Sandstones
328(2)
13.4.3 Statoil Snorre Pilot
330(2)
13.5 Conclusion
332(5)
Acknowledgments
332(1)
References
332(5)
14 Facility Requirements for Implementing a Chemical EOR Project
337(24)
John M. Putnam
14.1 Introduction
337(2)
14.2 Overall Project Requirements
339(4)
14.3 Modes of Chemical EOR Injection
343(4)
14.3.1 Polymer Flooding
344(1)
14.3.2 Surfactant-Polymer Flooding
345(1)
14.3.3 Alkaline-Polymer Flooding
345(2)
14.3.4 Alkaline-Surfactant-Polymer
347(1)
14.4 Water Treatment and Conditioning
347(3)
14.5 Handling and Processing EOR Chemicals On-site
350(8)
14.5.1 Polymer Handling, Processing, and Metering
350(4)
14.5.2 Surfactant Handling and Metering
354(1)
14.5.3 Alkaline Agent Handling, Processing and Metering
355(3)
14.6 Injection Schemes and Strategies
358(1)
14.7 Materials of Construction
359(1)
14.8 Conclusion
360(1)
References
360(1)
15 Steam Flooding
361(28)
James J. Sheng
15.1 Thermal Properties and Energy Concepts
361(3)
15.1.1 Heat Capacity (C)
361(1)
15.1.2 Latent Heat (Lv)
361(1)
15.1.3 Sensible Heat
362(1)
15.1.4 Total Volumetric Heat Capacity
362(1)
15.1.5 Thermal Diffusivity (α)
363(1)
15.1.6 Enthalpy (H, h)
363(1)
15.1.7 Vapor Pressure, Saturation Pressure, and Saturation Temperature
363(1)
15.1.8 Steam Quality
363(1)
15.1.9 Temperature-Dependent Oil Viscosity
363(1)
15.1.10 Gravitational Potential Energy
364(1)
15.1.11 Kinetic Energy
364(1)
15.1.12 Total Energy
364(1)
15.2 Modes of Heat Transfer
364(2)
15.2.1 Heat Conduction
365(1)
15.2.2 Heat Convection
365(1)
15.2.3 Thermal Radiation
365(1)
15.3 Heat Losses
366(1)
15.3.1 Heat Loss from Surface Pipes
366(1)
15.3.2 Heat Loss from a Wellbore
366(1)
15.3.3 Heat Loss to Over- and Underburden Rocks
366(1)
15.3.4 Heat Loss from Produced Fluids
367(1)
15.4 Estimation of the Heated Area
367(3)
15.5 Estimation of Oil Recovery Performance
370(1)
15.6 Mechanisms
371(1)
15.7 Screening Criteria
371(2)
15.8 Practice in Steam Flooding Projects
373(6)
15.8.1 Formation
373(1)
15.8.2 Injection Pattern and Well Spacing
374(1)
15.8.3 Injection and Production Rates
375(1)
15.8.4 Injection Schemes
376(1)
15.8.5 Time to Convert Steam Soak to Steam Flood
376(1)
15.8.6 Oil Recovery and OSR
377(1)
15.8.7 Completion Interval
377(1)
15.8.8 Production Facilities
378(1)
15.8.9 Water Treatment
378(1)
15.8.10 Monitoring and Surveillance
379(1)
15.9 Field Cases
379(10)
15.9.1 Kern River in California
379(2)
15.9.2 Duri Steam Flood (DSF) Project in Indonesia
381(1)
15.9.3 WASP in West Coalinga Field, CA
382(1)
15.9.4 Karamay Field, China
382(1)
15.9.5 Qi-40 Block in Laohe, China
383(3)
References
386(3)
16 Cyclic Steam Stimulation
389(24)
James J. Sheng
16.1 Introduction
389(1)
16.2 Mechanisms
389(2)
16.3 Estimating Production Response from CSS-Boberg and Lantz Model
391(4)
16.4 Screening Criteria
395(1)
16.5 Practice in CSS Projects
396(5)
16.5.1 General Producing Methods
396(1)
16.5.2 Injection and Production Parameters
397(3)
16.5.3 Completion Interval
400(1)
16.5.4 Wellbore Heat Insulation
400(1)
16.5.5 Incremental Oil Recovery and OSR
400(1)
16.5.6 Monitoring and Surveillance
400(1)
16.6 Field Cases
401(12)
16.6.1 Cold Lake in Alberta, Canada
401(1)
16.6.2 Midway Sunset in California
402(2)
16.6.3 Du 66 Block in the Liao Shuguang Field, China
404(2)
16.6.4 Jin 45 Block in Liaohe Huanxiling Field, China
406(1)
16.6.5 Gudao Field, China
407(1)
16.6.6 Blocks 97 and 98 in Karamay Field, China
408(3)
16.6.7 Gaosheng Field, China
411(1)
References
412(1)
17 SAGD for Heavy Oil Recovery
413(34)
Chonghui Shen
17.1 Introduction
413(3)
17.2 Evaluation of SAGD Resource
416(4)
17.2.1 Importance of Resource Quality
416(3)
17.2.2 Focus of Delineation
419(1)
17.3 Start-Up
420(4)
17.3.1 Circulation Heating and Inter-Well Communication Initialization
420(3)
17.3.2 Well Separation and Start-Up Period
423(1)
17.3.3 Wellbore Effects
423(1)
17.4 Well Completion and Work-Over
424(7)
17.4.1 Steam Circulation for Start-Up
424(1)
17.4.2 Thermal Wellbore Insulation
424(1)
17.4.3 Sand Control Liner
425(1)
17.4.4 Liner Plugging Issue and Treatment
426(2)
17.4.5 Recompletion to Fix Local Steam Breakthrough
428(1)
17.4.6 Intelligent Well Completion
429(2)
17.5 Production Control
431(3)
17.5.1 Steam Trap
431(1)
17.5.2 Wellbore Lift
432(1)
17.5.3 Geysering Phenomenon Under Natural Lift
433(1)
17.6 Well, Reservoir, and Facility Management
434(4)
17.6.1 Wellbore Pressure and Temperature
435(1)
17.6.2 Reservoir Monitoring
435(1)
17.6.3 Rock Deformation Evaluation and Surface Monitoring
436(2)
17.7 SAGD Wind-Down
438(2)
17.8 Integration of Subsurface and Surface
440(1)
17.9 Solvent-Enhanced SAGD
440(7)
References
442(5)
18 In Situ Combustion
447(96)
Alex Turta
18.1 Fundamentals
447(20)
18.1.1 Introduction and Qualitative Description of In Situ Combustion Techniques
447(7)
18.1.2 Design, Operation, and Evaluation of an ISC Field Project
454(13)
18.2 Field Applications
467(45)
18.2.1 Screening Guide
467(2)
18.2.2 Monitoring and Evaluation of an ISC Pilot/Project
469(4)
18.2.3 ISC Pilots
473(20)
18.2.4 Commercial ISC Projects in Heavy Oil Reservoirs
493(4)
18.2.5 Wet ISC Projects
497(15)
18.3 ISC Projects in Light Oil Reservoirs
512(8)
18.3.1 Commercial HPAI Projects in Very Light, Deep, Williston Basin Oil Reservoirs
512(4)
18.3.2 ISC Projects in Waterflooded Reservoirs Containing Very Light Oil
516(3)
18.3.3 ISC Failures in Reservoirs with Light-Medium Oils
519(1)
18.4 CISC Applications
520(5)
18.4.1 CISC Application for Heavy Oil Production Stimulation
521(3)
18.4.2 Increase of Injectivity for Water Injection Wells
524(1)
18.4.3 Sand Consolidation by Hot Air Injection ("Controlled Coking")
524(1)
18.5 New Approaches to Apply ISC in Combination with Horizontal Wells
525(7)
18.5.1 Horizontal Wells Drilled in Old Cohventional ISC Projects
525(1)
18.5.2 Long-Distance Versus Short-Distance Displacement
526(2)
18.5.3 THAI Process
528(3)
18.5.4 Other ISC Approaches (COSH and Top-Down ISC)
531(1)
18.6 Operation Problems and Their Remedies
532(2)
18.6.1 Critical Problems
533(1)
18.7 Noncritical Problems
534(9)
References
536(7)
19 Introduction to MEOR and Its Field Applications in China
543(18)
James J. Sheng
19.1 Introduction
543(1)
19.2 MEOR Mechanisms
544(4)
19.3 Microbes and Nutrients Used in MEOR
548(1)
19.4 Screening Criteria
549(1)
19.5 Field Applications
550(11)
19.5.1 Single-Well Microbial Huff-and-Puff
551(1)
19.5.2 Microbial Waterflooding
552(2)
19.5.3 Well Stimulation to Remove Wellbore or Formation Damage
554(1)
19.5.4 MEOR Using Indigenous Microbes
555(3)
Acknowledgments
558(1)
References
558(3)
20 The Use of Microorganisms to Enhance Oil Recovery
561(20)
Lewis Brown
20.1 Origin of the MEOR Concept
561(1)
20.2 Early Work on MEOR
562(1)
20.3 Patents on MEOR
563(4)
20.4 Our Projects on MEOR
567(9)
20.5 Future Studies
576(5)
References
577(4)
21 Field Applications of Organic Oil Recovery-A New MEOR Method
581(34)
Bradley Govreau
Brian Marcotte
Alan Sheehy
Krista Town
Bob Zahner
Shane Tapper
Folami Akintunji
21.1 Introduction
581(1)
21.2 Oil Release Mechanism
582(2)
21.3 Discussion of Applications
584(11)
21.3.1 Screening Reservoirs Is Critical to Success
584(1)
21.3.2 Organic Oil Recovery Can Be Applied to a Wide Range of Oil Gravities
585(2)
21.3.3 Reservoir Plugging or Formation Damage Is No Longer a Risk
587(1)
21.3.4 Microbes Reside in Extreme Conditions and Can Be Manipulated to Perform Valuable In Situ "Work"
588(1)
21.3.5 Organic Oil Recovery Can Be Successfully Applied in Dual-Porosity Reservoirs
589(1)
21.3.6 Applying Organic Oil Recovery Can Reduce Reservoir Souring
590(1)
21.3.7 Organic Oil Recovery Can Be Used in Tight Reservoirs
591(1)
21.3.8 An Oil Response Is Not Always Seen When Treating Producing Wells
591(4)
21.4 Case Study 1-Trial Field, Saskatchewan
595(9)
21.4.1 Background
595(1)
21.4.2 Reservoir Screening and Laboratory Work
595(1)
21.4.3 Field Application Process
596(1)
21.4.4 Nutrient Test in Producer
596(1)
21.4.5 Pilot
597(3)
21.4.6 Additional Producer Applications
600(1)
21.4.7 Expanding the Pilot
601(3)
21.4.8 Discussion
604(1)
21.5 Case Study 2-Beverly Hills Field, California
604(9)
21.5.1 Background
604(1)
21.5.2 Nutrient Test in Producer
605(1)
21.5.3 Injection Well Treatments
606(2)
21.5.4 Additional Producer Treatments
608(1)
21.5.5 OS-8
609(1)
21.5.6 BH-15
610(2)
21.5.7 Discussion of Results
612(1)
21.6 Conclusion
613(2)
References
613(2)
22 Cold Production of Heavy Oil
615(47)
Bernard Tremblay
22.1 Introduction
616(2)
22.2 Mechanisms
618(27)
22.2.1 Solution-Gas Drive
618(9)
22.2.2 Sand Production
627(18)
22.3 Field Case
645(15)
22.3.1 Heterogeneity of Reservoirs
645(6)
22.3.2 History Matching Cold Production Wells
651(1)
22.3.3 Predicting CHOPS Production
652(4)
22.3.4 Predicting Post-CHOPS Production
656(4)
22.4 Conclusions
660(2)
Acknowledgments 662(1)
References 662(5)
Index 667
James Sheng is currently a professor in petroleum engineering at Texas Tech University specializing in oil recovery research. Previously, he was a Senior Research Engineer with Total E&P USA, Team Leader Scientist with Baker Hughes, and a reservoir engineer with Shell, Kuwait Oil Company, and the Research Institute of Petroleum Exploration and Development in China. James has authored 2 books, both with Elsevier, over 70 articles, presented over 100 papers worldwide, and earned 4 patents to date. He earned a PhD and MSc from the University of Alberta, and a BSc from the University of Petroleum in China, all in petroleum engineering.
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