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El. knyga: Petroleum Fluid Phase Behavior: Characterization, Processes, and Applications [Taylor & Francis e-book]

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Petroleum Fluid Phase Behavior: Characterization, Processes, and ApplicationsDidesnis paveikslėlis
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"This book deals with complex fluid characterization of oil and gas reservoirs, emphasizing the importance of PVT parameters for practical application in reservoir simulation and management. It covers modeling of PVT parameters, QA/QC of PVT data from lab studies, EOS modeling, PVT simulation and compositional grading and variation. It describes generation of data for reservoir engineering calculations in view of limited and unreliable data and techniques like downhole fluid analysis and photophysics of reservoir fluids. It discusses behavior of unconventional reservoirs, particularly for difficult resources like shale gas, shale oil, coalbed methane, reservoirs, heavy and extra heavy oils"--

This book deals with complex fluid characterization of oil and gas reservoirs, emphasizing the importance of PVT parameters for practical application in reservoir simulation and management. It covers modeling of PVT parameters, QA/QC of PVT data from lab studies, EOS modeling, PVT simulation and compositional grading and variation. It describes generation of data for reservoir engineering calculations in view of limited and unreliable data and techniques like downhole fluid analysis and photophysics of reservoir fluids. It discusses behavior of unconventional reservoirs, particularly for difficult resources like shale gas, shale oil, coalbed methane, reservoirs, heavy and extra heavy oils.

Preface xvii
Acknowledgments xxi
Authors xxiii
1 Reservoir Fluid Properties 1(58)
1.1 Introduction
1(1)
1.2 Gas and Oil
1(18)
1.2.1 Gas Reservoirs: Hydrocarbon Gases Are Defined Based on Their Occurrences
4(1)
1.2.1.1 Dry Gas Reservoirs
4(1)
1.2.1.2 Wet Gas Reservoirs
4(1)
1.2.1.3 Gas Condensate Reservoirs
4(1)
1.2.2 Non-hydrocarbon Gases
5(5)
1.2.2.1 Carbon Dioxide (CO2)
5(1)
1.2.2.2 Hydrogen Sulfide (H2S) Gas
5(1)
1.2.2.3 Mercury (Hg)
6(1)
1.2.2.4 Coalbed Methane Gas
6(2)
1.2.2.5 Shale Gas
8(1)
1.2.2.6 Gas Hydrates
9(1)
1.2.3 Physical Properties of Gas
10(2)
1.2.3.1 Gas Density pg
10(1)
1.2.3.2 Gas Gravity, yg
11(1)
1.2.3.3 Gas Viscosity, Pg
11(1)
1.2.3.4 Gas Deviation Factor Z
11(1)
1.2.3.5 Gas Formation Volume Factor, Bg
11(1)
1.2.4 Oil Reservoir Types
12(1)
1.2.4.1 Black Oil Reservoirs
12(1)
1.2.4.2 Volatile Oil Reservoirs
12(1)
1.2.4.3 Heavy and Extra-Heavy Oil
13(1)
1.2.5 Physical Properties of Crude Oil
13(5)
1.2.5.1 Bubble-Point Pressure, Ph
14(1)
1.2.5.2 Oil Formation Factor, B
14(1)
1.2.5.3 Gas Formation Volume Factor, Bg
15(1)
1.2.5.4 Solution Gas-Oil Ratio, R
15(1)
1.2.5.5 Oil Viscosity, Po
16(1)
1.2.5.6 Oil Density, Po
17(1)
1.2.5.7 Oil Compressibility, co
17(1)
1.2.6 Chemical Properties
18(2)
1.2.6.1 Paraffins
18(1)
1.2.6.2 Naphthenes
18(1)
1.2.6.3 Aromatics
19(1)
1.2.6.4 Resins and Asphaltenes
19(1)
1.3 Non-hydrocarbon Crude Components
19(1)
1.4 Ternary Presentations of Crude Oil Classifications
20(8)
1.4.1 Water Properties
21(2)
1.4.1.1 Composition and Salinity
22(1)
1.4.1.2 Formation Volume Factor
23(1)
1.4.1.3 Density
23(1)
1.4.1.4 Compressibility
23(1)
1.4.2 Water Solubility in Hydrocarbon System
23(1)
1.4.3 Phase Behavior
23(2)
1.4.3.1 Gibb's Law
25(1)
1.4.4 Pure-Component Systems
25(3)
1.5 PV Diagram for Pure Systems
28(1)
1.6 Binary Systems
29(1)
1.7 Effect of Composition on Phase Behavior
30(1)
1.8 P-x and T-x Diagrams
31(2)
1.9 Retrograde Condensation
33(1)
1.10 Multicomponent Phase Behavior of Hydrocarbon
34(5)
1.10.1 Phase Behavior of Oil
34(1)
1.10.1.1 Undersaturated Oil
34(1)
1.10.1.2 Saturated Oil
34(1)
1.10.1.3 Volatile Oil
35(1)
1.10.2 Phase Behavior of Gas
35(3)
1.10.2.1 Dry Gas
35(2)
1.10.2.2 Wet Gas
37(1)
1.10.2.3 Gas Condensate
37(1)
1.10.3 Comparison of Phase Diagram of Hydrocarbon Fluids
38(1)
1.10.4 Phase Diagram of Reservoirs with Gas Cap
39(1)
1.11 Ternary Diagram
39(8)
1.11.1 Ternary Diagrams as a Function of Pressure
41(2)
1.11.2 Equation of States
43(1)
1.11.2.1 Period 1
43(1)
1.11.2.2 Period 2
43(1)
1.11.2.3 Period 3
43(1)
1.11.3 van der Waals Equation
44(1)
1.11.4 Redlich-Kwong Equation
45(1)
1.11.5 Soave-Redlich-Kwong Equation
46(1)
1.11.6 Peng-Robinson Equation
46(1)
1.11.7 Benedict-Webb-Rubin Equation
47(1)
1.12 Comparative Assessment of RK, SRK, and PR EOS
47(10)
1.12.1 Redlich-Kwong EOS
47(1)
1.12.2 Soave-Redlich-Kwong and Peng-Robinson EOS
48(1)
1.12.3 Zc as a Measure of Goodness of an EOS
48(1)
1.12.4 "Universal" Zc Predicted by Different EOS
48(1)
1.12.5 Vapor-Liquid Equilibrium
48(1)
1.12.6 Pressure and Temperature
49(1)
1.12.7 Fluid Contacts
50(1)
1.12.8 Reservoir Temperature
51(4)
1.12.8.1 Impact of Temperature on Subsurface Parameters
52(1)
1.12.8.2 Subsurface Gas Density
52(1)
1.12.8.3 Subsurface Fluid Viscosity
53(1)
1.12.8.4 Geothermal Gradient
54(1)
1.12.8.5 Sources of Temperature Measurement
54(1)
1.12.9 Reservoir Fluid Analysis
55(1)
1.12.9.1 Compositional Variations
56(1)
1.12.10 Non-equilibrium Distribution of Hydrocarbons
56(1)
References
57(2)
2 Fluid Characterization and Recovery Mechanism 59(54)
2.1 Introduction
59(1)
2.2 Reservoir Recovery Processes
60(7)
2.2.1 Rock-Fluid Expansion
61(1)
2.2.2 Depletion or Solution Gas Drive Reservoirs
62(1)
2.2.3 Gas-Cap Drive
63(2)
2.2.4 Water-Drive Reservoirs
65(1)
2.2.5 Combination Drive
65(1)
2.2.6 Segregation Drive
66(1)
2.2.6.1 General Material Balance Equation
67(1)
2.3 Gas Reservoirs
67(4)
2.3.1 Volumetric Gas Reservoirs
68(1)
2.3.2 Water-Drive Gas Reservoir
69(1)
2.3.3 Gas Condensate Reservoirs Production
69(1)
2.3.4 Fluid Characterization for Reservoir Simulations
70(1)
2.4 Secondary Recovery
71(6)
2.4.1 Water Injection
72(2)
2.4.2 Gas Injection
74(2)
2.4.2.1 Flue Gas Injection
75(1)
2.4.2.2 Nitrogen Injection
75(1)
2.4.2.3 Carbon Dioxide Injection
76(1)
2.4.3 Gas Cycling
76(1)
2.4.4 CO2 Sequestration
76(1)
2.5 Tertiary Recovery
77(14)
2.5.1 Chemical FOR
81(3)
2.5.1.1 Polysaccharides Biopolymer
82(1)
2.5.1.2 Synthetic Polymer
83(1)
2.5.2 Effect of Concentration and Shear Rate on Viscosity
84(1)
2.5.3 Rheology of Polymer and Shear Impact
84(1)
2.5.4 Salinity Impact
84(1)
2.5.5 Adsorption
84(4)
2.5.6 Surfactant Flooding
88(3)
2.5.6.1 Fluid-Fluid Interactions
89(1)
2.5.6.2 Phase Behavior
90(1)
2.6 Gas-Based EOR
91(8)
2.6.1 Immiscible and Miscible Water-Alternating Gas (IWAG) Injection
92(1)
2.6.2 Miscible Flooding
93(5)
2.6.2.1 Multi-Contact Miscibility
95(1)
2.6.2.2 Vaporizing Gas Drive
95(2)
2.6.2.3 Condensing Gas Drive
97(1)
2.6.2.4 Condensing and Vaporizing Drive
97(1)
2.6.3 CO2 Sequestration
98(1)
2.6.3.1 Trapping Mechanisms and Long-Term Fate of CO2
99(1)
2.7 Thermal EOR
99(10)
2.7.1 Cyclic Steam Stimulation
100(2)
2.7.2 Steam Flooding
102(5)
2.7.3 Steam Assisted Gravity Drainage (SAGD)
107(1)
2.7.4 In Situ Combustion
107(2)
2.8 PVT Data for Thermal EOR Processes
109(1)
References
110(3)
3 Advanced Fluid Sampling and Characterization of Complex Hydrocarbon Systems 113(16)
3.1 Introduction
113(1)
3.2 Hydrocarbon Sampling
113(12)
3.2.1 Sampling Location Considerations
114(4)
3.2.1.1 Pressure Data
114(2)
3.2.1.2 Compositional Gradients and API
116(2)
3.2.2 Sampling Challenges
118(17)
3.2.2.1 Downhole Sampling
119(5)
3.2.2.2 Surface Sampling
124(1)
3.3 Field Sampling
125(1)
References
126(3)
4 Planning of Laboratory Studies 129(14)
4.1 Introduction
129(1)
4.2 Conventional Oil and Gas Experiments
130(5)
4.3 Special Laboratory Experiments
135(7)
4.3.1 Swelling Test
135(1)
4.3.2 Minimum Miscibility Pressure
136(2)
4.3.3 Multiple Contact Miscibility
138(2)
4.3.3.1 Vaporizing Gas Drive
138(1)
4.3.3.2 Condensing Gas Drive
139(1)
4.3.4 Fluid Compatibility Studies
140(1)
4.3.5 Asphaltene Precipitation Envelope
141(1)
References
142(1)
5 Phase Behavior of Petroleum Reservoir Fluids in the Dense Phase or Supercritical Region 143(34)
5.1 Definition of Dense or Supercritical Phase
143(4)
5.2 Variation of Dense Phase Fluid Properties with Temperature and Pressure
147(4)
5.3 High Temperature High Pressure (HTHP) and/or Hyperbaric Reservoir Fluids
151(2)
5.4 Measurement and Modeling of Dense Phase Fluid Properties
153(4)
5.5 Practical Significance of Dense Fluid Phase in Transportation and EOR
157(13)
5.6 Successful Applications-Case Studies
170(2)
5.6.1 Dense Phase CO2
170(1)
5.6.2 Dense Phase or Supercritical Water (SCW)
171(1)
5.6.3 The General Prominence of Supercritical Fluids
172(1)
References
172(5)
6 Special Characterization for EOR Processes 177(16)
6.1 Introduction
177(1)
6.2 EOS Recap
177(1)
6.3 EOS Role on Numerical Simulation
178(2)
6.4 EOS Calibration
180(5)
6.4.1 Slimtube Calibration
183(2)
6.5 EOS Grouping
185(2)
6.5.1 Asphaltenes
186(1)
6.6 EOS Dynamic Testing
187(4)
6.6.1 Finite-Difference Considerations
189(2)
References
191(2)
7 Compositional, Fluid Property, and Phase Behavior Characteristics of Unconventional Reservoir Fluids 193(56)
7.1 Significance of Unconventional Reservoir Fluids
193(2)
7.2 Reservoir Fluids Containing Unusually Large Fractions of Non-hydrocarbon Components
195(7)
7.2.1 Gaseous Non-hydrocarbons
195(1)
7.2.2 Mercury
196(16)
7.2.2.1 Impact of Association of Hg with Petroleum Reservoir Fluids
198(4)
7.3 Formation of Solid CO2 and Effect of CO2 on Paraffin Wax
202(4)
7.4 Compositional Characteristics of Shale Gas and Shale Oil vs. Conventional Reservoir Fluids
206(6)
7.5 Fluid Property and PVT Characteristics of Fluids Containing Large Proportions of Non-hydrocarbons and Shale-Based Fluids vs. Conventional Fluids
212(25)
7.5.1 Fluid Phase Behavior of Acid Gases and Their Mixtures with Hydrocarbons
212(14)
7.5.2 Fluid Phase Behavior and Properties of Shale Reservoirs
226(11)
7.6 Measurement and EOS Modeling of Unconventional Reservoir Fluids-State of the Art
237(2)
References
239(10)
8 Porous Media Effects on Phase Behavior of (Unconventional) Petroleum Reservoir Fluids 249(26)
8.1 Practical Significance and Implications of Porous Media Effects on Phase Behavior
249(2)
8.2 Capillary Pressure
251(4)
8.2.1 Gas-Oil IFT
253(1)
8.2.2 Pore Size and Pore Size Distribution
254(1)
8.3 Inclusion of Confinement in Phase Behavior
255(16)
8.3.1 Capillary Pressure in Flash or Vapor-Liquid Equilibria (VLE) Calculations
255(6)
8.3.2 Flash or Vapor-Liquid Equilibria (VLE) Calculations using Modified Critical Temperature and Pressure
261(1)
8.3.3 Bubble-Point Calculations for the Methane-n-Butane Binary System Including Capillary Pressure
262(4)
8.3.4 Correcting Bulk PVT Data for Confinement
266(5)
8.4 Handling of Porous Media Effects on Phase Behavior in a Compositional Reservoir Simulator
271(1)
References
272(3)
9 Compositional and Phase Behavior Effects in Conventional and Exotic Heavy Oil FOR Processes 275(38)
9.1 CO2 Induced Hydrocarbon Liquid-Liquid Phase Split and Phase Behavior Type
275(3)
9.2 Experimental Observations and EOS Modeling of Hydrocarbon Vapor-Liquid-Liquid or Liquid-Liquid Phase Split
278(21)
9.2.1 Experimental Observations
278(11)
9.2.2 Stability Analysis and EOS Modeling
289(5)
9.2.3 Handling of Multiple Phases in a Compositional Reservoir Simulator
294(5)
9.3 Practical Significance of CO2 Induced Heavy Oil Phase Behavior
299(4)
9.4 Compositional Changes in a Heavy Oil in Exotic EOR Processes-Microbial and In Situ Combustion
303(4)
9.4.1 Microbial Enhanced Oil Recovery (MEOR)
303(2)
9.4.2 In Situ Combustion (ISC)
305(2)
9.5 Case Studies and Recent Advances
307(2)
References
309(4)
10 Flow Assurance in EOR Design and Operation 313(42)
10.1 Flow Assurance
313(1)
10.2 Wax
314(17)
10.2.1 Chemistry
314(1)
10.2.2 Phase and Physical Properties
314(4)
10.2.3 Laboratory Testing and Modeling
318(13)
10.2.3.1 Deposition Modeling-Wax Composition
318(1)
10.2.3.2 Deposition Modeling-WAT
319(1)
10.2.3.3 Deposition-Wax Disappearance Temperature
320(1)
10.2.3.4 Pour Point Temperature
320(1)
10.2.3.5 Rheology-Gelation Temperature
321(1)
10.2.3.6 Rheology-Viscosity
321(3)
10.2.3.7 Wax Deposition
324(3)
10.2.3.8 Rheology-Yield Stress
327(1)
10.2.4 Prevention and Mitigation
328(3)
10.2.4.1 Gelling/Pour Point Management
331(1)
10.3 Asphaltene
331(6)
10.3.1 Chemistry
331(1)
10.3.2 Phase and Physical Properties
332(2)
10.3.3 Laboratory Testing and Modeling
334(3)
10.3.4 Prevention and Mitigation
337(1)
10.4 Hydrate
337(6)
10.4.1 Phase and Physical Properties
338(2)
10.4.2 Laboratory Testing and Modeling
340(2)
10.4.2.1 Hydrate Formation Correlations
340(1)
10.4.2.2 Makogan
341(1)
10.4.2.3 Kobayashi et al.
341(1)
10.4.2.4 Berge Correlation
341(1)
10.4.3 Prevention and Mitigation
342(1)
10.5 Emulsion
343(9)
10.5.1 Formation of Emulsion
345(1)
10.5.2 Emulsion Stability
346(2)
10.5.3 Laboratory Studies
348(2)
10.5.4 Demulsification
350(7)
10.5.4.1 Reservoir Souring, Corrosion, and Aquathermolysis
350(2)
References
352(3)
11 EOS and PVT Simulations 355(16)
11.1 Introduction
355(1)
11.2 Black Oil and Compositional Models
355(2)
11.3 PVT Model Validation
357(6)
11.3.1 Sample Contamination Validation
359(2)
11.3.2 FOR Injection Considerations
361(2)
11.4 PVT Correlations
363(2)
11.5 Impact of PVT Uncertainty on Volume and Recovery Estimations
365(3)
References
368(3)
12 Empirical Relations for Estimating Fluid Properties 371(30)
12.1 Bubble-Point Pressure Correlations
372(4)
12.1.1 MB Standing Correlation
372(1)
12.1.2 Glaso
372(1)
12.1.3 Vasquez and Beggs
373(1)
12.1.4 Al-Marhoun
373(1)
12.1.5 De Ghetto et al. for Heavy Oil and Extra-Heavy Oil
373(1)
12.1.6 Hanafi et al.
373(1)
12.1.7 Petrosky and Farshad
374(1)
12.1.8 Velarde et al.
374(1)
12.1.9 Omar and Todd
374(1)
12.1.10 Lasater Bubble-Point Pressure
374(1)
12.1.11 Dew-Point Correlations
375(1)
12.2 Solution Gas Oil Ratio Correlations
376(2)
12.2.1 Standing
377(1)
12.2.2 Glaso
377(1)
12.2.3 Vasquez and Beggs
377(1)
12.2.4 Al-Marhoun
377(1)
12.2.5 De Ghetto et al
378(1)
12.2.6 Hanafi et al
378(1)
12.2.7 Petrosky and Farshad
378(1)
12.2.8 Velarde et al.
378(1)
12.3 Formation Volume Factor
378(4)
12.3.1 Arp's Correlation
379(1)
12.3.2 Standing Correlation
379(1)
12.3.3 Glaso
380(1)
12.3.4 Vasquez and Beggs
380(1)
12.3.5 Al-Marhoun
380(1)
12.3.6 Petrosky-Farshad Correlation
381(1)
12.3.7 Omar and Todd's Correlation for Malaysian Crudes
381(1)
12.3.8 Hanafi et al
381(1)
12.3.9 De Ghetto et al.-Heavy Oil and Extra-Heavy Oil
381(1)
12.3.10 Petrosky and Farshad
382(1)
12.4 Oil Compressibility Correlations
382(3)
12.4.1 Vasquez and Beggs
382(1)
12.4.2 Hanafi et al
383(1)
12.4.3 De Ghetto et al
383(1)
12.4.4 Petrosky and Farshad
384(1)
12.5 Viscosity Correlations
385(4)
12.5.1 Beggs and Robinson
385(1)
12.5.2 De Ghetto et al
386(1)
12.5.3 Hanafi et al
386(1)
12.5.4 Khan et al. (Saudi Arabian Oil)
387(1)
12.5.5 Ng and Egbogah
387(1)
12.5.6 Vasquez-Beggs correlation
388(1)
12.5.7 Gas Viscosity, Pg
388(1)
12.5.7.1 Lee-Gonzalez-Eakin
388(1)
12.5.8 Water Viscosity by Meehan
388(1)
12.5.9 Beal
388(1)
12.6 Density and Gravity
389(4)
12.6.1 Hanafi et al
389(4)
12.7 Minimum Miscibility Pressure
393(1)
12.8 Uncertainty in PVT Data
394(4)
References
398(3)
Index 401
Dr. Raj Tewari is Custodian Reservoir Engineering and Group Technical Authority at Petronas, Malaysia. During his more than three decades long career in the oil and gas industry, he has worked in various companies, namely ONGC, GNPOC, Sudapet and Petronas, as a practicing reservoir engineer. He started his career in ONGCs Institute of Reservoir Studies in the 1980s where he was involved with reservoir characterization and numerical simulation, oil and gas field development planning and EOR laboratory studies. After 12 years he moved to Mumbai as Manager Reservoir and contributed to the redevelopment of the giant carbonate field, Mumbai High. His responsibilities included water flood management and identification of IOR/EOR initiatives for the field. He moved to North Africa in early 2000 to lead the Reservoir Engineering at GNPOC, a joint venture company. During this period he was responsible for field development planning (FDP) studies and reservoir management and surveillance of GNPOC fields, producing at plateau rate of 300 kbopd. Dr. Tewari joined Petronas in 2007 and since then has been actively involved in redevelopment studies of number of major fields incorporating EOR. In 2010-2011 he joined the national oil company of Sudan as Custodian PE and was involved with cyclic steam stimulation and steam flood EOR projects. He has extensive experience in light and viscous oil fields development and management, reservoir characterization and simulation, EOR and reservoir management. He is actively involved in EOR studies and R&D projects in Petronas. He has conducted training courses on Fluid Characterization, Rock Properties, Advance EOR and Reservoir Engineering. He was visiting professor to Khartoum University and also teaches in UTP on specialized topics. Dr. Tewari holds a Ph.D. degree in Physics from Banaras Hindu University, India. He has published nearly 50 papers in journals and conferences. He has been chairperson and technical committee member for a number of SPE Technical workshops and conferences. Dr. Tewari is Industry Advisor to University Technology Petronas (UTP), Malaysia. He has been awarded SPE Asia Pacific Technical award for Production and Operation in 2015.



Abhijit Dandekar is Professor and Chair of the Petroleum Engineering program at the University of Alaska Fairbanks, where he has taught since January 2001. Before joining UAF, he was an assistant research professor at the Technical University of Denmark. In the summer of 2002 he also worked as visiting faculty at the University of Petroleum Beijing, P.R.C. He has also been a visiting professor at the African University of Science and Technology (AUST) in Abuja, Nigeria and visiting professor at the University of Witwatersrand, Johannesburg, South Africa (as Fulbright specialist). He holds a B.Tech degree in chemical engineering from Nagpur University, India and a Ph.D. degree in petroleum engineering from Heriot-Watt University, Edinburgh, UK. Prof. Dandekar has authored more than 80 papers and a widely adopted textbook on Petroleum Reservoir Rock and Fluid Properties and he is also the editor for Emerging Trends and Technologies in Petroleum Engineering book series (Taylor & Francis). He has supervised more than 30 graduate students and conducted several funded research projects primarily in the area of PVT and SCAL. In 2014 he received the SPE Distinguished Membership and Fulbright Specialist awards. In 2015 he was the recipient of the SPE Western North America Region Distinguished Achievement Award for Petroleum Engineering Faculty. Over the last 16 years he has contributed to numerous SPE activities, is a current petroleum engineering program evaluator (PEV) for ABET and has served on six visits.



Jaime Moreno is a reservoir engineer with focus on EOR R&D, instructor, and a principal engineer for Schlumberger. His strong expertise in field development and reservoir characterization with an emphasis in EOR was developed through a 20- year career, which started with Schlumbergers Holditch Reservoir Technologies in Denver as a simulation engineer working with NFR triple porosity reservoirs in the Gulf of Mexico, South America and unconventional reservoirs in continental USA. Throughout his career he has worked as lead technical engineer in several field projects, including field development planning, in USA, Malaysia, Australia, Middle East and North Africa. Starting in 1998 he held a combined role in R&D for EOR, concentrating on screening (patented technology), pilot planning, monitoring and surveillance. He has taught internal and external courses on EOR and compositional modeling. Mr. Moreno holds an Msc degree from the Colorado School of Mines in USA, has published nearly 20 papers in journals and conferences and has been a technical committee member of several SPE applied technical workshops and conferences in the Asia Pacific region.
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