Introduction to Petroleum Engineering PDF

Introduction to Petroleum Engineering Introduction to Petroleum Engineering John R. Fanchi and Richard L. Christiansen 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 pu...

Introduction to Petroleum Engineering Introduction to Petroleum Engineering John R. Fanchi and Richard L. Christiansen 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 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. 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 www.wiley.com. 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., | 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 https://lccn.loc.gov/2016019048 Printed in the United States of America 10 9 8 7 6 5 4 3 2 1 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 viContents 2 The Future of Energy 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 Sands, Shale Gas, and Shale Oil 31 2.3.4 Tar Sands 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 Sources of Fluid Data 61 3.7.1 Constant Composition Expansion 61 3.7.2 Differential Liberation 62 3.7.3 Separator 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 Volume 69 4.1.2 Saturation 70 4.1.3 Volumetric Analysis 71 Contents vii 4.2 Permeability 71 4.2.1 Pressure Dependence of Permeability 73 4.2.2 Superficial Velocity and Interstitial Velocity 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 Series 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 Sedimentary Basins and Traps 111 6.3.1 Traps 111 6.4 What Do You Need to form a Hydrocarbon Reservoir? 112 6.5 Volumetric Analysis, Recovery Factor, and EUR 113 6.5.1 Volumetric Oil in Place 114 6.5.2 Volumetric 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 viiiContents 7 Reservoir Geophysics 119 7.1 Seismic Waves 119 7.1.1 Earthquake Magnitude 122 7.2 Acoustic Impedance and Reflection Coefficients 124 7.3 Seismic 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 Seismic 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 Velocities 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 Systems 139 8.2.2 Hoisting System 141 8.2.3 Rotation System 141 8.2.4 Drill String and Bits 143 8.2.5 Circulation System 146 8.2.6 Well Control System 148 8.3 The Drilling Process 149 8.3.1 Planning 149 8.3.2 Site Preparation 150 8.3.3 Drilling 151 8.3.4 Open‐Hole Logging 152 8.3.5 Setting Production Casing 153 8.4 Types of Wells 155 8.4.1 Well Spacing 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 Contents 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 Spontaneous 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 Neutron Logs 169 9.4 Resistivity Logs 170 9.5 Other Types of Logs 174 9.5.1 Borehole Imaging 174 9.5.2 Spectral Gamma‐Ray Logs 174 9.5.3 Dipmeter Logs 174 9.6 Log Calibration with Formation Samples 175 9.6.1 Mud Logs 175 9.6.2 Whole Core 175 9.6.3 Sidewall Core 176 9.7 Measurement While Drilling and Logging While Drilling176 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 Suites 179 9.8.6 Scales 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 Surface Hardware 202 xContents 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 Separators 208 11.3 Pressure Rating for Separators 211 11.4 Single‐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 Shale 224 11.9 Activities 225 11.9.1 Further Reading 225 11.9.2 True/False 225 11.9.3 Exercises 225 12 Transient Well Testing 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 SBA Method 244 12.4.2 The LIT Method 245 12.5 Summary 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 Contents 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 Schilthuis 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 Simulators 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 Shale, Texas: Shale 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 Operations 291 15.1 The Midstream Sector 291 15.2 The Downstream Sector: Refineries 294 15.2.1 Separation 295 15.2.2 Conversion 299 15.2.3 Purification 300 15.2.4 Refinery Maintenance 300 xiiContents 15.3 The Downstream Sector: Natural Gas Processing Plants 300 15.4 Sakhalin‐2 Project, Sakhalin Island, Russia 301 15.4.1 History of Sakhalin Island 302 15.4.2 The Sakhalin‐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 Index327 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: 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 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 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. 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 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 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 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. 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: www.wiley.com/go/Fanchi/IntroPetroleumEngineering 2INTRODUCTION 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 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 Surface facilities Drilling and completion Well Reservoir Figure 1.1 Production system. 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 s­ ubdisciplines: 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 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 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/ft2 Volumetric flow rate bbl/day m3/s ft3/s Viscosity cp Pa∙s lbf∙s/ft2 4INTRODUCTION 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) qg GOR (1.1) qo Gas–water ratio (GWR) qg GWR (1.2) qw Water–oil ratio (WOR) qw WOR (1.3) qo One more produced fluid ratio is water cut, which is water production rate divided by the sum of oil and water production rates: qw WCT (1.4) qo qw 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 500 MSCFG/day GOR 1.25 MSCFG/STBO 400 STBO/day 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 WHAT IS PETROLEUM ENGINEERING? 5 Table 1.2 Rules of Thumb for Classifying Fluid Types Separator GOR Behavior in Reservoir due Fluid Type (MSCF/STB) Gravity (°API) 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 0) will result in a decrease in the volume of the system. Similarly, a decrease in pressure (Δp < 0) will result in an increase in the volume of the system. Formation Volume Factor. The volume of oil swells when gas is dissolved in the oil. The FVF for oil, Bo, expresses this swelling as a ratio of the swollen volume to the volume of the oil phase at a reference condition, usually the stock tank pressure and temperature. This ratio is expressed as reservoir volume divided by stock tank volume. In this sense “reservoir” refers to pressure, temperature, and composition that exist in a reservoir. An example of a unit for oil FVF in oil field units is RB/STB where “RB” refers to reservoir barrels and STB refers to stock tank barrels or it could be rm3/sm3 for reservoir meters cubed per stock tank meters cubed in metric units. For example, an FVF of 1.5 RB/STB means that for every barrel of oil produced to the stock tank, 1.5 barrels were taken from the reservoir. The 0.5 barrel volume difference represents the volume of oil phase lost as volatile species escaped from the liquid phase during the reduction in pressure from the reservoir up through the well to the separator and stock tank. Usually, most of the change in volume from stock tank to reservoir results from the volume of gas dissolved in the oil. But pressure and temperature also play a role. The increase in pressure from stock tank to reservoir compresses the oil a small amount, while the increase in temperature from stock tank to reservoir thermally expands the oil. FVF for oil usually ranges from 1 to 2 RB/STB. FVF for water is usually about 1 RB/STB because gas is much less soluble in water than in oil. Gas FVF varies over a wider range than oil FVF because gas volume is more sensitive to changes in pressure. 3.4 GAS PROPERTIES Formation Volume Factor. For this text, we use the ideal gas law to estimate the FVF Bg for gas: T (°R ) Bg ( RB / MCF ) = 5.03 (3.11) p ( psia ) where the units of each variable Bg, T, p are given in parentheses and MCF denotes 1000 ft3. The coefficient on the right‐hand side of the equation includes conversion factors. For this correlation, the temperature in degrees Rankine is required. To improve the estimate of Bg, the real gas law should be used in place of the ideal gas law. OIL PROPERTIES 55 The real gas equation of state can be written in the form pV Z= (3.12) nRT where Z is the dimensionless gas compressibility factor, R is the gas constant, and n is the number of moles of gas in volume V at pressure p and temperature T. The gas is an ideal gas if Z = 1 and a real gas if Z ≠ 1. Gas FVF for a given temperature and pressure is calculated from the real gas equation of state as psc ZT reservoir volume =Bg = (3.13) Z sc Tsc p standard volume The subscript sc denotes standard conditions (typically 60°F and 14.7 psia). Viscosity. The viscosity of gases at reservoir conditions usually ranges from 0.02 to 0.04 cp. Correlations are available for more precise estimates. Viscosities of gases are rarely measured for oil and gas applications—they are normally estimated with correlations. Heating Value. The heating value of a gas can be estimated from the composition of the gas and heating values associated with each component of the gas. The heating value of the mixture Hm is defined as Nc H m = ∑ yi Hi (3.14) i =1 where Nc is the number of components, yi is the mole fraction of component i, and Hi is the heating value of component i. Heating values of individual components are tabulated in reference handbooks. The heating value of a natural gas is often between 1000 and 1200 BTU/SCF where BTU refers to energy in British thermal units and SCF refers to standard cubic feet of gas. 3.5 OIL PROPERTIES Examples of correlations for estimating three properties of oils are provided in this section: BP pressure, FVF, and viscosity. Many correlations have been published. They often represent a particular geographic region or selection oil. The selection of a correlation should take into account the source of the data that was used to prepare the correlation. Correlations based on McCain (1990) are used here. Bubble‐Point Pressure. If a container is filled partly with oil and the remainder with gas, the amount of gas dissolved in the oil increases as pressure in the container increases. As long as some gas phase remains in the container, the applied pressure is the saturation pressure, and it is often called a BP pressure even though there may be more than a tiny bubble of gas in the container. At pressures higher than that needed to dissolve all the available gas in the container, the oil is considered undersaturated. The BP pressure, or Pbp in psi, can be related to the amount of gas in 56 PROPERTIES OF RESERVOIR FLUIDS solution (Rs in SCF/STB), gas gravity (γg), temperature (T) in°F, and API gravity (°API) with the following correlation: pb = 18.2 ( A − 1.4 ) (3.15) with 0.83 R  A= s  10 0.00091T − 0.0125×° API (3.16) γ  g  Example 3.2 Bubble‐point Pressure Calculate bubble‐point pressure for reservoir temperature of 220°F, oil gravity of 35°API, and gas gravity of 0.68. The amount of gas dissolved in the oil is 350 SCF/STB. Answer Use Equations 3.15 and 3.16 with the values provided: 0.83  350 SCF/STB  0.00091( 220° F ) − 0.0125( 35° API ) A=  10 = 103.11  0.68  Pb = 18.2 (103.11 − 1.4 ) = 1851 psi The plot in Figure 3.4 was created using the correlation of Equations 3.15 and 3.16 with the properties of Example 3.2 with Rs varying from near 0 up to 350 SCF/STB. Above the BP pressure of 1851 psi, Rs is constant at 350 SCF/STB. 400 350 Dissolved gas (SCF/STB) 300 250 200 150 100 50 0 0 500 1000 1500 2000 2500 3000 Pressure (psi) Figure 3.4 Demonstration of the correlation in Equations 3.15 and 3.16 with ­properties from Example 3.2. OIL PROPERTIES 57 Oil Formation Volume Factor. The FVF of oil at the BP pressure (Bob in RB/STB) can be estimated with the following correlation in terms of solution GOR (Rs in SCF/STB), gas gravity (γg), oil specific gravity (not API gravity), and temperature (T in °F): Bob = 0.98 + 0.00012 A1.2 (3.17) with 0.5  γg  A = Rs   + 1.25 T (3.18)  γo  Example 3.3 Oil formation Volume Factor Calculate formation volume factor for the same conditions as Example 3.2, that is, reservoir temperature of 220°F, oil gravity of 35°API, gas gravity of 0.68, and 350 SCF/STB of dissolved gas. Answer First, convert 35°API to oil specific gravity, and then use Equations 3.17 and 3.18 with the appropriate values: 141.5 141.5 γo = = = 0.85 °API + 131.5 35 + 131.5 0.5  0.68  A = ( 350 SCF/STB)   + 1.25 ( 220 ) = 588  0.85  Bob = 0.98 + 0.00012 ( 588 ) 1.2 = 1.23 RB/STB The plot in Figure 3.5 shows results for the correlation of Equations 3.17 and 3.18 with the properties of the previous example. We consider Rs varying from near 0 up to 350 SCF/STB. Oil FVF decreases because of compression of the oil above BP pressure. Oil FVF Bo at pressure p above BP pressure pb is calculated as Bo = Bob + δ p Bo ( p − pb ) (3.19) where Bob is oil FVF at BP pressure and δpBo is the change in oil FVF above BP pressure due to increasing pressure. The value of δpBo for the oil FVF shown in Figure 3.6 is approximately −1.4 × 10 −5 RB/STB/psi for pressures greater than BP pressure. The slope δpBo is negative since oil FVF decreases as pressure increases for pressures greater than BP pressure. 58 PROPERTIES OF RESERVOIR FLUIDS Oil formation volume factor (RB/STB) 1.240 1.220 1.200 1.180 1.160 1.140 1.120 1.100 1.080 0 500 1000 1500 2000 2500 3000 Pressure (psi) Figure 3.5 Demonstration of the correlation in Equations 3.17 and 3.19 with properties from Examples 3.2 and 3.3. 1.80 1.60 1.40 Oil viscosity (cp) 1.20 1.00 0.80 0.60 0.40 0.20 0.00 0 500 1000 1500 2000 2500 3000 Pressure (psi) Figure 3.6 Demonstration of the correlation in Equations 3.20 through 3.23 with ­properties from Examples 3.4 and 3.5. Viscosity. The following correlation for oil viscosity requires two steps. First, the viscosity (cp) of “dead” oil is estimated from API gravity and temperature (°F): 10 −0.0251×° API log10 ( µoD + 1) = 73.3 (3.20) T 0.564 Dead oil refers to oil that has little dissolved gas; it is equivalent to stock tank oil. The second step accounts for the decrease in oil viscosity that occurs as gas dis- solves into it: OIL PROPERTIES 59 µo = AµoD B (3.21) with A = 10.7 ( Rs + 100 ) −0.515 (3.22) B = 5.44 ( Rs + 150 ) −0.338 (3.23) where μoD is dead oil viscosity calculated in the first step and Rs is solution GOR (SCF/STB). Oil with dissolved gas is often called “live” oil. Live oil and dead oil have analogs in the world of carbonated beverages. Example 3.4 Dead Oil Viscosity Calculate dead oil viscosity for a 35°API oil at 220°F. Answer Substitute values into Equation 3.20: −0.0251( 35 ) 10 log10 ( µoD + 1) = 73.3 = 0.46 ( 220 ) 0.564 µoD = 10 0.46 − 1 = 1.90 cp Example 3.5 Live Oil Viscosity Calculate live oil viscosity for a 35°API oil at 220°F with 350 SCF/STB of ­dissolved gas. Answer Combine the dead oil viscosity from the previous example with the above values and Equations 3.21 through 3.23 to find live oil viscosity: A = 10.7 ( 350 + 100 ) −0.515 = 0.46 B = 5.44 ( 350 + 150 ) −0.338 = 0.67 = ( 0.44 )(1.90 cp ) 0.64 µo = AµoD B = 0.71 cp The plot in Figure 3.6 shows results for the correlation of Equations 3.20 through 3.23 with the properties of Examples 3.4 and 3.5. We consider Rs varying from near 0 up to 350 SCF/STB. 60 PROPERTIES OF RESERVOIR FLUIDS Oil viscosity increases because of compression of the oil above BP pressure. Oil viscosity μo at pressure p above BP pressure pb can be estimated using µo = µob + δ p µo ( p − pb ) (3.24) where μob is live oil viscosity at BP pressure and δpμo is the change in oil viscosity above BP pressure due to increasing pressure. The value of δpμo for the oil viscosity shown in Figure 3.6 is approximately 8 × 10−5 cp/psi for pressures greater than BP pressure. The value of the slope δpμo is positive since oil viscosity increases as pressure increases for pressures greater than BP pressure. 3.6 WATER PROPERTIES The presence of water in geologic formations means that the properties of water must be considered. Water properties are discussed in this section. Formation Volume Factor. The effects of pressure and temperature on the volume of water very nearly cancel, so the FVF of water is approximately 1.0 RB/ STB for most reservoirs. Viscosity. The viscosity of water depends on pressure, temperature, and compo- sition. At reservoir conditions, water will contain dissolved solids (mostly salts) as well as some dissolved hydrocarbon gases and small amounts ( VB VB > VA VA Oil Oil Oil VD < Vsat VE < VD > Psat PB > Psat PC = Psat PD < Psat PE 12000 NA 198 WELL COMPLETIONS 14 R = 1.0 0.9 12 0.8 0.7 10 0.6 Modified productivity index ratio 0.5 8 0.4 6 0.3 0.2 4 0.1 2 0 100 1000 10 000 100 000 1 000 000 Relative conductivity Figure 10.4 Relationship between modified productivity index ratio and relative conduc- tivity. (Source: Adapted from Figure 2 of McGuire and Sikora (1960).) Value of R (right‐hand side of figure): Lf R= (10.19) Lq The terms in the previous equations and associated units are defined as follows: J = productivity index after fracking J o = productivity index before fracking Lq = length of the side of the drainage quadrant, ft rw = wellbore radius, ft w = propped width of fracture, in. kf = permeability of proppant, md k = average formation permeability, md A = well spacing, acres Lf = fracture length from wellbore, ft The vertical axis combines productivity index ratio with a geometric factor (shown in brackets) that the authors added to scale the results to different drainage areas and well diameters. According to the authors (McGuire and Sikora, 1960, page 2), the modified productivity index ratio is “the ratio of generalized productivity indexes for fractured to HYDRAULIC FRACTURING 199 unfractured cases multiplied by a scaling factor.” In addition, relative conductivity “expresses the ability of the fracture to conduct fluid relative to that of the formation. It is the ratio of two products—fracture permeability times fracture width divided by formation permeability times the width of the drained area (­drainage radius).” Relative conductivity should be dimensionless. For convenience, the authors replaced drainage radius with A where A is the spacing in acres. The constant 40 in Equation 10.18 is a scaling factor. The magnitude of the scaling factor 40/A is 1 when A is 40 acres. A key to using Figure 10.4 is strict compliance with the units specified earlier. Use of Figure 10.4 is illustrated with the following examples. We begin by calculating relative conductivity for a specified well pattern and formation. Example 10.9 Relative Conductivity Find the relative conductivity for a fracture in a 40‐acre pattern. The formation ­permeability is 2 md, the fracture permeability is 150 darcies, and the fracture width is 0.3 in. Answer Substitute the given values into the definition of relative conductivity using the ­specified units: wkf 40 ( 0.3 in. )(150 000 md ) 40 Relative conductivity = = = 22 500 k A ( 2 md ) 40 acres The productivity index ratios for two different well radii are now compared. Example 10.10 Productivity Index Ratio A. Find the ratio of productivity indices for a reservoir with a 120‐ft fracture half‐length using the relative conductivity and other input from the previous example. The well radius rw is 3 in. B. Repeat the preceding example with well radius rw equal to 4 in. Answer A. The ratio = R L= f / Lq 120 / 660 = 0.18. For relative conductivity of 22 500, the reading on the vertical axis of Figure 10.4 is about 4.0, so the ratio of productivity indices is 4.0. In other words, produc- tivity after fracking is four times greater than the productivity of the unfracked formation. Next, the productivity scaling term 7.13 / ln(0.472 Lq /rw ) = 7.13 / ln ( (0.472)(660 ft ) / (0.25 ft ) ) = 1.00. B. For Lf /Lq = 0.18 and relative conductivity of 22 500, the reading on the vertical axis of Figure 10.4 is still about 4.0. However, the productivity scaling term is slightly different: 7.13 / ln((0.472)(660 ft ) /(0.33 ft)) = 1.04. So the ratio of ­productivity indices is 4.0 /1.04 = 3.8. 200 WELL COMPLETIONS The procedure for estimating fracture length is illustrated by the following example. Example 10.11 Fracture Length If the relative conductivity of a fracture is 1000 in., what length should be spec- ified for the fracture? Answer For this low relative conductivity, the ratio of productivity indices is about 1.8 for Lf /Lq = 0.1, and it is very insensitive to increasing fracture length. Rather than worry about fracture length, it would be better to find how to increase relative conductivity—either by making a wider fracture or providing for higher fracture permeability. If relative conductivity could be increased to 10 000 in., then Lf/Lq as high as 0.4 could make sense, allowing for a ratio of productivity indices as high as about 5.6. The relative conductivity of a fracture depends on two things that a petroleum engineer can control or influence during frack design: the permeability of the prop- pant pack and the width of the fracture, which relates to the amount of proppant placed in the fracture. The permeability of the proppant pack varies with size of the proppant particles. The size range of proppant is expressed by mesh range. Table 10.4 gives opening sizes for a short list of mesh numbers. For a proppant in the 30–50 US mesh range, its particles fall through a 30 US mesh sieve and are caught on a 50 US mesh sieve; as a result its particles are smaller than 0.060 cm and larger than 0.025 cm. Proppant pack porosities usually fall between 35 and 40%. An engineer can estimate the permeability k (cm2) of a clean proppant pack using the average diameter d (cm) of the proppants and the porosity of the pack: 1 φ 3d 2 k= (10.20) 150 (1 − φ )2 Table 10.4 Sizes of Openings for a Range of US and Tyler Mesh Numbers US Mesh Standard Tyler Mesh Standard Opening Size (cm) 12 10 0.170 14 12 0.140 16 14 0.118 18 16 0.100 20 20 0.085 30 28 0.060 40 35 0.043 50 48 0.030 60 60 0.025 70 65 0.021 80 80 0.018 100 100 0.015 HYDRAULIC FRACTURING 201 In a fracture, the proppant pack may include contaminating particulates of various sizes plus any remaining fracturing fluids that will decrease permeability below that of the previous equation. Permeability will also decrease if proppants break under stress, if proppant is embedded in fracture walls, and if fracture walls spall in the presence of liquids. As a result, the actual permeability of proppant in a fracture will be lower than the estimate from the previous equation. Example 10.12 Proppant Permeability Find the permeability of a proppant pack with porosity of 0.38 and average particle diameter of 0.063 cm. Answer 1 ( 0.38 ) ( 0.063 cm ) 3 2 k= = 3.78 × 10 −6 cm 2 ( ) 2 150 1 − 0. 38 Using the unit conversion 1 darcy = 9.87 × 10 −9 cm 2 , we obtain proppant perme- ability k = 383 darcies. The mass of proppant in a fracture typically ranges from 50 000 to 500 000 pounds. This mass mp relates to the size of the fracture and properties of the proppant pack: mp = ρ p Aw (1 − φ ) = ρ p Lee wh (1 − φ ) (10.21) where ρp is the density of proppant particles, A is the fracture area, w is the fracture width, ϕ is the porosity of the pack, Lee is the end‐to‐end length of the fracture, and h is the fracture height. The units for Equation 10.21 can be any consistent set of units. 10.5.1 Horizontal Wells Horizontal wells in very‐low‐permeability formations such as shales are typically cased, cemented, and fracked with 10 or more stages starting at the “toe” of the well and working back to the “heel” where the well bends up to the surface. In each stage, the casing must be perforated, then the formation is fracked, and finally a plug is placed in the casing on the heel side of the perforations to isolate the fracked interval from the next stage. To efficiently finish all these stages, service companies have developed hardware and methods to cycle quickly from perforating to fracking and to plugging. In some methods, the casing or liner is not cemented. In other methods, ball‐drop plugs are combined with the casing to isolate one frack stage from another. No doubt, fracking technology will continue to evolve. The permeability of shale formations is in the range of microdarcies and lower. With such low permeability, the relative conductivity (defined in Eq. 10.18) of the propped fracture can be increased with smaller fracture permeability. 202 WELL COMPLETIONS 10.6 WELLBORE AND SURFACE HARDWARE All of the previous sections deal with connecting the formation to the wellbore. In addition, wellbore and surface hardware are needed to complete the well and then produce oil, gas, and associated water. Wellbore hardware includes production ­tubing, nipples, subsurface safety valves, packers, and pumping equipment. Surface hardware includes the wellhead, the Christmas tree, a pump driver, a separator, storage tanks, and pipelines. In the following discussion, we briefly describe produc- tion tubing systems and then pumping or artificial lift systems and introduce surface facilities. Production tubing consists of many 30 to 40‐foot lengths of pipe joined together. Production tubing extends from the wellhead at the surface to the producing zone. The weight of the tubing is supported by the wellhead. A short piece of pipe, or landing nipple, is placed at or near the lower end of the tubing. The inside dimensions of the landing nipple are machined to fit with tools and other hardware used during workovers and other operations later in the life of the well. A packer may be installed at the lower end of the tubing to seal the annular gap between the tubing and the ­casing. In some wells, subsurface safety valves are installed in the tubing near the surface so that fluid flow can be stopped in the event of damage to surface valves and other equipment. Pumping, or “artificial lift,” equipment is needed in many wells to lift liquids to the surface because reservoir pressure is not sufficient on its own. Common methods for artificial lift include sucker rod pumps, electric submersible pumps (ESP), gas lift, or progressive cavity pumps (PCPs). These four methods are described here. The rocking motion of a pump jack (also known as horsehead, nodding donkey, grasshopper, etc.) is often encountered in oil country. The pump jack raises and lowers the sucker rod that drives a piston pump near the bottom of the tubing. In ESP, multiple impellers are mounted on a shaft driven by an electric motor. Power for the motor is provided by an electric cable that runs along the side of the tubing to the surface. Submersible pumps can be used in oil or gas wells to pump liquid volumes at high rates. They are also common in coal gas production, offshore production, and environmentally sensitive areas where the footprint of surface ­facilities needs to be minimized. In some wells, gas is injected at the surface into the tubing–casing annulus. The gas flows through “gas‐lift” valves into the tubing to help lift the liquid to the surface. The gas mixes with the liquid (oil or water) and reduces the density of the gas–liquid mixture. If the density is low enough, the reservoir pressure may be able to push the mixture to the surface. Invented by Rene Moineau in 1930, PCPs consist of a helical steel shaft or rotor that fits inside a helical rubber stator. When the rotor turns, cavities between the rotor and stator advance along their axis. Liquid inside the cavities is forced toward the surface. A PCP mounted near the end of production tubing is typically driven by a motor mounted on the wellhead and connected to the PCP rotor by a steel shaft. Although PCPs are used to lift liquids to the surface, they also function as downhole motors in drilling operations. ACTIVITIES 203 As noted previously, surface facilities of a well consist of the wellhead, the Christmas tree, a pump driver, a separator, storage tanks, and pipelines. Pump drivers were described earlier. The wellhead provides mechanical support for the casing and tubing and access through valves to annular spaces between successive casing strings and tubing. The Christmas tree is bolted to the top of the wellhead and is connected to the tubing. It is used to control fluids produced from the tubing. The Christmas tree usually splits into two or more branches adorned with valves and pressure gauges. Oil and gas wells produce oil, water, and gas in varying quantities and ratios. For example, some gas wells produce gas with a little condensate and some water, while other gas wells produce a lot of water. Connected to the Christmas tree, separators must cope with the challenges of separating these fluids. Most separators operate at 100–200 psi and depend on the differences in density among phases to separate the fluids by gravity segregation. To facilitate separation of oil and water and to prevent formation of ice and gas hydrates, most separators are heated, especially in cold weather. Effluent gas from the separator passes through a backpressure regulator that keeps pressure constant in the separator. Fluid levels in a separator are maintained with level‐control valves. At least two flow lines leave a separator: one carries gas to a central gas plant, the other carries liquids. For small rates of liquid flow, the liquids line goes to storage tanks at the well site. For high liquid rates, the liquids line goes to a central processing facility. As needed, trucks can unload liquid from storage tanks on location. 10.7 ACTIVITIES 10.7.1 Further Reading For more information about completions, see Economides et al. (2013), Hyne (2012), Denehy (2011), van Dyke (1997), Brooks (1997), Schecter (1992), and McGuire and Sikora (1960). 10.7.2 True/False 10.1 Skin can be negative or positive with units of feet. 10.2 Skin depends on the depth of penetration of formation damage. 10.3 Production tubing is routinely cemented to the borehole wall. 10.4 Liners extend from the surface down to the depth of the producing formation. 10.5 The number of shots per foot equals the number of shaped charges per foot. 10.6 If Brooks’ Npd is 40 for a perforation plan, the design can be improved by selecting shaped charges that will give more penetration. 10.7 Perforating guns are commonly used to punch holes in tubing. 10.8 Acetic acid is used for treatments of silicate minerals. 204 WELL COMPLETIONS 10.9 The permeability of a propped fracture increases with size of the proppant. 10.10 A drilling AFE does not include costs for completion. 10.7.3 Exercises 10.1 Estimate the skin for a well if the damaged zone extends 4 in. beyond the radius of the well, which is 3 in. The native formation permeability is 10 md, and the permeability of the damaged zone is 3 md. 10.2 Find the productivity index for a well with the following properties: well radius = 4 in. and re = 550 ft; formation thickness h = 20 ft; permeability = 15 md; oil viscosity = 0.95 cp; formation volume factor Bo = 1.55 RB/STB; and skin = 6. 10.3 Use the following values to find Brooks’ Npd: perforation penetration length Lp = 20 in.; perforation tunnel diameter dp = 0.3 in.; formation damage length Ld = 4 in.; number of shots per foot n = 4/ft; the ratio of horizontal to vertical permeability kh /kv = 10; and the perforation tunnel skin sp = 2. 10.4 For a particular perforation plan, Brooks’ N pd = 150. What should be done to improve the plan? 10.5 Find the McGuire–Sikora relative conductivity for a fracture in an 80‐acre pattern. The formation permeability is 0.01 md, the fracture permeability is 50d, and the fracture width is 0.2 in. 10.6 Find the parameter R used in Figure 10.4 for a fracture in an 80‐acre pattern. The length of the fracture from the wellbore is 220 ft. 10.7 Referring to Figure 10.4, if R is 0.3 and the relative conductivity is 50 000, find the ratio of productivity indices J/Jo. The well drains a 40‐acre pattern and the radius of the well is 4 in. 10.8 Estimate the permeability of a frack filled with 100 US mesh proppant. The porosity is 36%. 11 UPSTREAM FACILITIES The oil and gas industry can be divided into upstream, midstream, and downstream sectors. The upstream sector includes operations intended to find, discover, and produce oil and gas. The downstream sector consists of crude oil refining, natural gas processing, and marketing and distributing products derived from crude oil and natural gas. The midstream sector connects the upstream and downstream sectors and includes transportation, storage, and wholesale marketing of hydrocarbons. Upstream facilities are needed for managing fluid production and preparing it for transportation. These facilities are described here. 11.1 ONSHORE FACILITIES Fluid flow through the top of the well is controlled by a Christmas tree, which is installed on top of the wellhead. The Christmas tree is a collection of valves and fittings to control fluid flow. The wellhead is used to control pressure and support casing and tubing. It consists of the casing head and tubing head. Figure 11.1 illustrates a Christmas tree and wellhead. The flowline connects the wellhead assembly to the separator. The flowline can be buried to reduce seasonal temperature variations and protect the line from weather and wildlife. 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: www.wiley.com/go/Fanchi/IntroPetroleumEngineering 206 UPSTREAM FACILITIES Pressure gauge Wing valve Swab valve Wing Master valve Flow line Tubing head Wellhead Casing head Figure 11.1 Christmas tree and wellhead. Fluids flow from the wellhead assembly to separation and storage facilities. Separators are used to separate gas, oil, and water phases based on fluid density. If gas, oil, and water phases are in a vertical column, the gas phase will be at the top of the column, the water phase will be at the bottom of the column, and the oil phase is between the gas phase and water phase. Separators take advantage of gravity segre- gation to separate the fluids after production. A two‐phase separator will be used if one liquid phase and one gas phase are being produced. The liquid phase can be oil or water. If water, oil, and gas are being produced simultaneously, a three‐phase separator is needed. The three‐phase sepa- rator has separate outlets for oil, water, and gas. The gas outlet is near the top of the separator, while the water outlet is near the bottom of the separator. In some instances oil and water will mix and create an emulsion. A chemical emulsion breaker can be used to separate oil and water. A chemical analysis of pro- duced water can determine the compounds dissolved in the water phase. A heater treater is a separator that uses heat to separate oil and water. The process of treating produced fluids starts at the wellhead where they are pro- duced (Figure 11.2). The fluids flow through pipes to a separator where the different phases are separated. Each fluid phase is then moved to its own treatment equipment where it is measured, tested, treated, and/or gathered for transport to another facility. If chemical flooding is used in the system, then the produced fluid will typically be an oil–chemical emulsion that must be broken. Once broken, the oil and chemicals are separated out into tanks where they can be tested, the oil can be collected for the next step in the production process, and the chemicals can be reused. Chemical flooding is complex and expensive. Other equipment includes dehydrators (for removing water vapor from gas), oil and water storage tanks, flowlines, wellheads, compressors, and automation equipment. Automation equipment is used to monitor and, in some cases, control wells. On‐site storage tanks store produced oil and water until the liquids can be transported away ONSHORE FACILITIES 207 Storage tanks Separator Pump Figure 11.2 Oilfield production equipment. from the field. A tank battery is a collection of storage tanks at a field. Gas from the separator is usually routed to a flowline or compressor. The compressor boosts the pressure of the gas so that it can be injected into a flowline. A central processing unit, or gathering center, is a location for collecting fluids from multiple wells. The fluids produced from all connected wells flow through gathering center separator(s) and into commingled storage tanks. The gathering center can save money on processing fluids, but it can reduce the operator’s ability to analyze production from each individual well. Surface facilities such as drilling rigs, storage tanks, and compressor stations are needed to drill, complete, and operate wells. The surface area required for installing all of the facilities needed to develop a resource is called the footprint. The size of the footprint has an impact on project economics and environmental impact. As a rule, it is desirable to minimize the size of the footprint. Drilling rigs may be moved from one location to another on trucks, ships, or off- shore platforms; or drilling rigs may be permanently installed at specified locations. The facilities may be located in desert climates in the Middle East, stormy offshore environments in the North Sea, arctic climates in Alaska and Siberia, and deepwater environments in the Gulf of Mexico and off the coast of West Africa. Example 11.1 Pipeline Capacity A. A gathering center receives oil from 16 wells. Each well can produce up to 5000 bbl liquid per day per well. Maximum liquid flow rate is the flow rate when all wells are producing at capacity. What is the maximum liquid flow rate? B. The pipeline from the gathering center to a processing facility can carry 50 000 bbl liquid per day. Can all of the wells produce at maximum liquid flow capacity? 208 UPSTREAM FACILITIES Answer A. 16 wells 5000 bbl/day/well 80 000 bbl/day. B. No. The pipeline would have to be expanded or production from the wells must be limited to 50 000 bbl liquid per day. 11.2 FLASH CALCULATION FOR SEPARATORS The fluid stream produced from a well enters a separator where the fluid phases ­separate. The focus of this section is the separation of the gas phase and the liquid hydrocarbon phase. The compositions and volumes of the gas and liquid phases can be estimated with a flash calculation. Flash calculations are also used in models of many gas plant and refinery operations, as well as in compositional r­ eservoir models. To understand a flash calculation, consider adding F total moles of a mixture of hydrocarbons to a vessel operating at temperature T and pressure P in Figure 11.3. The mole fraction for each component in F is zi where the subscript i denotes compo- nent i. In the vessel, the mixture, or feed, equilibrates to yield a gas of molar amount G with mole fractions yi and a liquid of molar amount L with mole fractions xi. The number of moles in the feed must equal the sum of the moles in the gas and liquid phases. The total mole balance is F G L (11.1) Similarly, the moles of component i in the feed must equal the sum of the moles of component i in the gas and liquid phases. The component balance for component i is zi F yi G xi L (11.2) At equilibrium, the ratio of yi to xi is the k‐value: yi ki (11.3) xi Gas (G, yi) Feed (F, zi) Liquid (L, xi) Figure 11.3 Sketch and nomenclature for flash calculation. FLASH CALCULATION FOR SEPARATORS 209 The k‐value depends on temperature, pressure, and composition. For low pressures (