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9780471491927

Reservoir Stimulation , 3rd Edition

by ;
  • ISBN13:

    9780471491927

  • ISBN10:

    0471491926

  • Edition: 3rd
  • Format: Hardcover
  • Copyright: 2000-01-01
  • Publisher: WILEY
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List Price: $250.00

Summary

This third edition continues to provides a comprehensive study of reservoir stimulation from an all-encompassing engineering standpoint but has been completely rewritten to reflect the changing technologies in the industry. It sets forth a rationalisation of stimulation using reservoir engineering concepts, and addresses such topics as formation characterisation, hydraulic fracturing, matrix acidizing and chemical treatment. Formation damage which refers to a loss in reservoir productivity is also comprehensively examined. This extensive reference work remains essential reading for petroleum industry professionals involved in the important activities of reservoir evaluation, development and management, who require invaluable skills in the application of the techniques described for the successful exploitation of oil and gas reservoirs. Contributors to this volume are among the most recognized authorities in their individual technologies.

Author Biography

MICHAEL J. ECONOMIDES is Professor of Chemical Engineering at the University of Houston. Until the summer of 1998, he was the Samuel R. Noble Professor of Petroleum Engineering at Texas A & M University and served as Chief Scientist of the Global Petroleum Research Institute (GPRI). Prior to joining the faculty at Texas A & M University, Professor Economides was the Director of the Institute of Drilling and Production at the Leoben Mining Institute in Austria (1989–1993). From 1984 to 1989, he worked in a variety of senior positions with the Schlumberger companies, including Europe Region Reservoir Engineering and Stimulation Manager and Senior Staff Engineer, North America. Publications include authoring or co-authoring of 7 textbooks and more than 150 journal papers and articles. Professor Economides is involved in a wide range of industrial consulting, including major retainers by national oil companies at the country level and by Fortune 500 companies. He is the founder and a major shareholder in OTEK (Australia), a petroleum service and consulting firm with offices in five Australian cities. In addition to his technical interests, he has written extensively in wide circulation media on a broad range of topics associated with energy and geopolitical issues. KENNETH G. NOLTE has held various senior technical and marketing positions with Schlumberger since 1986. From 1984 to 1986, he was with Nolte-Smith, Inc. (now NSI Technologies, Inc.). Prior to 1984, Dr. Nolte was a research associate with Amoco Production Company, where he worked for 16 years in the areas of offshore/arctic technology and hydraulic fracturing. Dr. Nolte holds a BS degree from the University of Illinois and received an MS and PhD from Brown University. He has authored numerous journal publications and has various patents relating to material behavior, drilling, offshore technology and fracturing. Dr. Nolte was 1986–1987 SPE Distinguished Lecturer and received the Lester C. Uren Award in 1992.

Table of Contents

Preface: Hydraulic Fracturing, A Technology for All Time 1(1)
Ahmed S. Abou-Sayed
Reservoir Stimulation in Petroleum Production
Michael J. Economides
Curtis Boney
Introduction
1(2)
Petroleum production
1(2)
Units
3(1)
Inflow performance
3(8)
IPR for steady state
4(1)
IPR for pseudosteady state
5(1)
IPR for transient (or infinite-acting) flow
5(1)
Horizontal well production
6(4)
Permeability anisotropy
10(1)
Alterations in the near-wellbore zone
11(7)
Skin analysis
11(1)
Components of the skin effect
12(1)
Skin effect caused by partial completion and slant
12(1)
Perforation skin effect
13(3)
Hydraulic fracturing in production engineering
16(2)
Tubing performance and NODAL* analysis
18(2)
Decision process for well stimulation
20(2)
Stimulation economics
21(1)
Physical limits to stimulation treatments
22(1)
Reservoir engineering considerations for optimal production enhancement strategies
22(6)
Geometry of the well drainage volume
23(1)
Well drainage volume characterizations and production optimization strategies
24(4)
Stimulation execution
28(1)
Matrix stimulation
28
Hydraulic fracturing
18
Formation Characterization: Well and Reservoir Testing
Christine A. Ehlig-Economides
Michael J. Economides
Evolution of a technology
1(2)
Horner semilogarithmic analysis
1(1)
Log-log plot
2(1)
Pressure derivative in well test diagnosis
3(4)
Parameter estimation from pressure transient data
7(5)
Radial flow
7(2)
Linear flow
9(1)
Spherical flow
10(1)
Dual porosity
11(1)
Wellbore storage and pseudosteady state
11(1)
Test interpretation methodology
12(2)
Analysis with measurement of layer rate
14(1)
Layered reservoir testing
15(1)
Selective inflow performance analysis
15(1)
Analysis of multilayer transient test data
16(1)
Testing multilateral and multibranch wells
16(1)
Permeability determination from a fracture injection test
17(1)
Pressure decline analysis with the Carter leakoff model
17(4)
Filter-Cake plus reservior pressure drop leakoff model (according to Mayerhofer et al., 1993)
21
Formation Characterization: Rock Mechanics
M. C. Thiercelin
J.-C. Roegiers
Introduction
1(3)
Sidebar 3A. Mechanics of hydraulic fracturing
2(2)
Basic concepts
4(2)
Stresses
4(1)
Strains
5(1)
Sidebar 3B. Mohr circle
5(1)
Rock behavior
6(6)
Linear elasticity
6(2)
Sidebar 3C. Elastic constants
8(1)
Influence of pore pressure
8(1)
Fracture mechanics
9(2)
Nonelastic deformation
11(1)
Failure
11(1)
Rock mechanical property measurement
12(9)
Importance of rock properties in stimulation
12(1)
Laboratory testing
13(1)
Stress-strain curve
14(1)
Elastic parameters
15(4)
Rock strength, yield criterion and failure envelope
19(1)
Fracture toughness
19(1)
Sidebar 3D. Fracture toughness testing
20(1)
State of stress in the earth
21(7)
Rock at rest
22(1)
Tectonic strains
23(1)
Rock at failure
23(2)
Influence of pore pressure
25(1)
Influence of temperature
26(1)
Principal stress direction
26(1)
Stress around the wellbore
26(1)
Stress change from hydraulic fracturing
27(1)
In-situ stress management
28(1)
Importance of stress measurement in stimulation
28(1)
Micro-hydraulic fracturing techniques
28(6)
Fracture calibration techniques
34(1)
Laboratory techniques
34
Formation Characterization: Well Logs
Jean Desroches
Tom Bratton
Introduction
1(1)
Depth
2(1)
Temperature
2(1)
Properties related to the diffusion of fluids
3(10)
Porosity
3(2)
Lithology and saturation
5(1)
Permeability
6(2)
Sidebar 4A. Permeability-porosity correlations
8(2)
Pore pressure
10(1)
Skin effect and damage radius
11(1)
Composition of fluids
12(1)
Properties related to the deformation and fracturing of rock
13(11)
Mechanical properties
13(2)
Stresses
15(9)
Zoning
24
Basics of Hydraulic Fracturing
M. B. Smith
J. W. Shlyapobersky
Introduction
1(8)
What is fracturing?
1(3)
Why fracture?
4(2)
Design considerations and primary variables
6(1)
Sidebar 5A. Design goals and variables
7(2)
Variable interaction
9(1)
In-situ stress
9(1)
Reservoir engineering
10(3)
Design goals
11(1)
Sidebar 5B. Highway analogy for dimensionless fracture conductivity
11(1)
Complicating factors
12(1)
Reservoir effects on fluid loss
13(1)
Rock and fluid mechanics
13(7)
Material balance
13(1)
Fracture height
14(1)
Fracture width
15(1)
Fluid mechanics and fluid flow
15(1)
Fracture mechanics and fracture tip effects
16(1)
Fluid loss
17(1)
Variable sensitivities and interactions
18(2)
Treatment pump scheduling
20(6)
Fluid and proppant selection
20(1)
Pad volume
21(2)
Proppant transport
23(1)
Proppant admittance
24(1)
Fracture models
25(1)
Economics and operational considerations
26(1)
Economics
26(1)
Operations
27
Appendix: Evolution of hydraulic fracturing design and evaluation
1(1)
K. G. Nolte
Mechanics of Hydraulic Fracturing
Mark G. Mack
Norman R. Warpinski
Introduction
1(1)
History of early hydraulic fracture modeling
2(6)
Basic fracture modeling
2(1)
Hydraulic fracture modeling
3(3)
Sidebar 6A. Approximation to the Carter equation for leakoff
6(1)
Sidebar 6B. Approximations to Nordgren's equations
6(2)
Sidebar 6C. Radial fracture geometry models
8(1)
Three-dimensional and pseudo-three-dimensional models
8(17)
Sidebar 6D. Field determination of fracture geometry
10(1)
Planar three-dimensional models
11(1)
Sidebar 6E. Lateral coupling in pseudo-three-dimensional models
12(1)
Sidebar 6F. Momentum conservation equation for hydraulic fracturing
13(1)
Sidebar 6G. Momentum balance and constitutive equation for non-Newtonian fluids
14(2)
Cell-based pseudo-three-dimensional models
16(4)
Sidebar 6H. Stretching coordinate system and stability analysis
20(3)
Lumped pseudo-three-dimensional models
23(2)
Leakoff
25(3)
Filter cake
25(1)
Filtrate zone
26(1)
Reservoir zone
26(1)
Combined mechanisms
26(1)
General model of leakoff
27(1)
Other effects
27(1)
Proppant placement
28(1)
Effect of proppant on fracturing fluid rheology
28(1)
Convection
28(1)
Proppant transport
29(1)
Heat transfer models
29(1)
Historical heat transfer models
30(1)
Improved heat transfer models
30(1)
Fracture tip effects
30(6)
Sidebar 6I. Efficient heat transfer algorithm
31(1)
Sidebar 6J. Verification of efficient thermal calculations
32(1)
Linear elastic fracture mechanics
32(1)
Sidebar 6K. Crack tip stresses and the Rice equation
33(1)
Extensions to LEFM
34(1)
Field calibration
35(1)
Tortuosity and other near-well effects
36(4)
Fracture geometry around a wellbore
36(1)
Perforation and deviation effects
36(1)
Perforation friction
37(1)
Tortuosity
37(1)
Phasing misalignment
38(2)
Acid fracturing
40(4)
Historical acid fracturing models
40(1)
Reaction stoichiometry
40(1)
Acid fracture conductivity
41(1)
Energy balance during acid fracturing
42(1)
Reaction kinetics
42(1)
Mass transfer
42(1)
Acid reaction model
43(1)
Acid fracturing: fracture geometry model
43(1)
Multilayer fracturing
44(2)
Pump schedule generation
46(2)
Sidebar 6L. Approximate proppant schedules
47(1)
Pressure history matching
48(1)
Sidebar 6M. Theory and method of pressure inversion
48
Fracturing Fluid Chemistry and Proppants
Janet Gulbis
Richard M. Hodge
Introduction
1(1)
Water-base fluids
1(5)
Oil-base fluids
6(1)
Acid-based fluids
7(1)
Materials and techniques for acid fluid-loss control
7(1)
Materials and techniques for acid reaction-rate control
8(1)
Multiphase fluids
8(2)
Foams
9(1)
Emulsions
9(1)
Additives
10(9)
Crosslinkers
10(3)
Sidebar 7A. Ensuring optimum crosslinker performance
13(1)
Breakers
14(2)
Sidebar 7B. Breaker selection
16(1)
Fluid-loss additives
16(2)
Bactericides
18(1)
Stabilizers
18(1)
Surfactants
19(1)
Clay stabilizers
19(1)
Proppants
19(3)
Physical properties of proppants
19(2)
Classes of proppants
21(1)
Sidebar 7C. Minimizing the effects of resin-coated proppants
22(1)
Execution
22(1)
Mixing
22(1)
Quality assurance
23(1)
Acknowledgements
23
Performance of Fracturing Materials
Vernon G. Constien
George W. Hawkins
R. K. Prud'homme
Reinaldo Navarrete
Introduction
1(1)
Fracturing fluid characterization
1(1)
Characterization basics
2(1)
Translation of field conditions to a laboratory environment
2(1)
Molecular characterization of gelling agents
2(4)
Correlations of molecular weight and viscosity
2(1)
Concentration and chain overlap
3(1)
Molecular weight distribution
4(1)
Characterization of insoluble components
5(1)
Reactions sites and kinetics of crosslinking
5(1)
Rheology
6(13)
Basic flow relations
7(1)
Power law model
7(1)
Models that more fully describe fluid behavior
8(2)
Determination of fracturing fluid rheology
10(2)
Rheology of foam and emulsion fluids
12(3)
Effect of viscometer geometry on fluid viscosity
15(1)
Characterization of fluid microstructure using dynamic oscillatory measurements
16(1)
Relaxation time and slip
17(1)
Slurry rheology
17(2)
Proppant effects
19(3)
Characterization of proppant transport properties
19(2)
Particle migration and concentration
21(1)
Fluid loss
22(1)
Fluid loss under static conditions
23(1)
Fluid loss under dynamic conditions
24(1)
Shear rate in the fracture and its influence on fluid loss
25(1)
Influence of permeability and core length
26(1)
Differential pressure effects
26
Fracture Evaluation Using Pressure Diagnostics
Sunil N. Gulrajani
K. G. Nolte
Introduction
1(1)
Background
2(1)
Fundamental principles of hydraulic fracturing
3(7)
Fluid flow in the fracture
3(1)
Material balance or conservation of mass
4(1)
Rock elastic deformation
4(2)
Sidebar 9A. What is closure pressure?
6(3)
Sidebar 9B. Pressure response of toughness-dominated fractures
9(1)
Pressure during pumping
10(24)
Time variation for limiting fluid efficiencies
12(1)
Inference of fracture geometry from pressure
12(2)
Diagnosis of periods of controlled fracture height growth
14(1)
Examples of injection pressure analysis
15(1)
Sidebar 9C. Pressure derivative analysis for diagnosing pumping pressure
16(2)
Diagnostics for nonideal fracture propagation
18(5)
Sidebar 9D. Fluid leakoff in natural fissures
23(1)
Formation pressure capacity
24(3)
Pressure response after a screenout
27(1)
Fracture diagnostics from log-log plot slopes
28(2)
Near-Wellbore effects
30(2)
Sidebar 9E. Rate step-down test analysis-a diagnostic for fracture entry
32(2)
Analysis during fracture closure
34(11)
Fluid efficiency
34(3)
Basic pressure decline analysis
37(1)
Decline analysis during nonideal conditions
38(4)
Generalized pressure decline analysis
42(1)
Sidebar 9F. G-function derivative analysis
43(2)
Pressure interpretation after fracture closure
45(14)
Why linear and radial flow after fracture closure?
46(2)
Linear, transitional and radial flow pressure responses
48(1)
Sidebar 9G. Impulse testing
49(1)
Mini-falloff test
50(1)
Integration of after-closure and preclosure analyses
50(1)
Physical and mathematical descriptions
51(2)
Influence of spurt loss
53(1)
Consistent after-closure diagnostic framework
54(2)
Application of after-closure analysis
56(1)
Field example
57(2)
Numerical simulation of pressure: combined analysis of pumping and closing
59(2)
Pressure matching
60(1)
Nonuniqueness
60(1)
Comprehensive calibration test sequence
61
Background for hydraulic fracturing pressure analysis techniques
1(1)
Sunil N. Gulrajani
K. G. Nolte
Fracture Treatment Design
Jack Elbel
Larry Britt
Introduction
1(2)
Sidebar 10A. NPV for fixed costs or designated proppant mass
2(1)
Design considerations
3(11)
Economic optimization
3(1)
Treatment optimization design procedure
3(1)
Fracture conductivity
4(2)
Dimensionless fracture conductivity
6(2)
Non-Darcy effects
8(1)
Proppant selection
8(1)
Treatment size
9(1)
Fluid loss
10(1)
Viscosity effects
11(1)
Sidebar 10B. Fluid exposure time
12(1)
Injection rate
13(1)
Geometry modeling
14(3)
Sidebar 10C. Geometry models
14(1)
Model selection
15(1)
Sources of formation parameters
16(1)
Sidebar 10D. In-situ stress correlation with lithology
16(1)
Treatment schedule
17(7)
Sidebar 10E. Fracturing economics sensitivity to formation permeability and skin effect
17(1)
Normal proppant scheduling
18(3)
Tip screenout
21(3)
Multilayer fracturing
24(6)
Limited entry
24(1)
Interval grouping
25(1)
Single fracture across multilayers
25(1)
Two fractures in a multilayer reservoir
26(2)
Field example
28(1)
Sidebar 10F. Fracture evaluation in multilayer zones
28(2)
Acid fracturing
30(12)
Acid-etched fracture conductivity
31(1)
Sidebar 10G. Acid-etched conductivity
32(1)
Acid fluid loss
33(1)
Sidebar 10H. Fluid-loss control in wormholes
34(1)
Acid reaction rate
35(1)
Acid fracturing models
36(1)
Parameter sensitivity
36(5)
Formation reactivity properties
41(1)
Propped or acid fracture decision
41(1)
Deviated wellbore fracturing
42(1)
Reservoir considerations
43(2)
Fracture spacing
45(1)
Convergent flow
45(2)
Fracturing execution in deviated and horizontal wells
47(2)
Horizontal well example
49
Fracturing Operations
J. E. Brown
R. W. Thrasher
L. A. Behrmann
Introduction
1(1)
Completions
1(7)
Deviated and S-shaped completions
1(1)
Horizontal and multilateral completions
2(1)
Slimhole and monobore completions
2(1)
Zonal isolation
2(1)
Sidebar 11A. Factors influencing cement bond integrity
3(3)
Sidebar 11B. Coiled tubing-conveyed fracture treatments
6(2)
Perforating
8(11)
Background
8(1)
Sidebar 11C. Estimating multizone injection profiles during hydraulic fracturing
9(2)
Sidebar 11D. Propagating a microannulus during formation breakdown
11(1)
Perforation phasing for hard-rock hydraulic fracturing
11(3)
Other perforating considerations for fracturing
14(2)
Frac and packs and high-rate water packs
16(1)
Fracturing for sand control without gravel-pack screens
16(1)
Sidebar 11E. Calculation of minimum shot density for fracture stimulation
17(1)
Extreme overbalance stimulation
18(1)
Well and fracture connectivity
18(1)
Surface equipment for fracturing operations
19(7)
Wellhead isolation
19(1)
Treating iron
19(3)
High-pressure pumps
22(1)
Blending equipment
23(1)
Proppant storage and delivery
23(1)
Vital signs from sensors
24(2)
Equipment placement
26(1)
Bottomhole pressure measurement and analysis
26(3)
Proppant flowback control
29(1)
Forced closure
30(1)
Resin flush
30(1)
Resin-coated proppants
30(1)
Fiber technology
30(1)
Flowback strategies
30(2)
Sidebar 11F. Fiber technology
31(1)
Quality assurance and quality control
32(1)
Health, safety and environment
32(1)
Safety considerations
32(1)
Environmental considerations
33
Appendix: Understanding perforator penetration and flow performance
1(1)
Phillip M. Halleck
Post-Treatment Evaluation and Fractured Well Performance
B. D. Poe, Jr.
Michael J. Economides
Introduction
1(9)
Fracture mapping techniques
1(5)
Pressure transient analysis
6(4)
Post-treatment fracture evaluation
10(6)
Wellbore storage dominated flow regime
11(1)
Fracture storage linear flow regime
11(1)
Bilinear flow regime
11(2)
Formation linear flow regime
13(1)
Pseudoradial flow regime
14(1)
Pseudosteady-state flow regime
15(1)
Factors affecting fractured well performance
16(11)
Non-Darcy flow behavior
16(4)
Nonlinear fluid properties
20(1)
Fracture damage and spatially varying fracture properties
21(4)
Damage in high-permeability fracturing
25(1)
Heterogeneous systems
26(1)
Well test analysis of vertically fractured wells
27(12)
Wellbore storage dominated flow analysis
28(1)
Fracture storage linear flow analysis
28(1)
Bilinear flow analysis
29(1)
Formation linear flow analysis
29(1)
Pseudoradial flow analysis
29(1)
Well test design considerations
30(1)
Example well test analyses
31(8)
Prediction of fractured well performance
39
Introduction to Matrix Treatments
R. L. Thomas
L. N. Morgenthaler
Introduction
1(3)
Candidate selection
1(1)
Sidebar 13A. The history of matrix stimulation
2(1)
Formation damage characterization
3(1)
Stimulation technique determination
3(1)
Fluid and additive selection
3(1)
Pumping schedule generation and simulation
3(1)
Economic evaluation
4(1)
Execution
4(1)
Evaluation
4(1)
Candidate selection
4(4)
Identifying low-productivity wells and stimulation candidates
4(2)
Sidebar 13B. Candidate selection field case history
6(1)
Impact of formation damage on productivity
6(1)
Preliminary economic evaluation
7(1)
Formation damage characterization
8(2)
Sidebar 13C. Formation damage characterization field case history
9(1)
Sidebar 13D. Fluid and additive selection field case history
10(1)
Stimulation technique determination
10(1)
Treatment design
11(21)
Matrix stimulation techniques
11(1)
Treatment fluid selection
12(7)
Pumping schedule generation and simulation
19(10)
Sidebar 13E. Placement study case histories
29(3)
Final economic evaluation
32(1)
Execution
32(3)
Quality control
32(2)
Data collection
34(1)
Treatment evaluation
35(1)
Pretreatment evaluation
35(1)
Real-time evaluation
35(2)
Post-treatment evaluation
37
Formation Damage: Origin, Diagnosis and Treatment Strategy
Donald G. Hill
Oliver M. Lietard
Bernard M. Piot
George E. King
Introduction
1(1)
Damage characterization
1(3)
Pseudodamage
2(1)
Pseudoskin effects and well completion and configuration
3(1)
Formation damage descriptions
4(9)
Fines migration
4(2)
Swelling clays
6(1)
Scales
6(1)
Organic deposits
7(1)
Mixed deposits
8(1)
Emulsions
9(1)
Induced particle plugging
9(1)
Wettability alteration
10(1)
Acid reactions and acid reaction by-products
11(1)
Bacteria
11(1)
Water blocks
12(1)
Oil-base drilling fluids
13(1)
Origins of formation damage
13(13)
Drilling
13(8)
Cementing
21(1)
Perforating
21(1)
Gravel packing
22(1)
Workovers
22(1)
Stimulation and remedial treatments
23(1)
Normal production or injection operations
24(2)
Laboratory identification and treatment selection
26(5)
Damage identification
26(2)
Treatment selection
28(3)
Treatment strategies and concerns
31(8)
Fines and clays
33(1)
Scales
34(1)
Organic deposits
35(1)
Mixed deposits
35(1)
Emulsions
36(1)
Bacteria
36(1)
Induced particle plugging
36(1)
Oil-base drilling fluids
37(1)
Water blocks
37(1)
Wettability alteration
38(1)
Wellbore damage
38(1)
Conclusions
39
Additives in Acidizing Fluids
Syed A. Ali
Jerald J. Hinkel
Introduction
1(1)
Corrosion inhibitors
2(3)
Corrosion of metals
2(1)
Acid corrosion on steel
2(1)
Pitting types of acid corrosion
3(1)
Hydrogen embrittlement
3(1)
Corrosion by different acid types
3(1)
Inhibitor types
4(1)
Compatibility with other additives
4(1)
Laboratory evaluation of inhibitors
5(1)
Suggestions for inhibitor selection
5(1)
Surfactants
5(6)
Anionic surfactants
6(1)
Cationic surfactants
6(1)
Nonionic surfactants
6(1)
Amphoteric surfactants
7(1)
Fluorocarbon surfactants
7(1)
Properties affected by surfactants
7(2)
Applications and types of surfactants
9(2)
Clay stabilizers
11(2)
Highly charged cations
11(1)
Quaternary surfactants
12(1)
Polyamines
12(1)
Polyquaternary amines
12(1)
Organosilane
13(1)
Mutual solvents
13(1)
Adsorption of mutual solvents
14(1)
Chlorination of mutual solvents
14(1)
Iron control additives
14(2)
Sources of iron
14(1)
Methods of iron control
15(1)
Alcohols
16(2)
Acetic acid
18(1)
Organic dispersants
18(1)
Organic solvents
18(1)
Diversion
18(1)
Additive compatibility
19(1)
Facility upsets following acid stimulation
19(1)
Discharge requirements
19(1)
Prevention of facility upsets
20
Fundamentals of Acid Stimulation
A. Daniel Hill
Robert S. Schechter
Introduction
1(1)
Acid-mineral interactions
2(11)
Acid-mineral reaction stoichiometry
2(2)
Acid-mineral reaction kinetics
4(1)
Sidebar 16A. Calculating minimum acid volume using dissolving power
5(3)
Sidebar 16B. Relative reaction rates of sandstone minerals
8(2)
Precipitation of reaction products
10(1)
Sidebar 16C. Geochemical model predictions
11(2)
Sandstone acidizing
13(6)
Introduction
13(1)
Acid selection
13(1)
Sandstone acidizing models
13(3)
Sidebar 16D. Comparison of acid volumes for radial and perforation flow
16(3)
Permeability response
19(1)
Carbonate acidizing
19(1)
Distinctive features
19(1)
Wormholes
20(1)
Initiation of wormholes
21(2)
Acidizing experiments
23(3)
Sidebar 16E. Optimum injection rate for initiating carbonate treatment
26(1)
Propagation of wormholes
27
Appendix: Advances in understanding and predicting wormhole formation
1(1)
Christopher N. Fredd
Carbonate Acidizing Design
J. A. Robert
C. W. Crowe
Introduction
1(1)
Rock and damage characteristics in carbonate formations
1(1)
Rock characteristics
1(1)
Damage characteristics
2(1)
Carbonate acidizing with hydrochloric acid
2(7)
Introduction
2(1)
Historical background
2(1)
Reactivity of carbonate minerals with hydrochloric acid
3(1)
Acidizing physics
4(2)
Sidebar 17A. Wormhole initiation and propagation
6(1)
Application to field design
7(1)
Sidebar 17B. Acidizing case study
8(1)
Other formulations
9(5)
Organic acids
9(1)
Gelled acids
10(1)
Emulsions
11(1)
Microemulsions
11(1)
Special treatments
12(1)
Self-diverting acid
12(1)
Sidebar 17C. Examples of special treatments
13(1)
Sidebar 17D. Placement using self-diverting acid
13(1)
Treatment design
14(1)
Candidate selection
14(1)
Pumping schedule
14(1)
Additives
14(1)
Placement
14(1)
Conclusions
14(1)
Acknowledgments
15
Sandstone Acidizing
Harry O. McLeod
William David Norman
Introduction
1(1)
Treating fluids
1(3)
Hydrochloric acid chemistry
2(1)
Chemistry of hydrofluoric acid systems
2(2)
Solubility of by-products
4(2)
Calcium fluoride
5(1)
Alkali fluosilicates and fluoaluminates
5(1)
Aluminum fluoride and hydroxide
5(1)
Ferric complexes
5(1)
Kinetics: factors affecting reaction rates
6(1)
Hydrofluoric acid concentration
6(1)
Hydrochloric acid concentration
6(1)
Temperature
7(1)
Mineralogical composition and accessible surface area
7(1)
Pressure
7(1)
Hydrofluoric acid reaction modeling
7(1)
Other acidizing formulations
8(4)
Fluoboric acid
8(2)
Sequential mud acid
10(1)
Alcoholic mud acid
11(1)
Mud acid plus aluminum chloride for retardation
11(1)
Organic mud acid
11(1)
Self-generating mud acid systems
12(1)
Buffer-regulated hydrofluoric acid systems
12(1)
Damage removal mechanisms
12(6)
Formation response to acid
13(1)
Formation properties
13(1)
Formation brine compatibility
13(1)
Crude oil compatibility
14(1)
Formation mineral compatibility with fluid systems
14(2)
Acid type and concentration
16(2)
Methods of controlling precipitates
18(1)
Preflush
18(1)
Mud acid volume and concentration
18(1)
Postflush or overflush
18(1)
Acid treatment design considerations
19(4)
Selection of fluid sequence stages
20(1)
Typical sandstone acid job stages
20(1)
Tubing pickle
20(1)
Preflushes
20(1)
Main fluid stage
21(1)
Overflush stage
21(1)
Diversion techniques
22(1)
Typical sandstone acid job stages
22(1)
Matrix acidizing design guidelines
23(3)
Calculations
24(1)
Flowback and cleanup techniques
25(1)
Acid treatment evaluation
26(1)
Conclusions
27
Fluid Placement and Pumping Strategy
J. A. Robert
W. R. Rossen
Introduction
1(1)
Choice of pumping strategy
1(3)
Importance of proper placement
1(1)
Comparison of diversion methods
2(1)
Fluid placement versus injection rate
3(1)
MAPDIR method
3(1)
Chemical diverter techniques
4(2)
Historical background
4(1)
Diverting agent properties
4(1)
Classification of diverting agents
4(1)
Potential problems during diversion treatment
5(1)
Laboratory characterization
6(4)
Modeling diverter effects
7(2)
Field design
9(1)
Foam diversion
10(8)
Historical background
10(1)
Foam mechanisms
10(2)
Foam behavior in porous media
12(2)
Foam diversion experiments
14(1)
Modeling and predicting foam diversion
15(1)
Application to field design
16(2)
Ball sealers
18(1)
Mechanical tools
19(1)
Horizontal wells
20(3)
Optimal treatment
20(2)
Placement techniques
22(1)
Conclusions
23(1)
Acknowledgments
24
Matrix Stimulation Treatment Evaluation
Carl T. Montogomery
Michael J. Economides
Introduction
1(1)
Derivation of bottomhole parameters from wellhead measurements
1(1)
Monitoring skin effect evolution during treatment
1(3)
McLeod and Coulter technique
1(1)
Paccaloni technique
2(2)
Prouvost and Economides method
4(1)
Deriving skin effect during treatment
4(1)
Determining reservoir characteristics before treatment
4(1)
Behenna method
5(1)
Inverse injectivity diagnostic plot
5(1)
Limitations of matrix treatment evaluation techniques
5(3)
Sidebar 20A. Example calculation of the Prouvost and Economides method
6(1)
Sidebar 20B. Example application of the Hill and Zhu method
7(1)
Treatment response diagnosis
8(3)
Sidebar 20C. Production indications for matrix stimulation requirements
10(1)
Post-treatment evaluation
11(1)
Return fluid analysis
11(1)
Tracer surveys
11(1)
Conclusions
12
References
Chapters 1--12
R-1
Chapters 13--20
R-45
Nomenclature N-1
Index I-1

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