Petroleum engineering : principles, calculations, and workflows / Moshood Sanni.

Format:

Book

Author/Creator:

Sanni, Moshood, author.

Series:

Geophysical monograph series ; 237.

Geophysical monograph series ; 237

Language:

English

Subjects (All):

Petroleum engineering.

Physical Description:

1 online resource (521 pages).

Edition:

1st ed.

Place of Publication:

Hoboken, NJ : John Wiley and Sons, Inc. ; Washington, DC : American Geophysical Union, [2019]

Summary:

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 avaluable 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

Contents:

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

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

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

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

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

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

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

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

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

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).

Notes:

Includes bibliographical references and index

Description based on print version record.

ISBN:

1-119-38797-3

1-119-38798-1

1-119-38796-5

OCLC:

1054129044