Introduction to Petroleum Engineering 1st Edition


Presentation Description

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


Presentation Transcript

slide 2:

Introduct Ion to Petroleum e ng Ineer Ing

slide 3:

Introduct Ion to Petroleum e ng Ineer Ing John r . Fanch I and rI chard l . c hr Ist Iansen

slide 4:

Copyright © 2017 by John Wiley Sons Inc. All rights reserved Published by John Wiley Sons Inc. Hoboken New Jersey Published 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 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 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. For general information on our other products and services or for technical support please contact our Customer Care Department within the United States at 800 762‐2974 outside the United States at 317 572‐3993 or fax 317 572‐4002. Wiley also publishes its books in a variety of electronic formats. Some content that appears in print may not be available in electronic formats. For more information about Wiley products visit our web site at 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–dc23 LC record available at Printed in the United States of America 10 9 8 7 6 5 4 3 2 1

slide 5:

Contents About the Authors xiii Preface xv About the Companion Website xvi 1 Introduction 1 1.1 What is Petroleum Engineering 1 1.1.1 Alternative Energy Opportunities 3 1.1.2 Oil and Gas Units 3 1.1.3 Production Performance Ratios 4 1.1.4 Classification of Oil and Gas 4 1.2 Life Cycle of a Reservoir 6 1.3 Reservoir Management 9 1.3.1 Recovery Efficiency 9 1.4 Petroleum Economics 11 1.4.1 The Price of Oil 14 1.4.2 How Does Oil Price Affect Oil Recovery 14 1.4.3 How High Can Oil Prices Go 15 1.5 Petroleum and the Environment 16 1.5.1 Anthropogenic Climate Change 16 1.5.2 Environmental Issues 19 1.6 Activities 20 1.6.1 Further Reading 20 1.6.2 True/False 21 1.6.3 Exercises 21

slide 6:

vi COnTEnTs 2 t he Future of e nergy 23 2.1 Global Oil and Gas Production and Consumption 23 2.2 Resources and Reserves 24 2.2.1 Reserves 27 2.3 Oil and Gas Resources 29 2.3.1 Coal Gas 29 2.3.2 Gas Hydrates 31 2.3.3 Tight Gas s ands s hale Gas and s hale Oil 31 2.3.4 Tar s ands 33 2.4 Global Distribution of Oil and Gas Reserves 34 2.5 Peak Oil 36 2.5.1 World Oil Production Rate Peak 37 2.5.2 World Per Capita Oil Production Rate Peak 37 2.6 Future Energy Options 39 2.6.1 Goldilocks Policy for Energy Transition 39 2.7 Activities 42 2.7.1 Further Reading 42 2.7.2 True/False 42 2.7.3 Exercises 42 3 Properties of Reservoir Fluids 45 3.1 Origin 45 3.2 Classification 47 3.3 Definitions 51 3.4 Gas Properties 54 3.5 Oil Properties 55 3.6 Water Properties 60 3.7 s ources of Fluid Data 61 3.7.1 Constant Composition Expansion 61 3.7.2 Differential Liberation 62 3.7.3 s eparator Test 62 3.8 Applications of Fluid Properties 63 3.9 Activities 64 3.9.1 Further Reading 64 3.9.2 True/False 64 3.9.3 Exercises 64 4 Properties of Reservoir Rock 67 4.1 Porosity 67 4.1.1 Compressibility of Pore V olume 69 4.1.2 saturation 70 4.1.3 V olumetric Analysis 71

slide 7:

COn TEn Ts vii 4.2 Permeability 71 4.2.1 Pressure Dependence of Permeability 73 4.2.2 s uperficial V elocity and Interstitial V elocity 74 4.2.3 Radial Flow of Liquids 74 4.2.4 Radial Flow of Gases 75 4.3 Reservoir Heterogeneity and Permeability 76 4.3.1 Parallel Configuration 76 4.3.2 s eries Configuration 76 4.3.3 Dykstra–Parsons Coefficient 77 4.4 Directional Permeability 79 4.5 Activities 80 4.5.1 Further Reading 80 4.5.2 True/False 80 4.5.3 Exercises 80 5 Multiphase Flow 83 5.1 Interfacial Tension Wettability and Capillary Pressure 83 5.2 Fluid Distribution and Capillary Pressure 86 5.3 Relative Permeability 88 5.4 Mobility and Fractional Flow 90 5.5 One‐dimensional Water-oil Displacement 91 5.6 Well Productivity 95 5.7 Activities 97 5.7.1 Further Reading 97 5.7.2 True/False 97 5.7.3 Exercises 98 6 Petroleum Geology 101 6.1 Geologic History of the Earth 101 6.1.1 Formation of the Rocky Mountains 106 6.2 Rocks and Formations 107 6.2.1 Formations 108 6.3 s edimentary Basins and Traps 111 6.3.1 Traps 111 6.4 What Do You n eed to form a Hydrocarbon Reservoir 112 6.5 V olumetric Analysis Recovery Factor and EUR 113 6.5.1 V olumetric Oil in Place 114 6.5.2 V olumetric Gas in Place 114 6.5.3 Recovery Factor and Estimated Ultimate Recovery 115 6.6 Activities 115 6.6.1 Further Reading 115 6.6.2 True/False 116 6.6.3 Exercises 116

slide 8:

viii COnTEnTs 7 Reservoir Geophysics 119 7.1 s eismic Waves 119 7.1.1 Earthquake Magnitude 122 7.2 Acoustic Impedance and Reflection Coefficients 124 7.3 s eismic Resolution 126 7.3.1 Vertical Resolution 126 7.3.2 Lateral Resolution 127 7.3.3 Exploration Geophysics and Reservoir Geophysics 128 7.4 s eismic Data Acquisition Processing and Interpretation 129 7.4.1 Data Acquisition 129 7.4.2 Data Processing 130 7.4.3 Data Interpretation 130 7.5 Petroelastic Model 131 7.5.1 IFM V elocities 131 7.5.2 IFM Moduli 132 7.6 Geomechanical Model 133 7.7 Activities 135 7.7.1 Further Reading 135 7.7.2 True/False 135 7.7.3 Exercises 135 8 Drilling 137 8.1 Drilling Rights 137 8.2 Rotary Drilling Rigs 138 8.2.1 Power s ystems 139 8.2.2 Hoisting s ystem 141 8.2.3 Rotation s ystem 141 8.2.4 Drill s tring and Bits 143 8.2.5 Circulation s ystem 146 8.2.6 Well Control s ystem 148 8.3 The Drilling Process 149 8.3.1 Planning 149 8.3.2 s ite Preparation 150 8.3.3 Drilling 151 8.3.4 Open‐Hole Logging 152 8.3.5 s etting Production Casing 153 8.4 Types of Wells 155 8.4.1 Well s pacing and Infill Drilling 155 8.4.2 Directional Wells 156 8.4.3 Extended Reach Drilling 158 8.5 Activities 158 8.5.1 Further Reading 158 8.5.2 True/False 158 8.5.3 Exercises 159

slide 9:

COn TEn Ts ix 9 Well Logging 161 9.1 Logging Environment 161 9.1.1 Wellbore and Formation 162 9.1.2 Open or Cased 163 9.1.3 Depth of Investigation 164 9.2 Lithology Logs 164 9.2.1 Gamma‐Ray Logs 164 9.2.2 s pontaneous Potential Logs 165 9.2.3 Photoelectric Log 167 9.3 Porosity Logs 167 9.3.1 Density Logs 167 9.3.2 Acoustic Logs 168 9.3.3 n eutron Logs 169 9.4 Resistivity Logs 170 9.5 Other Types of Logs 174 9.5.1 Borehole Imaging 174 9.5.2 s pectral Gamma‐Ray Logs 174 9.5.3 Dipmeter Logs 174 9.6 Log Calibration with Formation s amples 175 9.6.1 Mud Logs 175 9.6.2 Whole Core 175 9.6.3 s idewall Core 176 9.7 Measurement While Drilling and Logging While Drilling 176 9.8 Reservoir Characterization Issues 177 9.8.1 Well Log Legacy 177 9.8.2 Cutoffs 177 9.8.3 Cross‐Plots 178 9.8.4 Continuity of Formations between Wells 178 9.8.5 Log s uites 179 9.8.6 s cales of Reservoir Information 180 9.9 Activities 182 9.9.1 Further Reading 182 9.9.2 True/False 182 9.9.3 Exercises 182 10 Well Completions 185 10.1 skin 186 10.2 Production Casing and Liners 188 10.3 Perforating 189 10.4 Acidizing 192 10.5 Hydraulic Fracturing 193 10.5.1 Horizontal Wells 201 10.6 Wellbore and s urface Hardware 202

slide 10:

x COnTEnTs 10.7 Activities 203 10.7.1 Further Reading 203 10.7.2 True/False 203 10.7.3 Exercises 204 11 Upstream Facilities 205 11.1 Onshore Facilities 205 11.2 Flash Calculation for s eparators 208 11.3 Pressure Rating for s eparators 211 11.4 s ingle‐Phase Flow in Pipe 213 11.5 Multiphase Flow in Pipe 216 11.5.1 Modeling Multiphase Flow in Pipes 217 11.6 Well Patterns 218 11.6.1 Intelligent Wells and Intelligent Fields 219 11.7 Offshore Facilities 221 11.8 Urban Operations: The Barnett s hale 224 11.9 Activities 225 11.9.1 Further Reading 225 11.9.2 True/False 225 11.9.3 Exercises 225 12 t ransient Well t esting 227 12.1 Pressure Transient Testing 227 12.1.1 Flow Regimes 228 12.1.2 Types of Pressure Transient Tests 228 12.2 Oil Well Pressure Transient Testing 229 12.2.1 Pressure Buildup Test 232 12.2.2 Interpreting Pressure Transient Tests 235 12.2.3 Radius of Investigation of a Liquid Well 237 12.3 Gas Well Pressure Transient Testing 237 12.3.1 Diffusivity Equation 238 12.3.2 Pressure Buildup Test in a Gas Well 238 12.3.3 Radius of Investigation 239 12.3.4 Pressure Drawdown Test and the Reservoir Limit Test 240 12.3.5 Rate Transient Analysis 241 12.3.6 Two‐Rate Test 242 12.4 Gas Well Deliverability 242 12.4.1 The s BA Method 244 12.4.2 The LIT Method 245 12.5 s ummary of Transient Well Testing 246 12.6 Activities 246 12.6.1 Further Reading 246 12.6.2 True/False 246 12.6.3 Exercises 247

slide 11:

COn TEn Ts xi 13 Production Performance 249 13.1 Field Performance Data 249 13.1.1 Bubble Mapping 250 13.2 Decline Curve Analysis 251 13.2.1 Alternative DCA Models 253 13.3 Probabilistic DCA 254 13.4 Oil Reservoir Material Balance 256 13.4.1 Undersaturated Oil Reservoir with Water Influx 257 13.4.2 s chilthuis Material Balance Equation 258 13.5 Gas Reservoir Material Balance 261 13.5.1 Depletion Drive Gas Reservoir 262 13.6 Depletion Drive Mechanisms and Recovery Efficiencies 263 13.7 Inflow Performance Relationships 266 13.8 Activities 267 13.8.1 Further Reading 267 13.8.2 True/False 267 13.8.3 Exercises 268 14 Reservoir Performance 271 14.1 Reservoir Flow s imulators 271 14.1.1 Flow Units 272 14.1.2 Reservoir Characterization Using Flow Units 272 14.2 Reservoir Flow Modeling Workflows 274 14.3 Performance of Conventional Oil and Gas Reservoirs 276 14.3.1 Wilmington Field California: Immiscible Displacement by Water Flooding 277 14.3.2 Prudhoe Bay Field Alaska: Water Flood Gas Cycling and Miscible Gas Injection 278 14.4 Performance of an Unconventional Reservoir 280 14.4.1 Barnett s hale Texas: s hale Gas Production 280 14.5 Performance of Geothermal Reservoirs 285 14.6 Activities 287 14.6.1 Further Reading 287 14.6.2 True/False 287 14.6.3 Exercises 288 15 Midstream and Downstream o perations 291 15.1 The Midstream s ector 291 15.2 The Downstream s ector: Refineries 294 15.2.1 separation 295 15.2.2 Conversion 299 15.2.3 Purification 300 15.2.4 Refinery Maintenance 300

slide 12:

xii COnTEnTs 15.3 The Downstream s ector: n atural Gas Processing Plants 300 15.4 s akhalin‐2 Project s akhalin Island Russia 301 15.4.1 History of s akhalin Island 302 15.4.2 The s akhalin‐2 Project 306 15.5 Activities 310 15.5.1 Further Reading 310 15.5.2 True/False 310 15.5.3 Exercises 311 Appendix Unit Conversion Factors 313 References 317 Index 327

slide 13:

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 engi- neering. 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: T echnology 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 explo- ration 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

slide 14:

xiv ABOUT THE AUTHORS 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 funda- mentals 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.

slide 15:

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 engi- neering. 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

slide 16:

ABOUT THE COMPANION WEBSITE This book is accompanied by a companion website: The website includes: • Solution manual for instructors only

slide 17:

Introduction to Petroleum Engineering First Edition. John R. Fanchi and Richard L. Christiansen. © 2017 John Wiley Sons Inc. Published 2017 by John Wiley Sons Inc. Companion website: 1 INTRODUCTION 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 perspectiv e 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.

slide 18:

2 INTRODUCTION Some companies form asset management teams composed of people with different backgrounds. The asset management team is assigned primary responsibility for devel- oping and implementing a particular project. Figure 1.1 illustrates a hydrocarbon production system as a collection of subsys- tems. 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. 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 sepa- rate 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 ref ineries. 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 Surface facilities Reservoir Well Drilling and completion FIGURE 1.1 Production system.

slide 19:

WHAT IS PETROLEUM ENGINEERING 3 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 reser - voir 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 sequestra- tion of gas and compressed air energy storage CAES. Geothermal energy can be obtained from temperature gradients between the shallow ground and surface subsurface hot w ater 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 res- ervoir 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 1.1 Examples of Common Unit Systems Property Oil Field SI Metric British Length ft m ft Time hr sec sec Pressure psia Pa lbf/ft 2 V olumetric flow rate bbl/day m 3 /s ft 3 /s Viscosity cp Pa∙s lbf∙s/ft 2

slide 20:

4 INTRODUCTION 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 q o q w q g be oil water and gas production rates respectively. These production rates are used to calculate the following produced fluid ratios: Gas–oil ratio GOR GOR g o q q 1.1 Gas–water ratio GWR GWR g w q q 1.2 Water–oil ratio WOR WOR w o q q 1.3 One more produced fluid ratio is water cut which is water production rate divided by the sum of oil and water production rates: WCT w ow q qq 1.4 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. 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 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 GOR MSCFG/day STBO/day MSCFG/STBO 500 400 125 .

slide 21:

WHAT IS PETROLEUM ENGINEERING 5 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 solu- tion 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 API o 141 5 131 5 . . 1.5 The specific gravity of oil is the ratio of oil density ρ o to freshwater density ρ w : o o w 1.6 The API gravity of freshwater is 10°API which is expressed as 10 degrees API. API denotes American Petroleum Institute. 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. TAbLE 1.2 Rules of Thumb for Classifying Fluid Types 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 V olatile 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 Data from Raymond and Leffler 2006. Example 1.2 API Gravity The specifc gravity of an oil sample is 0.85. What is its API gravity Answer API gravity API o 141 5 131 5 141 5 085 131 535 . . . . .

slide 22:

6 INTRODUCTION 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. 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 f ield is abandoned. TAbLE 1.3 Classifying 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

slide 23:

LIFE CYCLE OF A RESERVOIR 7 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 reser - voir. 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 disap- pears. In the miscible case injected gas mixes with oil and the process is considered an enhanced oil recovery EOR process. Buildup Appraisal well Discovery well Oil production rate First oil Plateau Decline Abandonment Economic limit Time FIGURE 1.2 Typical production profle.

slide 24:

8 INTRODUCTION 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 reco very. 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 pro- duction 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. Primary Oil production rate Secondary Time Tertiary Abandonment FIGURE 1.3 Sketch of production stages.

slide 25:

RESERVOIR MANAGEMENT 9 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 def- initions 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. Example 1.3 Gas Recovery The original gas in place OGIP of a gas reservoir is 5 trillion ft 3 TCF. How much gas can be recovered in TCF if recovery from analogous felds 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 0 70 53 5 .. TCFTCF. The upper estimate of gas recovery is 0 90 54 5 .. TCFTCF.

slide 26:

10 INTRODUCTION 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 efficiency E D 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 condi- tions and oil volume at final abandonment conditions divided by the oil volume at initial conditions: E SB SB SB D oi oi oa oa oi oi // / 1.7 where S oi is initial oil saturation and S oa 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 B oi and B oa refer to FVF initially and at abandonment respectively. V olumetric sweep efficiency E Vol 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: E EE VolA V 1.8 Areal sweep efficiency E A and vertical sweep efficiency E V 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 E A sweptarea totalarea 1.9 Example 1.4 Formation V olume Factor Suppose oil occupies 1 bbl at stock tank surface conditions and 1.4 bbl at res- ervoir 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 OilFVF vol at reservoirconditions vol at surfaceconditions OilFVF RB STB RB/STB 14 10 14 . . .

slide 27:

PETROLEUM ECONOMICS 11 and vertical sweep efficiency is defined as E V sweptnet thickness totalnet thickness 1.10 Recovery efficiency RE is the product of displacement efficiency and volumetric sweep efficiency: RE DVol DA V EE EE E 1.11 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. 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. Example 1.5 Recovery Effciency Calculate volumetric sweep effciency E Vol and recovery effciency 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 Displacementefficiency // / D oi oi oa oa oi oi oi : E SB SB SB SS o oa oi S 06 . Areal efficiency sweptarea totalarea sweep A :. E 075 Vertical sweep efficiency sweptnet thickness totalnet thickn V : E e ess 0 667 . Volumetric sweep efficiency vol AV :. EE E 05 Recovery efficiency RE DVol :. EE 03

slide 28:

12 INTRODUCTION 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 reser - voir 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: NPV RE 1.12 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 dis- count 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: NPV CAPEXOPEXTAX oo gg n N nn nn n n N nn n n Pq Pq rr 11 11 n n N nn nn nn n n Pq Pq r 1 1 oo gg CAPEXOPEXTAX 1.13 where N is the number of years P on is oil price during year n q on is oil production during year n P gn is gas price during year n q gn is gas production during year n CAPEX n is capital expenses during year n OPEX n is operating expenses during year n TAX n 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.

slide 29:

PETROLEUM ECONOMICS 13 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 profit- ability. 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. 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 pos- sible 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 uncer - tainty 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. Cash flow 80.00 60.00 40.00 20.00 NPV millions 0.00 –20.00 –40.00 Time years 12 34 5 67 8 NPV FIGURE 1.4 Typical cash fow. TAbLE 1.4 Definitions 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‐in vestment PI ratio Undiscounted cash flow without capital investment divided by total investment

slide 30:

14 INTRODUCTION 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 consid- ering 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 dis- rupt 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. 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. Example 1.6 Oil Security A. 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 Totaloil peryear million bbl/day days/yrbillion 20 365 73 .b bbl/yr Costofmilitary/bbl billion/yr billion bbl/yr /b . . 100 73 13 70 b bl b. How much is this cost per gallon Answer Cost/gal/bbl bbl/gal /gal . . 13 70 1420 33

slide 31:

PETROLEUM ECONOMICS 15 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 1.5 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 economi- cally 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 2016101 per barrel. If the price of oil stays at 2016101 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 coun- tries 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. TAbLE 1.5 Sensitivity 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

slide 32:

16 INTRODUCTION 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 wild- life 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 dis- covery 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 CO 2 carbon monoxide and nitrogen oxides

slide 33:

PETROLEUM AND THE ENVIRONMENT 17 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 illus- trated in Figure 1.5. Much of the solar energy arriving at the top of the atmosphere does not pass through the atmosphere to the surface of the Earth. A study of the distribution of light energy arriving at the surface of the Earth shows that energy from the sun at certain frequencies or equivalently wavelengths is absorbed in the atmosphere. Several of the gaps are associated with light absorption by a greenhouse gas molecule. One way to measure the concentration of greenhouse gases is to measure the concentration of a particular greenhouse gas. Charles David Keeling began measuring atmospheric carbon dioxide concentration at the Mauna Loa Observatory on the Big Island of Hawaii in 1958. Keeling observed a steady increase in carbon dioxide concentration since he began his measurements. His curve which is now known as the Keeling curve is shown in Figure 1.6. It exhibits an annual cycle in carbon dioxide concentration overlaying an increasing average. The initial carbon dioxide concentration was measured at a little over 310 parts per million. Today it is approximately 400 parts per million. These measurements show that carbon dioxide concentration in the atmosphere has been increasing since the middle of the twentieth century . Reflected Incident solar radiation ‘‘Greenhouse’’ Gas absorbs and re-emits IR Infrared radiation Atmosphere FIGURE 1.5 The greenhouse effect. Source: F anchi 2004. Reproduced with permission of Elsevier Academic Press.

slide 34:

18 INTRODUCTION Samples of air bubbles captured in ice cores extracted from glacial ice in Vostok Antarctica are used to measure the concentration of gases in the past. Measurements show that CO 2 concentration has varied from 150 to 300 ppm for the past 400 000 years. Measurements of atmospheric CO 2 concentration during the past two centuries show that CO 2 concentration is greater than 300 ppm and continuing to increase. Ice core measurements show a correlation between changes in atmospheric temperature and CO 2 concentration. Wigley et al. 1996 projected ambient CO 2 concentration through the twenty‐ first century. They argued that society would have to reduce the rate that greenhouse gases are being emitted into the atmosphere to keep atmospheric concentration beneath 550 ppm which is the concentration of CO 2 that would establish an accept- able energy balance. Some scientists have argued that optimum CO 2 concentration is debatable since higher concentrations of carbon dioxide can facilitate plant growth. People who believe that climate change is due to human activity argue that combustion of fossil fuels is a major source of CO 2 in the atmosphere. Skeptics point out that the impact of human activity on climate is not well established. For example they point out that global climate model forecasts are not reliable because they do not adequately model all of the mechanisms that affect climate behavior. Everyone agrees that climate does change over the short term. Examples of short‐term climate change are seasonal weather variations and storms. We refer to long‐term climate change associated with human activity as anthropogenic climate change to distinguish it from short‐term climate change. Carbon dioxide concentration at Mauna Loa Observatory Full record ending November 11 2014 400 390 380 370 CO 2 concentration ppm 360 350 340 330 320 310 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010 Annual cycle Jan Apr Jul Oct Jan FIGURE  1.6 The Keeling curve. Source: Scripps Institution of Oceanography UC San Diego‐content/plugins/sio‐bluemoon/ graphs/mlo_full_record.png

slide 35:

PETROLEUM AND THE ENVIRONMENT 19 Evidence that human activity is causing climate to change more than it would naturally change has motivated international attempts by proponents of anthropo- genic climate change to regulate greenhouse gas emissions and transition as quickly as possible from fossil fuels to energy sources such as wind and solar. Skeptics typi- cally argue that reducing our dependence on fossil fuels is important but they believe that the transition should occur over a period of time that does not significantly harm the global economy. One method for reducing the emission of CO 2 into the atmosphere is to collect and store carbon dioxide in geologic formations in a process known as CO 2 sequestration. Recent research has suggested that large‐scale sequestration of greenhouse gases could alter subsurface stress to cause fault slippage and seismic activity at the surface. 1.5.2 Environmental Issues Fossil fuel producers should be good stewards of the Earth. From a personal perspec- tive they share the environment with everyone else. From a business perspective failure to protect the environment can lead to lawsuits fines and additional regula- tion. There are many examples of society imposing penalties on operators for behavior that could harm the environment or already harmed the environment. A few examples are discussed here. Shell UK reached an agreement with the British government in 1995 to dispose an oil storage platform called the Brent Spar in the deep waters of the Atlantic. The envi- ronmental protection group Greenpeace and its allies were concerned that oil left in the platform would leak into the Atlantic. Greenpeace challenged the Shell UK plan by occupying the platform and supporting demonstrations that in some cases became violent. Shell UK abandoned the plan to sink the Brent Spar in the Atlantic and instead used the structure as a ferry quay. As a consequence of this incident governments throughout Europe changed their rules regulating disposal of offshore facilities Wilkinson 1997 Offshore Staff 1998. Another example is shale oil and gas development in populated areas. Shale oil and gas development requires implementation of a technique known as hydraulic fracturing. The only way to obtain economic flow rates of oil and gas from shale is to fracture the rock. The fractures provide flow paths from the shale to the well. Hydraulic fracturing requires the injection of large volumes of water at pressures that are large enough to break the shale. The injected water carries chemicals and small solid objects called proppants that are used to prop open fractures when the fracturing process is completed and the well is converted from an injection well operating at high pressure to a production well operating at much lower pressure. Some environmental issues associated with hydraulic fracturing include meeting the demand for water to conduct hydraulic fracture treatments and disposing produced water containing pollutants. One solution is to recycle the water. Another solution is to inject the produced water in disposal wells. Both the fracture process and the water disposal process can result in vibrations in the Earth that can be mea- sured as seismic events. The fracture process takes place near the depth of the shale

slide 36:

20 INTRODUCTION and is typically a very low magnitude seismic event known as a microseismic event. Water injection into disposal wells can lead to seismic events and possibly earthquakes that can be felt at the surface in a process known as injection‐induced seismicity Rubinstein and Mahani 2015 Weingarten et al. 2015. King 2012 has provided an extensive review of hydraulic fracturing issues associated with oil and gas production from shale. Concern about environmental effects has led some city county and state governments in the United States to more closely regulate shale drilling and production. Oil spills in marine environments can require expensive cleanup operations. Two such oil spills were the grounding of the 1989 Exxon Valdez oil tanker in Alaska and the 2010 explosion and sinking of the BP Deepwater Horizon offshore platform in the Gulf of Mexico. Both incidents led to significant financial penalties including remediation costs for the companies involved. In the case of the BP Deepwater Horizon incident 11 people lost their lives. The Exxon Valdez spill helped motivate the passage of US government regulations requiring the use of double‐hulled tankers. 1.6 ACTIVITIES 1.6.1 Further Reading For more information about petroleum in society see Fanchi and Fanchi 2016 Hyne 2012 Satter et al. 2008 Raymond and Leffler 2006 and Yergin 1992. For more information about reservoir management and petroleum economics see Hyne 2012 Fanchi 2010 Satter et al. 2008 and Raymond and Leffler 2006. Example 1.7 Environmental Cost A. A project is expected to recover 500 million STB of oil. The project will require installing an infrastructure e.g. platforms pipelines etc. that costs 1.8 billion and another 2 billion in expenses e.g. royalties taxes operating costs. Breakeven occurs when revenue expenses. Neglecting the time value of money what price of oil in /STB is needed to achieve breakeven STB refers to stock tank barrel. Answer T otal expenses 3.8 billion Oil price 3.8 billion/0.5 billion STB 7.6/STB b. Suppose an unexpected environmental disaster occurs that adds another 20 billion to project cost. Neglecting the time value of money what price of oil in /STB is needed to achieve breakeven Answer T otal expenses 23.8 billion Oil price 23.8 billion/0.5 billion STB 47.6/STB

slide 37:

ACTIVITIES 21 1.6.2 True/False 1.1 A hydrocarbon reservoir must be able to trap and retain fluids. 1.2 API gravity is the weight of a hydrocarbon mixture. 1.3 Separator GOR is the ratio of gas rate to oil rate. 1.4 The first stage in the life of an oil or gas reservoir is exploration. 1.5 Volumetric sweep efficiency is the product of areal sweep efficiency and dis- placement efficiency. 1.6 Net present value is usually negative at the beginning of a project. 1.7 DCFROI is discounted cash flow return on interest. 1.8 Nitrogen is a greenhouse gas. 1.9 Water flooding is an EOR process. 1.10 Geological sequestration of carbon dioxide in an aquifer is an EOR process. 1.6.3 Exercises 1.1 Suppose the density of oil is 48 lb/ft 3 and the density of water is 62.4 lb/ft 3 . Calculate the specific gravity of oil γ o and its API gravity. 1.2 Estimate recovery efficiency when displacement efficiency is 30 areal sweep efficiency is 65 and vertical sweep efficiency is 70. 1.3 Calculate volumetric sweep efficiency E Vol and recovery efficiency RE from the following data where displacement efficiency can be estimated as E SS S Doioroi / . Initial oil saturation S oi 0.75 Residual oil saturation S or 0.30 Area swept 480 acres Total area 640 acres Thickness swept 80 ft Total thickness 100 ft 1.4 A. If the initial oil saturation of an oil reservoir is S oi 0.70 and the residual oil saturation from water flooding a core sample in the laboratory is S or 0.30 calculate the displacement efficiency E D assuming displace- ment efficiency can be estimated as E SS S Doioroi / . b. In actual floods the residual oil saturation measured in the laboratory is seldom achieved. Suppose S or 0.35 in the field and recalculate displace- ment efficiency. Compare displacement efficiencies.

slide 38:

22 INTRODUCTION 1.5 A. A project is expected to recover 200 million STB of oil. The project will require installing an infrastructure e.g. platforms pipelines etc. that costs 1.2 billion and another 0.8 billion in expenses e.g. royalties taxes operating costs. Breakeven occurs when revenue expenses. Neglecting the time value of money what price of oil in /STB is needed to achieve breakeven b. Suppose a fire on the platform adds another 0.5 billion to project cost. Neglecting the time value of money what price of oil in /STB is needed to achieve breakeven 1.6 A. The water cut of an oil well that produces 1000 STB oil per day is 25. What is the water production rate for the well Express your answer in STB water per day. b. What is the WOR 1.7 A. Fluid production from a well passes through a separator at the rate of 1200 MSCF gas per day and 1000 STB oil per day. What is the separator GOR in MSCF/STB b. Based on this information would you classify the fluid as black oil or volatile oil 1.8 A. How many acres are in 0.5 mi 2 b. If one gas well can drain 160 acres how many gas wells are needed to drain 1 mi 2 1.9 A. A wellbore has a total depth of 10 000 ft. If it is full of water with a pressure gradient of 0.433 psia/ft what is the pressure at the bottom of the wellbore b. The pressure in a column of water is 1000 psia at a depth of 2300 ft. What is the pressure at a shallower depth of 2200 ft. Assume the pressure gra- dient of water is 0.433 psia/ft. Express your answer in psia. 1.10 A. Primary recovery from an oil reservoir was 100 MMSTBO where 1 MMSTBO 1 million STB of oil. A water flood was implemented following primary recovery. Incremental recovery from the water flood was 25 of original oil in place OOIP. Total recovery primary recovery plus recovery from water flooding was 50 of OOIP. How much oil in MMSTBO was recovered by the water flood b. What was the OOIP in MMSTBO 1.11 A. A core contains 25 water saturation and 75 oil saturation before it is flooded. Core floods show that the injection of water into the core leaves a residual oil saturation of 25. If the same core is resaturated with oil and then flooded with carbon dioxide the residual oil saturation is 10. What is the displacement efficiency of the water flood Assume displace- ment efficiency can be estimated as E SS S Doioroi / . b. What is the displacement efficiency of the carbon dioxide flood 1.12 The revenue from gas produced by a well is 6 million per year. The gas drains an area of 640 acres. Suppose you have 1 acre in the drainage area and are entitled to 25 of the revenue for your fraction of the drainage area which is 1 acre/640 acres. How much revenue from the gas well is yours Express your answer in /yr.