Petroleum Engineering

Principles, Calculations, and Workflows
 
 
Standards Information Network (Verlag)
  • 1. Auflage
  • |
  • erschienen am 21. September 2018
  • |
  • 528 Seiten
 
E-Book | PDF mit Adobe DRM | Systemvoraussetzungen
978-1-119-38796-1 (ISBN)
 

A comprehensive and practical guide to methods for solving complex petroleum engineering problems

Petroleum engineering is guided by overarching scientific and mathematical principles, but there is sometimes a gap between theoretical knowledge and practical application. Petroleum Engineering: Principles, Calculations, and Workflows presents methods for solving a wide range of real-world petroleum engineering problems. Each chapter deals with a specific issue, and includes formulae that help explain primary principles of the problem before providing an easy to follow, practical application.

Volume highlights include:

  • A robust, integrated approach to solving inverse problems
  • In-depth exploration of workflows with model and parameter validation
  • Simple approaches to solving complex mathematical problems
  • Complex calculations that can be easily implemented with simple methods
  • Overview of key approaches required for software and application development
  • Formulae and model guidance for diagnosis, initial modeling of parameters, and simulation and regression

Petroleum Engineering: Principles, Calculations, and Workflows is a valuable and practical resource to a wide community of geoscientists, earth scientists, exploration geologists, and engineers. This accessible guide is also well-suited for graduate and postgraduate students, consultants, software developers, and professionals as an authoritative reference for day-to-day petroleum engineering problem solving.
Read an interview with the editors to find out more:
https://eos.org/editors-vox/integrated-workflow-approach-for-petroleum-engineering-problems



Moshood Sanni, PetroVision Energy Services, UK

1. Auflage
  • Englisch
  • Newark
  • |
  • USA
John Wiley & Sons Inc
  • Für Beruf und Forschung
  • 61,46 MB
978-1-119-38796-1 (9781119387961)
weitere Ausgaben werden ermittelt
Moshood Sanni, PetroVision Energy Services, UK
  • Intro
  • TITLE PAGE
  • COPYRIGHT PAGE
  • CONTENTS
  • PREFACE
  • ACKNOWLEDGMENTS
  • Chapter 1 Petroleum System and Petroleum Engineering
  • 1.1. THE PETROLEUM ENGINEER
  • 1.2. ROLES OF THE PETROLEUM ENGINEER IN THE FIELD LIFE CYCLE
  • 1.3. ORIGIN OF PETROLEUM
  • 1.4. PETROLEUM SYSTEM
  • 1.4.1. Petroleum Source Rocks
  • 1.4.2. Petroleum Migration
  • 1.4.3. Reservoir Rock
  • 1.4.4. Seal Rock
  • 1.4.5. Traps
  • 1.5. PETROLEUM RESERVOIRS
  • 1.5.1. Reservoir Fluid Zones
  • 1.5.2. Reservoir Hydrocarbon Volumes
  • 1.6. PETROLEUM RESOURCE CLASSIFICATION
  • 1.6.1. Prospective Resources
  • 1.6.2. Contingent Resources
  • 1.6.3. Reserves
  • 1.6.4. Reserve Estimation Methods
  • 1.6.5. Use of Seismic Data for Petroleum Resource Calculation
  • 1.6.6. Resource Estimation at Different Stages of Life Cycle
  • 1.6.7. Reserve Reporting and Audit
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 2 Petroleum Reservoir Rock Properties
  • 2.1. POROSITY
  • 2.1.1. Absolute and Effective Porosity
  • 2.1.2. Porosity Determination
  • 2.2. PERMEABILITY
  • 2.2.1. Henry Darcy´s Experiment
  • 2.2.2. Darcy´s Law for Liquids
  • 2.2.3. Darcy´s Law for Gas
  • 2.2.4. Non-Darcy Flow
  • 2.2.5. Averaging Reservoir Permeability
  • 2.3. EFFECTIVE CONFINING PRESSURE DEPENDENCE OF POROSITY AND PERMEABILITY
  • 2.4. WETTABILITY
  • 2.4.1. Wettability Measurement
  • 2.5. CAPILLARY PRESSURE
  • 2.5.1. Capillary Tube Analogy of Porous Media
  • 2.5.2. Capillary Pressure and Fluid Distribution
  • 2.5.3. Capillary Pressure Defined as a Function of Radii of Curvature of Interface
  • 2.5.4. Experimental Determination of Capillary Pressure
  • 2.5.5. Leverett J-Function
  • 2.5.6. Empirical Relationship for Capillary Pressure
  • 2.5.7. Saturation Height Function Prediction in Reservoirs
  • 2.6. RELATIVE PERMEABILITY
  • 2.6.1. Relative Permeability Models
  • 2.6.2. Three-phase Relative Permeability
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 3 Reservoir Fluid Properties
  • 3.1. PHASE BEHAVIOR OF PETROLEUM HYDROCARBONS
  • 3.1.1. Black Oil (Low Shrinkage Oil)
  • 3.1.2. Volatile Oil (High Shrinkage Oil)
  • 3.1.3. Retrograde Gas (Gas Condensate)
  • 3.1.4. Wet Gas
  • 3.1.5. Dry Gas
  • 3.2. NATURAL GAS PROPERTIES
  • 3.2.1. Ideal Gas Behavior
  • 3.2.2. Real Gas Behavior
  • 3.2.3. Equation of State for Predicting Real Gas Behavior
  • 3.3. CRUDE OIL PROPERTIES
  • 3.3.1. Crude Oil Property Correlations
  • 3.3.2. Liquid Viscosity Model
  • 3.3.3. Interfacial Tension
  • 3.4. VAPOR LIQUID EQUILIBRIUM (VLE)
  • 3.4.1. Flash Calculations
  • 3.4.2. K Value Calculations
  • 3.4.3. Properties of Pseudocomponents
  • 3.4.4. Saturation Points
  • 3.5. RESERVOIR FLUID SAMPLING
  • 3.5.1. Bottomhole Sampling
  • 3.5.2. Surface Sampling
  • 3.6. FLUID EXPERIMENTS
  • 3.6.1. Gas Laboratory Experiment
  • 3.6.2. Oil Laboratory Experiment
  • 3.6.3. Enhanced Oil Recovery Experiments
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 4 Equations of States
  • 4.1. GENERALIZED REPRESENTATION OF EOS MODELS
  • 4.2. EOS MODELS FOR MULTICOMPONENTS
  • 4.2.1. Simple Mixing Rule
  • 4.2.2. van der Waals Mixing Rule
  • 4.2.3. EOS Model Parameters
  • 4.2.4. Solution of Cubic EOS
  • 4.2.5. Fluid Property Prediction using EOS
  • 4.2.6. Matching and Tuning EOS Models
  • 4.3. PRACTICAL STEPS IN TUNING EOS MODEL
  • 4.3.1. Challenges in Tuning EOS Models
  • 4.4. EQUATION OF STATES FOR VAPOR-LIQUID EQUILIBRIUM CALCULATIONS
  • 4.4.1. Steps in Carrying Out VLE Calculations using EOS
  • 4.4.2. Saturation Points Calculation using the EOS-VLE Method
  • 4.5. COMPOSITIONAL GRADING
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 5 Formation Evaluation
  • 5.1. FORMATION EVALUATION
  • 5.1.1. Well Deviation Survey Calculation
  • 5.1.2. Well Log Measurement
  • 5.1.3. Caliper Log
  • 5.1.4. Gamma Ray (GR) Log
  • 5.1.5. Spontaneous Potential (SP) Log
  • 5.1.6. Density Log
  • 5.1.7. Neutron Log
  • 5.1.8. Combined Neutron-Density Log
  • 5.1.9. Sonic Log
  • 5.1.10. Resistivity Log
  • 5.2. PERMEABILITY LOGS
  • 5.2.1. Permeability Logs from Formation Test
  • 5.2.2. Permeability Logs from Core Data
  • 5.2.3. Permeability Logs from Well Test Permeability
  • 5.2.4. Permeability Log Estimation from other Properties
  • 5.3. SUMMARY OF FORMATION EVALUATION
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 6 Formation Testing
  • 6.1 FORMATION TESTERS
  • 6.1.1. Flowline (Tool) Storage Effect (FLSE)
  • 6.2. ANALYSIS OF WIRELINE FORMATION TEST DATA
  • 6.2.1. Single Probe/Snorkel Module/Probe Module
  • 6.2.2. Spherical Flow Equation for a Probe
  • 6.2.3. Formation Pressure
  • 6.2.4. Formation Mobility and Permeability Calculation
  • 6.2.5. Upscaling WFT Permeability
  • 6.2.6. Mud Hydrostatic Pressure
  • 6.2.7. Straddle/Dual Packer Module
  • 6.2.8. Probe-Probe or Probe-Packer Configuration
  • 6.2.9. Fluid Sampling and Property Measurement
  • 6.2.10. Downhole Fluid Analysis
  • 6.2.11. Formation Pressure Log (Multistation Formation Testing)
  • 6.2.12. Analysis of Formation Pressure Log
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 7 Fluid Flow in Reservoirs
  • 7.1. DIFFUSIVITY EQUATION
  • 7.1.1. Diffusivity Equation for Gas
  • 7.1.2. Normalized Pseudopressure
  • 7.2. SOLUTION OF DIFFUSIVITY EQUATION
  • 7.2.1. Mathematical Methods for Solving the Diffusivity Equation
  • 7.3 BOUNDARY CONDITIONS DURING PRESSURE DIFFUSION IN RESERVOIRS
  • 7.3.1. Near Wellbore Effects
  • 7.3.2. Reservoir Behavior
  • 7.3.3. Boundary Effects
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 8 Well Test Analysis
  • 8.1. TYPES OF WELL TEST
  • 8.2. PHILOSOPHY OF WELL TEST ANALYSIS
  • 8.2.1. Well Test Objectives
  • 8.2.2. Well Testing at Different Stages of Field Life
  • 8.3. WELL TEST INTERPRETATION METHODOLOGY
  • 8.4. WELL TEST ANALYSIS APPROACH
  • 8.4.1. Pressure-type Curve Analysis
  • 8.4.2. Pressure Derivatives
  • 8.4.3. Well Test Derivative Diagnostic Plot
  • 8.4.4. Reservoir Behavior
  • 8.4.5. Reservoir Boundary Behavior
  • 8.4.6. Deconvolution
  • 8.5. INTERPRETATION MODELS
  • 8.5.1. Analytical Well Test Models
  • 8.6. UNCERTAINTY ASSOCIATED WITH WELL TEST ANALYSIS RESULT
  • 8.6.1. Confidence of Intervals in Well Test Analysis
  • 8.6.2. Factors that Affect Well Test Interpretation
  • 8.7. WELL TEST ANALYSIS IN THE GAS RESERVOIR
  • 8.8. EFFECT OF DEPLETION ON WELL TEST ANALYSIS IN GAS RESERVOIRS
  • 8.8.1. Pseudotime Transform
  • 8.8.2. Material Balance Correction
  • 8.9. MULTIPHASE WELL TEST ANALYSIS
  • 8.9.1. Perrine-Martin Approach
  • 8.9.2. Raghavan´s Pseudopressure Transformation
  • 8.9.3. Jones and Raghavan
  • 8.10. WELL TEST ANALYSIS USING FORMATION TEST DATA
  • 8.11. ANALYSIS OF VERTICAL INTERFERENCE TEST (VIT) FROM FORMATION TESTER
  • 8.12. WELL TEST DESIGN
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 9 Reservoir Inflow Performance
  • 9.1. STEADY-STATE PRESSURE RESPONSE FOR HOMOGENEOUS RESERVOIR
  • 9.1.1. Pressure Profile for Well Producing at Steady State
  • 9.2. PSEUDO-STEADY (SEMISTEADY) STATE PRESSURE RESPONSE FOR A HOMOGENEOUS RESERVOIR
  • 9.2.1. Generalized Pseudosteady State Inflow Equation
  • 9.2.2. Drainage Area
  • 9.2.3. Single-Phase Gas IPR
  • 9.2.4. Two-Phase Flow IPR
  • 9.2.5. Rate Dependent Skin Effect
  • 9.2.6. c and n Back Pressure IPR for Gas
  • 9.2.7. Empirical and Semi-Empirical IPR Models
  • 9.2.8. Effect of Changing Skin on IPR Model
  • 9.2.9. Effect of Changing the Water Cut on the IPR Model
  • 9.2.10. Effect of Changing Condensate Gas Ratio (CGR) on Gas IPR Mode
  • 9.2.11. Horizontal Wells-IPR
  • 9.2.12. Multilayered Reservoir
  • 9.2.13. Horizontal Well Intersecting Multiple Compartments
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 10 Well Production System
  • 10.1. CONCEPT OF PETROLEUM PRODUCTION ENGINEERING
  • 10.2. PRODUCTION WELL
  • 10.2.1. Well Downhole Equipment
  • 10.2.2 Well Surface Equipment
  • 10.3. WELL COMPLETION
  • 10.3.1 Lower Completion
  • 10.3.2 Tubing Completion
  • 10.3.3 Well Stimulation Treatment
  • 10.4. TUBING PERFORMANCE RELATIONSHIP (TPR)
  • 10.4.1. Flowing Tubing Pressure Gradient
  • 10.4.2. Multiphase Flowing Tubing Pressure Gradient
  • 10.4.3. Multiphase Flow Regimes
  • 10.4.4. Flowing Tubing Pressure Gradient Calculation
  • REFERENCES
  • BIBLIOGRAPHY
  • APPENDIX 10 A: VBA SOLUTION FOR EXERCISE 10.3
  • Chapter 11 Production System Analysis
  • 11.1. PRODUCTION SYSTEM ANALYSIS AT DIFFERENT NODES
  • 11.1.1. Design of Well Production System
  • 11.2. TURNER VELOCITY
  • 11.3. EROSION VELOCITY
  • 11.4. ARTIFICIAL LIFT METHODS
  • 11.4.1. Operating Principles of Artificial Lift Methods
  • 11.4.2. Selection and Design of Artificial Lift Systems for Productivity Enhancement
  • 11.4.3. Electrical Submersible Pump (ESP)
  • 11.4.4. Gas Lift
  • 11.5. FLOW ASSURANCE
  • 11.5.1. Gas Hydrates
  • 11.5.2. Wax
  • 11.5.3. Inorganic Scale Deposition
  • 11.5.4. Sand Production and Fines Migration
  • 11.5.5. Corrosion
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 12 Reservoir Material Balance
  • 12.1. MATERIAL BALANCE
  • 12.1.1. Material Balance as Solution to Inverse Problem
  • 12.2. OIL RESERVOIR MATERIAL BALANCE (OMB)
  • 12.2.1. Oil Material Balance Model Diagnosis
  • 12.2.2. Oil Material Balance Below Bubble Point Pressure
  • 12.2.3. Oil Material Balance Drive Index-Energy Plot
  • 12.3. AQUIFER MODEL
  • 12.3.1. Small Pot Aquifer Model
  • 12.3.2. Hurst-van Everdingen (HVE) Unsteady State Aquifer Model
  • 12.3.3. Carter-Tracy Aquifer Model
  • 12.3.4. Fetkovich Semisteady State Aquifer Model
  • 12.4. GAS RESERVOIR MATERIAL BALANCE (GMB)
  • 12.4.1. Gas Material Balance (GMB) Model Diagnosis
  • 12.4.2. Gas Condensate Material Balance(GCMB)
  • 12.4.3. Gas Material Balance Drive Index-Energy Plot
  • REFERENCES
  • BIBLIOGRAPHY
  • APPENDIX 12A VBA CODE FOR HURST-VAN EVERDINGEN (HVE) UNSTEADY STATE AQUIFER
  • Chapter 13 Decline Curve Analysis
  • 13.1. PRODUCTION DECLINE CURVE MODELS
  • 13.1.1. Exponential Production Decline Model
  • 13.1.2. Harmonic Production Decline Model
  • 13.1.3. Hyperbolic Production Decline Model
  • REFERENCES
  • BIBLIOGRAPHY
  • Chapter 14 Secondary and Tertiary Recovery Methods
  • 14.1. PRIMARY OIL RECOVERY
  • 14.2. SECONDARY OIL RECOVERY
  • 14.2.1. Water Injection
  • 14.2.2. Immiscible Gas Injection
  • 14.2.3. Immiscible Water Alternating Gas Injection (IWAG)
  • 14.3. TERTIARY (ENHANCED) OIL RECOVERY
  • 14.3.1. Miscible Gas Injection
  • 14.3.2. Miscible Water Alternating Gas Injection (MWAG)
  • 14.3.3. Chemical Injection
  • 14.3.4. Thermal Recovery
  • REFERENCES
  • BIBLIOGRAPHY
  • APPENDIX 14A VBA SCRIPT FOR EXERCISE 14.8
  • Index
  • EULA

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