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- Herausgeber: John Wiley & Sons
- Kategorie: Fachliteratur
- Sprache: Englisch
Presents key concepts and terminology for a multidisciplinary range of topics in petroleum engineering
- Places oil and gas production in the global energy context
- Introduces all of the key concepts that are needed to understand oil and gas production from exploration through abandonment
- Reviews fundamental terminology and concepts from geology, geophysics, petrophysics, drilling, production and reservoir engineering
- Includes many worked practical examples within each chapter and exercises at the end of each chapter highlight and reinforce material in the chapter
- Includes a solutions manual for academic adopters
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Veröffentlichungsjahr: 2016
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Table of Contents
COVER
TITLE PAGE
ABOUT THE AUTHORS
PREFACE
ABOUT THE COMPANION WEBSITE
1 INTRODUCTION
1.1 WHAT IS PETROLEUM ENGINEERING?
1.2 LIFE CYCLE OF A RESERVOIR
1.3 RESERVOIR MANAGEMENT
1.4 PETROLEUM ECONOMICS
1.5 PETROLEUM AND THE ENVIRONMENT
1.6 ACTIVITIES
2 THE FUTURE OF ENERGY
2.1 GLOBAL OIL AND GAS PRODUCTION AND CONSUMPTION
2.2 RESOURCES AND RESERVES
2.3 OIL AND GAS RESOURCES
2.4 GLOBAL DISTRIBUTION OF OIL AND GAS RESERVES
2.5 PEAK OIL
2.6 FUTURE ENERGY OPTIONS
2.7 ACTIVITIES
3 PROPERTIES OF RESERVOIR FLUIDS
3.1 ORIGIN
3.2 CLASSIFICATION
3.3 DEFINITIONS
3.4 GAS PROPERTIES
3.5 OIL PROPERTIES
3.6 WATER PROPERTIES
3.7 SOURCES OF FLUID DATA
3.8 APPLICATIONS OF FLUID PROPERTIES
3.9 ACTIVITIES
4 PROPERTIES OF RESERVOIR ROCK
4.1 POROSITY
4.2 PERMEABILITY
4.3 RESERVOIR HETEROGENEITY AND PERMEABILITY
4.4 DIRECTIONAL PERMEABILITY
4.5 ACTIVITIES
5 MULTIPHASE FLOW
5.1 INTERFACIAL TENSION, WETTABILITY, AND CAPILLARY PRESSURE
5.2 FLUID DISTRIBUTION AND CAPILLARY PRESSURE
5.3 RELATIVE PERMEABILITY
5.4 MOBILITY AND FRACTIONAL FLOW
5.5 ONE‐DIMENSIONAL WATER‐OIL DISPLACEMENT
5.6 WELL PRODUCTIVITY
5.7 ACTIVITIES
6 PETROLEUM GEOLOGY
6.1 GEOLOGIC HISTORY OF THE EARTH
6.2 ROCKS AND FORMATIONS
6.3 SEDIMENTARY BASINS AND TRAPS
6.4 WHAT DO YOU NEED TO FORM A HYDROCARBON RESERVOIR?
6.5 VOLUMETRIC ANALYSIS, RECOVERY FACTOR, AND EUR
6.6 ACTIVITIES
7 RESERVOIR GEOPHYSICS
7.1 SEISMIC WAVES
7.2 ACOUSTIC IMPEDANCE AND REFLECTION COEFFICIENTS
7.3 SEISMIC RESOLUTION
7.4 SEISMIC DATA ACQUISITION, PROCESSING, AND INTERPRETATION
7.5 PETROELASTIC MODEL
7.6 GEOMECHANICAL MODEL
7.7 ACTIVITIES
8 DRILLING
8.1 DRILLING RIGHTS
8.2 ROTARY DRILLING RIGS
8.3 THE DRILLING PROCESS
8.4 TYPES OF WELLS
8.5 ACTIVITIES
9 WELL LOGGING
9.1 LOGGING ENVIRONMENT
9.2 LITHOLOGY LOGS
9.3 POROSITY LOGS
9.4 RESISTIVITY LOGS
9.5 OTHER TYPES OF LOGS
9.6 LOG CALIBRATION WITH FORMATION SAMPLES
9.7 MEASUREMENT WHILE DRILLING AND LOGGING WHILE DRILLING
9.8 RESERVOIR CHARACTERIZATION ISSUES
9.9 ACTIVITIES
10 WELL COMPLETIONS
10.1 SKIN
10.2 PRODUCTION CASING AND LINERS
10.3 PERFORATING
10.4 ACIDIZING
10.5 HYDRAULIC FRACTURING
10.6 WELLBORE AND SURFACE HARDWARE
10.7 ACTIVITIES
11 UPSTREAM FACILITIES
11.1 ONSHORE FACILITIES
11.2 FLASH CALCULATION FOR SEPARATORS
11.3 PRESSURE RATING FOR SEPARATORS
11.4 SINGLE‐PHASE FLOW IN PIPE
11.5 MULTIPHASE FLOW IN PIPE
11.6 WELL PATTERNS
11.7 OFFSHORE FACILITIES
11.8 URBAN OPERATIONS: THE BARNETT SHALE
11.9 ACTIVITIES
12 TRANSIENT WELL TESTING
12.1 PRESSURE TRANSIENT TESTING
12.2 OIL WELL PRESSURE TRANSIENT TESTING
12.3 GAS WELL PRESSURE TRANSIENT TESTING
12.4 GAS WELL DELIVERABILITY
12.5 SUMMARY OF TRANSIENT WELL TESTING
12.6 ACTIVITIES
13 PRODUCTION PERFORMANCE
13.1 FIELD PERFORMANCE DATA
13.2 DECLINE CURVE ANALYSIS
13.3 PROBABILISTIC DCA
13.4 OIL RESERVOIR MATERIAL BALANCE
13.5 GAS RESERVOIR MATERIAL BALANCE
13.6 DEPLETION DRIVE MECHANISMS AND RECOVERY EFFICIENCIES
13.7 INFLOW PERFORMANCE RELATIONSHIPS
13.8 ACTIVITIES
14 RESERVOIR PERFORMANCE
14.1 RESERVOIR FLOW SIMULATORS
14.2 RESERVOIR FLOW MODELING WORKFLOWS
14.3 PERFORMANCE OF CONVENTIONAL OIL AND GAS RESERVOIRS
14.4 PERFORMANCE OF AN UNCONVENTIONAL RESERVOIR
14.5 PERFORMANCE OF GEOTHERMAL RESERVOIRS
14.6 ACTIVITIES
15 MIDSTREAM AND DOWNSTREAM OPERATIONS
15.1 THE MIDSTREAM SECTOR
15.2 THE DOWNSTREAM SECTOR: REFINERIES
15.3 THE DOWNSTREAM SECTOR: NATURAL GAS PROCESSING PLANTS
15.4 SAKHALIN‐2 PROJECT, SAKHALIN ISLAND, RUSSIA
15.5 ACTIVITIES
APPENDIX: UNIT CONVERSION FACTORS
REFERENCES
INDEX
END USER LICENSE AGREEMENT
List of Tables
Chapter 01
Table 1.1 Examples of Common Unit Systems
Table 1.2 Rules of Thumb for Classifying Fluid Types
Table 1.3 Classifying Hydrocarbon Liquid Types Using API Gravity and Viscosity
Table 1.4 Definitions of Selected Economic Measures
Table 1.5 Sensitivity of Oil Recovery Technology to Oil Price
Chapter 02
Table 2.1 SPE‐PRMS Reserves Definitions
Table 2.2 Global Estimate of Technically Recoverable Reserves of Unconventional Gas Trillion Standard Cubic Feet
Table 2.3 Nations with Largest Crude Oil and Natural Gas Proved Reserves in 2014
Table 2.4 Regional Distribution of Crude Oil and Natural Gas Proved Reserves in 2014
Chapter 03
Table 3.1 Classifications of Oils and Gases Using Pressure–Temperature Diagrams
Table 3.2 Classification of Oils and Gases by Generally Available Properties
Chapter 04
Table 4.1 Porosities of Media of Geologic Origin
Table 4.2 Examples of Permeability
Chapter 05
Table 5.1 Examples of Interfacial Tension
Table 5.2 Wetting Condition and Contact Angle
Chapter 06
Table 6.1 Geologic Time Scale
Chapter 07
Table 7.1 Classification of Earthquakes
Chapter 08
Table 8.1 Drilling Mud Density
Chapter 09
Table 9.1 Photoelectric Factors
Table 9.2 Principal Applications of Common Well Logs
Chapter 10
Table 10.1 Dissolving Power (Volume of Mineral per Volume of Acid Solution) for Carbonate Minerals
Table 10.2 Dissolving Power (Volume of Mineral per Volume of Acid Solution) for Minerals in Sandstone
Table 10.3 Approximate Closure Pressure Limits for Proppant Categories
Table 10.4 Sizes of Openings for a Range of US and Tyler Mesh Numbers
Chapter 11
Table 11.1 Producer‐to‐Injector Ratios for Common Well Patterns
Chapter 12
Table 12.1 Types of Pressure Transient Test
Chapter 13
Table 13.1 Arps Decline Curves
Table 13.2 Nomenclature for the General Material Balance Equation
Table 13.3 Physical Significance of Material Balance Terms
Table 13.4 Drive Indices for the General Material Balance Equation
Table 13.5 Recovery Efficiencies for Different Depletion Drive Mechanisms
Chapter 14
Table 14.1 Brown Field Flow Modeling Workflow
Chapter 15
Table 15.1 Downstream Sector Products
Table 15.2 Typical Composition of Natural Gas Products
Table 15.3 Typical Recovery of Components at Different NGL Plants
List of Illustrations
Chapter 01
Figure 1.1 Production
system.
Figure 1.2 Typical production profile.
Figure 1.3 Sketch of production stages.
Figure 1.4 Typical cash flow.
Figure 1.5 The greenhouse effect.
Figure 1.6 The Keeling curve.
Chapter 02
Figure 2.1 Top five oil‐producing nations as of 2014.
Figure 2.2 Top five oil‐consuming nations as of 2014.
Figure 2.3 Top five dry natural gas‐producing nations as of 2014.
Figure 2.4 Top five dry natural gas‐consuming nations as of 2014.
Figure 2.5 Illustration of a resource triangle.
Figure 2.6 Distribution of reserves.
Figure 2.7 Resource triangle.
Figure 2.8 Selection of shale plays in the contiguous United States.
Figure 2.9 World proved reserves from 2000 to 2014.
Figure 2.10 World oil production rate forecast using Gaussian curves.
Figure 2.11 World per capita oil production rate through 2014.
Figure 2.12 US energy consumption by source, 1650–2010 (quadrillion BTU).
Figure 2.13 Coal and oil transition periods based on US energy consumption by source, 1650–2010 (%).
Figure 2.14 Fraction of US annual energy consumption by source, 1950–2014.
Chapter 03
Figure 3.1
P–T
diagram for ethane.
Figure 3.2 Comparison of vapor pressure curves for ethane and
n
‐heptane to the phase envelope for a mixture of 59 mol% ethane and 41 mol%
n
‐heptane.
Figure 3.3 Additional nomenclature for
P–T
diagrams using data for 59/41 mol% ethane/
n
‐heptane.
Figure 3.4 Demonstration of the correlation in Equations 3.15 and 3.16 with properties from Example 3.2.
Figure 3.5 Demonstration of the correlation in Equations 3.17 and 3.19 with properties from Examples 3.2 and 3.3.
Figure 3.6 Demonstration of the correlation in Equations 3.20 through 3.23 with properties from Examples 3.4 and 3.5.
Figure 3.7 Effect of temperature and dissolved salts on viscosity of water at 14.7 psi (1 atm).
Figure 3.8 Constant composition expansion.
Figure 3.9 Differential liberation.
Figure 3.10 Multistage flash.
Chapter 04
Figure 4.1 Porous medium.
Figure 4.2 Definition of terms for Darcy’s law.
Figure 4.3 Pressure dependence of permeability.
Figure 4.4 Flow through two layers of porous material.
Figure 4.5 Serial flow through two adjacent beds of porous material.
Figure 4.6 Illustration of the effect of permeability dependence on direction (after Fanchi, 2010).
Chapter 05
Figure 5.1 Wettability of a surface in contact with two phases is measured by the contact angle.
Figure 5.2 Relationship between capillary pressure, water saturation, and elevation for a hypothetical reservoir.
Figure 5.3 Relationship between capillary pressure and saturation.
Figure 5.4 Hysteresis of capillary pressure.
Figure 5.5 Example of water and oil relative permeabilities for a porous medium containing water and oil.
Figure 5.6 Fractional flow for oil–water displacement with relative permeabilities shown in Figure 5.5.
Figure 5.7 Well locations in direct line‐drive pattern.
Figure 5.8 Application of Welge’s steps 2 and 3 to the fractional flow curve of Figure 5.6.
Figure 5.9 Application of Welge’s step 4 to the fractional flow curve of Figure 5.6.
Figure 5.10 Oil production during water–oil displacement.
Figure 5.11 Water saturation profile when the front is halfway through the sample.
Figure 5.12 Productivity index terms.
Chapter 06
Figure 6.1 The interior of the Earth.
Figure 6.2 The lithosphere.
Figure 6.3 Tectonic plates.
Figure 6.4 Tectonic plate movement.
Figure 6.5 The rock cycle.
Figure 6.6 Grain shapes.
Figure 6.7 Preparing a map. (a) Gather data and place in spatial location and (b) contour data.
Figure 6.8 Examples of contour tips.
Figure 6.9 Examples of traps.
Figure 6.10 Examples of reservoir rocks.
Chapter 07
Figure 7.1 Energy propagation as vibrations in the subsurface.
Figure 7.2 P‐wave and S‐wave.
Figure 7.3 Longitudinal P‐wave.
Figure 7.4 Seismic attributes for reflection coefficient.
Figure 7.5 Geometry of Fresnel zone.
Figure 7.6 Schematic of reservoir compaction features.
Chapter 08
Figure 8.1 Modern drilling rig.
Figure 8.2 Illustration of the hoisting system.
Figure 8.3 Derrick with pipe in rack.
Figure 8.4 Rotation system with a simplified hoisting system.
Figure 8.5 View up a derrick.
Figure 8.6 Drill pipe and drill collar.
Figure 8.7 Roller‐cone or tricone drill bit.
Figure 8.8 Illustration of the circulation system.
Figure 8.9 Blowout preventer.
Figure 8.10 A wellbore diagram for a vertical well.
Figure 8.11 Well spacing.
Figure 8.12 Directional wells and multilateral wells.
Chapter 09
Figure 9.1 Well log format.
Figure 9.2 Schematic of invasion zones.
Figure 9.3 Common reservoir rock types and an illustrative stratigraphic column.
Figure 9.4 Illustration of gamma‐ray (GR) log response. Compare with the porosity logs in Figure 9.5 and the resistivity logs in Figure 9.6.
Figure 9.5 Illustration of crossover of porosities from density and neutron logs. Compare with the GR log in Figure 9.4 and the resistivity logs in Figure 9.6.
Figure 9.6 Illustration of resistivity log. The three resistivity traces are for shallow, medium, and deep resistivity measurements. Compare with the GR log in Figure 9.4 and the porosity logs in Figure 9.5.
Figure 9.7 Sketch of formation resistivity factor for sands.
Figure 9.8 Illustration of a fence diagram showing correlation of a clean sand interval. (a) The clean sand interval is indicated by the GR logs. (b) Fence diagram displaying clean sand correlation.
Figure 9.9 Combination of well logs (depth is in ft).
Figure 9.10 Range of data sampling techniques.
Figure 9.11 Reservoir scales.
Chapter 10
Figure 10.1 Brooks’ correlation for productivity efficiency of perforations.
Figure 10.2 Hydraulic fracturing operation in Mansfield, Texas.
Figure 10.3 Orientation of three principal stresses and plan view of borehole breakout.
Figure 10.4 Relationship between modified productivity index ratio and relative conductivity.
Chapter 11
Figure 11.1 Christmas tree and wellhead.
Figure 11.2 Oilfield production equipment.
Figure 11.3 Sketch and nomenclature for flash calculation.
Figure 11.4 Stresses on a thin‐walled cylindrical pressure vessel.
Figure 11.5 Flow in an inclined cylindrical pipe.
Figure 11.6 Flow regimes for vertical two‐phase flow.
Figure 11.7 Flow regimes for horizontal two‐phase flow.
Figure 11.8 Illustration of a flow pattern map.
Figure 11.9 (a) Well locations in direct line‐drive pattern. (b) Well locations in staggered line‐drive pattern. (c) Well locations in five‐spot pattern.
Figure 11.10 Examples of offshore platforms.
Figure 11.11 Offshore platform in dry dock, Galveston, Texas.
Figure 11.12 Key components of an offshore platform.
Figure 11.13 Schematic of Barnett Shale cross section.
Chapter 12
Figure 12.1 Flow regimes.
Figure 12.2 Rates for the PBU test.
Figure 12.3 Horner plot.
Figure 12.4 Common flow patterns.
Figure 12.5 Log–log diagnostic plot of partially completed well.
Figure 12.6 Slopes of flow patterns on a log–log plot.
Figure 12.7 Conventional backpressure test.
Figure 12.8 Isochronal test.
Figure 12.9 Modified isochronal test.
Chapter 13
Figure 13.1 Illustration of a bubble map.
Figure 13.2 Probabilistic DCA workflow.
Figure 13.3 Production profiles of drive mechanisms.
Figure 13.4 Cross section of the East Texas Basin.
Figure 13.5 Illustration of an IPR versus TPC plot.
Chapter 14
Figure 14.1 Overlay of a reservoir grid.
Figure 14.2 Green field flow modeling workflow.
Figure 14.3 Wilmington Field, California.
Figure 14.4 Illustration of Wilmington Field fault blocks and stratigraphic zones.
Figure 14.5 Prudhoe Bay Field, Alaska.
Figure 14.6 Schematic cross section of the Prudhoe Bay Field, Alaska.
Figure 14.7 Cross section of the Fort Worth Basin.
Figure 14.8 Development area of the Barnett Shale, Texas.
Figure 14.9 Drilling rig on a shale development well pad.
Figure 14.10 Sketch of wellbore trajectories drilled from a shale development well pad.
Figure 14.11 Surface equipment at a shale gas well pad.
Figure 14.12 Puna Geothermal Venture (PGV), Hawaii and the main crater of the active Kilauea Volcano (after Fanchi and Fanchi, 2016).
Figure 14.13 Schematic of an air‐cooled binary geothermal power plant.
Chapter 15
Figure 15.1 Installing onshore pipelines.
Figure 15.2 Gas compressor.
Figure 15.3 South Texas refinery.
Figure 15.4 Distillation towers at a Texas refinery.
Figure 15.5 Typical distillation tower fractions and components.
Figure 15.6 Normal boiling points for normal alkanes.
Figure 15.7 Sakhalin Island region.
Figure 15.8 Sakhalin Island.
Figure 15.9 The Sakhalin 2 project: (a) fields for both Sakhalin 1 and Sakhalin 2 and (b) infrastructure for Sakhalin 2.
Figure 15.10 PA‐A (Molikpaq) platform, PA‐B platform, and Lun‐A platform.
Figure 15.11 TransSakhalin pipeline system.
Figure 15.12 LNG carrier in Aniva Bay.
Guide
Cover
Table of Contents
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INTRODUCTION TO PETROLEUM ENGINEERING
JOHN R. FANCHIandRICHARD L. CHRISTIANSEN
Copyright © 2017 by John Wiley & Sons, Inc. All rights reserved
Published by John Wiley & Sons, Inc., Hoboken, New JerseyPublished simultaneously in Canada
No part of this publication may be reproduced, stored in a retrieval system, or transmitted in any form or by any means, electronic, mechanical, photocopying, recording, scanning, or otherwise, except as permitted under Section 107 or 108 of the 1976 United States Copyright Act, without either the prior written permission of the Publisher, or authorization through payment of the appropriate per‐copy fee to the Copyright Clearance Center, Inc., 222 Rosewood Drive, Danvers, MA 01923, (978) 750‐8400, fax (978) 750‐4470, or on the web at www.copyright.com. Requests to the Publisher for permission should be addressed to the Permissions Department, John Wiley & Sons, Inc., 111 River Street, Hoboken, NJ 07030, (201) 748‐6011, fax (201) 748‐6008, or online at http://www.wiley.com/go/permissions.
Limit of Liability/Disclaimer of Warranty: While the publisher and author have used their best efforts in preparing this book, they make no representations or warranties with respect to the accuracy or completeness of the contents of this book and specifically disclaim any implied warranties of merchantability or fitness for a particular purpose. No warranty may be created or extended by sales representatives or written sales materials. The advice and strategies contained herein may not be suitable for your situation. You should consult with a professional where appropriate. Neither the publisher nor author shall be liable for any loss of profit or any other commercial damages, including but not limited to special, incidental, consequential, or other damages.
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Library of Congress Cataloging‐in‐Publication Data:
Names: Fanchi, John R., author. | Christiansen, Richard L. (Richard Lee), author.Title: Introduction to petroleum engineering / by John R. Fanchi and Richard L. Christiansen.Description: Hoboken, New Jersey : John Wiley & Sons, Inc., [2017] | Includes bibliographical references and index.Identifiers: LCCN 2016019048| ISBN 9781119193449 (cloth) | ISBN 9781119193647 (epdf) | ISBN 9781119193616 (epub)Subjects: LCSH: Petroleum engineering.Classification: LCC TN870 .F327 2017 | DDC 622/.3382–dc23LC record available at https://lccn.loc.gov/2016019048
ABOUT THE AUTHORS
John R. Fanchi
John R. Fanchi is a professor in the Department of Engineering and Energy Institute at Texas Christian University in Fort Worth, Texas. He holds the Ross B. Matthews Professorship in Petroleum Engineering and teaches courses in energy and engineering. Before this appointment, he taught petroleum and energy engineering courses at the Colorado School of Mines and worked in the technology centers of four energy companies (Chevron, Marathon, Cities Service, and Getty). He is a Distinguished Member of the Society of Petroleum Engineers and coedited the General Engineering volume of the Petroleum Engineering Handbook published by the Society of Petroleum Engineers. He is the author of numerous books, including Energy in the 21st Century, 3rd Edition (World Scientific, 2013); Integrated Reservoir Asset Management (Elsevier, 2010); Principles of Applied Reservoir Simulation, 3rd Edition (Elsevier, 2006); Math Refresher for Scientists and Engineers, 3rd Edition (Wiley, 2006); Energy: Technology and Directions for the Future (Elsevier‐Academic Press, 2004); Shared Earth Modeling (Elsevier, 2002); Integrated Flow Modeling (Elsevier, 2000); and Parametrized Relativistic Quantum Theory (Kluwer, 1993).
Richard L. Christiansen
Richard L. Christiansen is an adjunct professor of chemical engineering at the University of Utah in Salt Lake City. There, he teaches a reservoir engineering course as well as an introductory course for petroleum engineering. Previously, he engaged in all aspects of petroleum engineering as the engineer for a small oil and gas exploration company in Utah. As a member of the Petroleum Engineering faculty at the Colorado School of Mines from 1990 until 2006, he taught a variety of courses, including multiphase flow in wells, flow through porous media, enhanced oil recovery, and phase behavior. His research experiences include multiphase flow in rock, fractures, and wells; natural gas hydrates; and high‐pressure gas flooding. He is the author of Two‐Phase Flow in Porous Media (2008) that demonstrates fundamentals of relative permeability and capillary pressure. From 1980 to 1990, he worked on high‐pressure gas flooding at the technology center for Marathon Oil Company in Colorado. He earned his Ph.D. in chemical engineering at the University of Wisconsin in 1980.
PREFACE
Introduction to Petroleum Engineering introduces people with technical backgrounds to petroleum engineering. The book presents fundamental terminology and concepts from geology, geophysics, petrophysics, drilling, production, and reservoir engineering. It covers upstream, midstream, and downstream operations. Exercises at the end of each chapter are designed to highlight and reinforce material in the chapter and encourage the reader to develop a deeper understanding of the material.
Introduction to Petroleum Engineering is suitable for science and engineering students, practicing scientists and engineers, continuing education classes, industry short courses, or self‐study. The material in Introduction to Petroleum Engineering has been used in upper‐level undergraduate and introductory graduate‐level courses for engineering and earth science majors. It is especially useful for geoscientists and mechanical, electrical, environmental, and chemical engineers who would like to learn more about the engineering technology needed to produce oil and gas.
Our colleagues in industry and academia and students in multidisciplinary classes helped us identify material that should be understood by people with a range of technical backgrounds. We thank Helge Alsleben, Bill Eustes, Jim Gilman, Pradeep Kaul, Don Mims, Wayne Pennington, and Rob Sutton for comments on specific chapters and Kathy Fanchi for helping prepare this manuscript.
John R. Fanchi, Ph.D.Richard L. Christiansen, Ph.D.June 2016
ABOUT THE COMPANION WEBSITE
This book is accompanied by a companion website:
www.wiley.com/go/Fanchi/IntroPetroleumEngineering
The website includes:
Solution manual for instructors only
1INTRODUCTION
The global economy is based on an infrastructure that depends on the consumption of petroleum (Fanchi and Fanchi, 2016). Petroleum is a mixture of hydrocarbon molecules and inorganic impurities that can exist in the solid, liquid (oil), or gas phase. Our purpose here is to introduce you to the terminology and techniques used in petroleum engineering. Petroleum engineering is concerned with the production of petroleum from subsurface reservoirs. This chapter describes the role of petroleum engineering in the production of oil and gas and provides a view of oil and gas production from the perspective of a decision maker.
1.1 WHAT IS PETROLEUM ENGINEERING?
A typical workflow for designing, implementing, and executing a project to produce hydrocarbons must fulfill several functions. The workflow must make it possible to identify project opportunities; generate and evaluate alternatives; select and design the desired alternative; implement the alternative; operate the alternative over the life of the project, including abandonment; and then evaluate the success of the project so lessons can be learned and applied to future projects. People with skills from many disciplines are involved in the workflow. For example, petroleum geologists and geophysicists use technology to provide a description of hydrocarbon‐bearing reservoir rock (Raymond and Leffler, 2006; Hyne, 2012). Petroleum engineers acquire and apply knowledge of the behavior of oil, water, and gas in porous rock to extract hydrocarbons. Some companies form asset management teams composed of people with different backgrounds. The asset management team is assigned primary responsibility for developing and implementing a particular project.
Figure 1.1 illustrates a hydrocarbon production system as a collection of subsystems. Oil, gas, and water are contained in the pore space of reservoir rock. The accumulation of hydrocarbons in rock is a reservoir. Reservoir fluids include the fluids originally contained in the reservoir as well as fluids that may be introduced as part of the reservoir management program. Wells are needed to extract fluids from the reservoir. Each well must be drilled and completed so that fluids can flow from the reservoir to the surface. Well performance in the reservoir depends on the properties of the reservoir rock, the interaction between the rock and fluids, and fluid properties. Well performance also depends on several other properties such as the properties of the fluid flowing through the well; the well length, cross section, and trajectory; and type of completion. The connection between the well and the reservoir is achieved by completing the well so fluid can flow from reservoir rock into the well.
Figure 1.1 Production system.
Surface equipment is used to drill, complete, and operate wells. Drilling rigs may be permanently installed or portable. Portable drilling rigs can be moved by vehicles that include trucks, barges, ships, or mobile platforms. Separators are used to separate produced fluids into different phases for transport to storage and processing facilities. Transportation of produced fluids occurs by such means as pipelines, tanker trucks, double‐hulled tankers, and liquefied natural gas transport ships. Produced hydrocarbons must be processed into marketable products. Processing typically begins near the well site and continues at refineries. Refined hydrocarbons are used for a variety of purposes, such as natural gas for utilities, gasoline and diesel fuel for transportation, and asphalt for paving.
Petroleum engineers are expected to work in environments ranging from desert climates in the Middle East, stormy offshore environments in the North Sea, and arctic climates in Alaska and Siberia to deepwater environments in the Gulf of Mexico and off the coast of West Africa. They tend to specialize in one of three subdisciplines: drilling engineering, production engineering, and reservoir engineering. Drilling engineers are responsible for drilling and completing wells. Production engineers manage fluid flow between the reservoir and the well. Reservoir engineers seek to optimize hydrocarbon production using an understanding of fluid flow in the reservoir, well placement, well rates, and recovery techniques. The Society of Petroleum Engineers (SPE) is the largest professional society for petroleum engineers. A key function of the society is to disseminate information about the industry.
1.1.1 Alternative Energy Opportunities
Petroleum engineering principles can be applied to subsurface resources other than oil and gas (Fanchi, 2010). Examples include geothermal energy, geologic sequestration of gas, and compressed air energy storage (CAES). Geothermal energy can be obtained from temperature gradients between the shallow ground and surface, subsurface hot water, hot rock several kilometers below the Earth’s surface, and magma. Geologic sequestration is the capture, separation, and long‐term storage of greenhouse gases or other gas pollutants in a subsurface environment such as a reservoir, aquifer, or coal seam. CAES is an example of a large‐scale energy storage technology that is designed to transfer off‐peak energy from primary power plants to peak demand periods. The Huntorf CAES facility in Germany and the McIntosh CAES facility in Alabama store gas in salt caverns. Off‐peak energy is used to pump air underground and compress it in a salt cavern. The compressed air is produced during periods of peak energy demand to drive a turbine and generate additional electrical power.
1.1.2 Oil and Gas Units
Two sets of units are commonly found in the petroleum literature: oil field units and metric units (SI units). Units used in the text are typically oil field units (Table 1.1). The process of converting from one set of units to another is simplified by providing frequently used factors for converting between oil field units and SI (metric) units in Appendix A. The ability to convert between oil field and SI units is an essential skill because both systems of units are frequently used.
Table 1.1Examples of Common Unit Systems
Property
Oil Field
SI (Metric)
British
Length
ft
m
ft
Time
hr
sec
sec
Pressure
psia
Pa
lbf/ft
2
Volumetric flow rate
bbl/day
m
3
/s
ft
3
/s
Viscosity
cp
Pa∙s
lbf∙s/ft
2
1.1.3 Production Performance Ratios
The ratio of one produced fluid phase to another provides useful information for understanding the dynamic behavior of a reservoir. Let qo, qw, qg be oil, water, and gas production rates, respectively. These production rates are used to calculate the following produced fluid ratios:
Gas–oil ratio (GOR)
Gas–water ratio (GWR)
Water–oil ratio (WOR)
One more produced fluid ratio is water cut, which is water production rate divided by the sum of oil and water production rates:
Water cut (WCT) is a fraction, while WOR can be greater than 1.
Separator GOR is the ratio of gas rate to oil rate. It can be used to indicate fluid type. A separator is a piece of equipment that is used to separate fluid from the well into oil, water, and gas phases. Separator GOR is often expressed as MSCFG/STBO where MSCFG refers to one thousand standard cubic feet of gas and STBO refers to a stock tank barrel of oil. A stock tank is a tank that is used to store produced oil.
Example 1.1 Gas–oil Ratio
A well produces 500 MSCF gas/day and 400 STB oil/day. What is the GOR in MSCFG/STBO?
Answer
1.1.4 Classification of Oil and Gas
Surface temperature and pressure are usually less than reservoir temperature and pressure. Hydrocarbon fluids that exist in a single phase at reservoir temperature and pressure often transition to two phases when they are produced to the surface where the temperature and pressure are lower. There are a variety of terms for describing hydrocarbon fluids at surface conditions. Natural gas is a hydrocarbon mixture in the gaseous state at surface conditions. Crude oil is a hydrocarbon mixture in the liquid state at surface conditions. Heavy oils do not contain much gas in solution at reservoir conditions and have a relatively large molecular weight. By contrast, light oils typically contain a large amount of gas in solution at reservoir conditions and have a relatively small molecular weight.
A summary of hydrocarbon fluid types is given in Table 1.2. API gravity in the table is defined in terms of oil specific gravity as
Table 1.2Rules of Thumb for Classifying Fluid Types
Data from Raymond and Leffler (2006).
Fluid Type
Separator GOR (MSCF/STB)
Gravity (°API)
Behavior in Reservoir due to Pressure Decrease
Dry gas
No surface liquids
Remains gas
Wet gas
>50
40–60
Remains gas
Condensate
3.3–50
40–60
Gas with liquid dropout
Volatile oil
2.0–3.3
>40
Liquid with significant gas
Black oil
<2.0
<45
Liquid with some gas
Heavy oil
≈0
Negligible gas formation
The specific gravity of oil is the ratio of oil density ρo to freshwater density ρw:
The API gravity of freshwater is 10°API, which is expressed as 10 degrees API. API denotes American Petroleum Institute.
Example 1.2 Api Gravity
The specific gravity of an oil sample is 0.85. What is its API gravity?
Answer
Another way to classify hydrocarbon liquids is to compare the properties of the hydrocarbon liquid to water. Two key properties are viscosity and density. Viscosity is a measure of the ability to flow, and density is the amount of material in a given volume. Water viscosity is 1 cp (centipoise) and water density is 1 g/cc (gram per cubic centimeter) at 60°F. A liquid with smaller viscosity than water flows more easily than water. Gas viscosity is much less than water viscosity. Tar, on the other hand, has very high viscosity relative to water.
Table 1.3 shows a hydrocarbon liquid classification scheme using API gravity and viscosity. Water properties are included in the table for comparison. Bitumen is a hydrocarbon mixture with large molecules and high viscosity. Light oil, medium oil, and heavy oil are different types of crude oil and are less dense than water. Extra heavy oil and bitumen are denser than water. In general, crude oil will float on water, while extra heavy oil and bitumen will sink in water.
Table 1.3Classifying Hydrocarbon Liquid Types Using API Gravity and Viscosity
Liquid Type
API Gravity (°API)
Viscosity (cp)
Light oil
>31.1
Medium oil
22.3–31.1
Heavy oil
10–22.3
Water
10
1 cp
Extra heavy oil
4–10
<10 000 cp
Bitumen
4–10
>10 000 cp
1.2 LIFE CYCLE OF A RESERVOIR
The life cycle of a reservoir begins when the field becomes an exploration prospect and does not end until the field is properly abandoned. An exploration prospect is a geological structure that may contain hydrocarbons. The exploration stage of the project begins when resources are allocated to identify and assess a prospect for possible development. This stage may require the acquisition and analysis of more data before an exploration well is drilled. Exploratory wells are also referred to as wildcats. They can be used to test a trap that has never produced, test a new reservoir in a known field, and extend the known limits of a producing reservoir. Discovery occurs when an exploration well is drilled and hydrocarbons are encountered.
Figure 1.2 illustrates a typical production profile for an oil field beginning with the discovery well and proceeding to abandonment. Production can begin immediately after the discovery well is drilled or several years later after appraisal and delineation wells have been drilled. Appraisal wells are used to provide more information about reservoir properties and fluid flow. Delineation wells better define reservoir boundaries. In some cases, delineation wells are converted to development wells. Development wells are drilled in the known extent of the field and are used to optimize resource recovery. A buildup period ensues after first oil until a production plateau is reached. The production plateau is usually a consequence of facility limitations such as pipeline capacity. A production decline will eventually occur. Production continues until an economic limit is reached and the field is abandoned.
Figure 1.2 Typical production profile.
Petroleum engineers provide input to decision makers in management to help determine suitable optimization criteria. The optimization criteria are expected to abide by government regulations. Fields produced over a period of years or decades may be operated using optimization criteria that change during the life of the reservoir. Changes in optimization criteria occur for a variety of reason, including changes in technology, changes in economic factors, and the analysis of new information obtained during earlier stages of production.
Traditionally, production stages were identified by chronological order as primary, secondary, and tertiary production. Primary production is the first stage of production and relies entirely on natural energy sources to drive reservoir fluids to the production well. The reduction of pressure during primary production is often referred to as primary depletion. Oil recovery can be increased in many cases by slowing the decline in pressure. This can be achieved by supplementing natural reservoir energy. The supplemental energy is provided using an external energy source, such as water injection or gas injection. The injection of water or natural gas may be referred to as pressure maintenance or secondary production. Pressure maintenance is often introduced early in the production life of some modern reservoirs. In this case the reservoir is not subjected to a conventional primary production phase.
Historically, primary production was followed by secondary production and then tertiary production (Figure 1.3). Notice that the production plateau shown in Figure 1.2 does not have to appear if all of the production can be handled by surface facilities. Secondary production occurs after primary production and includes the injection of a fluid such as water or gas. The injection of water is referred to as water flooding, while the injection of a gas is called gas flooding. Typical injection gases include methane, carbon dioxide, or nitrogen. Gas flooding is considered a secondary production process if the gas is injected at a pressure that is too low to allow the injected gas to be miscible with the oil phase. A miscible process occurs when the gas injection pressure is high enough that the interface between gas and oil phases disappears. In the miscible case, injected gas mixes with oil and the process is considered an enhanced oil recovery (EOR) process.
Figure 1.3 Sketch of production stages.
EOR processes include miscible, chemical, thermal, and microbial processes. Miscible processes inject gases that can mix with oil at sufficiently high pressures and temperatures. Chemical processes use the injection of chemicals such as polymers and surfactants to increase oil recovery. Thermal processes add heat to the reservoir. This is achieved by injecting heated fluids such as steam or hot water or by the injection of oxygen‐containing air into the reservoir and then burning the oil as a combustion process. The additional heat reduces the viscosity of the oil and increases the mobility of the oil. Microbial processes use microbe injection to reduce the size of high molecular weight hydrocarbons and improve oil mobility. EOR processes were originally implemented as a third, or tertiary, production stage that followed secondary production.
EOR processes are designed to improve displacement efficiency by injecting fluids or heat. The analysis of results from laboratory experiments and field applications showed that some fields would perform better if the EOR process was implemented before the third stage in field life. In addition, it was found that EOR processes were often more expensive than just drilling more wells in a denser pattern. The process of increasing the density of wells in an area is known as infill drilling. The term improved oil recovery (IOR) includes EOR and infill drilling for improving the recovery of oil. The addition of wells to a field during infill drilling can also increase the rate of withdrawal of hydrocarbons in a process known as acceleration of production.
Several mechanisms can occur during the production process. For example, production mechanisms that occur during primary production depend on such factors as reservoir structure, pressure, temperature, and fluid type. Production of fluids without injecting other fluids will cause a reduction of reservoir pressure. The reduction in pressure can result in expansion of in situ fluids. In some cases, the reduction in pressure is ameliorated if water moves in to replace the produced hydrocarbons. Many reservoirs are in contact with water‐bearing formations called aquifers. If the aquifer is much larger than the reservoir and is able to flow into the reservoir with relative ease, the reduction in pressure in the reservoir due to hydrocarbon production will be much less that hydrocarbon production from a reservoir that is not receiving support from an aquifer. The natural forces involved in primary production are called reservoir drives and are discussed in more detail in a later chapter.
Example 1.3 Gas Recovery
The original gas in place (OGIP) of a gas reservoir is 5 trillion ft3 (TCF). How much gas can be recovered (in TCF) if recovery from analogous fields is between 70 and 90% of OGIP?
Answer
Two estimates are possible: a lower estimate and an upper estimate.
The lower estimate of gas recovery is .
The upper estimate of gas recovery is .
1.3 RESERVOIR MANAGEMENT
One definition of reservoir management says that the primary objective of reservoir management is to determine the optimum operating conditions needed to maximize the economic recovery of a subsurface resource. This is achieved by using available resources to accomplish two competing objectives: optimizing recovery from a reservoir while simultaneously minimizing capital investments and operating expenses. As an example, consider the development of an oil reservoir. It is possible to maximize recovery from the reservoir by drilling a large number of wells, but the cost would be excessive. On the other hand, drilling a single well would provide some of the oil but would make it very difficult to recover a significant fraction of the oil in a reasonable time frame. Reservoir management is a process for balancing competing objectives to achieve the key objective.
An alternate definition (Saleri, 2002) says that reservoir management is a continuous process designed to optimize the interaction between data and decision making. Both definitions describe a dynamic process that is intended to integrate information from multiple disciplines to optimize reservoir performance. The process should recognize uncertainty resulting from our inability to completely characterize the reservoir and fluid flow processes. The reservoir management definitions given earlier can be interpreted to cover the management of hydrocarbon reservoirs as well as other reservoir systems. For example, a geothermal reservoir is essentially operated by producing fluid from a geological formation. The management of the geothermal reservoir is a reservoir management task.
It may be necessary to modify a reservoir management plan based on new information obtained during the life of the reservoir. A plan should be flexible enough to accommodate changes in economic, technological, and environmental factors. Furthermore, the plan is expected to address all relevant operating issues, including governmental regulations. Reservoir management plans are developed using input from many disciplines, as we see in later chapters.
1.3.1 Recovery Efficiency
An important objective of reservoir management is to optimize recovery from a resource. The amount of resource recovered relative to the amount of resource originally in place is defined by comparing initial and final in situ fluid volumes. The ratio of fluid volume remaining in the reservoir after production to the fluid volume originally in place is recovery efficiency. Recovery efficiency can be expressed as a fraction or a percentage. An estimate of recovery efficiency is obtained by considering the factors that contribute to the recovery of a subsurface fluid: displacement efficiency and volumetric sweep efficiency.
Displacement efficiencyED is a measure of the amount of fluid in the system that can be mobilized by a displacement process. For example, water can displace oil in a core. Displacement efficiency is the difference between oil volume at initial conditions and oil volume at final (abandonment) conditions divided by the oil volume at initial conditions:
where Soi is initial oil saturation and Soa is oil saturation at abandonment. Oil saturation is the fraction of oil occupying the volume in a pore space. Abandonment refers to the time when the process is completed. Formation volume factor (FVF) is the volume occupied by a fluid at reservoir conditions divided by the volume occupied by the fluid at standard conditions. The terms Boi and Boa refer to FVF initially and at abandonment, respectively.
Example 1.4 Formation Volume Factor
Suppose oil occupies 1 bbl at stock tank (surface) conditions and 1.4 bbl at reservoir conditions. The oil volume at reservoir conditions is larger because gas is dissolved in the liquid oil. What is the FVF of the oil?
Answer
Volumetric sweep efficiencyEVol expresses the efficiency of fluid recovery from a reservoir volume. It can be written as the product of areal sweep efficiency and vertical sweep efficiency:
Areal sweep efficiency EA and vertical sweep efficiency EV represent the efficiencies associated with the displacement of one fluid by another in the areal plane and vertical dimension. They represent the contact between in situ and injected fluids. Areal sweep efficiency is defined as
and vertical sweep efficiency is defined as
Recovery efficiency RE is the product of displacement efficiency and volumetric sweep efficiency:
Displacement efficiency, areal sweep efficiency, vertical sweep efficiency, and recovery efficiency are fractions that vary from 0 to 1. Each of the efficiencies that contribute to recovery efficiency can be relatively large and still yield a recovery efficiency that is relatively small. Reservoir management often focuses on finding the efficiency factor that can be improved by the application of technology.
Example 1.5 Recovery Efficiency
Calculate volumetric sweep efficiency EVol and recovery efficiency RE from the following data:
S
oi
0.75
S
oa
0.30
Area swept
750 acres
Total area
1000 acres
Thickness swept
10 ft
Total thickness
15 ft
Neglect FVF effects since
B
oi
≈
B
oa
Answer
1.4 PETROLEUM ECONOMICS
The decision to develop a petroleum reservoir is a business decision that requires an analysis of project economics. A prediction of cash flow from a project is obtained by combining a prediction of fluid production volume with a forecast of fluid price. Production volume is predicted using engineering calculations, while fluid price estimates are obtained using economic models. The calculation of cash flow for different scenarios can be used to compare the economic value of competing reservoir development concepts.
Cash flow is an example of an economic measure of investment worth. Economic measures have several characteristics. An economic measure should be consistent with the goals of the organization. It should be easy to understand and apply so that it can be used for cost‐effective decision making. Economic measures that can be quantified permit alternatives to be compared and ranked.
Net present value (NPV) is an economic measure that is typically used to evaluate cash flow associated with reservoir performance. NPV is the difference between the present value of revenue R and the present value of expenses E:
The time value of money is incorporated into NPV using discount rate r. The value of money is adjusted to the value associated with a base year using discount rate. Cash flow calculated using a discount rate is called discounted cash flow. As an example, NPV for an oil and/or gas reservoir may be calculated for a specified discount rate by taking the difference between revenue and expenses (Fanchi, 2010):
where N is the number of years, Pon is oil price during year n, qon is oil production during year n, Pgn is gas price during year n, qgn is gas production during year n, CAPEXn is capital expenses during year n, OPEXn is operating expenses during year n, TAXn is taxes during year n, and r is discount rate.
The NPV for a particular case is the value of the cash flow at a specified discount rate. The discount rate at which the maximum NPV is zero is called the discounted cash flow return on investment (DCFROI) or internal rate of return (IRR). DCFROI is useful for comparing different projects.
Figure 1.4 shows a typical plot of NPV as a function of time. The early time part of the figure shows a negative NPV and indicates that the project is operating at a loss. The loss is usually associated with initial capital investments and operating expenses that are incurred before the project begins to generate revenue. The reduction in loss and eventual growth in positive NPV are due to the generation of revenue in excess of expenses. The point in time on the graph where the NPV is zero after the project has begun is the discounted payout time. Discounted payout time on Figure 1.4 is approximately 2.5 years.
Figure 1.4 Typical cash flow.
Table 1.4 presents the definitions of several commonly used economic measures. DCFROI and discounted payout time are measures of the economic viability of a project. Another measure is the profit‐to‐investment (PI) ratio which is a measure of profitability. It is defined as the total undiscounted cash flow without capital investment divided by total investment. Unlike the DCFROI, the PI ratio does not take into account the time value of money. Useful plots include a plot of NPV versus time and a plot of NPV versus discount rate.
Table 1.4Definitions of Selected Economic Measures
Economic Measure
Definition
Discount rate
Factor to adjust the value of money to a base year
Net present value (NPV)
Value of cash flow at a specified discount rate
Discounted payout time
Time when NPV = 0
DCFROI or IRR
Discount rate at which maximum NPV =0
Profit‐to‐investment (PI) ratio
Undiscounted cash flow without capital investment divided by total investment
Production volumes and price forecasts are needed in the NPV calculation. The input data used to prepare forecasts includes data that is not well known. Other possible sources of error exist. For example, the forecast calculation may not adequately represent the behavior of the system throughout the duration of the forecast, or a geopolitical event could change global economics. It is possible to quantify uncertainty by making reasonable changes to input data used to calculate forecasts so that a range of NPV results is provided. This process is illustrated in the discussion of decline curve analysis in a later chapter.
1.4.1 The Price of Oil
The price of oil is influenced by geopolitical events. The Arab–Israeli war triggered the first oil crisis in 1973. An oil crisis is an increase in oil price that causes a significant reduction in the productivity of a nation. The effects of the Arab oil embargo were felt immediately. From the beginning of 1973 to the beginning of 1974, the price of a barrel of oil more than doubled. Americans were forced to ration gasoline, with customers lining up at gas stations and accusations of price gouging. The Arab oil embargo prompted nations around the world to begin seriously considering a shift away from a carbon‐based economy. Despite these concerns and the occurrence of subsequent oil crises, the world still obtains over 80% of its energy from fossil fuels.
Historically, the price of oil has peaked when geopolitical events threaten or disrupt the supply of oil. Alarmists have made dire predictions in the media that the price of oil will increase with virtually no limit since the first oil crisis in 1973. These predictions neglect market forces that constrain the price of oil and other fossil fuels.
Example 1.6 Oil Security
If $100 billion is spent on the military in a year to protect the delivery of 20 million barrels of oil per day to the global market, how much does the military budget add to the cost of a barrel of oil?
Answer
B. How much is this cost per gallon?
Answer
1.4.2 How Does Oil Price Affect Oil Recovery?
Many experts believe we are running out of oil because it is becoming increasingly difficult to discover new reservoirs that contain large volumes of conventional oil and gas. Much of the exploration effort is focusing on less hospitable climates, such as arctic conditions in Siberia and deepwater offshore regions near West Africa. Yet we already know where large volumes of oil remain: in the reservoirs that have already been discovered and developed. Current development techniques have recovered approximately one third of the oil in known fields. That means roughly two thirds remains in the ground where it was originally found.
The efficiency of oil recovery depends on cost. Companies can produce much more oil from existing reservoirs if they are willing to pay for it and if the market will support that cost. Most oil‐producing companies choose to seek and produce less expensive oil so they can compete in the international marketplace. Table 1.5 illustrates the sensitivity of oil‐producing techniques to the price of oil. Oil prices in the table include prices in the original 1997 prices and inflation adjusted prices to 2016. The actual inflation rate for oil prices depends on a number of factors, such as size and availability of supply and demand.
Table 1.5Sensitivity of Oil Recovery Technology to Oil Price
Oil Recovery Technology
Oil Price Range
1997$/bbl
2016$/bbl 5% Inflation
Conventional
15–25
38–63
Enhanced oil recovery (EOR)
20–40
51–101
Extra heavy oil (e.g., tar sands)
25–45
63–114
Alternative energy sources
40–60
101–152
Table 1.5 shows that more sophisticated technologies can be justified as the price of oil increases. It also includes a price estimate for alternative energy sources, such as wind and solar. Technological advances are helping wind and solar energy become economically competitive with oil and gas as energy sources for generating electricity. In some cases there is overlap between one technology and another. For example, steam flooding is an EOR process that can compete with conventional oil recovery techniques such as water flooding, while chemical flooding is one of the most expensive EOR processes.
1.4.3 How High Can Oil Prices Go?
In addition to relating recovery technology to oil price, Table 1.5 contains another important point: the price of oil will not rise without limit. For the data given in the table, we see that alternative energy sources become cost competitive when the price of oil rises above 2016$101 per barrel. If the price of oil stays at 2016$101 per barrel or higher for an extended period of time, energy consumers will begin to switch to less expensive energy sources. This switch is known as product substitution. The impact of price on consumer behavior is illustrated by consumers in European countries that pay much more for gasoline than consumers in the United States. Countries such as Denmark, Germany, and Holland are rapidly developing wind energy as a substitute to fossil fuels for generating electricity.
Historically, we have seen oil‐exporting countries try to maximize their income and minimize competition from alternative energy and expensive oil recovery technologies by supplying just enough oil to keep the price below the price needed to justify product substitution. Saudi Arabia has used an increase in the supply of oil to drive down the cost of oil. This creates problems for organizations that are trying to develop more costly sources of oil, such as shale oil in the United States. It also creates problems for oil‐exporting nations that are relying on a relatively high oil price to fund their government spending.
Oil‐importing countries can attempt to minimize their dependence on imported oil by developing technologies that reduce the cost of alternative energy. If an oil‐importing country contains mature oil reservoirs, the development of relatively inexpensive technologies for producing oil remaining in mature reservoirs or the imposition of economic incentives to encourage domestic oil production can be used to reduce the country’s dependence on imported oil.
1.5 PETROLEUM AND THE ENVIRONMENT
Fossil fuels—coal, oil, and natural gas—can harm the environment when they are consumed. Surface mining of coal scars the environment until the land is reclaimed. Oil pollutes everything it touches when it is spilled on land or at sea. Pictures of wildlife covered in oil or natural gas appearing in drinking water have added to the public perception of oil and gas as “dirty” energy sources. The combustion of fossil fuels yields environmentally undesirable by‐products. It is tempting to conclude that fossil fuels have always harmed the environment. However, if we look at the history of energy consumption, we see that fossil fuels have a history of helping protect the environment when they were first adopted by society as a major energy source.
Wood was the fuel of choice for most of human history and is still a significant contributor to the global energy portfolio. The growth in demand for wood energy associated with increasing population and technological advancements such as the development of the steam engine raised concerns about deforestation and led to a search for new source of fuel. The discovery of coal, a rock that burned, reduced the demand for wood and helped save the forests.
Coal combustion was used as the primary energy source in industrialized societies prior to 1850. Another fuel, whale oil, was used as an illuminant and joined coal as part of the nineteenth‐century energy portfolio. Demand for whale oil motivated the harvesting of whales for their oil and was leading to the extinction of whales. The discovery that rock oil, what we now call crude oil, could also be used as an illuminant provided a product that could be substituted for whale oil if there was enough rock oil to meet growing demand. In 1861, the magazine Vanity Fair published a cartoon showing whales at a Grand Ball celebrating the production of oil in Pennsylvania. Improvements in drilling technology and the discovery of oil fields that could provide large volumes of oil at high flow rates made oil less expensive than coal and whale oil. From an environmental perspective, the substitution of rock oil for whale oil saved the whales in the latter half of the nineteenth century. Today, concern about the harmful environmental effects of fossil fuels, especially coal and oil, is motivating a transition to more beneficial sources of energy. The basis for this concern is considered next.
1.5.1 Anthropogenic Climate Change
One environmental concern facing society today is anthropogenic climate change. When a carbon‐based fuel burns in air, carbon reacts with oxygen and nitrogen in the air to produce carbon dioxide (CO2), carbon monoxide, and nitrogen oxides (often abbreviated as NOx). The by‐products of unconfined combustion, including water vapor, are emitted into the atmosphere in gaseous form.
Some gaseous combustion by‐products are called greenhouse gases because they absorb heat energy. Greenhouse gases include water vapor, carbon dioxide, methane, and nitrous oxide. Greenhouse gas molecules can absorb infrared light. When a greenhouse gas molecule in the atmosphere absorbs infrared light, the energy of the absorbed photon of light is transformed into the kinetic energy of the gas molecule. The associated increase in atmospheric temperature is the greenhouse effect illustrated in
