The World Energy Dilemma 159370271X, 978-1-59370-271-7

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Advance Praise for The World Energy Dilemma “Drawing on a long and distinguished career in the oil patch, Lou Powers has written a most insightful and pragmatic book on energy and energy policy which should be read widely. His irst-hand observations on the reservoirs of Saudi Arabia and the critical role of the Kingdom in the world’s economy is worth the price of admission. Technical and analytical, Powers’ perspectives are nicely interlaced with the personal, adding a vibrant and real touch.” — Dr. William L. Fisher, Barrow Chair and professor, Jackson School of Geosciences, University of Texas “Lou Powers’ rare and unique grasp of and irst-hand experience with the engineering and geological aspects of producing just about every type of oil and gas reservoir around the world, coupled with his understanding of the economics of the world oil and gas trade, makes his story one of the most educational books ever written about the global oil and gas industry. Anyone who wants to appreciate the problems to be faced by the world’s future energy providers needs to read Lou Powers’ book and learn the secrets of the giant oil and gas ields discovered in the past that Lou so generously shares in its pages.” — Gene Ames, former chairman of the Independent Petroleum Association of America, geologist, and oil and gas producer “Lou’s book represents perhaps the best, public Western assessment of the remaining oil reserves of Saudi Arabia. It also lays out the most plausible position of the Saudi royal family on what rate those reserves are depleted, which will come as a surprise to most readers. he chapter on Saudi Arabia alone is worth the price of the book!” — Jack Zagar, independent petroleum engineering consultant and former director of the Association for the Study of Peak Oil (ASPO), Cork, Ireland, former Aramco reservoir engineer “Lou Powers, my long-time friend and former mentor, has written the most credible book available to the public on the likely future of oil from Saudi Arabia. his book is a “must read” for all serious students of the worldwide energy supply in coming decades. Rather than speculate, Lou has documented his conclusions with sound engineering and economic analyses.” — Dr. John Lee, L.F. Peterson Endowed Chair, Regents Professor of Petroleum Engineering, Harold Vance Department of Petroleum Engineering, Texas A&M University

World Energy Dilemma

The

Louis W. Powers

Disclaimer The recommendations, advice, descriptions, and the methods in this book are presented solely for educational purposes. The author and publisher assume no liability whatsoever for any loss or damage that results from the use of any of the material in this book. Use of the material in this book is solely at the risk of the user. Copyright© 2012 by PennWell Corporation 1421 South Sheridan Road Tulsa, Oklahoma 74112-6600 USA 800.752.9764 +1.918.831.9421 [email protected] www.pennwellbooks.com www.pennwell.com National Account Executive: Barbara McGee Director: Mary McGee Managing Editor: Stephen Hill Production Manager: Sheila Brock Book Design: Susan E. Ormston Cover image courtesy Saudi Aramco. Library of Congress Cataloging-in-Publication Data Powers, Louis W. The world energy dilemma / Louis W. Powers. p. cm. Includes bibliographical references and index. ISBN 978-1-59370-271-7 1. Power resources. 2. Energy policy. I. Title. HD9502.A2P693 2012 333.79--dc23 2012014439 All rights reserved. No part of this book may be reproduced, stored in a retrieval system, or transcribed in any form or by any means, electronic or mechanical, including photocopying and recording, without the prior written permission of the publisher. Printed in the United States of America 1 2 3 4 5 16 15 14 13 12

Contents List of Illustrations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . vii Foreword . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .xiii Acknowledgments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xvii Abbreviations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .xxi Introduction: The World Energy Dilemma . . . . . . . . . . . . . . . . . . . . . 1 1 My Career Takes Off . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 2 Assignment Kingsville. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33 3 At Humble’s Houston HQ. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41 4 East Texas’s Major Oil and Gas Fields . . . . . . . . . . . . . . . . . . . . . . . . 51 5 Return to Kingsville. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 71 6 East and South Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 77 7 Saudi Arabia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87 8 Saudi Arabia’s Major Oil Fields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 95 9 Assessing the Saudi Situation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 117 10 Case Studies of an Independent Consultant. . . . . . . . . . . . . . . . . . 137 11 New Technology and Pricing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169 12 From Schemes to Scams. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191 13 A Traveling Man . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 201 14 The US Energy Debate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 221 15 America’s Energy Plan. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267 16 Epilogue: Family Man. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 275 Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 291

v

Illustrations Figures I–1 I–2 I–3 I–4 I–5 I–6 I–7 I–8 I–9 I–10 I–11 I–12 1–1 1–2 1–3 1–4 1–5 2–1 2–2 3–1 3–2 3–3 3–4 3–5 4–1 4–2 4–3 4–4 4–5 4–6 4–7 4–8 4–9 4–10 4–11 4–12 4–13

Oil-producing countries of the Middle East . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2 OPEC’s 2003–07 production cuts contributed to a severe price spike in 2008. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 ExxonMobil’s energy outlook 2004, liquid supply forecast . . . . . . . . . . . . . . .4 ExxonMobil’s energy outlook 2010, liquid supply forecast . . . . . . . . . . . . . . .5 ExxonMobil’s energy outlook 2012, liquid supply forecast . . . . . . . . . . . . . . .5 ExxonMobil’s energy outlook 2012, future percentage of energy supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 US Energy Information Administration estimate for China’s oil demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7 The growth of China’s auto sales . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7 Spurious reserve revisions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8 Real decline of world’s established oil and gas ields. . . . . . . . . . . . . . . . . . . . . .9 Global gas resources . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10 WTI monthly crude oil price per barrel, 2002–2011 . . . . . . . . . . . . . . . . . . . . .12 Steam-assisted gravity drainage (SADG) process . . . . . . . . . . . . . . . . . . . . . . . .19 Quiriquire Oil Field in Venezuela . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22 Canadian tar sands and heavy oil production forecasts. . . . . . . . . . . . . . . . . .30 Proposed Keystone Pipeline. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31 Canadian Production and Exports to the US . . . . . . . . . . . . . . . . . . . . . . . . . . .32 The Kingsville Production District included several large ranches in South Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .34 B-18 Electric log from Sarita East Deep ield. . . . . . . . . . . . . . . . . . . . . . . . . . . .39 Production history of Borregos ield through 2009 . . . . . . . . . . . . . . . . . . . . .43 Trans-Alaska Pipeline. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .45 Production history for the Prudhoe Bay ield . . . . . . . . . . . . . . . . . . . . . . . . . . .46 Alaska National Wildlife Area banned for petroleum development.. . . . . .48 Total Alaska North Slope production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .48 The East Texas Oil Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .52 The 50-year production history of the East Texas Oil Field . . . . . . . . . . . . . .53 North and south cross sections, east to west, from East Texas Field. . . . . .54 An example of the deepening activities of the East Texas Oil Field . . . . . .54 East Texas ield water advance over 50-year span . . . . . . . . . . . . . . . . . . . . . . . .55 Hawkins Dexter sand structure map . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56 Log structure of Lewisville and Dexter sands . . . . . . . . . . . . . . . . . . . . . . . . . . .57 Hawkins ield production history . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .58 Structure map of the Conroe ield. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59 Conroe Cockield oil sands logs and the upper Cockield gas sands . . . . .60 Cumulative production from the Conroe Field, 1930–2010 . . . . . . . . . . . . .61 Webster production history from 1937–2004. . . . . . . . . . . . . . . . . . . . . . . . . . .63 Structure map of Webster Field, Frio 1B—sand with original luid contact. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63 vii

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4–14 4–15 4–16 4–17 4–18 4–19 5–1 5–2 6–1 6–2 6–3 6–4 6–5 7–1 7–2 7–3 8–1 8–2 8–3 8–4 8–5 8–6 8–7 8–8 8–9 8–10 8–11 8–12 8–13 8–14 8–15 8–16 8–17 8–18 8–19 8–20 8–21 8–22 8–23 9–1 9–2 viii

Webster Field management scheme (also known as Friendswood Field) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 Webster Field recovery history through April 2011. . . . . . . . . . . . . . . . . . . . . .65 A map of the Katy Gas Field . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .66 The general structure of the Katy Cockield sands . . . . . . . . . . . . . . . . . . . . . .67 Katy Gas Field production history . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .68 A map of the Cockield Aquifer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .69 Typical wellhead setup. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .72 Powers’s commemorative hook rug with the Exxon logo and tiger . . . . . .75 Exxon Industrial Pipeline System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .78 Annual natural gas wellhead price, 1970–2009. . . . . . . . . . . . . . . . . . . . . . . . . .80 Hawkins inert gas injection project plant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .81 South Texas Division . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .83 King Ranch Gas Plant. Photo by Frank Kern. . . . . . . . . . . . . . . . . . . . . . . . . . . .83 Saudi Arabia oil production rate, 1945–2009 . . . . . . . . . . . . . . . . . . . . . . . . . . .88 Dick Martin, former chief reservoir engineer for Saudi Aramco . . . . . . . . .90 Seawater intake canal at Qurayyah Plant in Saudi Arabia. . . . . . . . . . . . . . . .93 Extent of proved Saudi reserve depletion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .96 Key Saudi Arabian oil and gas ields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .96 A 3D representation of the giant Saudi Arabian Ghawar Field. . . . . . . . . . .97 Ghawar oil ield in comparison to the state of Louisiana . . . . . . . . . . . . . . . .97 Ghawar water injection system. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .98 Ghawar water management. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .99 Ghawar regions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100 Oolitic limestone high permeability . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 Ain Dar/Shedgum area production history . . . . . . . . . . . . . . . . . . . . . . . . . . . 102 Ain Dar/Shedgum depletion status . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 102 Haradh-III crude oil production ramp-up in 1000 bpd. . . . . . . . . . . . . . . . 104 Haradh water production simulation difference between vertical and horizontal wells . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 104 Relative unit well costs show impact of technologies over a decade . . . . 105 Growth in Saudi Aramco reservoir simulation capabilities . . . . . . . . . . . . 106 Ultimate recovery of oil-in-place, Abqaiq Field . . . . . . . . . . . . . . . . . . . . . . . . 107 Abqaiq production history, 1940–2004, 2004–2010 forecast.. . . . . . . . . . 108 Example of multi-lateral horizontal drilling to recover Abqaiq “attic oil”. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108 Khurais Area Field—1,200 MBCD AL Development. . . . . . . . . . . . . . . . . . . 110 Shaybah Camp in Rub’ al-Khali Desert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 111 The Shaybah Field has a large gas cap that is processed and returned to the ield to maintain pressure for oil production.. . . . . . . . . . . . . . . . . . . 111 Saudi Aramco has drilled complex directional, multilateral wells at Haradh and Shaybah . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 112 Shaybah Field’s production capacity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 The large offshore ield of Safaniya could ultimately produce almost 38 billion bbl. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114 Prudhoe Bay production history, 1977–2009 . . . . . . . . . . . . . . . . . . . . . . . . . 121 Saudi reserves over time. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 122

Illustrations

9–3 9–4 9–5 9–6 9–7 9–8 9–9 9–10 9–11 9–12 9–13 9–14 9–15 10–1 10–2 10–3 10–4 10–5 10–6 10–7 10–8 10–9 10–10 10–11 10–12 10–13 10–14 10–15 10–16 10–17 10–18 10–19 10–20 10–21 11–1 11–2 11–3 11–4

Total oil-in-place for Saudi Arabian oil ields . . . . . . . . . . . . . . . . . . . . . . . . . 123 Saudi production and EIA capacity and production projections. . . . . . . 125 Saudi production rate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125 Sadad Husseini’s predictions for Saudi projection . . . . . . . . . . . . . . . . . . . . 126 Saudi Aramco depletion rates for various reserves. . . . . . . . . . . . . . . . . . . . . 127 Difference between 2D and 3D seismic representation. . . . . . . . . . . . . . . . 129 Horizontal well—detected fractures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130 Reservoir simulation room and attaché conference room in the EXPEC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 130 Detailed reservoir description zonation of major reservoirs . . . . . . . . . . . 131 Directional drilling managed from EXPEC Center, Dhahran Saudi Arabia. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 132 Examples of directional multilateral wells applied by Saudi Aramco. . . 133 Saudi Aramco’s forecast for maximum sustained capacity . . . . . . . . . . . . 134 Total Saudi Aramco rig level, 2000–2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 135 The S.K. East B Account 2 lease contained a major trapping fault . . . . . 140 Well production history of the Sarita S.K. East B Lease Account 2, Kenedy County, Texas, 1968–1980 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 141 US natural gas wellhead price, 1979–1982 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 144 Oil column thickness of the Salt Creek Field in the canyon limestone. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 145 Salt Creek Field production history . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 146 US oil pricing from 1981–2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 147 Mrs. S.K. East B Lease Account 2 production history. . . . . . . . . . . . . . . . . . 149 Exxon production history through 1995 of the Sarita Deep Field, Kenedy County, Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 150 US natural gas wellhead price, 1979–1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 151 Total ield production 1968–2005 Sarita Deep Field Account 2 B Lease, Kenedy County, Texas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 152 US natural gas wellhead price, 1995–2005 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153 Andy Turcotte, left, and Lou Powers at Number 1 Headington well . . . 154 Production history of Sarita S.K. B Lease, 1968–2010 . . . . . . . . . . . . . . . . . 155 US natural gas wellhead price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 156 East Seven Sisters ield sale leases. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157 Texas geologist and sales partner Don Boyd . . . . . . . . . . . . . . . . . . . . . . . . . . 157 Production buildup for the East Seven Sisters ield, Duval County, Texas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158 East Seven Sisters—Gorman No. 2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160 East Seven Sisters—Gorman Gas Unit production history, 1983–2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 161 Hazelwood Gas Unit—East Seven Sisters production history, 1982–2010 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 162 Tobin and Ann Armstrong. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 165 US Wellhead oil prices 1961–1989. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 170 OPEC pricing behavior, 1975–1985 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 171 Demand for OPEC oil vs. OPEC maximum sustained capacity. . . . . . . . 172 Free world demand for OPEC production . . . . . . . . . . . . . . . . . . . . . . . . . . . . 172 ix

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11–5 11–6 11–7 11–8 11–9 11–10 11–11 11–12 11–13 11–14 11–15 11–16 11–17 11–18 11–19 11–20 11–21 11–22 11–23 11–24 11–25 13–1 13–2 13–3 13–4 13–5 13–6 13–7 13–8 13–9 13–10 13–11 13–12 14–1 14–2 14–3 14–4 14–5 14–6 14–7 14–8 14–9 x

Weekly US spot price FOB weighted by estimated import volume . . . . . 174 OPEC production and capacity.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 174 Monthly US natural gas wellhead price. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 175 OPEC spare oil capacity, MMBbls/D . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176 World oil demand, MMBbls/D. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176 Relative strength of oil, market, and dollar . . . . . . . . . . . . . . . . . . . . . . . . . . . 177 Spread of WTI over/under Brent, January 2004 to January 2011 . . . . . . 178 Inlation adjusted real oil and gasoline prices . . . . . . . . . . . . . . . . . . . . . . . . . 179 US gas rig count . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 180 Onshore US natural gas supply growth and rig count. . . . . . . . . . . . . . . . . 181 Annual US natural gas consumption. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181 Average consumer price of natural gas in the US, 2007–2010. . . . . . . . . . 182 US gas consumption vs. price . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 183 Ratio of WTI posted prices to Texas Gulf Coast spot gas prices. . . . . . . . 184 Economic results—seven regions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 184 Base ixed natural gas supply forecast, lower 48 . . . . . . . . . . . . . . . . . . . . . . 186 Lower 48 gas supply history by completion date . . . . . . . . . . . . . . . . . . . . . . 186 US rotary rig count, active rigs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187 Lower 48 gross withdrawals—based on a zero percent demand growth case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 187 Lower 48 gross withdrawals—based on a 2% demand growth case . . . . . 188 Annual US nonassociated natural gas, wet after lease separation, proved reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 188 UAE production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203 Oman production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 203 Five Gulf States OPEC production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 204 Libyan oil production and projection through 2030.. . . . . . . . . . . . . . . . . . 205 Iraqi oil production, 1965–2010. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206 Iraqi petroleum capacity increase requires a multi-year ramp-up phase . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 207 India’s crude oil production and consumption . . . . . . . . . . . . . . . . . . . . . . . 208 India crude imports by country and region . . . . . . . . . . . . . . . . . . . . . . . . . . . 208 Kazakhstan and Tengiz production comparison. . . . . . . . . . . . . . . . . . . . . . 215 Former USSR production history . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 216 Statoil’s Gulfaks Offshore Platform . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 217 North Sea and onshore England production . . . . . . . . . . . . . . . . . . . . . . . . . 219 Gene Ames, former chairman of the Independent Producers Association of America and chairman of Venus Oil Company. . . . . . . . . 223 Historical US trade and oil deicits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 223 Forecast US oil trade deicit—OTA base forecast . . . . . . . . . . . . . . . . . . . . . . 224 History of US oil supply and demand, and projection. . . . . . . . . . . . . . . . . 226 2010 EIA forecast US demand and imports. . . . . . . . . . . . . . . . . . . . . . . . . . . 227 US crude imports from Mexico, Venezuela, and Canada . . . . . . . . . . . . . . 228 Oil consumption of barrels per person/annum . . . . . . . . . . . . . . . . . . . . . . . 235 Natural gas vehicles by country . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 236 US natural gas production. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 238

Illustrations

14–10 US natural gas storage as of May 4, 2012 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 239 14–11 Shale gas revenues boosted by inclusion of NGLs and condensate. . . . . 245 14–12 World oil and gas production growth and decline without further investment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 248 14–13 Worldwide progression of water depth capabilities for offshore drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 250 14–14 1991 fuel sources of US electricity generation. . . . . . . . . . . . . . . . . . . . . . . . . 254 14–15 2009 fuel sources of US electricity generation. . . . . . . . . . . . . . . . . . . . . . . . . 255 14–16 US electric consumption, 1991–2009. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 255 14–17 Effect of uranium price on fuel cost . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 257 14–18 Electricity rates and fossil fuel costs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 259 14–19 Grid-connected coal-ired and wind-powered capacity . . . . . . . . . . . . . . . . 261 14–20 World marketed energy use by fuel type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262 14–21 Non-hydro electric renewable power generation by energy source, 2008–2035 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 262 14–22 World and China annual coal consumption comparison, 2000–2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 264 14–23 Indian imports of coal, 2001–2015 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 265 15–1 Budgets of Departments of Energy, Interior, and EPA. . . . . . . . . . . . . . . . . 268 15–2 China versus US retail gasoline prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271 E–1 The Powers family home in Saudi Arabia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 283 E–2 Cheryl Powers on her irst day in Saudi Arabia, 1977 . . . . . . . . . . . . . . . . . . 284 E–3 Lou Ann Powers with her horse Sharif, Saudi Arabia. . . . . . . . . . . . . . . . . . 286 E–4 Ruth Nell, Jamie, and Lou Powers at Jamie’s Eagle Scout award ceremony in Dharan . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 287 E–5 Camping in the Saudi Arabian desert . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288

Tables 4–1 8–1 9–1 10–1 10–2 10–3 11–1 11–2 13–1 14–1 14–2 14–3 14–4 14–5

Summary of four large East Texas ields . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65 Average rock properties for different sections of the Ghawar Field. . . . . 100 Ultimate recovery from six large US oil ields . . . . . . . . . . . . . . . . . . . . . . . . . 120 Gas-in-place for 160 acres Mrs. S.K. East B-20. . . . . . . . . . . . . . . . . . . . . . . . . 142 Apparent gas-in-place from performance East Seven Sisters ield Gorman Lease. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 159 East Seven Sisters bottomhole pressures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 160 Oil and gas price forecast, 1988 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173 Correlation, oil vs. US dollar, S&P 500, US petroleum inventories. . . . . 177 March 2011 gasoline prices . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 218 Reserves required to get a 2:1 payout at various gas prices . . . . . . . . . . . . . 242 Reserves required to get a 2:1 payout at various gas prices . . . . . . . . . . . . . 242 Reserves required to get a 2:1 payout at various gas prices . . . . . . . . . . . . . 243 Average power plant costs by type . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 258 Estimated levelized costs of new generation resources, 2016. . . . . . . . . . . 260

xi

Foreword As oil diplomacy editor of the Oil & Gas Journal (OGJ ), my area of responsibility was international politics and the myriad organizations, countries, and companies that largely drive events in that realm. So, my work normally touched on the Organization of the Petroleum Exporting Countries (OPEC), the International Energy Agency (IEA), and their respective member countries. My work also touched on China and its growing demand for oil, Japan’s nuclear meltdown, and the consequences of increased demand of liqueied natural gas. Russia’s East Siberia Paciic Ocean pipeline occupied much of my attention given the rivalry between Japan and China to secure the new supplies of oil that would be forthcoming. Of course, given those demands, a keen rivalry began to develop between Russia and Saudi Arabia for increased market share in the Asia-Paciic region. A major part of my work also focused on terrorism, resource nationalism, and even swordish now and again. But petroleum engineering was a subject that never appeared in any of the thousands of articles I wrote for the OGJ over the years. So, I was a little surprised when OGJ Editor Bob Tippee approached me with the idea of editing a book on petroleum engineering. Bob must have sensed my likely reaction, for he said, “I think you’ll ind this book very interesting. The guy who wrote it, Lou Powers, was chief petroleum engineer for the Saudis in 1977–79.” That immediately grabbed my attention. My relationship with the Saudis goes back to 1980 when I began teaching at King Abdulaziz University in Jeddah. That was a remarkable experience for me, coming out of Southern California into a culture that was so different from anything I had experienced. It was also a time of war, with conlict rising and eventually raging between Iraq and Iran. Back then, little was said of the war in public venues. But now and again one would get surprising glimpses of military activity even as far south as Jeddah. On one trip northward along the Red Sea coast, I vividly recall seeing a convoy of military vehicles and—under their tarpaulins lapping in the wind—various bits of military hardware: artillery, tanks, and light trucks. It was all headed north. The war did not seem to have much other impact at the time, though the feeling against Iran was pretty strong. Coming back to the present, I expressed interest in seeing Lou Powers’s book and getting to work on it.

xiii

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Even now I remember lipping through the pages to read about Lou’s experience in Saudi Arabia. His career had largely been with ExxonMobil and its afiliates, a career that had seen him working in a variety of locations in the US with one very insightful trip down to Venezuela to work on the heavy oil ventures then underway in that country. I was fascinated to learn about the profession of petroleum engineering and how Lou’s career had begun in aerospace before he moved over to oil. He also always seemed to be in the right place at the right time as far as employment went, and I could see how—little by little—his experiences led him to be chosen as the chief petroleum engineer in Saudi Arabia for the world-famous Aramco. As a student of oil history, especially the genesis and development of Aramco, I was fascinated to have the insights of the man hired to manage the oil reserves of the world’s largest producer. Above all, I was intrigued by the technology developed to determine Saudi Arabia’s oil reserves, as well as the continuing reinements in that technology that enable those reserves to be reestimated time and again. For me, Lou Powers’s manuscript was a timely item, coming into my hands just as war clouds were beginning to spiral over Libya in the early spring of 2011. At the time, there was concern around the world of supply shortages as a result of the growing conlict in that long-troubled North African country. Amid those concerns, Saudi Arabia’s Minister of Petroleum and Mineral Resources Ali I. Al-Naimi continually offered his country’s reassurances about its ability to keep the market supplied, no matter what the losses would be in Libya. Prices rose anyway. A similar situation emerged nearly a year later, as the US and its allies attempted to thwart Iran’s nuclear ambitions by urging an international boycott of Tehran’s oil. Prices began to rise as fears of shortages engulfed the world. Once again, Saudi Arabia’s Al-Naimi offered reassurances that his country could easily maintain supplies to offset any potential losses from Iran. But as prices continued to rise, Al-Naimi took the unusual step of commenting on the role of the media. “What we don’t understand is why the media and some of the organizations are negative on the fundamentals,” Al-Naimi said when addressing the problem of rising prices despite suficient supplies. That seemed to me a key point: many journalists simply have no idea when it comes to understanding the fundamentals of the oil industry and their impact on prices. And what could be more fundamental than understanding petroleum reserves: how they are calculated, how much xiv

Foreword

can be produced from them, and how much remains to be produced? All of those questions fall into the domain of the petroleum engineer, and as a petroleum engineer with more than 50 years’ experience, Lou Powers has some amazing answers. The World Energy Dilemma has much to say about the current state of the world and its need for oil. What it has to say is of major importance to journalists like me, but also many others. It is a book technical enough to meet the demands of the petroleum engineer, but not too technical for the lay reader. This is a book about one man’s life and how his experience can be brought to bear on one of the key problems of our time: the ever-growing demand for oil and the dilemmas we face in attempting to meet that continuing demand growth. Eric Watkins Los Angeles April 2012

xv

Acknowledgments Not the least, I wish to thank Ruth Nell, my wife of 52 years, who put up with ten moves, two foreign assignments, and helped raise three wonderful children, Jamie Powers, Lou Ann (Powers) Davenport, and Cheryl Ruth (Powers) Stillson. Ruth Nell also edited the early drafts of this book. Bob Burke, former editor of Offshore Magazine provided help on organization. Regrettably, Bob passed away on March 12, 2011, as this book was being sent to PennWell for publication. Gene Ames, former chairman of the Independent Producers Association of America and chairman of Venus Oil Company, gave me direction and guidance through the years. I consulted with numerous former colleagues at Jersey Production Research Co.; Humble; Powers Petroleum Consultants, Inc. (PPC); and Patterson, Powers, and Associates (PPA) to produce this book. They include Ron Lantz, George Binder, Pat Ketchum, Robert G. Parse, Willet Clark, Kenneth Taylor, Joe Marek, Mickey Finch, Ed Holdstein, Dudly Gravitt, Frank Kern, and Bill Curtis. In addition, Claude Cooke and Richard Sinclair, both former Exxon researchers, provided input about advances in fracturing technology. Also contributing was Doc Stokley and his recent review of the fracturing political problems in America and his input to resolving the well completion problems on a task force from Exxon Production Research to Aramco during my tour in Saudi Arabia. My friend and coworker Jack Zagar at Aramco provided numerous charts as well as philosophy about Saudi Aramco and thoughts about the Middle East that are incorporated into this book. Now a private consultant, Jack has kept up with Saudi thinking and in particular that of Saudi Aramco. Jack lives in Cork, Ireland, and is a consultant with Dr. Colin Campbell, the European expert on peak oil, who also provided input. B.R. Koehler, Petroskills instructor recruiter, who had a long career with Aramco and worked with me in Saudi Arabia, also provided a detailed review. Sadad Al-Husseini, former Saudi Aramco senior vice president of exploration and production, provided insights along with presentation xvii

THE WORLD ENERGY DILEMMA

slides from his Oil and Money conference. Dr. Al-Husseini is now an independent consultant with ofices in Bahrain. Numerous former Aramco employees were helpful too, including Ed Price, chief petroleum engineer and vice president of exploration and production at Saudi Aramco, who followed me as head of Aramco Petroleum Engineering from 1979–90; Aramco economist Lanny Littlejohn; Aramco engineer Jerry Ronquill; and Aramco engineer Saleem Akter, who provided a review and input from the trip to Russia in 1989. Saleem is now President of Orient Petroleum (Central Asia) Ltd., a Hashoo Group company based in Dubai. Rich Shiffman provided me with a copy of Saudi Aramco’s The Energy Within: a Photo History of the People of Saudi Aramco, and Saudi Aramco kindly gave me permission to use photos from the book. I also wish to thank Michael Lynch, president of Strategic Energy and Economic Research, Inc., for his input. I also received input from former employees of PPC and PPA Keith Dowling, Mark Roach, George Hite, and Lynn McCoy, as well as H.G. and Martha Mills, former ExxonMobil geologists, who subleased ofices and provided geologic services to PPC and PPA. Special thanks go to long-term PPC employees Mal England, Dan Tidwell, Nina Milligan, and Carol Callahan, who supported me through the years. Other consultants who provided input and gave me permission to use their work or information include J. Marshall Adkins of Raymond James Energy; Russell Wright of Groppe, Long, and Littell; Arthur Berman; Ken Morgan of the TCU Energy Institute; Mike Chafin of Valence Energy Corp.; Pete Rose, former head of the American Association of Petroleum Geologists; and Charles Smith, former professor of petroleum engineering at the University of Wyoming. Presten Meeks, formerly of Mobil and Conoco, reviewed the draft and provided suggestions. Eddie T. Cousins provided his report on Korean rigs being redirected from the Gulf after the Obama administration slowdown. Journalists at the Houston Chronicle provided several articles. Merit Energy CEO Bill Gayden, who served as chairman of the Perot Energy Policy Committee in 1992, provided the Perot Energy Plan. xviii

Acknowledgments

I am also most appreciative to Max E. Rasquinha, executive vice president, Global Overseas Services, and to Karl Schmidt, director, Regional Operations Center, Iraq IAP Worldwide Services. Thanks also go to Lasser Inc. for approval to use the Lasser Data system for downloading certain production from ields in Texas, and to Scott Mitchell of Wood Mackenzie Consultants to use their base Texas map. I wish to thank Bob Pepples, my accountant of 30 years, who found the link to the “facts about ANWR” website. Last, I want to thank the many wonderful people, supervisors, peers with Exxon, Aramco, PPC, PPA, and the many engineers, geologists, and lawyers who allowed me to grow through my association with them. Last but not least, I want to acknowledge the contribution of Eric Watkins for his professionalism in the editing of my original manuscript. Eric, formerly oil diplomacy editor of the Oil & Gas Journal, as well as a journalist with more than 20 years in the Middle East, brought his long experience to bear on my ideas, helping me shape them for inal publication.

xix

Abbreviations $/Bbl. Dollars per barrel 3D. Refers to seismic processing. 2D is a lower-resolution process. 4D is 3D run at later times. ANWR. Arctic National Wildlife Refuge ARC. Aramco Research Center ARCO. Atlantic Research Company ASPO. Association of Peak Oil b/d. Barrels per day BBbls. Billions of barrels bbl. barrel Bcf. Billions of cubic feet Bcm. Billion cubic meters BOE. Barrels of oil equivalent BP. British Petroleum Oil Company CCS. Carbon capture and storage CEO. Chief executive oficer CNG. Compressed natural gas cp. Centipoises, a measure of viscosity CSIS. Center for Strategic and International Studies D. 1,000 millidarcies DNR. Department of Natural Resources EIA. US Energy Information Agency EIGS. Exxon Industrial Gas System (intrastate) EXPEC. Name for the exploration production ofice building in Dhahran, Saudi Arabia ft. feet FPC. Federal Power Commission GIP. Gas-in-place GLL. Groppe, Long & Littell IEA. International Energy Agency IPAA. Independent Petroleum Association of America JPR. Jersey Production Research JV. Joint venture km. Kilometers LNG. Liqueied natural gas Mb/d. Thousand barrels per day MBCD. Thousand barrels per calendar day xxi

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Mcf. Thousand cubic feet md. Millidarcies (measure of ease of low through porous rock) MFSG. Major Field Study Group, East Texas Division MMb/d. Million barrels per day MMBbls/day OE. Million barrels per day of oil equivalent (gas converted to oil on energy equivalent basis) MMBTU. Million British thermal units of energy MMcf/ac-ft. Millions of cubic feet of gas per acre-foot of reservoir rock MMcf/month. Million cubic feet of gas per month NRI. Net revenue interest OECD. Organization for Economic Cooperation and Development OGJ. Oil and Gas Journal OOIP. Original oil-in-place OPEC. Organization of the Petroleum Exporting Countries PDVSA. Petroleos de Venezuela SA POWERS. Parallel Oil, Water, and Gas Enhanced Reservoir Simulator. GigaPOWERS™ is the second generation of Saudi Aramco’s leading reservoir simulator. No relation to author. PPA. Patterson, Powers, and Associates, Inc. PPC. Powers Petroleum Consultants, Inc. psi. Pounds per square inch RI. Royalty interest RJE. Raymond James Energy SAGD. Steam-assisted gravity drainage SITP. Shutin tubing pressure SONJ. Standard Oil of New Jersey SRM. Systematic Reservoir Management (management system applied to East Texas Division reservoirs) Sw. Percent of pore space occupied by water TAP. Trans-Alaska Pipeline TCF. Trillions of cubic feet TCO. Tengizchevroil Partnership (Kazakhstan) TGP. Texas Gulf Paciic Pipeline Company TOA. Temporary overseas assignment TRC. Texas Railroad Commission TSC. Technical service contract WI. Working interest WTI. West Texas Intermediate (a light crude oil used as a benchmark in oil pricing) φ. Porosity (fraction of rock with pore space) xxii

ABBREVIATIONS

Saudi Aramco Crude Grades ASL. Arabian Super Light, 42.0°API AXL. Arabian Extra Light, 39.4°API AL. Arabian Light, 32.8°API AM. Arabian Medium, 30.2°API AH. Arabian Heavy, 27.7°API

xxiii

Introduction The World Energy Dilemma

S

audi Arabia’s newly appointed oil minister Ali I. Al-Naimi appeared at the ifth annual Conference on Trade and Finance held in

London on September 29, 1995. According to one report, the de facto leader of the Organization of the Petroleum Exporting Countries (OPEC) “appeared sanguine

about

rising

non-OPEC

production,

describing it as a ‘fact of life’—and perhaps even a blessing in disguise for those with large reserves like Saudi Arabia. The fact that non-OPEC is inding more reserves like Saudi Arabia is in a way good for the industry. It continues to promote and perpetuate the use of hydrocarbons and lessens the pressure to move away from this source of energy. Al-Naimi dismissed prospects for output restraint by non-OPEC producers to support oil prices. ‘There is no non-OPEC entity. There are 70–80 independent producers, each with their own circumstances,’ he said.”

1

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Talk about control. It’s worth noting that the main oil-producing countries of the Gulf region—Saudi Arabia, Iran, Iraq, Oman, Kuwait, and the UAE—occupy about as much land area as Texas and Oklahoma (ig. I–1).

IRAQ Kuwait

IRAN

KUWAIT

Manama Dhahran

QATAR

Dubai

Abu Dhabi Muscat

SAUDI ARABIA

UAE OMAN

Fig. I–1 Oil-producing countries of the Middle East: this relatively small region encompasses nearly the same land area as the states of Oklahoma and Texas, but with a high concentration of the world’s oil supply.

The predominant role of Middle Eastern suppliers prompts consideration of several key questions:

2

1.

Will the Middle East governments want to provide oil that the world may require or want to hold up the price of oil?

2.

Will demand forecasts be too high because of higher oil prices? In 1994, the year before Al-Naimi’s speech, we were looking at $25/ barrel (bbl). But what about the effects of the green movement, motor fuel replacement, Middle East instability, and non-OPEC supply?

INTRODUCTION

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3.

Will capital and desire be available in a timely manner?

4.

What oil prices do energy planners use in justifying billion-dollar investments that take place four or ive years in the future?

Meanwhile, here are some thoughts about the ive Gulf oil producers from my friends Jack Zagar and Colin Campbell: 50% of the world’s remaining cheap oil reserves are in ive Middle East Gulf countries— Saudi Arabia, Iran, Iraq, Kuwait, and the UAE—but 98% of the world’s population resides elsewhere. Figure I–2 shows the impact of OPEC’s 2003–07 production cuts that helped lead up to the 2008 price spike. Note the impact of OPEC on historical price patterns. OPEC had control in 2003–2007, but by 2010 Saudi Arabia was primarily in control, with upwards of 4 million barrels per day (b/d) of spare capacity. Not today.

Fig. I–2 OPEC’s 2003–07 production cuts contributed to a severe price spike in 2008.

Figure I–3 shows a year-2004 forecast of future demand and supply by ExxonMobil. Note ExxonMobil’s forecast that by 2030 the call on OPEC oil would be 50 million b/d. I attended a meeting where this analysis was presented. ExxonMobil was optimistic on what OPEC would deliver in the future—primarily their estimate of Saudi Arabia: not that they could not, but that they would not. I still believe that premise. I also thought ExxonMobil’s forecast of future world demand was too high, considering 3

THE WORLD ENERGY DILEMMA

what I thought would be future world oil prices. ExxonMobil forecast world oil demand of 120 million b/d by 2030.

Fig. I–3 ExxonMobil’s energy outlook 2004, liquid supply forecast

Exxon had an optimistic eye back in 2004 when gazing into the future. But compare that with Exxon’s energy outlook to 2030 issued in 2010. In igure I–4 note that Exxon has reduced liquid demand/supply from OPEC back to 36 million b/d from 50 million b/d. A large part of the reduced call on OPEC in 2030 is due to Exxon’s dropping its world forecast demand by 20 million b/d by 2030 to 100 million b/d. In Exxon’s 2012 forecast just two years later, the world demand has grown back for the year 2030 to 109 million b/d (ig. I–5). Note that this is about the same 2030 production level projected by Daniel Yergin in his new book, The Quest (2011, Penguin Press). However, Yergin adds a lot of buts to his forecast that I call dilemmas. It is good to do forecasts, but let’s remember words from E.F. Schumacher’s Small is Beautiful: “The world will appreciate most who say ‘Stop, Look, and Listen’ rather than ‘Look it up in the forecast.’ ”1 4

Fig. I–4 ExxonMobil’s energy outlook 2010, liquid supply forecast

Fig. I–5 ExxonMobil’s energy outlook 2012, liquid supply forecast

THE WORLD ENERGY DILEMMA

It is interesting that biofuels and tar sands in Venezuela and Canada have entered the picture. In biofuels, government incentives have certainly played a role, at the cost of higher food prices around the world. Other alternative fuel sources will become important in the future, but hydrocarbons will maintain the largest percentage as a source of energy (ig. I–6). Note that ExxonMobil forecast only a small amount of energy use for biomass and other renewables in spite of public announcements of spending hundreds of millions of dollars, particularly in the biomass area. In fact, by 2040 Exxon still forecasts 86% of the world’s energy will be coming from conventional energy resources: coal, oil, natural gas, hydro, and nuclear. Natural gas will be the big growth supply.

Fig. I–6 ExxonMobil’s energy outlook 2012, future percentage of energy supply

There’s another issue, too: China’s appetite for oil. Figure I–7 shows the 2004 forecast by the US Energy Information Administration (EIA) of China’s growing demand for oil. In 2011, the EIA estimated China’s demand to be 9.6 million b/d against net imports of 5.4 million b/d. In other words, 56% of China’s total demand is now imported. For years, China was subsidizing fuel costs. However, with the higher prices we are seeing, it will be interesting to see if China reinstates those subsidies. China’s upward trend in demand for oil is not expected to slow down; its transportation system continues to expand at an accelerated rate. Consider igure I–8, which shows the growth in China’s auto sales. To date, the Chinese have not developed a natural gas transportation system. 6

Fig. I–7 US Energy Information Administration estimate for China’s oil demand

Fig. I–8 The growth of China’s auto sales

THE WORLD ENERGY DILEMMA

Another matter of concern is the subject of world oil reserves. I suspected that number had been overstated in some countries. Then in February 2005, Royal Dutch Shell gave us a perfect example of what concerned us: reporting a proit increase even as it reduced assets in the ground. Could something similar be happening in the Middle East? Figure  I–9, by Zagar and Campbell, shows what they consider are spurious reserve revisions. The subject of Kuwait reserves was brought up in 2004 by Petroleum Intelligence Weekly. Apparently based on a leaked report of the Kuwait Oil Co., the country’s reserves, including those in the Neutral Zone, were only 48 billion bbl as against the 94 billion bbl attributed to them in igure I–9. This may be part of the 300 billion bbl that Sadad Husseini was talking about in his speech at the 2007 London Oil and Money Show. As for Saudi Arabia, I discuss its reserves, along with new technologies, at length later in the book.

Fig. I–9 Spurious reserve revisions, billions of barrels (BBbls)

8

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Figure I–10 is important from a historical perspective. ExxonMobil, in its 2004 outlook, analyzed the real decline of both oil and gas ields around the world and determined it to be between 4%–6% per year, or an average of 5%. What this means is that each year we now need 4.25–4.5 million barrels of new oil capacity just to offset decline. This decline, analyzed some eight years ago, is still the industry standard, as will be developed later in the book. The growth in demand was too optimistic, as previously discussed.

Oil Equivalent (OE)

Fig. I–10 Real decline of world’s established oil and gas ields. ExxonMobil Energy Outlook 2004.

While petroleum resources show continued growth, it’s mostly due to what is termed “unconventional resources” and deepwater. New technology and added reserves make natural gas the growth fuel of the future. While oil resources keep growing, I am concerned for the petroleum industry’s ability to meet the increasing world demand in the future. Figure I–11 details the worldwide supply of natural gas and the widening expansion of this unconventional resource.

9

THE WORLD ENERGY DILEMMA

Fig. I–11 Global gas resources. ExxonMobil Energy Outlook 2012.

Natural gas on a worldwide basis will continue to be developed, but natural gas development in North America is coming to a halt due to the low price of $2–$3 per thousand cubic feet (Mcf). Horizontal drilling and multiple-stage fracing for natural gas is just too expensive in most basins to meet acceptable returns. One of the themes of this book is that stability and peace in the Middle East are essential if we are to avoid another catastrophic worldwide energy price spike led by the rocketing cost of oil. But stability and peace may just be dreams considering how things stand now. Note the October 2012 US Justice Department report on Iran’s reported attempt to assassinate Adel A. Al-Jubeir, the Saudi ambassador to the United States. Then, too, what will the death of Saudi Defense Minister Crown Prince Sultan bin-Abul Aziz—the heir apparent to King Abdullah—mean for stability in Saudi Arabia? There are other points of concern:

10

1.

The world is entering a dangerous period where the demand for energy will be a driving force (for good and evil).

2.

Capital investment will intensify, particularly for development of energy resources of all kinds (jobs will be plentiful).

3.

Tight supply and demand balance will cause unusual swings in prices for energy resources.

INTRODUCTION

THE WORLD ENERGY DILEMMA

4.

Higher gasoline prices of $3+ will ultimately tame demand in the US.

5.

Rising oil prices will drive other energy prices higher and will make energy investments in coal, natural gas, and uranium more attractive.

We’ll see what $3.70 gasoline does for demand in the US. Meanwhile, here are some points all of us need to watch out for: 1.

Tight supply and demand balance

2.

Demand growth in Asian countries as their economic desire to drive cars grows with their economic power

3.

Oil ield terrorism in the Middle East and all parts of the world

4.

Increasing greed of host governments as they cut the share going to the producers, e.g., Russia, Ecuador, and Venezuela

5.

Increasing tension between the US and key producing countries

6.

Increasing competition between the new high-growth consumers and the Organization for Economic Cooperation and Development (OECD) countries for limited supply

Many of these have come true in the last ive years, and US inluence on world markets has declined. Over this period of time, I gave speeches to civic clubs, inancial groups, and meetings of the Geological Society, the Houston Chapter of the Society of Petroleum Engineers, and the 2007 Enhanced Oil Recovery Symposium in Tulsa, Oklahoma. In several talks, I listed concerns and things to watch for. Unfortunately, too many of my concerns have come to pass. Perhaps it’s time to review things all over again. The world is in an energy dilemma. On the one hand, new technology is alive and well, adding billions of barrels of oil and trillions of cubic feet of natural gas worldwide. On the other hand, world crude supply, for a variety of reasons, has not kept up with increasing world oil demand. This book’s primary objectives are to explain how the world got into this dilemma and to give some thoughts on the way ahead. In October 2011, Libya’s ruler Muammar Gadhai was executed after prolonged civil war, and the normally quiet Kingdom of Saudi Arabia experienced acts of violence over trials of arrested terrorists. Earlier in 2011 the Gulf Cooperation Council sent troops to Bahrain to quell dissent after Bahrain’s King Hamad bin Isa al-Khalifa declared a three11

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month state of national emergency. Given such events, it may be too late for new and sound energy policies to be developed to avoid the next energy crises. While Hosni Mubarak may be gone in Egypt, who or what comes after him? On March 4, 2011, the price of West Texas Intermediate (WTI) crude topped $114/bbl, while the world price cost $10–$15/bbl more as measured by Brent crude (ig. I–12). However, all forms of energy, including natural gas, will follow in time, and the world’s economic system, weak already, will fall again into another downward spiral.

Fig. I–12 WTI monthly crude oil price per barrel, 2002–2011

Governments around the world are uncertain of what to do about rising oil prices. For many countries, there is nothing that can be done. Price is in the hands of the suppliers, principally a few OPEC member states. Also, there are the big consuming countries that continually require more energy to improve their economies and provide their people a better life. America, for example, may decide to promote the growth of corn to produce more ethanol to mix with gasoline. But that may mean that the poor countries of the world suffer from increasing food prices. America’s 12

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inability to stop being the world’s largest consumer also has had a large impact on world oil prices. With just 4.4% of the world population, the US nonetheless consumes 22% of the world’s petroleum, most of it for transportation. Sadad Husseini illustrated this quite well in his 2005 Oil and Money show presentation, where he projected that it will be a problem for the US by 2020. I say, how about now? The US has to be careful not to shoot itself in the foot as it attempts to reduce motor fuel consumption. Smaller cars—maybe even electricpowered ones—are certainly a way to go for many families. An obvious solution for the US is to make a strong push to convert leets—particularly trucks and locomotives—to natural gas. Private automobiles will follow if an easily accessible distribution system is put in place. This probably will require legislative action from either state governments or the federal government, but it does not require federal subsidies. Government incentives to buy new energy eficient products—such as Washington’s “Cash for Clunkers” program—may provide short-term energy reductions, but they do so at a cost to our grandchildren. Such programs would be acceptable if the current generation of taxpayers had the cash to pay. Unfortunately, we don’t. Saudi Arabia’s decision in the late 1970s to limit production has adversely affected world oil prices as surplus supplies have dwindled. The Saudis have recently added new production capacity, but by the beginning of 2011, they had not supplied additional production into world oil markets. By the end of February 2011, it was reported that the Saudis have 12 million b/d to offset the loss of Libyan crude during that country’s civil war. However, due to lack of rig availability, this igure may have slipped. In any case, we know from speeches by Saudi oficials, including the oil minister and the president of Saudi Aramco, that the Kingdom does not plan to increase production capacity beyond 12.5 million b/d anytime in the foreseeable future. Saudi production levels and its ability to deliver in the future receive major emphasis in this book, based on my personal experience in the country as well as my continued contacts there and around the world. Wars and continued turmoil in the Middle East have had a major impact in limiting the development of new oil capacity, while existing capacity has declined. The continuation of warring factions in the Middle East, as well as active terrorism, has played a major role in the world’s oil capacity decline, notably in Iran and Iraq. The Iraqis do have 13

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the potential to increase their production. But will instability in the region allow them to do so in a timely manner? What impact will result from President Obama’s decision to pull out essentially all American troops left in Iraq by the end of 2011? Will Exxon, BP, and Eni S.p.A. be able to recoup their $100 billion investment? Could reinvestment in Iraq’s oil ields lead to stability and peace or more war? What about the growing inluence of Iran in Iraq as our troops withdraw, particularly in the southern region around Basra? The problem, however, is not limited to the Middle East: Venezuela under the socialism of President Hugo Chavez gives us another example of declining oil supplies to the world. Meanwhile, the rapidly growing economies of China and India make them the world’s fastest growing consumers of oil. Chinese and Indian national oil companies have spread throughout the world, seeking new energy resources in competition with major international oil companies. Also complicating the picture, Western countries have tried to enforce sanctions against Iran, OPEC’s number-two producer after Saudi Arabia, because of their fears over Tehran’s alleged development of nuclear weapons. Other countries, such as India, which already has nuclear bombs, also have a large and growing appetite for more supplies of oil from the Middle East. India’s oil production has latlined for the last eleven years, while its demand has grown at 4% per year. India is now importing 76% of its domestic needs. But who is India’s largest supplier of imported oil? That distinction goes to Iran, which provided 17% of India’s imported oil in 2009. Can the West then enforce sanctions against Iran? India meanwhile is rapidly expanding its own nuclear power supply in cooperation with Western suppliers endorsed by the US government. On a worldwide basis, decisions related to global warming supposedly caused by CO2 are having a major impact. But oil, natural gas, coal, and uranium will be the preferred fuels of the future unless major breakthroughs are achieved. This does not mean that green energy sources will not contribute. The question is, how high must oil prices rise before green energy becomes competitive without government subsidies? So-called investments in green energy by governments such as the US really are the tax dollars of our grandchildren. Governments, particularly the US, should be focusing their main decisions on how to reduce the deicit spending that results from rising crude prices and oil imports. That is, they must become proactive in the 14

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development of their own resources, not trying to determine how to reduce CO2 based on questionable scientiic facts. In early March 2011, the US was creating a daily balance-of-payments deicit of $1.15 billion or, annualized, $420 billion. That is an amount larger than the country’s peak deicit year of 2008. Consider also how the devastating earthquake that struck Japan in 2011, with all of its adverse effects on that country’s nuclear industry, presents us with yet another aspect of the growing dilemma before us. As Japan’s nuclear industry collapsed, the country began to import more oil—a process that could be duplicated by other countries around the world now using nuclear energy. This book is based on my more than 50 years’ work as a petroleum engineer and what I have experienced in that capacity. But the book is more than a mere review of my personal history. Some of the projects I worked on 50 years ago are now at the very heart of the world’s energy dilemma. For example, my involvement with some of America’s major oil ields its in with my understanding of Saudi reserves today. My early work on tar sands in Venezuela and Canada bears on the current discussion over the Keystone XL pipeline project. This book brings those assignments and others to bear on today’s world oil and gas dilemma. In summary, the world of energy supply is complex, and its issues need to be addressed not only in the United States but around the world.

Notes 1. Schumacher, E.F. 1973. Small Is Beautiful: Economics As If People Mattered. New York: Harper & Row.

15

1 MY CAREER TAKES OFF

M

y 50-year career as a petroleum engineer, supervisor,

manager,

and

consultant

would take me to many places in the

world, not least to the Kingdom of Saudi Arabia, even now the holder of the world’s largest reserves of petroleum. My career also took me to other main oil- and gas-producing countries in the Middle East, Europe, Canada, Latin America, and Central Asia. I had plenty of opportunities to study ields in Canada and Venezuela, two of the world’s largest producers of oil. My career also gave me the opportunity to study America’s great oil ields, including the country’s biggest at Prudhoe Bay in Alaska, as well as numerous other large ields in Texas and Oklahoma.

17

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Jersey Production Research Co. All of these experiences began with my irst job in 1958 when Jersey Production Research Co. (JPR)—an afiliate of the Standard Oil Co. of New Jersey (SONJ), later known as ExxonMobil—offered me a position as a mechanical engineer in drilling research. JPR even had ofices for one or two engineers, and that was appealing. But I was more interested in their new methods of oil recovery—particularly their steam and other thermal applications. At the last minute, JPR called and offered me a job in new methods of oil recovery, and I accepted it. The starting salary was $6,000 a year, and they said I would get a $360-per-year increase on completion of my master’s degree. My irst job was in the lab where we ran tests of oil recovery on tar by injecting steam into a cell that contained formation sand. Hot water, other miscible luids, and carbon dioxide (CO2) were studied to determine how much heavy oil or tar could be recovered. We also took on studies of ire looding and in-situ combustion by injecting air along with water. Many of the engineers and geologists had their doctorates. I wondered if I had gotten in over my head. One of my early supervisors was Tom Boberg, head of the lab’s Thermal Oil Recovery, who developed the so-called Huff and Puff concept for SONJ in the early 1960s. In the Huff and Puff process, steam is injected into a heavy oil reservoir, and then oil and water are produced back at a higher rate because the heat around the wellbore reduces the viscosity of oil. The Canadians, who refer to Huff and Puff as cyclic steam injection, have taken this process to another level with the advent of shallow horizontal drilling. That’s where a horizontal well is drilled in the upper part of the sand, and a deeper horizontal well is drilled as a producer. That way, the steam injection can occur over a large distance away from the vertical well to heat the reservoir rock. Then it can be turned around as a producer or drive the steam and heat to reduce the viscosity of the heavy oil. The Canadians have called this process steamassisted gravity drainage (SAGD). See igure 1–1. In the lab we had a few barrels of tar, some of it from the Athabasca Tar Sands in Alberta, Canada, and some from Venezuela’s Orinoco Tar Belt—both of them sources of oil that are being developed today with prices greater than $60/bbl. At the time, when we were researching ways to get the tar to produce, the price of oil was in the range of $1–$2/bbl. A couple of samples of the oil or tar were so thick that they could not be 18

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poured out of a bucket at room temperature. You had to heat the tar up to get it into the core holder, and then cool the container holding the sand and the tar back to reservoir temperature.

Fig. 1–1. Steam-assisted gravity drainage (SAGD) process. Source: Canadian Centre for Energy Information.

Investigating Heavy Oil Eventually I was sent to Fort Scott, Kansas, near our Missouri Deerield steam project. The lab had been running a test of steam injection in a very small pilot to determine the commerciality of a shallow 160-ftdeep heavy oil reservoir. The crude was sticky, 1,000 centipoise (cp) at reservoir temperature, but nothing like the Athabasca or Orinoco tar sands at 50,000 or more cp.1 Carter Oil Co., the operator, had been injecting superheated steam for four years without much success. They did produce about 7,000 bbl of oil over the four years, but it took more energy to generate the steam. The competitors who stood along our fence didn’t know if we were trucking oil in or taking it out. We wanted to know what the residual oil was in the steam-swept zone. My job was to catch the cores, wrap them, and transport them 19

THE WORLD ENERGY DILEMMA

back to Tulsa for a core lab to inspect them to determine the residual oil saturation in the steam-swept area. As we became more eficient, we got so we could drill and core a well in two to three days—so, there were many trips to Tulsa. One unusual event occurred when we were coring the wells. In order to speed up the operation on one occasion, the operator did not set a conductor surface pipe, a standard operating practice. The operator simply moved the rig to the site, drilled down to the coring point, took the core, and circulated a cement plug. Next, the cement was coming out of the hole. The pumper described it as “a cement post coming out of the ground.” What we saw looked like the Old Faithful geyser at Yellowstone Park. The operations people from Carter Oil thought maybe they could just blow down the injection wells and that would reduce the pressure enough to kill the well. That did not phase the well blowing out, since these rocks had been heated with superheated steam for more than four years. The solution was to borrow a water hose from the Nevada, Missouri, Fire Department, connect it to a 6-ft pipe or nipple, get close to the crater (now about 6 ft wide), and hope the pipe was heavy enough to draw the hose down into the well. It worked. The operator pumped cold water down the hole to cool the rock, then circulated heavy cement, and plugged the well. Carter people had to pay the Nevada Fire Department for their hose. Another experiment we ran at Deerield was to see if we could ignite the heavy oil by pumping linseed oil into the formation, which had a much lower lash point than the heavy oil, and then pump air into the well, hoping spontaneous combustion would take place. Others had used heaters placed down hole, but someone at the lab thought this method of pumping linseed oil and air might be an easier and less expensive method to start a ire lood. One night I was in the ield. The wind was blowing, and earlier it had been raining. The ield was very muddy and cold. My job was to monitor the well and see if the thermocouple wire we had run down the hole was indicating any rise in temperature. That night, it was pitch black and about seven degrees Fahrenheit. We had built a fence and put a gate around the well, and the compressor was pumping air into the well with a temperature of about 20

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135 degrees Fahrenheit. I was leaning over the wellhead trying to get a reading from the temperature gauge, and all of a sudden I felt a blast of warm air hit me from behind. I thought the well had blown up. I did not wait to ind the gate. I just charged through the fence like a crazed bull. When I picked myself up and looked back to see a lame coming out of the well, I realized what had happened. The rubber compressor hose had become disconnected from the wellhead and was swinging back and forth wildly in the breeze. The difference in temperature between 7 and 135 degrees made quite a difference to my rear end. As it turned out, I had only a few scratches. JPR had a six-week intensive reservoir school, and SONJ experts from throughout the country were called on to lecture there. One particularly interesting gentlemen was Slip Slider, a petroleum engineering professor from my alma mater, Ohio State University. Slider was humorous but a good teacher. I never took any courses from him while at Ohio State, as I was studying to become a mechanical engineer back then. As I recall, the top student at the reservoir school that year was Gordon Willmon from Canada, who later became one of the top executives for Imperial Oil. The following year I was asked to be the assistant to Bob Ledbetter, who ran the reservoir engineering school. That year we had 30 men and one woman from around the world. The one woman was unique. She worked for the Iraq Petroleum Co. at a time when SONJ had a inancial interest there. She had a math degree from an English university and was being trained to be a reservoir engineer. As I recall, she scored very well in the reservoir engineering school. When she left, we heard from her for a year or two, but then nothing. We often wonder what happened to her through all the turmoil that has occurred in Iraq. Sometime during my assignment, I decided that computers were the way of the future. JPR had one IBM 650 computer, but I realized that economic calculations were done on spreadsheets and not on the computer. I decided they could be done much faster with computers. The IBM 650 required punch cards for data entry, and it used a computer language called Fortran. The computer took up a room the size of my ofice. I read the Fortran manual, decided on my own the economic parameters I wanted to calculate from a cash-low stream, such as payout, return on investment, present value at certain discount rates, and investor’s rate of return. After a few months I completed the task, and it worked. I wanted 21

THE WORLD ENERGY DILEMMA

to know if the new methods of oil recovery made any economic sense at the projected rate of inlation. At the time, I recall the price of oil was $1–$3/bbl, and under government price controls, natural gas was in the range of $0.10–$0.20/MMBTU. At one research meeting I went to, somebody said we could run ireloods in every ield in America if we could get $5/bbl. But that was wrong. The person had forgotten, or didn’t understand, about inlation of oil ield services including the cost of natural gas, plus the corrosion and well problems when the ire or combustion front got to the producers.

Heading for Venezuela In 1960, at the end of the third year of my tour at JPR, I was offered an assignment at an oil ield camp in a place called Quiriquire in eastern Venezuela (ig. 1–2). SONJ Chief Engineer Max Sons, out of the New York ofice, had requested that Tom Boberg conduct a reservoir study and some type of thermal test in Quiriquire, a large, 5-billion bbl heavy oil ield. Boberg and I left to meet with the executives of Creole Oil, SONJ’s Venezuelan afiliate in Caracas. We would overnight in Caracas, staying at the then-beautiful Tamanaco Hotel.

Fig. 1–2 Quiriquire Oil Field in Venezuela

22

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We showed up at the Creole ofice to meet with the executives. But the doors were locked, and we were met by a guard at the door brandishing a machine gun. It was a holiday in Venezuela. We stayed over for another day and met with Creole’s chiefs. As I recall, they were a couple of very large men. They both were sitting on their chairs, smoking very large cigars. After going over the purpose of our trip, Boberg then launched into explaining about the new sand that we were using to fracture oil wells in the US. After listening for a few minutes, one chief took out his cigar and asked the other, “How do you think that sand would do in my begonia beds?” I was not sure he heard much of what Boberg had said, but he quickly dismissed us and sent us on our way. There were not many questions about what I was going to do in Quiriquire. We left quickly and planned to depart the next day for Quiriquire via Maturin in the jungles of eastern Venezuela. We arrived after a 30-km ride through the jungle and went to the house of Frank Chuck, the camp superintendent. He called the chief engineer and said, “We’ve got these researchers here.” Needless to say, the greeting was less than friendly. I do not think they liked having outside researchers, as he called us, interfering with their business, particularly researchers sent by the SONJ head ofice. They took us to the bachelor quarters, which would be my home for the next three months. The house was on stilts. Apparently, in the early days, tigers were a problem. The pillows were stuffed with straw and were a bit damp in the humid jungle climate. On occasion, I did see an Iguana sunning himself on the porch. Telephone communication at that time was limited with the States, so most of my communication with my wife, Ruth Nell, would be by letter, which was quite slow. The irst letter took 12 days. Boberg then headed back to Tulsa, while I was introduced to Clyde Walker, head reservoir engineer. Walker assigned me a young technician who wanted to learn English. He was sharp and very helpful. So, I did not learn much Spanish. My irst objective was to learn what type of reservoir I was working with. It was a massive 3,000-ft thick conglomerate reservoir that had numerous shale layers inter-bedded between the conglomerate reservoirs. The net sands averaged only 204 ft out of the 3,000 gross ft. Shale made up most of the section. The thin sands were tough to 23

THE WORLD ENERGY DILEMMA

correlate between wells, even though the ield was developed on a nominal 20-acre spacing. The deposit is what is called an alluvial fan: the reservoir rock was made up of large rocks, pebbles, sand, and silt. Several wells had been cored, and sometimes the cores contained very large rocks. There was an estimated 5.5 billion bbl of original oil-in-place (OOIP). By the end of 1963, Quiriquire had produced 606 million bbl of oil, but its production had declined to 33,000 b/d. What was the trap? Strangely enough, the reservoir had no rock seal but was sealed by tar, which had formed around a pool of lighter 16.2oAPI oil around the body of mobile oil. The oil itself was viscous and pumped to the surface. There were 423 pumping wells spread throughout the jungle. I irst needed to understand what the primary recovery would be. When I arrived, Creole thought it would be 14% of the initial OIP. This was relatively low because of the reservoir complexities and the very viscous nature of the oil being displaced by the mountain rain water. The ield did have a nominal water drive from the mountains where the rainwater leaked through tar barrier once the reservoir pressure declined. No doubt the recovery was low, and SONJ’s Max Sons thought this would be a good place to try a thermal oil recovery technique. Among other things, there was a lot of shale to heat along with the sands. The ield was discovered in 1928. After studying the reservoir, I concluded the OIP was overstated by 100%. The moveable OOIP was only about 2.5 billion bbl and consequently the ultimate recovery would be about 28%. In computing the OOIP, a mistake had been made when the surrounding tar barrier had been included in the OOIP. Clyde Walker, the camp’s head reservoir engineer, agreed with my conclusion. I then concluded that thermal methods would be too expensive: too much lost heat because of the inter-bedded shale. If anything, Creole might try a pilot water injection program in a part of the reservoir where the external water-drive had not been very effective.

24

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Showdown over My Conclusions After a break to get my family, I learned that Max Sons had called a meeting of some 25 or more engineers and geologists from across the Western Hemisphere to review the preliminary results of my study. It was in the middle of summer, and I remember how three men from SONJ’s Canadian afiliate Imperial Oil were sweating profusely. There were no air conditioners at that time. After my presentation, all there—including three Creole directors—were asked to offer comments. One of the more momentous statements came from a Creole director, not an engineer, who suggested that “rather than injecting more water, maybe we should drill water wells around the ield to catch the water before it got into the ield.” He concluded that would reduce the water production and the operating costs. He obviously did not understand reservoir engineering principles, as water was the primary drive mechanism that supported the production of oil. The room went quiet. You could hear a pin drop. I do not remember who spoke next, but it was a long time coming. Next, my family and I were off to Caracas to inish my report, or so I thought. I typed the report and sent the draft off to Creole management. Ruth Nell learned to be my editor early on. I was told they liked it and wanted me to present the conclusions to the Creole board of directors. I was on a high! Here I was only four years with the company and my irst major study looked like a winner. I thought the presentation went well. Nobody told me I needed to clear my report with my bosses in Tulsa, and the Creole Directors told me they liked my conclusions.

Surviving a Storm Back in Tulsa, I learned that new management was in place. Dale Woody, vice president, had been transferred in from Humble Oil and Reining, SONJ’s domestic afiliate. He was a very outspoken man with lots of ideas and would come to play a signiicant role in my future career. Though neither I nor any of my colleagues knew it at the time, Woody’s real purpose was to merge the JPR Lab with Humble’s Domestic Research Lab in Houston.

25

THE WORLD ENERGY DILEMMA

On returning to Tulsa, I was taken to meet Woody in his ofice, and I also was told that Max Sons wanted to meet with me before the inal report was released. Sons wanted Bert Willman, who I had previously worked for, to review the report and be ready to meet Sons in about a week. My high was beginning to slip. I was ready to move on to my next project, but not quite yet. A week later I entered the room and took my seat opposite Max Sons. He said he had made a recent trip to Caracas. He looked right at me and said that the Creole directors had beaten him over the head with a rough draft of my report, shaking his ist at me with the report in his right hand. I started to say something, but he interrupted me, saying that he had never read “a weaker recommendation in his life,” along with some other words indicating that I had no guts. I wanted to slide under the table. My career hit a new low. But Max Sons did not know me very well, and I fought back for two-and-a-half hours, telling him that to proceed with expensive thermal processes did not make sense in Venezuela at this time. Sons disagreed, and he told Willman that he wanted the report rewritten more to his liking. After the meeting, Woody came out, put his arm around me and congratulated me. “I like to see a man stand up for what he believes,” he said. Later, I found out that Sons was not high on Woody’s list even though he was the top man in SONJ’s petroleum management at the time. The other managers were pretty quiet. My career did seem to have hit a new low. Three weeks later the report was still not done. It seems that the paragraph that Sons objected to had not really been changed, so they sent me to Woody’s ofice to iron it out. This time I agreed that they could say anything they wanted to in the cover letter that Woody would sign, provided they left in the report the paragraph that Sons objected to. Even though I was at a low point, I still felt I had a friend in Woody. The next week, I was called in and told that they were very happy with my work, and appreciated me taking on the Venezuela assignment. They were going to give me a nice raise. It was just eight months since the last one, which was unheard of. Ruth Nell and I would stick around a while longer—a lot longer. I even considered going back to school and getting a doctorate, but I soon eliminated that idea. 26

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Training in Reservoir Simulation In my last couple of years at JPR, I received training in reservoir simulation. As I recall, I had some sharp coworkers, including Red Shefield, J.K. “Jim” Patterson, who later became my partner in PattersonPowers and Associates, and Keith Coates, a real brain in reservoir simulation. Jim and I were studying the Abqaiq ield in Saudi Arabia. This was my irst association with any Saudi ields, but it was certainly not to be my last, as later chapters will show. We were running two-dimensional cross sections as well as areal studies. As I recall, the cross sections ran ine, but we could not match the OOIP with a 2D areal model. This was because of the thickness of the reservoir at 200–300 ft. Areal models seemed to work ine for thinner reservoirs. The rock properties used were core relative permeability and core capillary pressures. I discussed this problem Keith Coates, and he developed a new concept of pseudo-relative permeability and pseudo-capillary pressure from the 2D cross sections. These curves were applied in the areal models, and they seemed to match the OOIP more correctly and gave more realistic areal model projections. It became standard use in future reservoir simulation models. We could model a few 1,000 blocks in those models. Back then the main problem with simulation was the lack of reservoir data, cores, special logs, and the like to put into the reservoir models. History matching in older ields was used to try and correct for the lack of data. The Prudhoe Bay ield developed by BP and Exxon is a case study, where the operators cored 100 wells out of the initial 400 drilled. These early data efforts have paid off many times as this large ield continues to produce more than the expected reserves, as we’ll see in later chapters.

My First Brush with Saudi Arabia In the fall of 1964 came the big announcement that most of us would be moving to Houston and merged with Humble Research Laboratory— the plan that Woody had been sent to implement. The company would downsize and lose about 10% of the professional staff. You were on the 27

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list to move if you had not been told you were not going. JPR would help sell your house. We lost some good people, but that was the way it was. The rest of us, about 300 families, were offered trips to Houston. Most of them bought beautiful new homes, but we rented for a reason few people knew. About a year earlier, I had been visiting with the Aramco engineering representatives who wondered if, after I had done my study on the Abqaiq ield, I might be interested in accepting a position in their reservoir engineering group in Arabia. JPR was informed. Aramco was not hiring at the time, but an Aramco engineer said he would go back and try to get a position approved. By the time of the move to Houston, nine months later, we still had not heard from Aramco, and my supervisor advised me to move. “We can use you even if the Aramco offer does not come through,” he said. Three months after our move to Houston, the opportunity arrived to go to Saudi Arabia. Bill Moore, my supervisor at that time, told me that management did not want me to leave the Lab, but I wanted a change. Bill said he would try to get me a position with Humble Oil & Reining (later Exxon) in their US production department. He suggested a meeting in Humble’s downtown ofice with Planning Manager Larry Rawl, who would one day become CEO of Exxon. On the day of the meeting, I was ushered into Rawl’s ofice. As I stood up at the end of the meeting, Rawl said: “Make up your mind about the Aramco offer. Then, maybe we will talk.” It was not quite the response I had hoped to hear. When I reported back to Bill Moore, he advised me to not give up on Humble. Moore said he was “transferring back to Humble and was to become the division reservoir engineer in the South Texas Division ofice in Corpus Christi and wanted me to go to Kingsville as a senior reservoir engineer.” My wife and I made the decision to go to Kingsville, but this was not to be the last time that Aramco would enter our lives— not by a long shot.

Controversy over Venezuela’s Tar Sands Meanwhile, little did we employees of JPR know that our work and research on tar sands would lead to a major dispute between Exxon and the government of Venezuela 50 years later. But that’s exactly what happened when Venezuela’s President Hugo Chavez announced in 2008 28

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that oil companies that had been investing in the Orinoco deposits would have to increase their royalty payments to the government to 60% from 40%. This sort of decision is one of the dilemmas that international oil companies face: contracts that cannot be considered secure when new leaders take over a country. Exxon claimed it had invested $2 billion, but when it demanded compensation for the takeover, Chavez reacted by kicking Exxon and ConocoPhillips out of the country. At the time, the total production was 600,000 b/d. Then Chavez invited other companies to assume control of the operations of Exxon and ConocoPhillips. That eventually resulted in Venezuela approving two new joint ventures aimed at adding 800,000 b/d of production from the Orinoco, with the government taking a 60% royalty. The irst joint venure (JV) was between Venezuela’s stateowned Petroleos de Venezuela SA (PDVSA) and various international oil companies, including Respol, Indoil, and Petronas. The second JV was between PDVSA and Chevron, Impex, Mitsubishi, and Suepelopetro. Exxon ired back by requesting courts in the US, the Netherlands, and the Netherlands Antilles to freeze $12 billion in assets of Venezuela. Chavez retaliated by cutting off exports of PDVSA’s crude oil to Exxon, amounting to about 5% of the US irm’s crude supply. In 2010 Venezuela reported that its proved reserves as of yearend 2009 were up 23% to 211 billion bbl, primarily due to the addition of 39 billion bbl from the Orinoco heavy oil belt. The United States Geological Survey later put the OOIP—not reserves—at 513 billion bbl. What a difference 50 years makes, as well with oil priced at $90/bbl.

Controversy over Canada’s Tar Sands, Too Another dilemma has arisen over Canada’s Athabasca tar sands that we studied at JPR. Those deposits are mainly in Alberta, but some also extend into the western edge of Saskatchewan. In heavy oil ields, steam stimulation and steam drive are now utilized together with horizontal drilling. Some 1.5 million b/d have been added to Canadian supply from heavy oil production through mining and thermal applications such as steam stimulation and steam drives, many now also using horizontal drilling. Some estimates put Canada’s supply at 2.55 million b/d by 2015 (ig. 1–3). 29

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Fig. 1–3 Canadian tar sands and heavy oil production forecasts. Courtesy Raymond James Energy. Background forecasts as reported by The Oil Drum.2

The importance to the US of Canada’s Athabasca Tar Sands and steam-assisted heavy oil cannot be denied. But critics abound. Consider an article from the June 28, 2010, edition of the Houston Chronicle, which starts by stating that, “From the ranches of East Texas to Capitol Hill, folks suddenly have the jitters about a proposed pipeline that would bring Canadian crude to the reineries of Houston and Port Arthur.” The pipeline they’re referring to is the Keystone XL, and the story goes on to explain that the $7 billion project “would increase America’s access to crude from Canada’s tar sands.” Then comes the view of critics that “oil lowing through the 2,000-mile pipeline would come with a high environmental toll, leaving behind toxic sludge ponds and destroyed forests while producing large amounts of gases linked to climate change.” The story tells readers that “ranchers also worry about the possibility of groundwater contamination.” If true, what about the thousands of miles of pipelines in America already? The alternative is for the Canadians to sell the oil to the Chinese, who are already buying up tar sand properties. The story cites Matthew Tejada of the advocacy group Air Alliance Houston, who said, “This isn’t a hard thing for people to understand. We’re picking up Canada’s trash and dumping it in Texas.” 30

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My response is that the pipeline will help ensure that Mr. Tejada will have gasoline to run his car from one of the most secure sources of oil possible for America. But criticism of this project does not end there. The proposed Keystone XL Pipeline (ig. 1–4) eventually attracted the attention and concern of the Environmental Protection Agency (EPA). One high-level EPA oficial said that the pipeline doesn’t adequately evaluate potential health impacts on minority communities near the Port Arthur reinery where some of the crude would be  processed. Such remarks relect frequently expressed views of EPA Administrator Lisa Jackson that minorities and poor people have historically not had a say on decisions such as these that continue to have a direct impact on their health and quality of life.

Fig. 1–4 Proposed Keystone Pipeline. Courtesy Raymond James Energy.

Does Jackson not realize that construction of the pipeline will provide thousands of jobs to the minorities and poor along its route as well as in the Beaumont, Texas, area, which at the time had one of the highest rates of employment in the state, at 11%? One of the reineries to receive the crude is owned by Motiva, which itself is 50% owned by Saudi Aramco. The Saudis have already committed to spending $2 billion to expand this reinery. It has been permitted, and is being constructed. But what kind of message are we trying to send to the Saudis with our dithering over the Keystone 31

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project? Secretary of State Hillary Clinton, whose department has control over approval of the pipeline, reportedly said that she “was inclined to approve the project.” Yet in a news conference with Canada’s Prime Minister Steven Harper, President Obama dismissed the Keystone project after the Canadian raised the subject. The US could beneit from the import of this resource (ig. 1–5).

Fig. 1–5 Canadian production and exports to the US

Secretary Clinton then wafled in testimony before the Senate Appropriations Committee, saying that she was “reluctant to express an opinion on the project.” Clinton said she was “generally supportive of receiving more oil from Canada” but also mentioned “the importance of the US doing more in energy eficiency and renewables and looking for clean ways to use our own resources as well.” What kind of double talk is this? The Chinese love it. They would like to capture this oil. America had better get busy and put Americans to work when it comes to energy supplies.

Notes 1. V.V. Valleroy, Willman, B.T. Campbell, J.B., and Powers, L.W. July 1967. “Deerield Pilot Test of Recovery by Steam Drive,” Journal of Petroleum Technology, Volume 19, No. 7, 956–964. 2. Raymond James, Weekly Energy Report, Apr. 19, 2010; and “The Oil Drum.” http:// www.theoildrum.com/.

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H

umble’s production district in Kingsville, Texas, was one of the irm’s most active at the time, drilling more than 300 wells per year.

Figure 2–1 shows the approximate boundaries of the District, along with the oil and gas ields. Red stands mainly for gas and green mainly oil. The District area basically covered the region from Corpus Christi southward to the Rio Grande along the US-Mexico border. The District encompassed several large spreads, such as the 800,000-acre King Ranch, as well as the 50,000-acre Armstrong Ranch, located in the center of the King Ranch. There were many others, including East Ranch, Santa Fe Ranch, Kenedy Ranch, and the Mrs. S. K. East Ranch. Most of the leases were held by production under the original lease terms signed many years earlier.

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Fig. 2–1 The Kingsville Production District included several large ranches in South Texas.

Carl Peters was the Kingsville district manager. His primary job was to work with large ranch owners and to maintain good relations with the large leaseholders. The assistant district manager really ran the day-to-day operations, and it had been a good training position for many of the top management at Humble, which later became ExxonMobil. At that time in Kingsville, the assistant district manager was Jerry Bullock, a very knowledgeable man who I would later work for again at Humble’s headquarters in Houston.

District Reservoir Engineer This was a busy time for engineers and geologists, and a great time for learning for this petroleum engineer. I had a lot to learn. I was one of the few from research who had been transferred to a production district at 34

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that time, and several more followed. After about a year, I was promoted to district reservoir engineer in charge of one of four Reservoir Groups: North, South, Three Field (Borregos, TCB, and Seeligson). There was also a natural gas group that primarily worked on ields supplying gas to the 2-billion-cubic-foot-per-day (Bcf/d) gas plant located on the King Ranch, west of Kingsville. I was able to be involved in the installation of many water loods to maintain pressure and increase ultimate oil recovery. These were primarily in the Kelsey ield where Humble still had an operations camp, but no engineers. During this process, I learned a lot about reservoir heterogeneity. Sometimes we found that wells were completed in isolated lenses because of faults or other impermeable barriers. After injection of water, the maps sometimes had to be changed to it the low patterns we found. On balance, in spite of this, most of the water loods were very successful. In these permeable reservoirs, we would generally inject down dip and move the oil to the up dip producers similar to the pressure maintenance programs I later found in Saudi Arabia.

Interlude in Houston Shortly after being assigned to the South District Reservoir Group, I was summoned to headquarters in Houston to represent the District at a meeting called especially to discuss Humble’s operations on the 50,000acre Armstrong Ranch. The Armstrongs by marriage were also mineral owners on the King Ranch, and they were concerned about not getting their share of the exploration development wells drilled. As a result of complaints about the lack of drilling by Major Armstrong, Mike Wright, the chairman of the board, organized a special task force comprised primarily of geologists and geophysicists. I was given an opportunity to review the study. But on the day of the meeting, I was just to observe— unless there was a question asked about District operations. Major Armstrong used to go to the ield and visit with the pumpers. He knew exactly what was going on in the ield. Humble CEO Mike Wright opened the meeting, and asked for the presentation. The main conclusion was that the Armstrong Ranch had been fully explored, and the geologists concluded that the potential for additional drilling was not as good as drilling on the King Ranch. At that time, Exxon had a policy of drilling no more than one gas well per 640-acre unit. 35

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Meanwhile, I stayed quiet—except for having a terrible cough. Someone pointed to the tray in front of me where candy was kept, along with some cough lozenges. I was quite impressed: about 20 of Humble’s top management, engineers, and geologists were on the 42nd loor of the Humble Building. At the end of the meeting, Mike Wright asked a critical question. The major had complained to him recently, asking, “Why was production cut in half the last two weeks?” All eyes turned to me. I wanted to crawl under the table. I then said in a hoarse voice: “As a result of this major review, one of my engineers took a look at how much we were producing from all of the ields into one of our major gas sales. He found we had been overproducing the Armstrong Ranch related to their reserves compared to our other ields and mineral owners, and I felt it my duty to cut back the Armstrong sales. At that time, there was surplus gas deliverability in the country compared to demand. In response, the ield operating personnel had done just as we had asked them to do, that is, cut back the Armstrong Ranch lease and reallocate the demand to all leases in the sale on a ‘ratable take.’ ” The room got very quiet, and then Mike Wright said, “Son, you did just right. But next time, would your hand be a little slower on the throttle, particularly when we are getting ready to have a major meeting at the request of the mineral owner?” I headed back to Kingsville feeling that I had done the correct thing.

Back to Kingsville Never in my 21-year history with Humble, Exxon, or Aramco do I recall any of my supervisors asking me to do anything illegal or morally wrong. When certain rules or laws had two interpretations, we obviously took the one most beneicial to Exxon. I think this goes contrary to a lot of public opinion and that the criticism of the major oil companies, at least for Humble at that time, was not justiied. However, Humble did operate under a “Goals and Objectives” program which caused certain Exxon employees to operate in an unethical manner. This tended to cause some employees to understate their goals. It was up to management to correct this.

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There were times when I observed employees violating certain Texas Railroad Commission (TRC) rules in order to meet their production goals. Based on Humble management that I knew, if they caught the employees violating the rules, they were disciplined. One day, management announced to the engineering supervisors that the District would be entertaining a group of dignitaries from Houston and New York. We were not involved in any meetings, but they would be coming by our ofices. We were expected to be in our ofices at the appointed time. When the group came down the hall, I immediately recognized Max Sons from my Venezuela days. He said, “Well, if it isn’t my old Quiriquire buddy. I had lost track of where you were.” I was not sure it was a good thing he had found me. But it apparently had little affect on my career. Overall maybe Quiriquire had helped rather than hurt. Who knows? Borregos was one of the largest ields in the district and Humble USA, producing more than 15,000 b/d with more than 50 separate reservoirs. It was located a few miles west of Kingsville, the location of the large 2-bcf/d King Ranch gas plant. As the Borregos ield began to decline, we were looking for a way to boost production. That is how we got our merit raises: by raising the District revenue. At that time, 1965–68, no one at Exxon was forecasting increasing oil prices. Production levels were controlled by the TRC, which helped keep prices from sinking too low. There were three ways to increase your proits: cut costs, drill more wells, or increase your production levels through hearings at the TRC. We learned that the TRC would permit us to combine all 50 or more reservoirs into one after a proper hearing to prove the combination would not promote waste. After the ruling by the TRC, the ield allowable was set based on the sums of the previous allowable, and then the oil could be taken from any reservoir or completion. Production peaked in 1967 at about one million bbl per month or 33,000 b/d, more than twice the 15,000 b/d three years earlier. This was a major undertaking by several engineers in the Kingsville District; Leroy Hand along with Bill Boyd were instrumental in accomplishing this task. Once the ield started to decline, it was fast, at some 30% per year. While our merit raises were tied to the revenue generated, it was a little tough on those who followed. 37

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A day that I will never forget came at a morning meeting just after Hurricane Alan blew in at Raymondville, followed Highway 77 to the south of Kingsville, and then turned to the northwest with the center crossing over the King Ranch Gas Plant before it headed inland. Hurricane Allen dumped 20 inches of rain in Kingsville and the surrounding ranch area. Swamp buggies were brought in from Houston, and they were the only way you could get around the looded ranches. When the storm blew in, Humble was drilling two 15,000-ft high pressure gas wells south of Kingsville. Before a storm, the drillers were always sure the pipe was in the hole to keep the derrick from blowing over. The meeting was held in Jerry Bullock’s ofice. We were trying to get back into operations after the storm. When it came time for the morning drilling report, it was revealed that the rig crews were having a bit of trouble getting back to drilling at the two deep gas wells. Just before they had run the pipe in the hole, they had just cemented a production liner in both wells. When they igured the top of the cement in both wells, they miscalculated and put the drill pipe into the cement before it was set up. As a result, the drilling superintendant reported that both wells were stuck. Before Hurricane Allen blew in, the drilling crews on both rigs had pulled the drill pipe up out of the cement—or so they thought. Sure enough, both wells had the drill bits stuck in the cement. Jerry’s comment was “Egads!” or something like that, and he started to pull the rest of the hair out of his prematurely balding head. The room went deathly silent before the drilling superintendant started to explain how this could happen. I worked for Jerry Bullock twice, and he was a real gentleman. But I knew he could get excited.

The Deep High-Pressure Frio Pay Toward the end of my irst tour in Kingsville, I was assigned to a special project to study the problems we were having completing some high-pressure wells in the deep Frio pay 14,000–15,500 ft. Several had blown out. The production from a few wells completed depleted very fast. Fred Perkins, the division manager in Corpus, would be in charge of the study. I along with a drilling engineer named Bob Hicks and a geologist named Jerry McQueen would make up the team. 38

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The bottomhole pressures were tremendous, 9,300 psi at 10,000 ft in this overpressured reservoir (normal pressure would have been only 4,300 psi). One of our questions concerned the permeability of the rock. It was expected to be less than 1 millidarcy (md) or very low. It was decided to twin two wells that had been lost after encountering the high pressures. Both wells were to be drilled only 200 ft from the lost, plugged wells at the surface. One was to be drilled in the Sarita East Deep Field, and the other in the El Paistle Deep ield. This was my irst exposure to the Sarita East Deep Field, but this ield would have a signiicant impact on my business life for the rest of my career. The irst well was in the Sarita East Deep ield (ig. 2–2). The objective was to twin the B16 well which had been lost only 200 ft away. Even though the pressure was high, with extreme care we could actually core the well. Extremely high-density mud was used to control the well pressure. When the well reached the coring point, a core barrel was installed and the drillers pulled 60 ft of core that was immediately sent to the lab for analysis.

Fig. 2–2 B-18 Electric log from Sarita East Deep ield

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To everybody’s surprise, the core had 40 md permeability, which meant the ease to produce was some 40 times more than expected. One of our objectives was to match the logs to the cored data, but the logs were not to be run until the well reached total depth. Since we were still in sand, the team decided to take another core. That turned out to be a mistake. After cutting the second core, apparently when it was being pulled, the core barrel served as a swab, and they were in danger of losing control. The next report was that the drilling crew had to leave the core barrel in the hole, and they had set a cement plug back up the hole and began sidetracking around the stuck core barrel. Fortunately for the team, the bit somehow got back into the old hole after the sidetrack, and we got the log we needed to correlate with the irst core. The porosity or amount of pore space as a percentage of rock was much higher than expected at 26%–29%. This compares to 20%–21% and even 17% for the tighter rock found in much of the deep high pressure sands. The second well we were trying to core was Risken No. 2, another 200-ft offset to the Risken 1 in the El Pastile Deep Field. The geologists called it the coring point. We cut the core, and we got 60 ft of shale, but no sand. How could this be? Another learning point: reservoirs go where they are laid down, not necessarily where the map shows. Sometimes unknown faults cause the same problem. Our team requested another core. Drill ahead until you hit sand, and then run in the core barrel. W.D. “Bill” Stevens, the new assistant district superintendent and later president of Exxon USA, said, “No way.” We then persuaded Fred Perkins, the Corpus division manager, to enter the fray. He asked Bill if there had been any trouble taking the irst core. Bill said, “No, other than there was no sand.” Perkins then ordered him to do “as the team had requested.” Our team accomplished the objective of getting two cores to correlate our logs. Some of the deep sands we penetrated were tight, and no one could predict when that would occur. Each deep well in the future would have to be managed with caution. New completion procedures requiring larger intervals would be required for the tighter sands, and perhaps fracing would be required. But change was coming to me and my family. We were on our way to Houston for two different assignments: one at the Headquarters Production Ofice and the other at the East Texas Division. 40

3 AT HUMBLE’S HOUSTON HQ

I

was sent to Humble’s production headquarters in Houston to ill an opening in the Production Headquarters

Planning

group.

Before

I

departed Kingsville, Assistant District Manager W.D. “Bill” Stevens’s last comment was, “Just remember, a headquarters assignment, after the work in the District, will be long periods of deep depression mixed in with a few peaks of adulation.” Boy, did Bill ever hit the nail on the head! Times were indeed quiet on the 19th loor of the headquarters building. At the time, Humble’s chief petroleum engineer, Harold Wright, had just taken a month’s sick leave, and my planning manager was gone on three weeks’ vacation. I recall looking for something to do. Emmet Wells and Dale Woody, who had backed me over my Venezuelan report, were the two operations managers. Jimmy Postgate, Humble’s vice president of production, occupied the corner ofice on the 19th

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loor. My irst month was spent mostly in the corporate planning library reading magazines. I wondered what the hurry was. I sure remembered Bill Stevens’s words about the job I was coming to. This was one those periods of depression.

My Thinking Prevails That month I even had an opportunity to answer a letter of my own, one I had written to headquarters when I was in Kingsville. Dale Woody brought it to me and asked me to prepare a response for the South Texas Division. The essence of the original letter was that the Division’s Kingsville District—instigated by one of my engineers—wanted to drill a second well on a 640-acre unit. At that time, the company rule was one gas well per 640 acres. Humble had a man at headquarters named Frank Homsely whose job was to carry out and enforce that policy. The objective was to save money and not drill too many gas wells. However, from my experience in the Kingsville District, I had learned that gas wells there often would not drain 640 acres due to barriers, faults, and other geologic phenomena. To me, whatever made economic sense should be drilled, and in my draft response back to the South Texas Division, I proposed that they drill whatever wells they thought made the required rate of return. The 640-acre rule was costing Humble money. Reservoirs were not homogenous. Dale Woody agreed, and he sent my response to the Division. Homsely threw a it when he came back. Ultimately, though, my thinking prevailed, and Humble changed its long-standing rule of spacing no more than one well for every 640 acres. Next, I remember headquarters learning that the great Borregos ield in the Kingsville District was on a 30%-per-year decline (ig. 3–1). Dale Woody and Harold Wright both came into my ofice at different times wanting to know what on earth was going on in the Kingsville District. They had learned about the sharp decline in late 1966 and early 1967. Both had worked in Kingsville, and Woody was upset. I told them about our ability to accelerate the rate of production—and substantially so—through a change in the ield rules. But, then, when your ield is producing with only two or three years of reserves left, you have to expect a sharp decline. 42

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Fig. 3–1 Production history of Borregos ield through 2009

For example, when a ield goes on a decline and it has 10 years of reserves left, you can expect a decline of around 10% per year. This might be for a tighter reservoir rock. But for more permeable reservoirs, such as the Borregos reservoir rock, with the number of wells drilled you could have a 30% ield decline, when the reserve life is only three years at the rate of production. I’m not so sure I convinced Woody and Wright, but I did my best. At that time, in August 1968, we had had only a few months of the 30% decline, and they just could not believe that Borregos could go on such a steep decline. From an economic standpoint, if you are in a supplyconstrained environment, accelerating production is not always the most proitable thing to do—much like the dilemma the Saudis are in now as the world’s consuming countries press for more and more oil supply. But we’ll have more to say on that in later chapters. Meanwhile, I got involved in drafts of several speeches for Humble Vice President Jimmy Posgate and in providing him the backup. Fortunately, I had my writing training at JPR, which helped immensely. But I still had to redraft several times to get it the way he or others wanted it. Harold 43

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Wright, Dale Woody, and Emmet Wells made up the committee that really controlled the career paths of engineers at Humble. So, I would come out of there a winner or else. Jerry Bullock became the planning manager who I reported to, and Harold Wright eventually came back from sick leave. Things began to pick up. Harold Wright was always thinking of new ways for Humble to make a proit, although he was not always able to convince the Humble board of directors. One time when oil was $2–$3/bbl, I remember Harold wanting to buy out all of the other operators in the East Texas ield. He knew oil was going up, but not everybody on the board agreed. Dale Woody was something else, a bit more lamboyant. One time I was sitting in Jimmy Posgate’s ofice along with Woody. I don’t recall the subject, but I do recall Posgate picking up the book titled The Rational Manager, throwing it at Woody, and telling him to go back to his ofice and read it. Woody was still full of ideas and ready to form a task force at any moment. During the Borregos discussion, I think he had it in mind to form a headquarters task force to help arrest the ield’s decline. But from my irst meeting with him on my return from Quiriquire in 1964, I always knew that Woody supported me.

The Prudhoe Bay Discovery With 23 billion bbl of original oil in place (OOIP), Prudhoe Bay is the largest USA discovery since the East Texas ield in the 1930s. The oil column was more than 400 ft thick, and it contained a huge gas cap of more than 40 trillion cubic ft (tcf) of natural gas reserves. I was working in headquarters when the Prudhoe Bay ield was discovered in 1968, and we spent some time working on the initial planning. The ield is located 400 miles north of Fairbanks, 650 miles north of Anchorage, 250 miles north of the Arctic Circle, and 1,200 miles from the North Pole—all in all, a rather inhospitable location. Atlantic Richield (ARCO) and Humble were 50-50 owners in a large number of acres. Sohio, later bought by BP, was the other major owner, along with several other companies that had small interests. ARCO and BP were both operators until ARCO’s interests were purchased by ConocoPhillips.

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The Trans-Alaska Pipeline (TAP) transports the oil from Prudhoe Bay on Alaska’s north coast to Valdese, the shipping port on its south coast (ig. 3–2). Originally, TAP’s capacity was 1.6 million b/d. But the addition of viscosity reducers, an ARCO contribution, increased throughput to 2.0 million b/d, as other ields on the North Slope became connected to TAP. While BP later got a black eye in the 2010 Gulf of Mexico accident, at Prudhoe Bay it has done an excellent job of developing the largest discovery of conventional oil in North America. There have been a few problems with corrosion, but BP and Humble have done a great job of managing this large ield. It took some 10 years and $9 billion before the pipeline to Valdez was completed. At the time of discovery, Humble’s estimate for the line was—as I recall—only $900 million. Government delays and environmental restrictions were a big part of the extra costs— as they always seem to be.

Fig. 3–2 Trans-Alaska Pipeline

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The initial plan for the Prudhoe Bay Field called for a four-to-ive year development time. Ten years later, the ield was put on production at 1.6 million b/d. All of the equipment was built in the US, and the project employed thousands of workers. Higher oil prices, new technology, and an excellent technical staff were able to increase reserves in the Prudhoe Bay ield by 39%–47% over the original amount of reserves estimated (ig. 3–3). Ultimate recovery from this giant ield is now projected to be 59%–61% of the OOIP. This growth in reserves for a large ield is not unusual, and as we shall see later it also has happened in the Saudi ields, too.

Fig. 3–3 Production history for the Prudhoe Bay ield. Source: Alaska Department of Natural Resources.

Other tools used by engineers and geologists include: •

46

Taking cores from 100 of the irst 400 wells drilled to develop a good geologic model of the ield. Some were cored in oil-based mud to get good initial water saturations.2

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•

Inill drilling. Initial development was on 160-acre spacing; now the spacing is down to 20–40, and more than 2,000 wells have been drilled.

•

Horizontal drilling, which is being applied to capture undrained oil for particular strata. In some cases, J-hook horizontal wells are being employed as injectors to drive upswept oil to producers. These upswept areas are being located in what are called 4D seismic surveys.

•

Miscible luids, which are injected in some of the injection wells to increase the recovery over and above what straight water would recover the operator. British Petroleum is currently using seawater and investigating the use of a different water to sweep the oil more eficiently.

•

Stripping condensate out of the gas that is produced and returned the lean gas to the reservoir. The Prudhoe Bay ield has a large gas cap of 45 tcf that will someday be piped south for domestic use. At current gas prices of $2.30 per million British thermal unit (MMBTU), the pipeline continues delayed.

The example of Prudhoe Bay reinforces my position that many other large ields in the world, such as those in Saudi Arabia as we shall later see, are not about to go on a decline as many of the pessimists would have you believe—at least as long as political stability is maintained. A point of interest is that the politicians in Washington, controlled by the environmentalists, have allowed TAP to remain underutilized for more than 25 years because of the ban on the Arctic National Wildlife Refuge (ANWR) where lies a potential 15–30 billion bbl of oil, shown in igure 3–4. What a travesty for the American people and for oil consumers around the world with 1.4 million b/d of pipeline capacity available at this time (ig.3–5). Maybe BP’s Gulf of Mexico blowout tragedy will cause the US Senate to wake up and allow exploration and development of ANWR and create thousands of jobs at the same time. Recent studies from Alyeska Pipeline Company suggest a new problem: if pipeline low drops below 500,000 b/d, problems may begin to develop, and at 350,000 b/d the pipeline may have to be shut down due to ice forming in it.2

47

Fig. 3–4 Alaska National Wildlife Area banned for petroleum development.

Fig. 3–5 Total Alaska North Slope production. Source: Alaska Department of Natural Resources.

CHAPTER 3

AT HUMBLE’S HOUSTON HQ

I Become Division Reservoir Engineer In Houston, my new position as division reservoir engineer required a lot of work, which I enjoyed very much. Humble’s East Texas Division contained some of the big oil and gas ields that made billionaires of many of the early oil pioneers.4 Fortunately, Humble had a large position in many of these ields, most of which were discovered in the early 1930s and during World War II. The division manager was John Bell, an old timer near retirement. Bert Crowder, another long timer, was the assistant division manager. Another gentleman with a large responsibility was Mark Krause, joint interest manager, in that unitization efforts were a prime emphasis in the Conroe, Hawkins, and Webster ields. Jim Flatt was the East Texas division engineering manager. At the division engineering level, we had four groups reporting to Flatt: production engineering, gas engineering, civil engineering, and reservoir engineering. The East Texas Division reservoir engineering had two groups for coordinating the ive District reservoir engineering groups of each district: Tyler, Beaumont, Goose Creek, Katy, and Tomball. Headed by Joe Richardson, one of the most expert reservoir engineers I have known, we also had the Major Field Study Group (MFSG). That group was conducting special reservoir studies on three of the four big oil ields—Hawkins, Webster, and Conroe—prior to the unitization projects that were being implemented. The irst thing I did was to organize trips to the ive separate districts to become familiar with the people, their mode of operation, and surveillance of the reservoirs. With the assistance of my right-hand men, Richard Hickman and Charlie Parr, I implemented what later became known as Systematic Reservoir Management (SRM) reviews. We gave the ive districts a few months to prepare, and then scheduled reviews at each one, including presentations and written reports. SRM signiicantly improved each district’s ability to react to changing conditions and to hand over information to new people, enabling them to become familiar with a particular ield or reservoir.

49

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Notes 1. Information provided by Ed Holdstein, former ExxonMobil enhanced oil recovery manager. 2. Ibid., and Alaska Department of Natural Resources. 3. Alyeska Pipeline Service Co. 2007. The Facts: Trans Alaska Pipeline System. 4. Burrough, Bryan. 2009. The Big Rich: Rise and Fall of the Greatest Texas Oil Fortunes. New York: Penguin.

50

4 EAST TEXAS’S MAJOR OIL AND GAS FIELDS

I

n this chapter I outline the major oil ields of the East Texas Division and the development projects I worked on, including the East Texas

Oil Field, Hawkins Oil Field, Conroe Oil Field, Webster Oil Field, and Katy Gas Field. These were some of the largest ields in America prior to the discovery of Prudhoe Bay in Alaska. My work on these ields was crucial to my understanding and development as a petroleum engineer—experience that would later lead to my appointment in Saudi Arabia as chief petroleum engineer of Aramco.

The East Texas Oil Field The East Texas Field, discovered in 1931, was the largest US oil ield prior to the discovery of Prudhoe Bay. The East Texas ield was the ield that Harold Wright had tried to convince the board to purchase 51

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other working interest positions in (ig. 4–1). During my time in the East Texas Oil Field, major hearings were held in Austin to determine its most eficient producing rate. Engineer Ron Lohec handled this hearing for Humble. Because of its long history, no attempts were ever made to unitize this ield. It was a long-standing practice to produce this ield on a lease basis, and the operators formed a water-disposal company to reinject the water to the lanks of the ield to supplement the natural water-drive.

Fig. 4–1 (Left) Key oil and gas ields in Humble’s East Texas Division. (Right) the East Texas Oil Field

The East Texas Oil Field, which encompassed 140,000 acres, has had more than 30,340 wells drilled with an ultimate spacing of 4.6 acres per well. The reservoir was found at a shallow depth of 3,100–3,300 ft, and the trap was formed by a pre-Austin Chalk unconformity to the East.1 The sands were very permeable, ranging from 1,000–3,000 md. Production during the last 53 years is depicted in igure 4–2. Note that the ield is nearly depleted, although it is still producing 10,000 b/d with a very high water-oil ratio of 50 bbl of water for every one bbl of oil. The 50-year production history of the East Texas Oil Field is shown in igure 4–2. Note that since discovery, this ield has produced more than 52

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EAST TEXAS’S MAJOR OIL AND GAS FIELDS

5.43 billion bbl of oil—74% of the original 7 billion bbl of OOIP. The ield has a strong water-drive with water reinjection down dip.

Fig. 4–2 The 50-year production history of the East Texas Oil Field

Figure 4–3 illustrates cross sections from the same study. Note the massive section on the down dip, or west side of the ield, breaking in to more stringerized sands on the east side. This was one of the major surveillance projects for the Tyler District Reservoir Engineering group, making sure all of the deeper stringers were effectively drained. Figure 4–4 shows an example of the deepening activities undertaken at that time. 53

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Fig. 4–3 North and south cross sections, east to west, from East Texas Field

Fig. 4–4 An example of the deepening activities of the East Texas Oil Field2

Many of the wells drilled in the 1930s were drilled only to the top upper sands, and later after perforating guns were invented, the wells were deepened and a liner run and cemented in place. 54

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EAST TEXAS’S MAJOR OIL AND GAS FIELDS

Early on, the East Texas Oil Field operators formed a cooperative water disposal and reinjection program, and they have traced the water movement over time. Figure 4–5 shows the advance of the water from 1951–93.

Fig. 4–5 East Texas ield water advance over a 50-year span3

Hawkins Oil Field Studies by Joe Richardson’s MFSG indicated that gas injection would result in a signiicant increase in reserves compared to continuing the natural water-drive. The plan was to inject lue gas (the combustion product of burning natural gas), stop further water inlux, and displace the remaining oil column with gas. Flue gas injection was later replaced by nitrogen injection. This plan would require unitization of the ield to protect the rights of all owners. Unitization in Texas required, essentially, a 100% agreement of all owners, quite a challenge considering that there were more than 2,000 operators and royalty owners. 55

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Mark Krause, as joint interest manager, was in charge of this unitization effort that included help from the MFSG for technical support, land men to contact the various owners, and the regulatory group and lawyers to assemble a presentation to the TRC. Operating plan development, including in-house management approval, required more than two years of study by engineers and geologists. Obtaining approvals by owners and the state required just 18 months, quite an accomplishment by the team. Part of the original study indicated that there was the potential of even more recovery by using gas to displace water from water-invaded portions of the oil column so that the residual oil could be remobilized and produced. Figure 4–6 shows the complicated structure of the Hawkins ield. The faulted nature and structure are the result of deep-seated salt zones which have grown over time. The east side of the major fault, shown as shaded in the igure, had a strong water-drive. In the western side of the fault, a tar zone existed in the northern and southern portion of the oil column. Some reduction in pressure occurred before water broke through the northern tar zone, providing water-drive recovery. Water encroachment did not occur in the southern area, which caused some problems with the skewing of the gas cap to the south as oil was produced.

Fig. 4–6 Hawkins Dexter sand structure map4

56

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Figure 4–7 illustrates the log section with numerous sand zones that appear in the Lewisville and Dexter Sands. The original oil column was 280 ft thick. The oil gravity was 24.2°API and the viscosity was 3.7 cp, compared to the lighter, less viscous oil at found in the East Texas Oil Field. Later in the life of the Hawkins ield, the viscosity increased to an estimated 15 cp as some of the heavier oil near the base of the oil column was pulled up. The Hawkins ield was initially developed on 20-acre spacing. However, inill drilling even in the later stages contributed to increased ultimate recovery.

Fig. 4–7 Log structure of Lewisville and Dexter sands5

The Dexter Sands contain the majority of the OOIP. Their high permeability of 3,400 md and structural dip of more than 5 degrees are the factors that make oil recovery by gas injection better than water displacement as described by Joe Richardson and the MFSG. The original plan to displace the remaining oil column with gas has been expanded to a double displacement process where nitrogen is injected to displace oil from water-invaded sections of the original oil column and remobilize the resident residual oil. ExxonMobil has recently announced a plan to spend $340 million on the double displacement process that will recover an additional 40 million bbl of oil. Ultimate recovery is now estimated at 920 million bbl or 71% of the 1.3 billion bbl of OOIP. This is a high recovery for a complex faulted multi-sand ield, 57

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proving the excellent reservoir management over time that Exxon has applied. Figure 4–8 shows the production history for Hawkins Field.

Fig. 4–8 Hawkins ield production history

Conroe Oil Field Conroe Oil Field was the second major ield under study at the time, another highly faulted dome north of Houston. This study was headed by Bob Whitson, a senior and highly respected Exxon engineer. The Conroe Oil Field was also highly faulted like the Hawkins Oil Field. 58

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From the time of its discovery in 1937, Conroe by 1975 had produced 500 million bbl of oil by a combination of water and gas cap drive.6 Figure 4–0 shows a three-dimensional model of this ield. The major problem determined by the study was that the gas cap was losing gas to the overlying upper Cockield gas sands as they were being produced to meet gas supply. This seepage was allowing oil to move into the gas cap with a possible loss of 40 million bbl of oil unless some remedial action was taken. Figure 4–10 shows a log section of the Conroe Cockield oil sands and the upper Cockield gas sands.

Fig. 4–9 Structure map of the Conroe ield

59

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Fig. 4–10 Conroe Cockield oil sands logs and the upper Cockield gas sands7

A temporary solution was to increase the oil production and then to unitize the ield so oil could be taken from where it was optimum, independent of lease equity considerations. A large effort was made to convince the leaseholders and to get Texas Railroad Commission approval to allow unitization and to increase the Conroe ield allowable. The 30-sq-mile ield was developed on 20-acre spacing with more than 1,100 wells, back in the 1930s. Most were completed openhole at about 5,000 ft. Later liners were run and cemented, and then the individual sands were perforated for better control. In the 1970s, prior to unitization, the ield had 27 operators with 150 leases, a seemingly insurmountable task. But under the guidance of Mark Krause and Joe Richardson’s MFSG, the mission was accomplished. As shown by igure 4–11, Conroe’s cumulative production from the 1930s has amounted to 734 million bbl. Its recovery to date is 56% of the 1.3 billion bbl in place. Note that the water-oil ratio is 88 bbl of water 60

CHAPTER 4

EAST TEXAS’S MAJOR OIL AND GAS FIELDS

per bbl of oil, which has to be near the economic limit even at $80/bbl oil prices. Also note the large increase in gas production in 1999–2000 when the operator and the other joint interest owners decided to deplete the gas cap. During this time, frame gas production reached a peak rate of 174 million cubic feet per day (MMcfd). Instrumental in this was Bob Whitson, who was rehired by Exxon after retirement to continue providing guidance to the younger engineers and to apply his expertise to the major ields of Conroe and Webster, the next ield to be discussed.

Fig. 4–11 Cumulative production from the Conroe Field, 1930–2010

In December 2009, Denbury Resources, Inc., said it acquired 95% of the Conroe Unit and planned to inject carbon dioxide to increase ultimate recovery by 125 million bbl or 9% more of the OOIP. Denbury 61

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planned to spend between $750 million and $1 billion to redevelop the Conroe ield for CO2 injection. Denbury will get their CO2 from their Green Pipeline which runs to Houston from the irm’s Jackson Dome carbon-extraction facilities in Mississippi. Denbury expects to boost production to 15,000 b/d from 2,500 b/d. Based on my experience with CO2 looding at JPR and as an independent consultant, however, I suspect the additional recovery estimated by Denbury for this 80-year-old oil ield is optimistic, particularly since the ield has already recovered 56% of the OIP. The communication with other reservoirs in this highly faulted ield is well-known fact. Also, there is an additional risk as this ield is in a rapidly growing residential area.

Webster (Friendswood) Oil Field The Webster Oil Field, also known as Friendswood, is located 30 miles south of Houston. The Webster Oil Field, a bit smaller than Conroe Oil Field, is still a substantial reservoir, containing 900 million bbl OOIP.8 The trap is similar to Conroe: faulted, with a gas cap, and about 6,000 ft deep. Webster was discovered in the late 1930s, and it contributed strongly to the World War II oil supply. Figure 4–12 plots Webster’s production history through 2004. Note that this plot uses a linear scale in million b/d as contrasted to the other plots in this report that were obtained from a commercial source, which uses logarithmic scales, million bbl/month. Initially, Webster was also developed on 20-acre spacing, and it had about 200 mostly openhole wells, that is, wells drilled to the top of the formation. Screened liners were then installed to prevent sand low, and these were later replaced with cemented liners where the individual sands could be perforated. After unitization, the ield was inilled to 10-acre spacing or 400 wells, with numerous stringers that were unitized in the Webster Unit. The reservoir rock was unconsolidated with permeability of 300–1,000 md. The 29oAPI oil had a viscosity of about 1 cp. As shown in igure 4–13, the structure of the Webster Oil Field is highly faulted, like the Conroe and Hawkins ields. The Webster Oil Field had a strong water-drive in the east fault block, a moderate-tostrong water-drive in the west fault block, and a moderate water-drive and gas cap expansion in the southwest fault block. 62

Fig. 4–12 Webster production history from 1937–20049

Fig. 4–13 Structure map of Webster Field, Frio 1B—sand with original luid contact10

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The unitization project that was accomplished was a major undertaking for Mark Krause and the MFSG. Prior to unitization, there were 52 individual leases and 660 mineral owners. Unitization was a ive-year effort, lasting from 1969 to 1973. Figure 4–14 gives a good view of the overall management scheme, while igure 4–15 shows the history, with recovery of 599 million bbl of oil as of April 1, 2010. The water-oil ratio as reported is currently 38 bbl of water per one bbl of oil. The gas cap blow down in 2000 was well documented, and gas cap peak production was 330 MMcfd. Table 4–1 summarizes the four large ields we have discussed so far, showing the current cumulative oil production, OOIP, and the projected recovery as a percent of the OOIP. These four ields averaged 72% recovery and all are nearing depletion. When one compares this to Prudhoe Bay’s ultimate recovery of 60%, this gives support to the idea that good ields, with quality rock and medium to good relative oil viscosity, will have high relative recovery of 60% or better with good management practices using the latest in reservoir engineering technology and at today’s oil prices.

Fig. 4–14 Webster Field management scheme (also known as Friendswood Field)11

64

Fig. 4–15 Webster Field recovery history through April 2011

Table 4–1 Summary of four large East Texas ields OOIP MMBbls

Produced MMBbls

% Rec

East Texas

7,000

5,430

78%

Hawkins

1,300

847

65%

Conroe

1,300

734

56%

900

599

67%

10,500

7,610

72%

Webster Total

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Katy Gas Field Katy Gas Field was the ifth major reservoir study underway while I was the East Division reservoir engineer. Located 22 miles west of Houston, near the town of Katy, this ield was the subject of a study conducted by an engineer named Mickey Finch, who worked under the supervision of Joe Marek, the Katy District reservoir engineer. At the time, the Katy Gas Field was the fourth largest ield in the US, with an estimated 8 tcf or more of gas-in-place (GIP). The ield was ideally suited to supply the growing demand for gas in the Texas Gulf Coast area. As shown in igure 4–16, Katy Field—discovered in 1939—covered about 50 square miles.

Fig. 4–16 A map of the Katy Gas Field12

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The Katy Gas Field was developed on a nominal spacing of 640 acres for a given reservoir. In total there were some 220 completions, including oil wells to deplete the thin oil rims found in the 12 Cockield sands. There has been some Wilcox deeper drilling since the Cockield development, but the Wilcox sands were not in the 1971 study or the Cockield Unit. Figure 4–17 shows the general structure of the 12 Katy Cockield sands. Notice the lack of faulting in this ield, compared to the Hawkins, Conroe and Webster oil ields previously reviewed. Note that on a few of the gas reservoirs, there are a few thin oil rims. Figure 4–18 shows the Katy production history for the Katy Cockield Unit sands. Prior to 1962, when production began, the Katy Gas reservoirs had been cycled to recover the condensate and liquid petroleum gas products. Note that a total of 5.893 tcf of gas has been produced since blow-down of this large gas reserve began in 1961. The peak rate was in 1973 at 1,315 MMcf/d, and it is now down to 3.2 MMcf/d. Major gas production did not begin until 1961 with the kick-off of the Texas Gulf Paciic (TGP) 20-year sale.

Fig. 4–17 The general structure of the Katy Cockield sands13

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No. wells

Fig. 4–18 Katy Gas Field production history

The TGP contract off-take rate per the contract was 1 MM/d cu ft per 8 Bcf of reserves. The reserves were to be based on a reserve study conducted by a joint team of Humble and TGP engineers. There was incentive to make the reserves as large as possible from Humble the seller and TGP the buyer based on the volumetric data available at the time. The estimated recoverable reserves then were about 7 tcf or a recovery of 88%. A few of the 12 reservoirs had strong water-drives and needed to be depleted irst to maximize recovery. Others had to be delayed in order to maximize the recovery of oil from the thin oil rims some of the reservoirs had been produced. In performing their SRM of the Katy Gas Field, the district reservoir engineers could not explain the rate of the pressure depletion they were observing versus using the eight TCF of gas-in-place. As a consequence, a major reserve study was undertaken by Mickey Finch 68

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EAST TEXAS’S MAJOR OIL AND GAS FIELDS

under the supervision of Joe Marek. They immediately recognized the inluence of depletion of other reservoirs in the Cockield aquifer that had an inluence on the pressure in the Katy ield because of inference. The particular ields investigated are illustrated in igure 4–19.

Fig. 4–19 A map of the Cockield Aquifer14

Many times this step is overlooked when analyzing reservoir pressure performance. Besides the pressure draw-downs in the associated ields, the original GIP estimate was suspect, and it was necessary to reduce the original estimate of GIP to 7 tcf from 8 tcf. This was a bitter pill to swallow, since the division manager knew that would adversely impact the division proit and loss. I understand that the division did reduce the reserves a year or so later. Note that with 5.893 tcf of gas produced, the Katy Gas Field is nearly depleted from existing wellbores, producing only 3 MMcf/d. It thus appears that the reserve reduction in the 1970 study was justiied. Some of the reservoirs are now being used for peaking, that is, gas is stored and produced during peak demand. This is the exception to the rule that large reservoirs get bigger with time. 69

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Notes 1. Wang, F.P., W.A. Ambrose, T.F. Hentz, F. Bonnaffe, and R.G. Loucks, Bureau of Economic Geology; John A. and Katherine Jackson, School of Geosciences, The University of Texas at Austin. 2008. “Engineering and Geologic Characterization of Giant East Texas Field: North and South Pilot Studies.” SPE Paper 115683. 2. Ibid. 3. Ibid. 4. Carson, L.O., Exxon Co. USA. 1988. “Performance of Hawkins Field Under Gad Drive-Pressure Maintenance Operations and Development of an Enhanced Oil Recovery Project.” SPE/DOE 17324. 5. Ibid. 6. Wang, F.P., W.A. Ambrose, T.F. Hentz, F. Bonnaffe, and R.G. Loucks; Langenberg, M.A., D.M. Henry, and M.R. Chlebana, Exxon Co. USA. 1995. “Performance and Expansion Plans for the Double Displacement Process in the Hawkins Field.” SPE Paper 28603, Nov. 7. Whitson, R.E., W.A. Burnes, Jr., and W.J. Davies. 1975. “A Study of the Conroe Field.” SPE Paper 5081, July. 8. Brady, Teresa, A., ExxonMobil, SPE, And Robert E. Whitson, SPE. 2002. “Friendswood Field—A Case Study in Reservoir Management.” SPE Paper 77640 ,Sept. 9. Ibid. 10. Moore, B.L., member of SPE-AIME, Exxon. SPE Paper 6880, “Webster Field Unit Waterlood Facilities.” 11. Ibid. 12. Finch, M.P. and Joe Marek, assisted by Dr. J.D. Huppler of Esso Production Research Company. 1972. “The Long-Range Planning Function as Related to the Katy Field, Gas Sales.” Fall Meeting of SPE in New Orleans. 13. Ibid. 14. Ibid.

70

5 RETURN TO KINGSVILLE

I

n September 1971, Mr. Woody called and said that management wanted me to go back to Kingsville to be the assistant district manager

under Carl Peters. I had just inished the assignment as the East Texas Division reservoir engineer, but Woody said that management thought I needed some training in operations. I agreed. Carl Peters was still the district manager. Jim Flatt, who I had worked for in the East Texas Division, was now the South Texas operation manager. Mr. Flatt reported to W.D. “Bill” Stevens, who was now the division manager of the South Texas Division. So, I was going to work with familiar faces, in a familiar place. Jim Flatt was in an awkward position, having never worked in South Texas, and I had no experience as a production or drilling engineer. Still, Exxon management thought this would be a good next place to go.

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First Responders I was replacing Judd Miller who had moved on to take charge of Humble’s Natural Gas Department. There was a major difference between Judd and me. He was a late night worker, and he held meetings well into the evening hours. By contrast, I was an early riser. So, on my arrival, the District personnel had to make a few adjustments in their work schedules. To keep me out of trouble, I had two very capable operations superintendents in Mitch Ryon and Fred Rogers, and I really mean good. Mitch and Fred, who I relied on a lot, taught me a tremendous amount about what to do and what not to do in operating oil and gas ields. By this time, all drilling responsibilities had been transferred to Houston, but we were still irst responders in case of trouble on a drilling job in the Kingsville District. A well blew out near the highway west of the Kingsville. Mitch swung into action and started tying ropes in big knots. He directed the ield helpers to pump mud with the knots into the wing valve and circulate it through the blowout preventers, which were leaking. Apparently, the rams were leaking and mud was beginning to unload from the well through the failed blowout preventer (see ig. 5–1). The Drilling Department called Red Adair, but all was quiet at the well by the time he arrived.

Fig. 5–1 Typical wellhead setup

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Another incident involved Fred Rogers. I heard a call on the radio that there had been a problem on a Seeligson gas well with a well-head pressure of 1,900 psi but that the operations people had it under control. That night at a party for one of our retiring ield superintendents, they related the following story. McEvoy, who produced the valves on many of our well heads, had sent an operator to ix a leaking bonnet. The bonnet seals around the stem to keep the valve from leaking. In the process, he put a cheater on it, stripped the threads, and the stem of the valve blew out with 1,900 psi pressure. If he had been in front of the well, he would have been killed. Another service man was near the well and started snapping pictures. I had a perfect picture of a man holding the stem with the expression on his face saying: “Oh [sugar], what have I done?” By evening, the Humble ield people had the situation under control, with no explosion or ire. Two cars were parked in the gas plume. Wisely, they pulled these two cars out of the plume without starting them. They took another bonnet with two long pipes welded on both sides and an extension with a valve that was left open. Then with the valve open, they were able to screw the new bonnet on with the gas lowing through with the valve open. Once they screwed on the new bonnet, they proceeded to close the valve on the pipe and had the well under control. Several people could have been killed, but Fred and his men came to dinner that night as if nothing happened. As it turned out, the stem had a hairline crack in it. After that, McEvoy was invited to a meeting with us at our ofices. We presented slides that were taken at the event and required McEvoy to manga lux all 4,000 of the stems they had in inventory. We also required that if they wanted to continue to sell to Humble they would have to rewrite their training manual, particularly as to using cheaters when tightening valve bonnets, later known as the Kingsville Barbeque. One of my main jobs was to work with all groups—including accounting, headed by Bill Parker—to set out the district budget, including revenue and expense forecasts for the year. At that time, the Kingsville District was an important proit center for Exxon. If we missed, we would hear it from way up the line. For weeks, we had been working hard with all groups, and Parker was charged with putting together the numbers for division management, including Jim Flatt and Bill Stevens, among others. 73

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Bill Stevens was known for being hard-nosed when it came to cost control. In fact, I was told when Stevens was in the District, he did away with paper coffee cups and made all employees bring their own mugs from home as his way of impressing the troops on cost control. It was reported that his secretary showed up at his house for a party once and even brought her own cup in keeping with his ofice rules. I opened the budget meeting, but everyone looked very serious, and I thought a little levity was needed. So, Fred Rogers, who was quite bald, wore a wig. Bill Stevens could not believe his eyes. I am not sure I made a hit with the way I ran that meeting. My opening view graph was a Tiger—remember this symbol for Exxon?—going over the door of a pay toilet that bore the motto “A Penny Saved Is a Penny Earned.” The struggle between cost control and safe operations continues to be a problem for some companies and is one of the dilemmas faced by oil companies. In today’s news, it appears some companies have not found the proper balance.

A Man with the Patience of Job Carl Peters, my district superintendent, drove a big green station wagon with two whip antennae: one for monitoring the police and the other for company information. He kept both going all of the time, and sometimes the chatter got loud. Carl always traveled with a saddle and boots in the trunk just in case one of the ranch owners wanted to talk to him while herding cattle. Carl was gentle, kind, and a good listener. If one of the mineral owners needed something, Carl was always at their beck and call. Sometimes it was a sick dog or cat that needed to be taken to a veterinarian, maybe 100 miles away. In Carl, the company directors had picked the perfect man. Carl was content to stay and take on us young upstarts, always providing the steady hand. On occasion, Carl would take me to the King Ranch ofices across the street in the Kleberg Bank. The King Ranch owned the new ofice building we were in. In a way, they were the largest leaseholder in the world, with some 800,000 acres, and we were their leaser. I also took trips with Carl to the Kenedy Ranch, Armstrong Ranch, Santa Fe Ranch, and East Ranch, where Humble held all the mineral rights, a unique arrangement. The ranch sizes ranged from 74

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50,000–800,000 acres. I was introduced to the various South Texas legends, such as Mrs. Kenedy, Tobin and Ann Armstrong, the Klebergs, and Tom and Evelyn East. Yes, Carl was the right man. He had the patience of Job.

Humble Becomes Exxon USA In early 1973, Humble took a bold move by changing its name and those of all of its afiliates. We were to become Exxon USA. At the time, Ruth Nell and I were expecting our next baby, our “Kingsville surprise.” Lou Ann was now 8 and Jamie 10. I was very busy at the ofice, but I started hooking rugs to pass time in the evenings with Ruth Nell. To commemorate the company’s name change, I designed a rug with a new Exxon logo with a tiger sitting on the top of the sign. Then, I added the numbers 19 and 73 on both sides, along with small logos of Esso, Enco, and Humble (ig. 5–2)

Fig. 5–2 Powers’s commemorative hook rug with the Exxon logo and tiger

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I told my wife I would have the rug done before the new baby arrived. One day, Ruth Nell called: it was near time. Then, about a week later, Cheryl Ruth, a third joy in our life arrived. I won my bet that I would have it done before Cheryl would arrive. At the time, I was sure that I would be with Exxon the rest of my life. I had been a proud Humble man, and I was sure Exxon would be the same. But I also was beginning to get some signs that another move was coming. Sure enough, three months to the day, another move was in the ofing and with another three-month-old baby, too.

76

6 EAST AND SOUTH TEXAS East Texas Again

I

n the East Texas Division, Carl Swenson was now division manager, Bert Crowder was still assistant manager, and Mark Krause was

inishing up the major unitization projects that were underway in my previous assignment there. In the East Texas Division, I now had four groups reporting to me for coordination with Division Management: Division

Gas

Engineering,

Civil

Engineering,

Reservoir Engineering, and the Major Field Study Group headed by Monte Taylor. One of the largest groups, Division Gas Engineering, headed up by chemical engineer Oscar Barron, was responsible for design and operation of seven large gas plants located in the East Texas Division. These plants were designed to recover ethane and heavier components from natural gas. Oscar Barron’s group designed compression stations 77

THE WORLD ENERGY DILEMMA

along the gathering system bringing gas to Houston and East Texas from the King Ranch gas plant in South Texas (ig. 6–1).

Fig. 6–1 Exxon Industrial Pipeline System

Civil Engineering was a new group to me, and was then headed by an expert in the ield, Stanley Lewis. They were responsible for constructing, the gas plants, compressor stations, water lood injection stations. They also built the Hawkins Flue Gas Injection Station at the Hawkins ield. Reservoir Engineering was headed up by Dave Mantor, and the Major Field Study Group was headed by Monte Taylor. There was still a lot of work going on implementing the major ield unitization, and unitization and implementation of the large increase in production from the Hawkins, Friendswood, and Conroe unitization efforts. These production efforts were coordinated by the Division Production Engineering groups, at that time headed by Frank Wolfe, who also came from Exxon Production Research, and later by Jack O’Conner.

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Division Engineering Management At this time, the Division Engineering Management positions were all headed by very experienced engineers who knew what they were doing. My role as division engineering manager was to provide assistance to them when needed to get Division Management approval. My role also called on me to manage the movement of engineers as openings developed and to provide overall coordination of the goals and objectives program, including the merit pay raises. We had about 500 engineers in the East Texas Division. Division Gas Engineering had a group to coordinate with headquarters’ Natural Gas Department to market the 2.7 billion cubic ft per day that was being delivered to the Exxon Industrial Pipe Line System from Exxon ields, including those from East Texas. This was a big undertaking and represented about 4% of the total US gas supply. This group was headed by a Jack Huppler and later Jack Walker, another engineer whom I had worked with earlier at Kingsville. Judd Miller, who had preceded me in Kingsville as assistant district manager, was head of the Headquarters Natural Gas Department. This system was continuing to grow as Houston grew. Exxon’s contract with Houston Lighting and Power required Exxon to provide 50% of their Houston supply, and Houston was growing fast. It was a very challenging job for the gas and civil engineers. They were building new gas plants and putting in new compressors to boost the low of gas in the 30-in. and 36-in. lines. One major project of the Division Natural Gas Engineers was to renegotiate a large natural gas contract with Houston Lighting and Power. This 20-year contract, written in 1964, required Exxon to provide 50% of Houston Lighting and Power’s gas requirements at an extremely low price, in the $0.20/MM BTU price range. Meanwhile, intrastate natural gas prices were taking off, and the large royalty owners were demanding much higher payments, in the $1/MMBTU price ranges. Exxon also realized there would be a day in the not-too-distant future when they would not be able to meet their contractual commitment to keep pace with demand growth in Houston. This contract was renegotiated in 1973–74 and saved Exxon from facing a deliverability shortfall and gained a price, more in line with 79

THE WORLD ENERGY DILEMMA

the market, of around $1 per MMBTU of gas. The wisdom of this renegotiation was very beneicial to Exxon in the following years as natural gas prices for the following few years rapidly escalated (see ig. 6–2).

Fig. 6–2 Annual natural gas wellhead price, 1970–2009.

Busy Times for Civil Engineering With all of the projects and production increases brought about by unitization, these were extremely busy times for the Civil Engineering Department. Stanley Lewis and his men performed with very little input from my position. Civil Engineering was responsible for the on-ground construction of the various pipelines, water injection stations, and compressor additions. One particular construction project undertaken was the addition of some 10,000 horsepower at the Katy Gas Plant that was added to boost the gas pressure as the ield pressures were falling, to maintain gas deliverability. Another big project Civil Engineering was working on was 80

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the design of the inert gas injection facilities at Hawkins in igure 6–3. It was underway but actually constructed after I had moved to my next assignment. This was the irst major lue gas project in the US. It was later converted to nitrogen.

Fig. 6–3 Hawkins inert gas injection project plant

By the time I got back to the East Texas Division, Monte Taylor was in charge of the Division Reservoir group working towards unitization projects in the Conroe, Friendswood, and Hawkins oil ields. The unitization effort had essentially been completed by this time, but lots of follow-up work was required as the ields were now producing at much higher rates. Major production increases were available, based on unitization, and the production allowable set by the TRC. The systematic reservoir management (SRM) reviews were continuing on an annual basis and were critical to support the higher producing rates which were now permitted under the TRC rules. Production Engineering was responsible for coordinating with the ive District Production Engineering groups in stepping up the surveillance, logging, and sand control as production rates in the major 81

THE WORLD ENERGY DILEMMA

ields had been increased considerably. They were also responsible for designing and implementing cathodic protection systems to reduce both downhole as well as surface pipe corrosion.

On to South Texas Division The division manager was R.C. Granberry, another mild-mannered man like Carl Peters in Kingsville. Granberry gave lots of support. There were two division operation managers: Bob Parse and me. The Kingsville Production District and the King Ranch Gas Plant would report through me the irst year. Then I was transferred to the Corpus Christi District, which included responsibility of working with the independent union called the Employee Federation and coordination with the Houston Drilling department, which at that time coordinated all of the Division’s drilling activity. The Corpus Christi District was north of the Kingsville District. The King Ranch Gas Plant was the largest in the world, located about 10 miles west of Kingsville (ig. 6–4). At its peak, the plant processed some 2.1 billion cubic feet (bcf) of gas a day, or about 3% of all gas produced in America. The plant was delivering some 84,000 b/d of plant products and about 2.0 billion cu ft/day of residue gas into the two pipelines that transported gas into the Houston and East Texas areas. At 30-in. and 36-in. in diameter, the two pipes were huge. The East Texas Division where I had just come from was responsible for the two pipes and the associated nine compression stations, once the gas left the tailgate of the King Ranch Gas Plant (ig. 6–5). One of our jobs was to give inal approval to all drilling locations. At that time, the Division was drilling and completing some 400 wells per year. We were also charged with coordinating the District goals and objectives—a major undertaking each year. In my second year I began to work with the employees’ labor union. Mainly we listened to their ideas on how to improve their lives, and they knew we depended on them to get the work done. Personnel problems were few, but we had to take disciplinary action when necessary. Most of the employees at the time were long-time company oriented, and they did a good job.

82

Fig. 6–4 South Texas Division

Fig. 6–5 King Ranch Gas Plant. Photo by Frank Kern.

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Emergency on the Exxon Gas Pipeline System One morning we were having coffee with Exxon Chairman Randy Meyer, who came for a visit on the 17th loor of the Wilson Tower, location of the South Texas Exxon ofices in Corpus Christi, Texas. My secretary came to the door and motioned me over. She explained that somebody had called and reported an explosion at an Exxon pump station west of Corpus Christi. I could see the smoke that morning, some 30 miles away. Coffee was over. I called the King Ranch Gas Plant, and the operator reported they were losing pressure. Sure enough, the No 1 compressor station on the 30-in. and 36-in. Exxon Industrial Gas System (EIGS) lines had blown up. While the EIGS line actually was the responsibility of the East Texas Division, we in the South Texas Division were the closest Exxon operations people. Bob Parse and Ken Taylor, the Corpus District operations superintendent, headed out. Ken had training in ighting well ires. I stayed on the phone. When Bob arrived, he found both the 30-in. and 36-in. lines venting gas to the atmosphere, the reason for the big smoke lume. Unfortunately a compressor mechanic died in the explosion. Bob said that the lame was so hot that he could not get within a block of the ire. The safety valves had failed to close, meaning that Houston was about to lose 50% of its lights. There was a tremendous amount of gas packed in the 200 miles of those 30-in. and 36-in. lines. Bob recalls that the ire departments at nearby Sinton and Robstown had already arrived but that they could not get close to the ire. Asbestos suits were requested from the local Corpus Christi Reinery ire departments. Ken Taylor and “Babe” Clark, an EIGS employee, agreed to try and manually shut off the valves that had failed to close. Bob watched with his binoculars from a block away as the men approached the center of the ire. The men closed the valves and the ire began to burn down. There was a bit of a problem in that the quick shut-down valves were stuck and could not be closed. The men had to turn a backup valve 124 revolutions to close it—a daunting task considering the heat and the time it took. Exxon was very fortunate that it did not lose two more employees that day, as the two men who shut the valve were not harmed. 84

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By this time, about 4:00 p.m., the line pressure in Houston had dropped to about 50 psi above that required to keep the generators going at Houston Lighting and Power. It was soon determined that wasps—mud daubers—had built their nest in the air control vent lines that caused the safety valves to fail to close. New safety procedures were instituted to prevent this from ever happening again.

85

7 SAUDI ARABIA

I

n 1977 I got the surprise of my life when my boss called me in to ask if I would be interested in moving to Saudi Arabia to assume the position

of chief petroleum engineer for the Arabian American Oil Co. (Aramco). Other than my six-month trip to Venezuela, my entire 19-year career had been spent in domestic afiliates of the company that had become Exxon. Of course, I had been involved in reservoir studies of ields in Venezuela, Canada, and Saudi Arabia through my work with JPR. In fact, along with Jim Patterson, I had performed reservoir studies on Saudi Arabia’s large Abqaiq ield, which was discovered in 1974 and contains 25 billion bbl of OOIP. I arrived in Saudi Arabia to ind a totally overworked staff trying to accomplish the impossible. The Aramco shareholders—Exxon 30%, Texaco 30%, Chevron 30%, and Mobil 10%—owned the Saudi

87

THE WORLD ENERGY DILEMMA

concession, and they provided overall management of Aramco. By 1977 the Arab oil embargo was over and, at the time we arrived, the roads were clogged with 10-ton Mercedes trucks. In Dhahran, construction of new buildings and housing was moving at a fevered pitch. The oil ields were being pressure-maintained by 8 million bbl and more of water injection, primarily from a large brackish water aquifer. Some dump looding was occurring, but this was being replaced by the shallow water aquifer being pumped. Capacity was targeted for 16 million b/d by 1982, some ive years away. Figure 7–1 gives the production history of Saudi Aramco from the beginning until January 1, 2010. Note the irst black line of 8 million b/d in August 1977 when I arrived and the then-targeted capacity of 16 million barrels per day by 1982, some ive years later. Notice that Saudi Arabia had produced 30.6 billion bbl by the time we arrived. Through January 2010, the production had grown to 122.4 million bbl.

Fig. 7–1 Saudi Arabia oil production rate—MMBbls/d, 1945–2009

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During the rapid buildup in production, there may have been some areas where pressure had declined below the desired level, but this was not permanent damage as some were led to believe. Admittedly, some wells were showing water invasion. However, this is not a sign of damage. It is a sign that water is displacing oil, not being lost. As we arrived, a large seawater injection station at Qurayyah on the East coast of Saudi Arabia was under construction.

Assessing Saudi Reserves Shortly after my irst week in Saudi Arabia, I suggested to my boss that I spend the next two to three weeks visiting the district ofices at Abqaiq and at Ras Tanura. He agreed, and I had access to a helicopter to visit these two ofices as well as any of the production facilities for a fast course in where things stood from the standpoint of petroleum engineering. On completion of the tour, I returned and dictated a 16-page report of my indings. Among other things, it included a section on our totally inadequate stafing to accomplish the tasks at hand, not even considering the fact that Saudi Aramco was planning a 60% increase in oil capacity in the next ive years to the 16 million b/d target. To my surprise, that portion of the report was well received, and within approximately six weeks I was off to launch one of the largest-ever recruiting trips for petroleum engineers. Saudi Aramco management had approved 162 new positions. I was looking for engineers of all types to staff up the four departments. Reporting to me were reservoir engineering, production engineering, drilling engineering, and the large Technical Service Laboratory, which was assigned to the Petroleum Engineering Department. At that time I had around 80 US-trained engineers. We also had a few new Saudi engineers who had been trained at the new Saudi universities, while others had received their training in US universities. The two primary objectives of the Aramco Reservoir Engineering group were to determine reserves and plan their depletion. Aramco had reservoir engineers in both the Ras Tanura and the Abqaiq ofices, as well as the main Dhahran ofice. Reservoir Engineering was headed by Richard E. “Dick” Martin, an Englishman and one of the most 89

THE WORLD ENERGY DILEMMA

knowledgeable engineers—both in engineering and in Middle Eastern affairs—that I had met (ig. 7–2). Dick had worked with Gulf Oil in Kuwait right after World War II, as well as in Iran and Iraq through Esso Middle East. He had worked 15 years in Saudi Arabia, and was serving as six-month relief in the job I was assuming.

Fig. 7–2 Dick Martin, former chief reservoir engineer for Saudi Aramco

In total, we had 15–20 engineers in different groups in reservoir engineering as well as 70–80 engineers and a few geologists doing reservoir studies in the US on contract with Aramco. Under Petroleum Engineering, I had about 500 employees, many of them technical assistants from all parts of the world. We were in a multicultural world. My secretary, Freda Ferris, was from Bombay, India, and she was really competent. Production Engineering (downhole) was headed by Bert Golding, a long-time Aramco employee. Drilling Engineering was headed by Tom Edmondson on loan from Chevron, and the Tech Service Lab was run by Art Davis, another long term Aramco manager. The Tech Service lab did analysis for many other departments in Aramco. When I arrived there were many rigs running as Aramco was scrambling to reach the 16 million b/d production target. Their primary objective was to get the well drilled as fast as they could. In fact, they had 90

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an annual party for the drillers, and they passed out rewards for those who completed the wells the fastest. In my estimation this was a wrong objective, because Production Engineering had to spend lots of money and time repairing wells that were drilled in such haste that many had cement failures—a familiar problem even these days, as shown by BP’s Macondo blowout. After the originator of the drilling game was away from Saudi Arabia, Tom was able to convince the drilling department to cancel the game. At the time we were beginning explore for Deep Khuff Gas. I remember getting involved with the safety procedures for a dificult well being drilled outside the Abqaiq camp. This gas was below many of the shallow structures, such as in the Ghawar area, which is being developed to help supply Saudi Aramco’s growing need for gas. Khuff gas has a very high degree of H2S and has to be handled very carefully. As of 2010, Saudi Aramco claimed 279 tcf of associated and nonassociated gas. In 2010, the Saudis produced 9.7 bcf/d of raw gas to their plants, according to the 2010 Saudi Aramco Annual Report. Production engineers were primarily concerned with making downhole completions, repairing cement jobs, and maximizing production. They were concerned with any downhole problems related to corrosion of the casing and/or tubing string. Even in the days of vertical wells, some were capable of producing 10,000–50,000 b/d, particularly in the higher permeability areas of North Ghawar and Abqaiq, as well as the offshore ields of Sainiya, MarJan, and Zuluf. For the most part reservoir rock quality was excellent, with permeabilities in many reservoirs ranging from one to upwards of ten darcys. In the offshore wells, sand control was sometimes a problem which needed attention. While Surface Production Engineering was not assigned to the Petroleum Engineering Department, we were concerned for the safety of the various low lines at the Dhahran camp site related to their proximity to the housing areas. A joint task force was formed, and recommendations were formulated for management.

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A Problem of Corrosion As I traveled around the Kingdom, corrosion of the pipes was a constant concern. On a sightseeing trip with my family, we ran through what I thought was a puddle of oil on the highway. I sped up, stopped at the local police station, honked with lights blinking, and hollered in Arabic: “Wadja sait,” which means “Lots of oil.” By the time they got there, one car already had lipped over, and there could have been more. That night, when we came back through, the police chief was very appreciative. Another time, our house was rocked by a loud boom that sounded like a jet crashing through the sound barrier. Unfortunately, that night 11 Saudi operators were killed due to a leaking gas line that blew up, the number one GOSP at Abqaiq some 50 km from our house. The technical service lab worked for all of the Aramco engineering departments. They had many chemists working on all kinds of problems related to transporting sour crude and sour gas throughout the Kingdom. Art Davis handled these issues with other department heads without directly involving me. One issue of immediate concern to me was the issue of compatibility of the connate water and the seawater they were about to inject—a massive 2 million b/d—mainly into the Arab-D reservoirs. When I arrived, it was just getting started. The Arab D connate water saturation, which was only 10%–15% of the pore space, was quite low compared to most reservoirs I was familiar with. It did have a high level of strontium in it, but the seawater was relatively high in sulfates. In my South Texas experience I had seen the result of these two chemicals mixed in the producing wells where a precipitate of strontium sulfate developed was a serious problem. Strontium sulfate can only be removed from the production string mechanically. At that same time some of the engineers had heard of a developing problem in the producing wells in Dubai where they were injecting seawater (ig. 7–3). When I asked Art Davis for some compatibility tests, they were not available. For whatever reason he could not produce them. I then asked that some tests be run immediately. Sure enough, when he reported back it looked like precipitation could be a serious problem.1 As it has turned out, because of the large volume of shallow aquifer water injected ahead of the seawater, this apparently has not caused problems. 92

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Fig. 7–3 Seawater intake canal at Qurayyah Plant in Saudi Arabia. Courtesy Saudi Aramco.

Saudis Abandon Plans for 16 Million b/d A few months after returning from my recruiting trip, my boss— George Covey, vice president of production and exploration—called me in and asked for the keys to my company car. He said that Sheikh Yamani had told the shareholders that the 16 million b/d development plan had been dropped and that we could look forward to a production target of no more than 10 million b/d. Covey added that our capital budget had been cut “some 10-fold” that day. Back then, the Saudis put up the capital, not the shareholders. Our job was to work with other departments and decide what we could do with a budget of $500 million per year, not the $5.5 billion we had been working on. Little did I know that the Saudis were working on a takeover from the four shareholders, but I knew something had happened that would impact the course of the world for years to come. I went home and wrote in my diary, “On this day, the world changed.” It really did, too, as a million or so foreign workers were given dismissal 93

THE WORLD ENERGY DILEMMA

notices and sent home. The roads became unclogged, the derricks came down, and our recruiting efforts stopped. We did, however, hire 72 of the 162 approved AFEs I had gone to the States to hire. We needed them just to get the job done, even with a reduced budget. The Saudis have never produced more than the 10 million b/d since my assignment in Saudi Arabia some 33 years ago, until just recently. In the early 1980s the Saudis were the swing OPEC producer until they had enough. Remember the painful years of 1986–88 when the Saudis cranked back up and sent world oil prices tumbling to below $12/bbl.

Notes 1. When I left the Kingdom in 1979, Saudi Aramco was preparing to run some tests under actual well conditions. While I never received a direct report, I understand that in the well tests where the two waters were mixed, strontium sulfate did form. However, it did not appear to be a serious problem, since for years they had been injecting shallow brackish water that had actually displaced the Arab D Water ahead of the seawater, so the problem was deemed insigniicant, and consequently the seawater injection was expanded to the 13 million b/d it stands at today. This is a massive undertaking, and there is no project like it today anywhere in the world.

94

8 SAUDI ARABIA’S MAJOR OIL FIELDS

I

n this chapter I review the current status of ive of Saudi Arabia’s major ields: Ghawar, Safaniya, Abqaiq, Khurais, and Shaybah. First,

consider the reported stage of depletion of the key ields as reported by Saudi Aramco in 2004. Since they have produced about 19 billion barrels more since then, one could say their state of depletion overall is 33% (ig. 8–1). But as the Saudis claim they have increased their reserves, essentially offsetting their production, the yearend 2009 stage of depletion is between 28%–33%. In any event, the Saudis have a large resource base to produce and develop from existing ields (ig. 8–2).

95

Fig. 8–1 Extent of proved Saudi reserve depletion. (Saudi Aramco, 2004, CSIS, Washington D.C.)

Fig. 8–2 Key Saudi Arabian oil and gas ields

CHAPTER 8

SAUDI ARABIA’S MAJOR OIL FIELDS

Ghawar the Super Giant Figure 8–3 is a three-dimensional structure map of the Saudi’s super-giant Ghawar ield, showing the six discoveries that have all been conirmed to be part of the ield with more than 200 billion bbl of OOIP. This, without a doubt, is the world’s largest oil ield. This igure also shows Abqaiq as a separate accumulation, which has 25 billion bbl of OOIP. In terms of OOIP, Abqaiq is about the same size as America’s Prudhoe Bay ield, But Ghawar is more than eight times larger than Prudhoe Bay. To get a sense of its size, consider igure 8–4 which shows the 170-mile long ield compared to the state of Louisiana.

Fig. 8–3 A 3D representation of the giant Saudi Arabian Ghawar Field1

Fig. 8–4 Ghawar oil ield in comparison to the state of Louisiana2

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Ghawar is 19 miles wide. Its oil column, from top to bottom, is reported to be 1,300 ft thick—more than four times the thickness of the oil column in Prudhoe Bay. The thickness of an oil column is very beneicial to enhancing oil recovery because of the large difference in gravity forces to push oil out. Since 1965, the Saudis have injected 6–10 million b/d of water on the lanks of Ghawar to maintain pressure and to displace the oil from the rocks. Since the early 1980s, seawater has been used around the periphery of the ield. It is not surprising that some wells produce water: that is depletion and not damage as some people claim. Some gas has been returned in the Ain Dar Dome, forming a secondary gas cap, which also has assisted in maintaining pressure. As shown in igure 8–5, Saudi Aramco has the capacity to inject 10 million b/d of seawater around the periphery of the ield. Through 2003, Ghawar produced very little water considering the amount of water that had been injected.

Fig. 8–5 Ghawar water injection system

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The overall level of production has stayed at about 5 million b/d during 1993–2003, while the water cut or the percentage of total luids actually declined to a level of 33%. This performance came about as high water-cut producers were replaced with new wells drilled in areas not yet invaded by the water, many of them directional or multilateral. With 200 billion bbl of OOIP, and applying a recovery factor of 60%, this gives original reserves of 120 billion barrels. In 2008, a Saudi Aramco oficial stated that Ghawar’s initial original reserves were more than 100 billion bbl, and that production amounted to more than 65 billion bbl. On this basis, Ghawar has produced about 54% of its reserves versus the 48% shown in igure 8–6. The 2003 depletion rate of 5 million b/d was about 3.3% per year of the remaining Ghawar reserves. Ghawar is divided into six separate regions for development and surveillance as shown in igure 8–7. By far, Ain-Dar and Shedgum on the north end of the ield have produced the bulk of the oil. The Ain Dar and Shedgum areas per Saudi Aramco were 60% depleted compared to Haradh of 10% as of Jan. 1, 2004. Development started on the north and proceeded to the south. Table 8–1 gives some rock properties, though these are not necessarily oficial Aramco data. As I recall, the permeability was on the order of 1,000 millidarcies on the north degrading to 100 more or less on the south end. Of interest is the general direction of the permeabilty from north to south.

Fig. 8–6 Ghawar water management

99

Fig. 8–7 Ghawar regions

Table 8–1 Average rock properties for different sections of the Ghawar Field3 Field

Thickness (feet) Porosity (%) Water Saturation (%) Permeability (md)

Ain Dar

204

19

11

671

Shedgum

194

19

11

639

Uthmaniyah

180

18

11

220

Hawiyah

180

17

11

220

Haradh

140

14

11

52

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The Ain Dar/Shedgum Area The rock on the north region of Ghawar was a clean oolitic limestone, and degraded to a denser dolomite on the south end (ig. 8–8). There were zones or areas of super-permeability where the rock had holes like honey comb visible to the naked eye. The drill bits dropped during the drilling operation. The super-permeability of more than ive darcys (1,000 millidarcies equals one darcy) was due to leached cladecoropsis, a situation in North Uthmaniyah discovered by Cal Daetwyler of Exxon Production research in 1977–79. Figure 8–9 shows the production history of this area. With an established decline rate of 1.5%, I predict another 4.9 billion bbl have been produced from the Ain Dar/Shedgum area. Based on igure 8–10, Saudi Aramco’s production is now about 73% depleted compared to the 60% at year-end 2004.

Fig. 8–8 Oolitic limestone high permeability

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Fig. 8–9 Ain Dar/Shedgum area production history 4

Fig. 8–10 Ain Dar/Shedgum depletion status5

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In 2004, Saudi Aramco conirmed several aspects of their thinking. While they used 60% recovery, the same as I have used, their target is 75% based on their estimate of proved, probable and possible reserves, and contingent reserves as shown by igure 8–7. This conirms my estimate of 60%, at least for the Ain Dar/Shedgum proved reserves. I certainly could not attest to their 32.3 billion bbl of other types of reserves. The rock here is very uniform, and possibly some type of nitrogen or lue gas injection might sublimate the water-drive recovery. The Hawkins Oil Field, which I discussed in chapter 4, has beneited from this type of drive mechanism.

Haradh While Haradh was discovered in 1949, serious development was deferred until 2006 when Saudi Aramco instituted a 300,000 b/d increment for the south end of Ghawar. By 2004, Haradh had produced only 10% of its ultimate reserves. In 2006, the Haradh Increment III was started up, and Nansen Saleri, Aramco’s former chief reservoir engineer, published a report in the Energy Tribune.6 Figure 8–11 illustrates the ramp-up in production to the target rate of 300 million b/d in 2006. The result of Saudi Aramco’s simulation model is shown in igure 8–12. Note the long delay in water production for this development using horizontal versus vertical wells. One other achievement for this plan was a substantial cost reduction in the overall capital costs. While a smart well was certainly more costly, the overall productivity increase more than offset the development costs, as illustrated in igure 8–13. According to Saleri, “The smart completions were necessary to insure production sustainability against the risk of premature water encroachment through fault and fracture systems. Geosteering played a major role in Haradh III because accurate placement of multi-lateral within the Arab D Reservoir as well as the integrity of the hole trajectories were necessary to achieve target rates of 10,000 b/d.”

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Fig. 8–11 Haradh-III crude oil production ramp-up in 1000 bpd7

Fig. 8–12 Haradh water production simulation difference between vertical and horizontal wells.8

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Fig. 8–13 Relative unit well costs show impact of technologies over a decade9

The fourth technology component in Haradh III was I-ield. All 12 of the observation and 28 of the MRC wells were equipped with downhole monitoring systems. The subsurface data was transmitted in real time to Dhahran, about 350 km from Haradh, and complemented real-time surface measurements fed through the supervisory-control and data-acquisition SCADA system. Saudi Arabia has applied these same techniques in two other ields, Khurais and Shabhah. As far as I know, no other ields in the world have been developed and produced in this manner. Figure 8–14 illustrates the growth in reservoir simulation capabilities, which are some of the most advanced in the world. In 1977–79, we could run only 2D simulation models, both areal and vertical. But in 1994, Saudi Aramco began running 3D models on their ields. At that time, their model contained 100,000 cells. But by 2009, Saudi Aramco models could contain more than 100 million cells—a marked change from my time there. In 2010, the Saudis announced a billion-cell model.

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Fig. 8–14 Growth in Saudi Aramco reservoir simulation capabilities10

Abqaiq Abqaiq is the most depleted of all of the Saudi oil ields, and had an estimated depletion of 73% of the original reserves at yearend 2003. With about 25 billion bbl of OIP, my estimate of ultimate recovery was 15 billion bbl or 60%, which is too low. Based on a water-to-oil ratio, as shown in igure 8–15, the recovery was already 57% of the OOIP. The trend was toward 72%, with a water/oil ratio of only 2:1—hardly an economic limit. Based on this data, the Abqaiq Arab D reservoir may approach 80% ultimate recovery. The rock properties are very similar in permeability and quality to the north end of Ghawar.

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Fig. 8–15 Ultimate recovery of oil-in-place, Abqaiq Field

This was the reservoir I studied in the early 1960s as a reservoir engineer with JPR. At the time, I thought I was studying one of the true giant ields of the world, and it was large by US standards. The oil was relatively light, and it had a gravity of more than 30oAPI. It was not until 1967 that a comparable ield was found in America, with the discovery of Prudhoe Bay. The Prudhoe Bay ield had produced 12 billion barrels of oil by the end of 2011 and is very similar in size to Abqaiq. Prudhoe Bay’s ultimate recovery is projected to be 58%–62% of the OOIP. But Prudhoe Bay is sandstone and more complex or heterogeneous than Abqaiq. Figure 8–16 shows Abqaiq’s production history as recorded in 2004. Note that the production was forecast to decline to about 200,000 b/d by 2010. In recent years, Saudi Aramco has drilled several targeted horizontal wells to get more oil out of this ield. Figure 8–17 shows the directed drilling to recover this bypassed oil.

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Fig. 8–16 Abqaiq production history, 1940–2004, 2004–2010 forecast.

Fig. 8–17 Example of multi-lateral horizontal drilling to recover Abqaiq “attic oil”11

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Saudi Aramco plans to recover Hanafa oil, which underlies the Arab D, at some time in the future. The Saudis also are planning to apply tertiary projects, such as lue gas injection many years in the future. Their attic oil recovery project is a direct result of the applications of innovative technology by Saudi Aramco to maximize reserves.

Khurais Complex The Khurais and adjacent ields’ 1.2 million b/d build, using the latest new technology, was one of the largest single production adds in the history of the world. The project was started in 2006, and is now completed. The ield is located just west of Ghawar, and it contains an estimated 38 billion bbl of OOIP. Based on an assumed 60% recovery, the 38 billion bbl of OOIP give ultimate reserves of 28.8 billion bbl. There is one unique feature of this new development project, which took three years to develop using 12 rigs. All 420 wells were drilled horizontally, both injectors and producers. As far as I know, this is the only project like it in the world. According to Kaku Teming, director of upstream research at Aramco Services, Saudi Aramco injected water to repressurize the Arab D reservoir to original conditions before the production increment began. Seawater is being injected by an extension from the Quryyah Seawater plant located on the coast. Seawater capacity through this system now exceeds 12 million b/d, with 2 million  b/d committed to the Khurais Area Fields. This ield was on production when I was there, but pressure rapidly depleted because of lack of pressure maintenance support. Here we are some 33 years later, and a large new source of oil capacity has just been developed. Figure 8–18 represents a schematic of the well locations that have been drilled. All water injection is along the base of the structure with oil production from the crest. All of the wells were drilled horizontally, and some with multiple laterals. Total costs of this project are estimated to be $8–$9 billon. As reported, the cost of this production increment, including the cost of expanding the seawater plant, was less than $7,000– $8,000 per b/d of production. That is relatively inexpensive compared to other development projects around the world. Consider the $30,000– $100,000 per b/d for a tar sands project in Canada.

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Fig. 8–18 Khurais Area Field—1,200 MBCD AL Development12

Shaybah—a Remote Field in the Empty Quarter Discovered in 1967, Shaybah is another of Saudi Arabia’s world class oil and gas discoveries with 39 billion bbl OOIP. The ield is located 550 km southeast of Dhahran near the border with Dubai (ig. 8–19). This is a very tough climate where the temperature soars to 125°F, the wind blows 50 mph, and the dunes grow to 1,000 ft high. When I arrived in 1977, this ield was on the rapid development plan, but it fell off of the list when the budget cut occurred. At that time industry technology had not been developed for horizontal or directed drilling of multilateral completions, and in 1978 all of the development would have been with vertical wells. The Shaybah Field produces extra light crude of 42°API. The oil column is 600 ft (gross) thick. However, the permeability is relatively low by Saudi standards at a reported 18 millidarcies. The oil column is overlain by a 110

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huge gas cap of 30 tcf. Since there is no gas market, all produced gas is processed and returned to the formation. Liquids are processed out of the gas to run the various power generators at this remote camp. Figure 8–20 shows the Shaybah structure with the large gas cap of basically stranded gas. Other than processing, which removes the heavier components of the gas, it is returned to the reservoir to assist in maintaining reservoir pressure. Saudi Aramco engineers believe the ield has a weak water drive. According to reports, the proved reserves range from 14 billion bbl to 19 billion bbl, which give recoveries of 36%–49%.13 But Saudi Aramco puts the reserves at about 19 billion bbl, or nearly 50%.

Fig. 8–19 Shaybah Camp in Rub’ al-Khali Desert

Fig. 8–20 The Shaybah Field has a large gas cap that is processed and returned to the ield to maintain pressure for oil production.

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Targeted directional wells, such as the ones drilled at Haradh, are the unique feature of the Shaybah development. The initial development was based on horizontal wells with one or two laterals. Initial development required only 100 wells to produce the 500,000 b/d. The initial 500,000 b/d was put on for about $5,000 per b/d. By 2002, Saudi Aramco was drilling much more complex wells, and, as shown by igure 8–21, a production ramp-up to 750,000 bbl capacity had just been completed. Some of the newer completions have as many as eight laterals, capable of producing 10,000 b/d. The use of multilateral wells at Haradh has really been proved at Shayhab, where a typical MRC well produces some 10,000 b/d versus straight horizontal wells, which produce an average of 3,000 b/d.

Fig. 8–21 Saudi Aramco has drilled complex directional, multilateral wells at Haradh and Shaybah14

Figure 8–22 illustrates the historical production buildup through 2007, along with two capacity increases, one of 250,000 b/d completed in 2009, and another 250,000 b/d planned for 2014. These data show that Shaybah Field produced six years at 500,000 b/d, then 575,000 b/d for four more years, and increased production to 750,000 b/d in 2010. The 500,000 b/d relates to a depletion rate of 1% per annum of initial reserves. Cumulative production through 2009 is estimated about 10% of the initial reserves or 1.9 billion bbl. Shaybah is certainly not being strained at the moment, and it could run for another 50 years. At the 112

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production rate of 750,000 b/d, the Shaybah Field is producing only 1.4% per annum of the initial reserves.

Fig. 8–22 Shaybah Field’s production capacity

Safaniya—Largest Offshore Field in the World In addition to the giant onshore Ghawar ield, Saudi Arabia also is blessed with Safaniya, the world’s largest offshore ield (ig. 8–23), with 63 billion bbl OOIP. It is reasonable to expect this high-quality ield to ultimately produce at least 60% of its OOIP of reserves, or 37.8 billion bbl. Safaniya is a very high-quality sandstone, as opposed to Ghawar, which is limestone. Safaniya is very permeable with sections up to 10,000 millidarcys. The average permeability is less, but the ield contains some of the more porous and high-permeability reservoir sandstone rock that I have ever seen. The oil column in the Safaniya ield is 600–900 ft thick. Another unique feature about Safaniya is the gravity of its crude: 27°API with a reservoir oil viscosity 10–20 cp range. Safaniya was put on production in 1957, at a time when fuel oil was in a glut on the market. The ield has a very strong natural water-drive. At the current depletion rate of only 1% of my estimate of reserves, the ield has a many years before decline sets in. 113

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Fig. 8–23 The large offshore ield of Safaniya could ultimately produce almost 38 billion bbl.

In the absence of a production graph, I estimate the oil that has been produced through 2009 at 15.5 billion bbl of production or a depletion of about 40%. Current producing capacity is estimated to be 1.2 million b/d/. The 60% recovery is a reasonable estimate. The oil viscosity and rock permeabilities are very similar to those found in the East Texas Hawkins Field, where recoveries of 71% are expected with nitrogen injection being applied. Of course, that would be many years in the future. From this review, I conclude that Saudi Aramco can produce at current levels for another 30 years or more. But I also do not see production rising much, even if world demand pushes up world prices gradually. If we have a price spike, the Saudis may choose to respond with higher rates of production. Other than a few times in the past when the Saudis got a little too bullish in their public announcements, such as 114

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Sheik Yamani’s statements in 1977, the 10 million b/d target has been their guiding light. Had the world only listened! In October 2011, the 15 million b/d target again came in the news as the Saudi oil minister announced Saudi Aramco had no plans to expand capacity. In addition, it was reported that the Saudi Aramco’s preliminary production for September was only 9.3 million b/d versus the previous August reported production of 9.8 million b/d.

Notes 1. Abdulkader M Aii, Abdulkadar M., Saudi Aramco. 2004. “Ghawar: The Anatomy of the World’s Largest Oil Field.” AAPG. 2. Ibid. 3. Croft, Greg. “The Ghawar Oil Field, Saudi Arabia.” http://www.gregcroft.com/ ghawar.ivnu. 4. CSIS Saudi Washington Meeting, 2004. 5. Ibid. 6. Saleri, Nansen G. 2007. “Dawn in the Desert: Saudi High Tech Paying Off at Ghawar.” Energy Tribune, September. 7. Ibid. 8. Ibid. 9. Ibid. 10. Cera Conference 2004. Saudi-Aramco developed POWERS simulator, no relation to author. 11. Spring 2010 Cover of Saudi Aramco Journal of Technology. 12. Salamy, Salam P. 2008. “Saudi Aramco Capacity Expansion Projects.” 2008 SPE Annual Technical Conference and Exhibition, Denver, Colo. 13. Ibid. 14. Journal of Petroleum Technology. 2003. SPE 81487 ME Oil Show.

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D

uring the 1970s, Aramco was responsible for keeping world oil prices from going through the roof. When I arrived in August 1977, Saudi Arabia’s capacity target was 16 million b/d by 1982, just ive years away. The ive-year budget called for more than $27.5 billion in capital spending, or about $5.5 billion a year. In 2011 dollars, that $27.5 billion equates to $100 billion. At the time, news commentator Jack Anderson1 was urging the US Congress to see if Aramco’s four US shareholders had conspired with the Saudi government to boost oil prices. At the same time, Senator Frank Church was conducting a separate hearing to determine if Aramco’s four shareholders were operating the ields prudently, raising the question of whether Saudi Arabia could be counted on into the future as a reliable supplier of crude oil. It seems that these two investigations were at cross-purposes. One was trying to say that production was too low, while the other was saying it was too high. 117

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I did not know about these hearings when I accepted the job with Aramco in 1977. But in 1979, during my second year in Saudi Arabia, a short version of the full Church report was published.2 I was later surprised to learn that some of production forecasts used were from the preliminary work we had done, as they were subpoenaed from the records of US shareholders. Saudi Arabia’s Oil Minister Sheikh Zaki Yamani was furious that the US government was able to subpoena what he considered to be private records of a foreign country considering reserves and production rates. Historically, the hearings are worth noting since the Church committee was trying to embarrass the four shareholders for overproducing the oil ields. Some of the unpublished pages of the report by the Church Committee were rumored to say some unlattering comments concerning the four shareholders’ operation of the Saudi concession, for example, that they had grossly mismanaged and overproduced the Saudi oil ields. At the same time, the US Department of Justice was subpoenaing records to show collusion between the four shareholders in an attempt to hold production down to drive up prices. But there was no evidence, nor was there a reported inding in these hearings. In fact, in August 1977, the four shareholders’ plan for production of 16 million b/d was intact, and the shareholders had done a good job of increasing capacity, even after the oil embargo of 1973–74.

A Question of Reserves When I arrived, the total remaining reserves for Saudi Arabia was 248 billion bbl, including proved, probable, and possible—as reported by the Church committee. At the time, Aramco was doing its planning on a proved and probable basis, as I recall, using 35%–45% for their recoveries. Dick Martin and I agreed that for Aramco’s short-term planning, we should use only the proved reserves of 110 billion bbl. That changed Aramco’s planning base, but it did not change the Saudi’s proved reserves. Obviously that igure cut both the peak rate we should plan for as well as the length of time before decline would set in. Yes, that did change the outlook. No longer would our forecasts show the previously reported forecasted rates of 20–25 million b/d until more evidence of the probable and possible reserves could be obtained. Also, it disturbed the four shareholders’ gas task force planning group as, all 118

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of a sudden, people realized that the north end of Ghawar (Ain Dar/ Shedgum) would someday go on a decline, and that other ields would have to be tied into the gas system down the road. They also realized that the Kingdom would have to plan for other plants to be built and tied into the master gas plan. This did create a bit of disturbance among the four shareholders’ gas planners and the ofice of Sheikh Yamani. All of a sudden it looked like the Saudis were going to be called on to spend another $3–$4 billion sooner than planned. Some were probably calling for my quick replacement. But in a few months, the furor settled down after Aramco’s chief operating oficer Hugh H. Goerner allowed me to take the initiative with the shareholder technical representatives. Today, Saudi Arabia has eight gas plants spread throughout the oil producing region, and it produced 1.2 million b/d of gas plant liquids in 2010—hydrocarbons that are not included in OPEC quotas. Were we right back in 1978–79? No, we weren’t, when one looks at the amount of reserves that have been produced since then. But maybe we were right, given the technology we that we knew at that time. Total production since I left Saudi Arabia has amounted to 91.8 billion bbl. Since 1995, under Saudi direction, Aramco has maintained production at the level of 8–9 million b/d level, and recently up to the 10 million b/d level, with no indication of a fall-off as predicted in 2005.3 I base the above conclusion on the following facts, partially from my experience of more than 50 years as a practicing reservoir engineer and manager, my detailed review and update of six large US oil reservoirs that I have been associated with, and my detailed review of the technology that has been developed—and is being applied to Saudi reservoirs—since my time there. During my Exxon days, I was the East Texas Division reservoir engineer and engineering manager where four of the large East Texas ields were situated. During 1969–73, three of these large ields were being unitized, and major production increases were granted by the Texas Railroad Commission. I also reviewed the performance of the East Texas Field, the state’s largest. Elsewhere, I have reviewed the performance of a large reserve in the Salt Creek ield, which has similar reservoir characteristics to the much larger limestone ields of Saudi Arabia. For these ive ields, along with the Prudhoe Bay ield—the largest oil ield in the US—I then developed the estimated ultimate recovery after reviewing all of the relevant factors. As shown in table 9–1, all of 119

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these ields, which are in their inal stages of depletion, have ultimate recoveries projected in the 56%–78% range. There is no question that the large ields in Saudi Arabia will have ultimate recoveries of 60% or higher, assuming that oil prices are in the range of $70–$100/bbl or more and that there is stability in the region. Table 9–1 Ultimate recovery from six large US oil ields

Field

OOIP BBbls

Ult Reserves BBbls OOIP

Ultimate Recovery %OOIP

Prudhoe Bay

21.60

13.30–14.00

58–62

7.00

5.43

78

East Texas Hawkins

1.30

0.84

65

Conroe

1.30

0.73

56

Webster

0.90

0.60

67

Salt Creek

0.67

0.43

60

An illustration of what I mean by the current state of technology is illustrated by a short review of the Prudhoe Bay ield, operated by BP, with Exxon holding a large stake. Prudhoe Bay is highly faulted, contains an oil column of more than 400 ft, 21.6 billion bbl of OOIP, and a 45 tcf gas cap.4 The ultimate recovery of 58%–62% of the OOIP has come about with the advent of new tools in the reservoir engineer’s tool kit that did not exist when I was sent to Saudi Arabia: 1.

3D seismic

2.

3D reservoir simulation with up to a 100 million cell models in Arabia, from which engineers and geologists can much better deine the stratigraphy of the reservoir internal properties

3.

Horizontal drilling, including the ability to steer the well to a speciic target, plus multiple laterals

4.

Improved well logging to pick up fractures, and

5.

Application 4D seismic, multiple runs of 3D seismic to pick up luid movement and trapped or by-passed oil.

The BP and Exxon engineers had these tools in Alaska, and they have applied them in a world-class manner to capture the reserves from Prudhoe Bay. After 33 years’ output, Prudhoe Bay has produced 120

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12.2 billion bbl. Note in igure 9–1 how Prudhoe Bay Field’s production decline lattened out as the engineers and geologists went after the hard-to-produce oil. The 12.2 billion bbl produced from Prudhoe Baby is 3.2 billion bbl more than the original estimated reserves of 9 billion bbl. That’s 33% more than originally estimated. And the ield still produces 300,000 b/d. Prudhoe Bay, on a reserve basis, has produced on a relative basis three times the depletion rate of the average Ghawar depletion rate.

Fig. 9–1 Prudhoe Bay production history, 1977–2009

Currently Saudi Arabia’s proved reserves, according to Saudi Aramco, stand at 260 billion bbl of crude oil and condensate. The Saudis have been fairly constant, with reserve adds, offsetting yearly production (ig. 9–2). Remaining reserves are made up of three elements: the OOIP, a recovery factor, and the amount of oil produced since discovery. In 2008, the Saudis set the goal of achieving recoveries of 70% in their major producing ields. That will be most dificult, but possibly achievable given new technology and today’s prices. Achieving the goal will probably require a large amount of new drilling. But there’s no doubt that the Saudis have the oil.

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Fig. 9–2 Saudi reserves over time. Source: Saudi Aramco Annual Report, 2010.

Sadad Husseini, a person I have a lot of respect for, was an up-andcoming Saudi manager when I worked in Saudi Arabia. Sadad eventually rose to the level of senior vice president of production and exploration. In 2007, Sadad talked about a rate cap of 12 million b/d instead of the 15 million b/d per rate cap suggested by Saudi Aramco. But even Sadad has defended the igure of 260 million bbl as being a reliable estimate of Saudi reserves since leaving Aramco. Also well worth listening to is Ed Price, former vice president of exploration and production for Saudi Aramco, who succeeded me as chief petroleum engineer in 1979 and who stayed on in various capacities until 2000. Ed believes that the reserves are at least within 10% of Aramco’s igure, or 234 billion bbl. A third opinion comes from petroleum consultant Jack Zagar, a former Aramco reservoir engineer now with MHA Petroleum Consultants, Ireland. Jack, who also worked with me in Saudi Arabia, used igure 9–3 to develop a feel for the total reserve situation in Saudi Arabia. In the graph, Zagar shows the date of discovery through 2004 and the reported OOIP for those ields. Note that the super giant Ghawar, discovered in 122

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1948, is right off the graph at 200 billion bbl. The graph includes total OOIP on a cumulative basis for just the ields on production, and it also includes the discoveries for ields not yet on production.

Fig. 9–3 Total oil-in-place for Saudi Arabian oil ields5

Zagar concludes that Aramco has been growing OOIP, and his estimate is about 580 billion bbl, with 64% of the reserves located in the 10 large producing ields. In 2005, Zagar used a 45% recovery versus Aramco’s 52%. Considering what has been produced since 2005, Zagar’s remaining proved reserves as of yearend 2009 would be only 157 billion bbl. That’s 40% less against Aramco reserves of 260 billion bbl. This is a wide range, 157–260 billion bbl. My opinion, after reviewing the US ields, is that the 10 or so larger Saudi ields that have 64% of the OOIP should recover considerably more than Zagar’s estimate of 45%. I would assign a 60% recovery to these 10 ields, and a 45% recovery to the other 90 or so ields. Stephen A. Holditch, a consultant on the International Advisory Board for Saudi Aramco Resarch, said that the 60% is probably on the low side, and he restated Aramco’s goal of 70% recovery in the main ields. 123

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Zagar’s estimate of 580 billion bbl OOIP may be more realistic than the 700 billion bbl suggested by Aramco. Applying these factors and adjusting for the 122 billion bbl produced so far, I estimate the proved reserves to be 211 billion bbl at yearend 2009 or 81% of Saudi Aramco’s estimate. Zagar’s adjusted estimate and mine both allow for the 16.5 billion bbl of reserves added since 2004. Note that this does not consider new exploration discoveries and the potential of oil being found in shale source rocks as is being done in the US today. So, are the Saudis about to go on a severe production decline as the pessimists of the world would lead us to believe? Regardless of whether the yearend 2009 reserves are 157 billion bbl or the 260 billion bbl Aramco reported, the simple answer is, “No, they are not going into production decline.” However, I do not expect Saudi production to grow above the target of 10 million b/d set by Sheikh Yamani in 1979, and the reason for that is simple: the Saudis would not want to see prices fall. There is nothing unusual here. This was the same sort of thinking of one of Exxon’s major royalty owners in the 1970s. The owner used to tell Exxon not to apply to the TRC to increase the allowables in his ield. The owner thought that prices were going up in the future, much like Sheikh Yamani who, referring to oil revenues, said in 1978, “My grandchildren will need that oil, too.” The key questions for energy planners are: how long will the Saudis be a reliable producer? Can they be counted on to deliver oil? What rate can they be counted on? These questions have stumped and confused energy planners for the last several decades.

Historical Projections of Saudi Production Before giving you my ideas of the future of Saudi Arabia’s production, let me irst show the historical projections of Saudi capacity and production forecasts by the US Energy Information Administration (EIA). When I irst saw this graph in 2005 (ig. 9–4), I was shocked. How could the top planners in the EIA be so out of touch with Saudi thinking? Even as far back as 1978, when the 16 million b/d plan was dropped, the Saudis had no intention of spending to produce the quantity of oil that forecasters were demanding. As shown in igure 9–5, Saudi Arabia’s production has rarely exceeded 10 million b/d. However, as Jack Zagar once told me, it is presumptuous 124

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to assume that Saudi Arabia will produce additional oil to meet the world needs. It is a complex issue, as the Saudis enjoy a high standard of living with oil at $80/bbl. The Saudi government budget earns $720 million a day in oil revenue. In 2009, though, after the global economic crash with oil priced at $35/bbl, they only received $315 million per day. So, why would they want to hurt themselves by producing more oil at reduced income, even though they have reported production capacity of 12.1 million b/d, or a little more than two million bbl of spare capacity?

Fig. 9–4 Saudi production and EIA capacity and production projections6

Fig. 9–5 Saudi production rate—million b/d

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Zagar also noted that Saudi Arabia’s population has increased more than three times since he and I were there in the late 1970s. How best should it proceed with its reform and democratic processes? What is the impact on its non-oil-related investments? What should be done about the declining dollar? How best to plan and prepare for the post-oil period? What is the quid-pro-quo between Washington and Riyadh? What impact do Washington’s relationships with Palestine and Israel have on Saudi policy? According to Zagar, “These are but a few examples of the myriad questions facing the House of Saud.” Then in 2011 came the unrest in Egypt, Libya, Yemen, and Syria, with confrontations between government and street demonstrations threatening stability in all countries of the region. To an extent the Saudis keep the world guessing about what they will do with their surplus. But I believe they will be good stewards of their precious oil reserves and will try to maintain a couple million b/d of spare capacity as they move forward, to be used only to prevent price lare-ups, as was the case during the Libyan crisis in 2011. Sadad Husseini gave the world a glimpse of how long the Saudis might produce, with his projections for 10 million b/d and 12 million b/d producing rates (ig. 9–6). Sadad shows his projections until 2035 at a producing rate of 12 million b/d and until 2045 at a 10 million b/d rate.

Fig. 9–6 Sadad Husseini’s predictions for Saudi projection7

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Since I have varied opinions as to what the reserves are today, ranging from Zagar’s 157 billion bbl to Sadad’s 260 billion bbl, I developed a model that assumes no cut in the Saudi reserves of 260 bbl, a 10% cut, a 20% cut, a 30% cut, and 40% cut. Even if the reserves are 40% less than what Aramco states them, it will take the Saudis 30 years at a 10 million b/d rate to get to a stateside depletion rate of 8% as shown in igure 9–7. If one uses my 20% reduction in reserves, the depletion rate of Saudi reserves in 30 years with a 10 million b/d rate will only be 4%. I might note, too, that these conclusions do not take into account any new discoveries. Yet, that cannot be discounted as there have been a few smaller ields found over the last several years, as seen previously in igure 9–3.

Fig. 9–7 Saudi Aramco depletion rates for various reserves, base 262.5 BBbl

The main worry concerning Saudi Arabia’s crude supply in the next 30 years is not supply. They certainly have the reserves and the technology to do the job at current price levels. Manpower may be a problem, and they will also need to place close attention to their corrosion control to maintain the seawater supply system that is so critical to their production maintenance program. The Saudis have made great strides, and they have applied all the technology that has become available. In some areas, the Saudis may be in a leading position worldwide. No, the worry will 127

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not be about supply. It will be about politics, and it will involve a strong commitment to defense of their facilities. According to a report by the Center for Strategic and International Studies (CSIS), Saudi Arabia has a police force of some 35,000 guarding its oil infrastructure at a cost of $8 billion a year. There have been unsuccessful attacks on Saudi oil facilities, such as the one on the Abqaiq processing center in 2007. The Saudis continue to monitor their population, and they have been successful in arresting a few hundred prospective terrorists. However, public unrest, demonstrations, and uprisings in nearby countries like Yemen, Bahrain, and Iran raise additional questions about Saudi Arabia for governments around the world who depend on a stable supply of oil. Events in Egypt, Libya, Tunisia, and Algeria raise similar levels of concern. Yes, the Saudis have their problems, and the loss of Saudi Arabia as a friend to the West would have imponderable consequences. Business between Saudi Arabia and the US has been lourishing. The US buys Saudi oil and provides the country with weapons of defense. In 2011, US Secretary of Defense Robert Gates signed a $60 billion arms deal, shoring up the Saudi’s ability to defend themselves in the event of a conlict with Iran. In regards to trained engineers and geoscientists, the Saudis have done a good job of training their own professionals at their own universities. One had just been built outside the Dhahran Camp when we arrived in 1977. Training Saudi engineers and geoscientists was a key element in Sheikh Yamani’s plan in the 1970s. A signiicant development in Saudi Arabia has been construction of the massive seawater injection plant to support the withdrawals of oil from their ields. As of 2011, they had 13.2 million bbl per day of capacity to inject water from the Qurayyah Sea Water Injection facility. Without this system, the Saudi reservoirs would lose pressure and productive capacity would rapidly decline. The Saudis have made great strides in improving their technology and overall understanding of their reservoirs since I was there, and they may be industry leaders in several areas. I could add the fast learning curve that the Saudis have been on in drilling directional wells and multilateral completions. The center for all their computer application and interpretation is the Dhahran Exploration and Petroleum building in Dhahran 128

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When it comes to new technology, 3D seismic versus 2D seismic is like the difference between night and day in understanding what a reservoir really looks like (ig. 9–8). New logging interpretation is also a critical piece of the Saudis’ new understanding in determining where the high-permeability channels are compared to low-permeability rock. There are other examples, too. Engineers upgrading from 2D to 3D seismic in the recently developed Khurais ield have a much better ability to pinpoint multilateral directional drilling. The engineers can pick out much more fracturing and zones of high permeability and denser zones. Figure 9–9 shows how logging tools can pick out vertical fractures in horizontally drilled wells. Information generated from graphic depictions of the distribution of the reservoir rocks is greatly enhancing reservoir development and planning. Such technological developments were made possible by the rapid developments in computer processor speeds and memory storage, and by the efforts of company personnel in the Exploration and Petroleum Engineering Center (EXPEC), as shown in igure 9–10. The Center links computer, exploration, petroleum engineering, and laboratory facilities, essentially eliminating the company’s dependence on upstream technological support from other oil companies.

Fig. 9–8 Difference between 2D and 3D seismic representation8

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Fig. 9–9 Horizontal well—detected fractures

Fig. 9–10 Reservoir simulation room and attaché conference room in the EXPEC

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3D reservoir models with high-speed gigabyte cells represent the most recent technological innovation announced by Aramco, and almost all of their reservoirs have huge, high-speed 3D models. The two largest ields have been placed in this model, which is called Giga Powers. In 1987 I visited Aramco Headquarters in Dhahran and noted many changes, including EXPEC. Back then, Ron Lantz owned the rights to Eclipse, one of the more powerful 3D simulators. Lantz had a meeting with Sadad Husseini at the time, and said that Sadad envisioned “reservoir engineers running simulators much like a pilot lies an airplane trainer.” It appears that Husseni’s vision is now up and running. From what I read, this area of Saudi Aramco’s business is irst-class, and they may now be leading the world in their technology as it applies to understanding the rock properties of their reservoirs and how to predict the future (ig. 9–11). During my time as chief petroleum engineer, an area I focused on was getting a better handle of the internals of the reservoir. I used to say “garbage in equals garbage out” when it came to reservoir simulation as it stood in the late 1970s. It looks like the Saudis have come a long way since then.

Fig. 9–11 Detailed reservoir description zonation of major reservoirs

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In particular, I wish to note the Saudis’ speed in learning about and applying horizontal drilling and multilateral wells. They have made tremendous strides. Directional wells and the ability to hit speciic targets some two miles deep received a lot of publicity in 2011. Apparently, Saudi Aramco has used those tools and is applying them on a daily basis (ig. 9–12). When I was in Saudi Arabia, we had a blowout in the Arab Gulf, and we brought in a team to get us within 25 feet. Today, directional drilling is even more precise.

Fig. 9–12 Directional drilling managed from EXPEC Center, Dhahran, Saudi Arabia

According to Saudi Aramco’s 2008 annual report, some 600 directional wells were drilled and steered from the EXPEC geosteering center that year. Unoficially, I understand that by March 2012 Saudi Aramco had just 95 rigs running, even though they have built their producing capacity to around 12 million b/d. The split between development, workover, and exploration wells is about 60-20-20. Some 60% of the development wells are horizontal, while the split between oil and gas is 50-50. Saudi Aramco is pursuing an active drilling program for both oil and gas resources. Figure 9–13 shows examples of what is meant by directional multilateral wells as applied by Saudi Aramco. From this chart, one can repeat that Saudi Aramco may be leading the industry in critical areas. Can super reservoir simulators with effective directional drilling, combined with relatively low depletion rates with huge oil columns lead to recoveries greater than 60% of OOIP? The Saudis think so, with a stated 132

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objective of 70% recovery as laid out in their 2008 annual report. They may get there with help from reapplication of 3D, called 4D, such as used in Prudhoe Bay. I know, however, that given stability and continuing to produce at or below 10 million b/d day can give them another good 30 years or more of production before their total production decline begins. This will require billions of dollars and massive drilling programs. New discoveries of unconventional oil from the sources rocks would extend this plateau period.

Fig. 9–13 Examples of directional multilateral wells applied by Saudi Aramco

From time to time, Saudi Aramco has released some indication as to their forward thinking. One should realize, however, that the Saudis are no different from any other oil company. Forecasts are subject to change as world events and economic conditions unfold. In 2008, Saudi Aramco’s forecast of sustained capability saw production rising to 12 million b/d in 2012 as shown in igure 9–14. Note the planned increments of new production that Saudi Aramco projected. Note also that all but the Manifa increment were installed as forecast. As I was writing this book, I understood Manifa development was occurring at a slower pace, but this may have all changed as more rigs become available. While the Manifa Arab Heavy Increment may be delayed, there is a planned drilling program. Manifa, has an estimated 48 billion bbl of OOIP, as seen in igure 9–3. 133

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Fig. 9–14 Saudi Aramco’s forecast for maximum sustained capacity9

Manifa is mostly located in shallow bay waters on the east coast of Saudi Arabia. Development will require several extended reach wells as well as directional drilling from islands to be constructed in the bay. Saudi Aramco has maintained a high level of drilling through 2008 to offset their primary decline in developed ields reported to be about 8% and to bring on the new increments of production. With the fall in oil prices since 2008, Saudi Aramco had reduced its rig count to 90–92 as rig contracts came up for renewal, as seen in igure 9–15. It is interesting to note that about 50% of the rigs are used in gas development as well as gas exploration. Recent unoficial reports are that the Saudis’ rig count could be back up over 130 and expected to grow as they work to maintain their surplus oil capacity. During 2011 additional rig availability was somewhat of a problem. While Saudi Aramco continues with the implementation of new oil production projects, they have not given up on improving recovery in their existing ields. The large water-injection pressure-maintenance projects have been very effective in getting high oil recoveries in their current producing reservoirs. As stated earlier, Saudi Aramco’s objective is to achieve 70% overall recovery. The Abqaiq ield looks like depletion under water injection as well as gas injection will recover 72% of OIP with a water/oil ratio of only 2.0. 134

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Fig. 9–15 Total Saudi Aramco rig level, 2000–201010

Even then, Saudi Aramco carries on a strong research program and has a separate group called the EXPEC Advanced Research Center (ARC). In 2009 Saudi Aramco listed 120 upstream projects, covering geophysics, geology, production, drilling, simulation, and reservoir. This ranges all the way from studying additional recovery methods, inding trapped or bypassed oil, to improved interpretation of 3-4D seismic, and improving their reservoir models—which already are some of the most sophisticated in the world. Most of this work is conducted internally with Saudi engineers. When it comes to the question about Saudi reserves and their long-term ability to deliver a stable oil supply, the simple answer is, “Yes, given political stability. Without stability the future is not known.” Following my assignment in Saudi Arabia, for reasons explained in the epilogue, I decided to leave Exxon and Aramco and become and independent consultant.

Notes 1. Robinson, Jeffrey. 1988. Yamani: The Inside Story. New York: Simon & Schuster. 2. Simmons, Matthew R. 2005. Twilight in the Desert: The Coming Saudi Oil Shock and the World Economy. Appendix C. Hoboken, NJ: John Wiley & Sons.

135

THE WORLD ENERGY DILEMMA 3. Ibid. 4. Holstein, E.D., and H.R. Warner Jr. 1994. SPE 28573, “Overview of Water Saturation Determination for the Ivishak (Sadlerochit) Reservoir, Prudhoe Bay Field.” SPE Annual Meeting, New Orleans. 5. Zagar, Jack. 2005. “Saudi Arabia: Can It Deliver?” 31st Pio Manzu International Conference, Rimini, Italy, Oct. 28–30. 6. Mike Lynch, president of Strategic Energy and Economic Research. 7. Al Husseini, Sadad I. 2005. “A Producer’s Perspective on the Oil Industry.” Oil and Money Conference. 8. Al Waleed, A. 2010. “Khurais Complex—1: Field Development Required Best Practices, Leveraged Technology.” Oil & Gas Journal, Feb. 22. 9. Salamy, Salam P. 2008. “Saudi Aramco Capacity Expansion Projects.” SPE Annual Technical Conference and Exhibition, Denver Colo. 10. Ibid.

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A

fter my return to the US in the summer of 1979, there was a job on most street corners, considering my background. But I wanted to

take a little time and make the right decision. I made a list of contacts, some with Exxon and some with others I met outside of Exxon. I traveled to Kingsville in South Texas and to Tyler in East Texas. I visited with many of the friends I had made throughout the years. I visited J.K. “Jim” Patterson who worked with me in Tulsa at the JPR Lab in reservoir simulation. Jim had recently resigned from InterComp, a computer software company, and he was interested in starting up his own consulting company. After some discussion, we decided to incorporate as Patterson, Powers & Associates, Inc. (PPA). Jim had continued to develop his computing skills, and had a good career at Intercomp. He understood the mechanics

137

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of independent consulting from which I could learn. He was president, and I became senior vice president. Jim and I started out in a one-room ofice that could barely it two desks. Fortunately, one or the other of us was out of the ofice most of the time trying to drum up business. We started slow, but business picked up rapidly. Jim was a whiz at computers. As I recall, he got a big job from Conoco modeling a North Sea gas ield that occupied him for a few months. I was struggling to pick up a few clients, but there was never a month when we did not bring home some revenue. These were busy times in the oil patch, and we felt fortunate to be involved. Jim spent a lot of time writing software, which he was very good at. He developed an excellent economics package called Pecan, which we sold. We hired several excellent engineers who have gone on to be successes in their own right. Gary Crawford joined us to be our well test analyst. Gary was one of the best in the industry on expensive, long, drawn-out well tests. He had come with me to work in Saudi Arabia, and he was one of the one of the recruits from Exxon Research. Gary has continued in the industry, working in his specialty. Pete Taylor also joined us, having known Jim from Intercomp. Pete was another one with a strong computing background. Later Jim and Pete would form a partnership of their own. We also hired Lynn McCoy, a log analyst and computer specialist. George Schaefer, now senior vice president of the Houstonbased consulting irm Miller & Lentz, joined us with a strong gas engineering background. We also had in-house geologists with us: Herbert G (Skip) and Martha Mills, who we knew from Kingsville days, subleased ofice space from us and were available whenever we needed help with geology. Landman services were supplied by John Hafner just down the hall from our ofice. After ive years, though, it appeared that the working relationship between Jim and me was less than desired. So, we decided to go our own separate ways. I offered to retain the ofice support staff, ofice manager Mal England, drafting supervisor Dan Tidwell, and a couple of others. I also retained Keith Dowling, a young Aggie engineer. The others would leave to ind their own destiny. On June 1, 1984, Ruth Nell and I founded Powers Petroleum Consulting Co. (PPC), and Jim and I decided who should keep which clients. He would keep all rights to any of the computing software that 138

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he had developed. If any property sales closed after June 1, they would accrue to PPC. During my PPC days, I added two other engineers with extensive banking backgrounds, Andy Merryman and Chuck Brittan. Mark Roach, a very knowledgeable engineer with a strong computer and database background, and Kevin McNichol, formerly with Amoco and an independent oil and gas company, also joined our staff. George Hite, who I had worked with at Exxon, joined PPC and became a vice president with the ultimate objective to purchase the company in the future.

Sarita S.K. East B Lease Account 2 Kenedy County, Texas In early 1980, shortly after Patterson and I formed PPC, a mortician in Kingsville named Andrew J. Turcotte contacted me through James Patten of the Kleberg Bank. Turcotte and some other relatives had settled a 15-year lawsuit with the Catholic Church over the estate of Mrs. S.K. East. The heirs and their attorneys, some 250 of them, ended up with a 25% royalty interest on 13,864 acres in Account 2. The Catholic Church, the other party, ended up with a similar-sized tract on the west half of the S.K. East B lease (see ig. 10–1). Humble/Exxon were the operators on both tracts, and owned 100% of the working interest (WI).1 Approximately 2,500 acres were productive, but by 1980 the S.K. East B Account 2 lease was producing very little: 1–2 MMcf/d compared to more than 60 MMcf/d when I irst went to Kingsville in 1965–67. A major trapping fault ran along the division line between the two tracts (ig. 10–1). Exxon was the operator, and I was very familiar with the prior production on this lease. Most of the gas was on the down dip side of the fault, or on the Account 2 tract. Turcotte had a few wells on other leases that I been involved with when I worked in Kingsville as the assistant district manager. As I recall, he was not very happy with me at that time. James Patten, a Kingsville banker, told me about Turcotte and his need to hire a reservoir consultant to determine what he had just won in the lawsuit. This lease I recalled was where I was involved in coring the B-18 well 15 years earlier.

139

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Fig. 10–1 The S.K. East B Account 2 lease contained a major trapping fault

I told Patten that if Turcotte wanted to hire me, “he should call me rather than my chasing Exxon royalty owners after just resigning from Exxon.” It had been some three years since I worked for Exxon in South Texas. So, I was surprised to get his call. I told Turcotte that I could do the job if he could get Exxon to release the logs. They had not been released before. I could not work with him if anything I found out or did for him led him to sue Exxon. He agreed and wrote a letter to Exxon, and they released the logs for us to evaluate his interest. His portion of the 25% royalty was 5% of the 100% royalty. This gave him a 0.0125 net revenue interest (NRI) in the entire 13,864 acres. Back then, the entire 13,864 acre lease had only two wells producing 1–2 MMcfd, and the gas price was controlled at about 40 cents/MMBTU. 140

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Figure 10–2 shows the well production history of the wells that had produced since the ield was discovered in 1968. Obviously, compared to a few years earlier, the large lease was generating a miniscule amount of revenue. The initial pressures were very high: 9,300 psi at 10,000 feet.

Fig. 10–2 Well production history of the Sarita S.K. East B Lease Account 2, Kenedy County, Texas, 1968–1980

The following gives some detail of how we came up with initial reserves of 250 Bcf, including the 70 Bcf that had been produced. Back then, these reserves would have been classiied as nonproducing probable. I do not recall assigning a reserve classiication to the Sarita, Mrs. S.K. B lease reserves. The sands were some of the thickest I had seen in the US, and the area was highly faulted. We had no geologic or seismic interpretation, but did have a full set of logs available. The B-20 Sarita S.K. East well, which is signiicant later in this story, had more than 380 ft of net gas spread over 3,000 ft of Lower Frio Sands. The bottom 200 ft was basically sand, probably in the 1–5 md permeability with porosity of 17%. The ield operated under Statewide Rules of 40 acres. No ield rules, that is— Exxon’s 640 acres were never applied for. 141

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This area included down-to-coast growth faults that we visualized through the subsurface at that time. The sands varied by quality, remember the coring of the B-18 well when I worked with Exxon. The permability in B-18 in the M-O2 sand, one of the upper sands, was 40 md. B-18 had produced 20 Bcf before it was lost. Note that Exxon had perforated only the bottom 50 feet of the thick 200 ft O-41 sand in the B-20, and that the well was never fracture stimulated before it produced some 21 Bcf through 1978. The well was then abandoned with the other 333 ft untested. Jerry McQueen, who was on the Deep Gas Task Force at Exxon earlier, performed the log analysis to determine the net pay in each well, and we converted it to gas-in-place. Table 10–1 shows the log analysis over the 3,000-ft gross thickness for the Mrs. S.K. East B No. 20 well. Analyzing each log and applying it to the 2,500 prospective acres, we concluded that the reserves were 250 Bcf. Counting the 70 Bcf already produced, this left 130 Bcf still to be produced. We also risked the GIP by using a 50% recovery factor as most of the reserve was from relatively tight rock. Table 10–1 Gas-in-place for 160 acres Mrs. S.K. East B-20 Individual Well Gas-in-Place Analysis Mrs. S.K. East B-20 Bg = 363 SCF/cubic-ft

Depth (ft)

142

MMCf/ Sw(%) ac-ft

Reservoir

H (ft)

ø (%)

11,680–11,713

M-02

22

21

58

1.394

12,078–12,100

˝

18

22

58

1.460

12,100–12,105

˝

5

19

62

1.141

12,110–12,138

˝

23

21

59

1 360

12,150–12,168

˝

8

20

70

0.948

12,194–12,220

˝

4

21

67

1 095

12,298–12,303

˝

4

20

56

1.390

12,438–12,452

M-34

8

17

60

1 074

12,512–12,520

˝

7

20

65

1.106

Gas-in-Place Bcf/160 Acre 17.826

2.612

CHAPTER 10

Depth (ft)

CASE STUDIES OF AN INDEPENDENT CONSULTANT

MMCf/ Sw(%) ac-ft

Reservoir

H (ft)

ø (%)

12,687–12,696

M-64

5

19

63

1 111

12,708–12,715

˝

8

17

70

0.806

12,794–12,810

˝

16

22

68

1.112

12,952–12,955

M-81-82

4

17

62

1.025

13,011–13,026

˝

10

23

60

1.454

13,945–13,985

O-19

34

18

60

1.138

13,990–13,996

˝

4

21

38

2.057

14,118–14,138

O-41

18

21

50

1.659

14,142–14,162

˝

18

21

41

1 958

14,205–14,220

˝

15

23

48

1.890

14,222–14,232

˝

8

23

38

2.253

14,232–14,245

˝

13

20

55

1.422

14,245–14,266

˝

21

18

62

1.081

14,266–14,282

˝

12

23

48

1.896

14,282–14,290

˝

8

20

55

1.422

14,370–14,380

O-41

10

16

42

1.466

14,405–14,418

˝

13

15

58

0.995

14,445–14,462

˝

17

20

55

1.422

14,490–14,494

˝

4

17

40

1.612

14,530–14,542

˝

10

20

60

1.264

14,560–14,580

˝

12

22

43

1.981

14,580–14,592

˝

12

20

60

1.264

14,608–14,620

˝

12

17

60

1.074

Total

383

Gas-in-Place Bcf/160 Acre

4.766

2.982

7.504

50.756 87

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At the time, the Federal Power Commission (FPC) controlled gas prices, which ranged from $0.44/MMBTU to more than $7 for new completions made below 15,000 ft. For new wells above 15,000 ft, where most of the gas reserves were, the price was $2.65/MMBTU. We told the Turcottes that gas prices were escalating for new wells at about the same rate that people were discounting their money. Figure 10–3 shows the average price of natural gas for 1979–83. It was a reasonable assumption to multiply the reserves times the current price to come up with a value of $82 million for the 25% royalty. The Turcottes came for a meeting in Houston. I remember Andy Turcotte saying: “Wow that makes me a millionaire!” He and his wife, Denise, owned 5% of the 25% royalty interest. I warned him not to spend the money yet since I had never tried to sell anything like that. He asked, “What would you charge?” Before the meeting was over, I told him that I would look into it and get back to him.

Fig. 10–3 US natural gas wellhead price, 1979–1982 ($ per thousand cubic feet)

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Salt Creek Field, West Texas Another major reserve study we did was on the Salt Creek Field in West Texas in 1983. The client was Rosewood Resources, owned by Caroline Hunt of Dallas. Our contact was Roy King, an engineer I met when working in Exxon’s East Texas Division. Rosewood wanted an evaluation to determine what the ield might be worth and to review reservoir operations. In 1983, the industry was in a downturn, but we were able to employ Keith Dowling, a young engineer fresh out of school, to work on the Salt Creek Field Study. Production in 1983 was being maintained by both water and gas injection. The Salt Creek ield, as seen from 3D seismic, is dual build-up of a reef on the sea bed. The ield is very heterogeneous Canyon limestone at a depth of 6,300 ft, with permeability ranging from 1 to 2,000 md, with an average of only 20 md. Average porosity is only 11%. The thickness of the oil column is 250 ft, as shown in igure 10–4.

Fig. 10–4 Oil column thickness of the Salt Creek Field in the canyon limestone2

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The ield was discovered in 1950, and water injection was started in 1953 with a line drive down the center of the ield with 40 acre well spacing. The water lood was modiied several times, and by the early 1990s the ield was developed on 20-acre spacing with 5 spot patterns. The PPC study was completed in 1984 prior to considerable inill drilling in the late 1980s and 1993, when the CO2 injection was started. We predicted ultimate recovery of 363 million bbl of an estimated 672 million bbl of OOIP, a recovery of 56%. In 1984, the producing water-oil ratio was about 3 to 1. After the 1984 PPC study, the operators took aggressive action to accelerate production by converting the ield from 40-acre spacing line drive water injection to 20-acre 5 spots, and in 1993 they implemented what is referred to as CO2 WAG injection. Figure 10–5 shows the production history through March of 2010. Note that in March 2004, the production was 24,000 bbl/month, and that the water-oil ratio was about 30 bbl of water for 1 bbl of oil. Using Paper 88720 data, the ultimate recovery was projected to be 403 million bbl or 60% recovery. The decline rate after the production increase was then 10% per year.

Fig. 10–5 Salt Creek Field production history3

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This analysis does raise a question in my mind. Did the inill drilling and CO2 add only 4% recovery, and did it primarily just accelerate production? A signiicant conclusion is that this is another example of a complex tight heterogeneous limestone reservoir where recovery of 60% can be achieved through the application of strong reservoir management, including the application of 3D to better understand the complexity of the reservoir. Figure 10–6 shows the oil price behavior from 1981–2009, according to the US Energy Information Administration (EIA). Note that most of the production acceleration was done in 1996–2000, a period of low oil prices, and how the 10% decline set in as prices were going up in during 2000 period. We did lots of other reservoir studies, but on a smaller scale. We maintained high ethical standards and resisted efforts by clients to make their reserves bigger than they should be. Ethics is required.

Fig. 10–6 US oil pricing from 1981–2009

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Property Sales In 1979–2005, we participated in some $250 million of property sales, representing the largest part of revenue earned by the two consulting irms, PPA and PPC. Sometimes we joined with others and shared a portion of our commissions. Typically, these would be sales in the range of $5–$10 million for small independents or large royalty owners. We made one $29 million sale, which was our largest. We would provide irms with an engineering and geologic study of the subject property and estimate the range of values we might expect. We would charge our client for those services, but we would reimburse them out of the commission we were paid, which was in the range of 2%–5% of the sales price for a smaller property, less than $1 million. We charged the prospective buyers a small fee of $100–$500 after signing a conidentiality agreement to acquire our data package. We would offer the package to a preselected list of buyers on a speciic date that had been approved by the sellers, and would offer a meeting in our ofice to review the data set. We offered the properties on a irst-come basis. For example, if we had an offer in tow, we would not see the second bidder until inishing discussions with the irst one.

Sarita S.K. East B Lease Account 2 In response to Turcotte, after we completed his reserve evaluation, we investigated what standard procedures were. Some suggested the Layman formula, that is, 5% on the irst million, 4% on the second million, on down to 1% on the ifth million and more. Turcotte and a few of his cousins agreed to that, and put up a total of 5% royalty interests out of 100% for ive sellers, keeping in mind that there were 230 individual royalty owners in the ield. In subsequent sales, Turcotte et al. agreed to a bigger commission later based on his satisfaction with the irst sale. The data set included the detailed logs that Exxon permitted us to have. At the time, Exxon was not interested in buying any of the royalty we had for sale. Exxon had put a rig back in the ield, and in 1981–83 we made four separate sales totaling $16 million from about 20% of the 25% royalty. We averaged $625,000 per percent of royalty, or the equivalent of $62.5 million for the full 25% royalty. We actually sold some as high 148

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as $825,000 per percent of the 25% royalty. A ifth sale went south and turned into litigation. Figure 10–7 shows the production history at the time of our irst sale. Note that the ield peaked at a rate of 59 MMcfd in 1970, but 12 years later declined to less than 1 MMcfd. Notice the pickup to about 3 MMcfd by the end of 1982 as the result of Exxon putting a rig back in the ield. Exxon put two rigs back to work as the gas prices accelerated.

Fig. 10–7 Mrs. S.K. East B Lease Account 2 production history

We were successful in our irst sales on the Mrs. S.K. East B Lease Account 2 for three reasons: 1.

Acquiring the logs and providing a competent log review by Jerry McQueen, 149

THE WORLD ENERGY DILEMMA

2.

Exxon’s putting two rigs back in the ield to redevelop the B Lease at the time we were trying to sell it, and

3.

The rising price of gas at rate of 20%–30% per year.

Companies with a vision of the future placed great value on the largely nonproducing asset because of their belief that gas prices would go up and their conidence that Exxon would redevelop the ield in a technically competent way. The results from Exxon’s development on the B Lease were most disappointing from a buyer’s prospective. Exxon spent $30–$40 million to reactivate the B Lease, drilling 5–6 new wells. As shown by igure 10–8, though, Exxon never got the rate above 7 MMcf/d after the royalty was sold. The buyers were extremely disappointed.

Fig. 10–8 Exxon production history through 1995 of the Sarita Deep Field, Kenedy County, Texas

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Amazingly, Exxon never fractured a single Sarita East Deep well during this 14-year time period with new high-strength proppants. Meanwhile, Exxon Research had developed two new high-strength proppants: bauxite and resin-coated sand. The bauxite was the same material that was used in the 19,000 ft Johns Field in 1987. Sintered bauxite was developed to overcome frac sand crushing at these depths and temperatures.4 Our analysis suggested a rate of more than 50 MMcf/d was needed to get a reasonable payout. Another discouraging thing for the buyers and for Exxon was the way gas prices dropped after the royalty was sold. The rapid rise in gas prices in 1979–1983 fell apart, and throughout 1986–95 hovered in the $1.50–$2 range as the producers strove to work off a huge gas bubble (ig. 10–9). Exxon was looking for a way out since much of the $35–$40 million they had spent had to be written off. Exxon found its way out on discovering a small independent, Headington Oil. That irm offered to pay Exxon a rumored $15 million or more for 320 acres, the sweet part of the 13,864 acre lease that included the area around B-20, previously discussed. Exxon retained the rest of the Sarita B Account 2.

Fig. 10–9 US natural gas wellhead price, 1979–1995 ($ per thousand cu ft)

It is surprising what competition, guts, and technology developed in the 1980s by Exxon Production Research can do to a tired old gas ield. Better gas prices can certainly help. Exxon owned the balance of the 13,865 acre B Lease Account 2 B Lease, and it responded to what was happening on the 320-acre portion of the B lease. Figure 10–10 shows 151

THE WORLD ENERGY DILEMMA

the total ield production from the 13,864 acre Account 2 B lease from 1968 through 2005, when Headington sold out to another operator. Note that the production rate peaked during 1998, a result of what Headington taught Exxon in how to produce from this dificult—but producible—lease.

Fig. 10–10 Total ield production 1968–2005 Sarita Deep Field Account 2 B Lease, Kenedy County, Texas

Over the ten years that Headington owned the 320-acre tract, it and Exxon brought the production up from 2–3 MMcf/d to a peak of 164 MMcf/d. Over this ten-year period, 103 Bcf was produced. Exxon started drilling to surround the 320-acre lease, and also started using about a million pounds of bauxite per completion. Figure 10–11 shows the related gas prices during this period. When production peaked in 1998, 152

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gas was still priced in the $2/Mcf range. So, the other factors discussed led to the big revenue change.

Fig. 10–11 US natural gas wellhead price, 1995–2005 ($ per thousand cu ft)

In the spring of 1996, Turcotte got excited. He still owned some royalty on the subject lease, and said, “You’ve got to come down and see what is happening to the B Lease! Headington, a new operator, must have purchased some of the B Lease. Headington has been drilling for ive months, and have just fraced their irst well Headington East #1, with 1.6 million pounds of a new material called bauxite. Exxon was now running 3D seismic over the whole lease, and it is a beehive of activity. They tell me that Headington is about to spud their second well.” Turcotte had it right: things were popping on the B lease. The old B-20 well (Exxon) was perforated only in the bottom 50 ft of the O-41, as noted earlier, and the well was never fractured before it was abandoned for mechanical problems. As our log analysis showed, B-20 had 383 net feet of pay with 83 Bcf of GIP with an assumed drainage area of 160 acres. Headington chose to do things differently. I recall they had extreme dificulty in getting the Number 1 East S well down, between losing returns and restoring enough mud in the hole to drill the well through the O-41 sand. Headington could not run an electric log on the well because of losing returns. They were able to run a through-pipe log and correlate with B-20.

153

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Knowing they were in the same fault block, Headington—at least by Exxon standards—made several gutsy calls: •

They perforated the entire 200 ft section of the O-41.

•

They never tested the well.

•

They proceeded to pump 1.6 MM pounds of bauxite through the casing, not the tubing as was Exxon’s practice. They must have used heavier wall casing than Exxon would run.

•

They brought the well on at 15–17 MMcf/d.

When Andy Turcotte and I visited the site, Number 1 Headington well was awaiting a pipeline connection (ig. 10–12). When we were there, Exxon had just spudded B-43 and at the same time was running 3D seismic on the rest of the B Lease. The rest is history. Headington and Exxon produced 103 Bcf over this 10-year period, versus only 22 Bcf produced by Exxon in the 14 years after the royalty sales. In the fall of 2005, Newield Oil & Gas bought out Headington Oil for a rumored $75 million. That’s more than four times what Headington originally paid. Newield also did a 50-50 joint venture with Exxon on the rest of the 13,860 acre lease. So, the rest of the story is Newield.

Fig. 10–12 Andy Turcotte, left, and Lou Powers at Number 1 Headington well

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Figure 10–13 shows the production history of the entire 42-year development of the Sarita S.K. B Lease. Newield brought the production back up to 72 MMcf/d with an active drilling program. They drilled additional wells on the 320-acre Headington tract, and they have brought the spacing on the tract to nearly 10 acres, including the junked and abandoned wells. They have also discovered new gas traps at 17,000 ft. Figure 10–14 shows the pricing history for US natural gas over these 43 years. Newield had the advantage of much higher gas prices, but note how prices fell in 2009 as another bubble in gas prices developed due to falling demand and a new supply of gas being brought on by shale gas development. Note the time period of the evaluation and the royalty sales. Those who held on to royalties or recently inherited it from deceased royalty owners in the 1980s have done well. In 2009 Newield cut back on drilling. Their latest completion is Mrs. S.K. B lease 94 as the 3D seismic has led them to ind gas at 17,000 ft down dip from the main producing area on the Headington tract.

Fig. 10–13 Production history of Sarita S.K. B Lease, 1968–2010

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Fig. 10–14 US natural gas wellhead price

East Seven Sisters, Duval County Texas East Seven Sisters ield (ig. 10–15) is located in Duval County, Texas, and is located along a trend of ields that had shallow production. Due to higher natural gas prices (as shown in igure 10–14) that brought about federal pricing for wells drilled below 15,000 ft deep and deeper horizons, the Wilcox pay became a hot prospect for drilling in 1983–84. At Seven Sisters, the pay zones were 10,000–15,000 ft deep. Don Boyd, shown in igure 10–16, who I knew during my time in Corpus Christi, had bought our irm’s Sarita data set. While he made some disparaging comments about the Sarita East Sale, he came to us and asked if we could sell his small WI and royalty interest (RI) in the J.W. Gorman Tract in the J.W. Gorman unit. Don was a strong personality, and well known in the South Texas geologic scene. He had won many awards in his professional career.

156

Fig. 10–15 East Seven Sisters ield sale leases

Fig. 10–16 Texas geologist and sales partner Don Boyd

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Don found the East Seven Sisters ield and retained a small WI (2.34% with NRI of 1.64% and also had an ORRI of 0.94%). Atlantic Richield (ARCO) was the operator. Before the sales were completed on the Gorman lease in East Seven Sisters ield, Don joined as a partner, and we ultimately sold some $70 million of WI and royalty interest from the J.W. Gorman and the offsetting Hazelwood lease to the east. We offered Boyd’s WI and RI for sale to ARCO and Exxon, but they were offering only half of what the sellers ultimately received. This was a deep Wilcox Pay that was very productive from somewhat tight sands, 0.5 to 5.0 md based on buildup tests, but it also was at the very high pressure of 12,000–13,000 psi. The trapping mechanism looked very similar to Sarita East Deep. The westernmost portion, 160 acres of the J.W. Gorman, was nonproductive at the Wilcox level because it was the wrong side of the controlling fault. The gas contained a high 4%–5% of CO2 that had to be removed before meeting pipeline speciications. Figure 10–17 shows the production buildup for the Gorman 640 acres.

Fig. 10–17 Production buildup for the East Seven Sisters ield, Duval County, Texas

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The East Seven Sisters rapid buildup in production was the direct result of the prices set by the FPC, which allowed prices for wells below 15,000 ft be set at more than $7/Mcf and for wells 10,000–15,000 t to be set as Section 102, or generally in the $3–$4/Mcf range. All of the Wilcox gas was priced at these higher rates. The gas contract did have a market-out clause, and just prior to the sale, the gas pipeline had reduced prices to $4/Mcf from $5/Mcf on June 1, 1983. This was reported to the prospective buyers. Table 10–2 gives the apparent gas-in-place (GIP) for three of the ive completions at the time of the sales: Table 10–2 Table of apparent gas-in-place from performance East Seven Sisters ield Gorman Lease Well

Zone

Apparent Gas-In-Place, Bcf

Arco Gorman 2

Howell

27.0

Arco Gorman 3

Howell

11.0

Sub Total Arco Gorman 4 Total

38.0 Reagan

4.5 42.5

Figure 10–18 illustrates the P/Z curve for J.W. Gorman 2 which shows the 27 Bcf GIP. Table 10–3 gives the shutin tubing pressures (SITP) which were converted to bottomhole pressures. We also used calculated bottomhole pressures from lowing tubing pressures. ARCO did a very good job of taking and providing both bottomhole and lowing tubing pressures, all of which was supplied to the prospective buyers. So, how did the buyers of the Gorman royalty turn out? On the one hand, it seems that Boyd’s understanding of the falling pressures and the declining gas prices was about right as suggested in igure 10–19. On the other hand, the P/Z plots apparently gave a good handle on the GIP, and when one considers the ifth well, which was just put on at the time of our sales, the P/Z data we provided in the data set should have alerted the sellers that production was about to fall.

159

Fig. 10–18 East Seven Sisters—Gorman No. 2

Table 10–3 East Seven Sisters bottomhole pressures Well

SITP (psi)

Gorman G. U. #2

10,286

8-17-82

7,800

3-02-83

Gorman G. U. #3 Gorman G. U. #4 Gorman G. U. #5 Gorman G. U. #6

Date

7,750

3-28-83

6,014

12-23-83

7,150

3-27-83

5,161

12-24-83

7,150

3-25-83

4,565

12-19-83

7,567

12-18-83

7,000

1-11-84

9,600

1-24-84

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Fig. 10–19 East Seven Sisters—Gorman Gas Unit production history, 1983–2010

According to Richard Sinclair, a noted fracing expert, most of the wells were fraced by ARCO, using resin-coated proppants that helped maintain low and held back formation production as Exxon experienced at Sarita Deep. Their irst frac job with the resin-coated proppants was in 1983. As production continued in the later stages, the pressure the resin-coated proppants was drawn down must have helped hold the reservoir rock in-place. A portion of the royalty interest was sold on the Hazelwood 160-acre unit at this same time and is included in the total sale number mentioned earlier. A similar analysis was made for the ive wells on the Hazelwood Unit. Exxon’s Farmer leases down dip and to the east offset this unit. The production proile for this much smaller unit for its ive wells was not too dissimilar from the larger Gorman unit. ARCO also fraced the Hazelwood wells with resin-coated proppant. Note in igure 10–20 that 161

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the Hazelwood Unit has produced 55.7 Bcf over the same time frame and that it has a much shallower decline.

Fig. 10–20 Hazelwood Gas Unit—East Seven Sisters production history, 1982–2010

Don Boyd impressed me with his ability to convince the other side when in his opinion differed on an issue. For example, he sold his small RI for an acceptable price. The offer letter included a comment that the company would buy his WI an equivalent price. When the WI offer came, it was not an equivalent price and Boyd took the buyer to task. They admitted that they had added an extra well in their irst offer and taken it out in the second offer. Boyd threatened to sue, and made all types of threatening suggestions to them. In the end, they increased their price and the sale was consummated. Later he asked me if I had ever read Lewis Ringer’s book Winning Through Intimidation. I had not, but soon did. Shortly after Don’s interest sold, I talked to one of the royalty owners. I had a $7 million offer to buy a portion of his interest from a company 162

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that was raising money in the market to buy properties. I met with the royalty owner who told me the offer was about right, but that the Don’s and my commission was too high. I closed up my brief case and proceeded to leave. He said, “Wait a minute! Don’t get huffy. Come back and sit down!” Our agreement called for a 2.5% commission of the sales price, and he wanted me to cut it to 2%. That is what you call a “commissionectomy,” and that is what Lewis Ringer’s book is all about. He has a chapter by that title in the book and explains what to do when it happens to you. I made four more trips to San Antonio with the same company that had $7 million each time to buy more of the royalty. You can igure what that 0.5% reduction in commission would have cost Don and me if I had succumbed to the pressure by the royalty owner on the irst trip.5 Another sale from the same leases was to a company in Louisiana. The seller was an independent out of Oklahoma City who owned a WI on the ARCO-operated Gorman tract. I sent the prospective buyer in Louisiana the brochure describing the property. They claimed they had not seen it after a couple of weeks, so I sent another one. This time, they claimed they already looked at it from another agent. I was sure that this was not right. I had an exclusive on the sale. So I called to talk to the president of the company, which was raising lots of money to buy properties. The secretary called back. She said to send the data set and that she would be sending the check for it. There had been a mix-up, she said. This time we were charging $500. At the seller in Oklahoma, I was dealing with a person who reported to the CEO. We inally got the offer up to $28 million, but the banks that held the company’s debt would not agree to the split between the banks and the company. The deal fell through. A month later I was visiting another client’s ofice in New Orleans, and I decided to pay a visit on the prospective buyer I had been dealing with. I introduced myself and said I was sorry that the sale had fallen through. The prospective buyer said they were “sure hoping to buy the property.” He understood that the Oklahoma seller had taken it off the market. I said, “That’s not quite true. Are you sure you cannot offer any more?” He said, “Well, maybe we have another million.” I said, “That might be enough.” I asked if I could offer that to the Oklahoma CEO, who seemed to be the sticking point along with the banks. The prospective buyer said, “Go ahead and see what they say.” 163

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Upon returning to Houston, I called the CEO and told him what had happened. This time he came back and said that he and the banks would do it. I called the Louisiana company and said, “It’s done.” The engineer for the Louisiana irm said he would have to go back to his board for inal approval. I waited 3–4 days for their call. The call came: “You know, Powers, the price of gas has been dropping, and my board would not back me up.” I had a pit in my stomach and dreaded making the call to the Oklahoma CEO to tell him my bad news. Then, two days later, I got another call from the Louisiana engineer. He said, “The board has changed their mind. We will do it.” So, we made a $29 million sale. I learned that I had to appreciate that what will be, will be. I learned to be persistent, patient, and calm. In the days of PPC, we made many more sales and it was an important part of our revenue.

The Armstrong Ranch Early in the days of PPA, I got a call from Joe Marek, a long-time friend during my Kingsville and Katy District days who was now working for Petrus Oil in Dallas. Petrus was owned by Ross Perot, who later ran for president of the United States. Joe was their acquisitions engineer, and a darned good one. He said, “We have a land man here by the name of Barclay Armstrong. His family owns a large ranch in South Texas. They would like to meet you.” Barclay’s parents, Tobin and Ann Armstrong (ig. 10–21), who served as US Ambassador to Great Britain during the Ford administration, managed and lived on the ranch in South Texas. The Armstrongs have a 50,000-acre ranch in the middle of the four divisions of the King Ranch leased by Exxon. I was familiar with the Armstrong ranch, and I had met Mr. Armstrong on one of my trips with Carl Peters during my time in the Kingsville District. The meeting in our ofice opened up a whole new line of business that I had not even thought about before Joe’s call. Present were Barclay, Tobin, and his brother John Armstrong, who was associated with the King Ranch, plus a couple of other family members. A key question was: would I alert them and their lawyer, Hayden Head of Corpus Christi, if I found that Exxon had done anything wrong? I doubted that I would ind anything, knowing Exxon’s mode of operation. So I agreed, and they signed a contract retaining PPA as their petroleum consultant. 164

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Fig. 10–21 Tobin and Ann Armstrong

Hayden Head wrote a letter notifying Exxon that they had hired PPA. After some debate with Exxon about the Armstrong’s hiring me, Head wrote Exxon again and advised them reread their lease agreement with the Armstrong family. Among other things, the lease agreement said that Exxon must share anything they knew about the minerals with the Armstrong family—a very unusual clause that was not in most lease agreements. The clause was in black and white, and it also covered the seismic data that Exxon had never shared. That contract began a very close and personal relationship with the Armstrong family that extended until we sold PPC 12 years later in 1995. I had not worked in South Texas or on the Armstrong Ranch since 1977. I had no problem advising Tobin and his family of my willingness to let them know of any problems I found. And we did ind a few problems that were more of an operational nature, rather than accounting. We

165

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brought these issues to the attention of the Armstrong family and that ended in an out-of-court settlement. While we never worked directly for the King Ranch, some of their family members hired us to look after some of their oil and gas investments. The family members were trying to diversify from just the royalty earnings on the King Ranch. One was Andrew Jitcoff, a son-in-law of John Armstrong, who asked me, “What would you do if you had a million dollars of your mother-in-law’s money and invested it in a half-dozen independent oil and gas operators. What kind of report would you do?” Back then, the income tax for the high income earners was running 70%. I told him, “I hope a good one. But let me see what you have.” Soon, we had a contract to evaluate his investments with several independent oil and gas programs. We worked this contract with the much larger irm of Miller & Lents as well as with a gentleman by the name of James Pierson, who Jitcoff had worked with before on some of the King Ranch mineral problems. Pierson was a gentlemen and a pleasure to work with. The project went on for several years, but the results of investing in the oil patch from 1984 through the early 1990s were pretty disappointing. We ended up trying to recover what funds we could from the operators and assisting Jitcoff in shutting down these investment programs.

Auditing Royalties from Oil and Gas Firms Our experience with the Armstrong family and what we were reading in the newspapers led us to seek another line of business that again was totally unexpected: auditing oil and gas companies payments to their royalty owners. When I worked at Exxon, I had little to do with payments to royalty owners, and I was not aware that royalty owners were not being paid according to their leases. Before this part of our work was inished, we had audited some 30 oil and gas irms, most of the majors as well as many independents in the post-crash period of the mid-1980s. We worked with lawyers as well as with other consultants such as Miller & Lents, and with natural gas expert Dick Jack. I lost some respect for oil and gas irms, and particularly some of their personnel. It had become a practice by many individuals 166

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within those companies to skim some of the cream off for the company by taking advantage of unsuspecting royalty owners, sometimes by mistake, sometimes for other reasons. We were not an accounting irm that told the oil companies that we were hired to look into their payment records. We were an engineering irm that, with the help of lawyers, would draft a letter for our clients and their lawyers requesting that certain questions be answered before we began the actual inspection of their records. This was a different approach from standard accounting irm audits, according to feedback we got. Many oil and gas companies, for whatever reason, took a long time to answer our questions. Some even required a second letter. Through these audit procedures, along with the help of several lawyers and other consultants, we were able to recover many millions of dollars for our clients. We found all types of problems: not paying market value for oil and gas; selling gas to an afiliated marketing company but not paying royalty on the actual sale price of gas; excessive marketing costs on gas; and errors in how they calculated the cost deducts, including the price of natural gas in the cost deducts which was given free to the producer. We even found some companies trying to hide behind the statue of limitations, hoping their past payment errors would not be found until it was too late. This is not meant to be an indictment of the whole industry. A few companies we found tended to be a lot worse than others. We never had a jury render an opinion over issues we found in our audits. A few lawsuits were iled, but the oil and gas companies always settled with our clients, with a conidentiality agreement and a clause in the settlements that usually read something like this: “We do not agree to the claims but want to settle amicably and to avoid further litigation costs.”

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Notes 1. A working interest (WI) owner pays his share of investment, operating expenses, and taxes as opposed to a royalty interest (RI), who pays no portion of the investment and operating expenses. 2. Bishop, Deborah L., SPE, ExxonMobil Production Company; Mike E Williams, SPE, Exxon Mobil Production Company; Stephen E. Gardner, SPE, Exxon Mobil Production Company; David P Smith, Exxon Mobil Production Company; Tom D. Cochrane. 2004. SPE Paper 88720. “Vertical Performance in a Mature Carbonate CO2 Flood: Salt Creek ield Unit, Texas.” SPE Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, Oct. 10–13. 3. Sinclair, Richard. 1983. “Improved Well Stimulation with Resin Coated Proppants,” SPE Paper 11579. Oklahoma City, March. 4. Ely, J.W., S.A. Holditch, and Assocs. Inc.; W.J. Cobb, William Cobb, and Assocs.; and B. Elkin, and D.D. Bell, Tominlson Interest. 1989. “Successful Proppent Fracturing of Ultra Deep Sour Gas Reservoir.” Conference paper. SPE Annual Technical Conference and Exhibition, Oct. 8–11 October, San Antonio, Texas. 5. Ringer, Lewis. 1974. Winning Through Intimidation. New York: Fawcett Crest Books.

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3

D seismic surveys were becoming popular as the new technology developed. We assisted in getting nonproductive acreage released

from Exxon for two large ranches: the Armstrong’s 50,000-acre spread and the East’s 40,000-acre Santa Fe property. We also assisted in getting 3D run on the 50,000-acre Kenedy Ranch. Through our in-house geologists, H.G. and Martha Mills, we had access to all of the 2D seismic on the Armstrong Ranch. They were convinced there were more prospects on the released Armstrong acreage. We worked with a landman by the name of John Hafner. In 1990–95, during the last few years of PPC, we and Hafner were able to get 3D seismic shoots on three large pieces of land. Ultimately, we know that one new ield on the Santa Fe Ranch, the Tom East Field, was discovered by Coastal States utilizing the new 3D seismic. On the Armstrong Ranch, Headington Oil

169

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was able to ind new undeveloped sands in the Candelaria ield. But as far as I know, nothing major has been found on the 3D shoot area of the Kenedy Ranch. 3D and now 4D seismic shoots also have been one of the major industry technical advances contributing to the growth in world oil and gas resources.

Oil and Gas Pricing Studies In the early 1980s, there was the rapid rise in oil prices, with a sharp fall by 1986 as shown in igure 11–1. Energy planners around the world were hungry for a deinitive analysis to the future direction of oil prices. In 1986 the Saudis decided not to be the sole swing supply of OPEC oil, and they increased production to more than 8 million b/d from 3.4 million b/d during 1986–89. In 1986 this caused US oil prices to collapse to about $12/bbl from $32/bbl. Energy planners received a great correction, as many forecasters saw $200/bbl oil just around the corner based on the rising trend during 1975–81. Then the unthinkable happened: King Fahd of Saudi Arabia, through his oil minister Sheik Yamani, told the world that his country would no longer be the sole defender of world oil prices.

Fig. 11–1 US Wellhead oil prices, $/bbl, 1961–1989

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PPC responded by forming a team of international experts, combined with Powers’s understanding of OPEC drivers, and prepared two reports, one in 1986 and another in 1988. One team member was Dick Martin, who had a 40-year career in the Middle East, including 15 years with Aramco and the remaining time with Iran, Iraq, and Kuwait. When I worked for Aramco in 1977–79, Dick was in charge of reservoir engineering. Also joining the team was W.M. Stevenson, a long time Exxon International exploration engineer. In the 1986 report we showed how different perceived prices would drive demand and OPEC capacity, and—as a result—the timing when OPEC capacity would get squeezed and world oil prices would take off. In the past, the surplus of OPEC spare capacity was controlling factor in OPEC’s ability to raise world oil prices, and it is expected to be in the future, as shown in igure 11–2. World oil prices seem to increase when demand reaches 85% of OPEC capacity. We analyzed the world on a region-by-region basis, and we projected world demand and OPEC capacity under pricing perceptions of $12, $20, and $30 per bbl to see how long it would take before demand on OPEC reached 85% of OPEC capacity. The study was sponsored by Rosewood Resources, the same irm that hired us to do the Salt Creek Field Reserve Study. We were allowed to sell the price perception study to other companies. Figures 11–3 and 11–4 show the results of our study. From these projections, one can see if industry perceived a $30/bbl price, then OPEC would have plenty of capacity for years to come. If industry perceived a $12/bbl price, the low price scenario will be short-lived, as OPEC surplus capacity would rapidly disappear.

Fig. 11–2 OPEC pricing behavior, 1975–1985

171

Fig. 11–3 Demand for OPEC oil vs. OPEC maximum sustained capacity

Fig. 11–4 Free world demand for OPEC production

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When oil prices dropped again in 1988, we undertook a second pricing study. That 1988 report was more comprehensive than the earlier one. It included our forecast of projected prices of US and world oil and US natural gas. It also included an analysis of when the US gas bubble would be depleted to justify a rise in natural gas prices. Table 11–1 shows the results of our study. T. Boone Pickens was one of the more interesting customers who bought our pricing study. Mesa Petroleum, Pickens’s company, was in discussions with Tenneco for a major buyout of their oil and gas properties. I had about two hours with Pickens on a private plane light from Lubbock, Texas, to present the study. As I recall, he thought our study was a bit conservative. Who knows? He went on to become a billionaire when the price spike of 2007–2008 happened due to tight OPEC supplies. Table 11–1 Oil and gas price forecast, 1988 Escalated Price Scenario

Oil and Gas Price Planning Forecast ($/Bbl and $/Mcf)

(1988 $)

(1988 $)

Middle East Light

Range of Middle East Light

Range of Middle East Light

Range of WestTexas Intermediate

USA Gas Prices

1988*

17.00

14.00–15.00

14.00–15.00

16.00–17.00

l.50–1.60

1989

17.00

15.00–17.00

15.00–17.00

17.00–19.00

1.70–1.90

1990

17.68

17.00–19.00

18.00–20.00

20.00–22.00

2.20–2.40

1991

18.39

21.00–23.00

23.00–25.00

25.00–27.00

2.90–3.20

1992

19.12

23.00–25.00

26.00–28.00

28.00–30.00

3.50–3.80

1995

21.51

26.00–28.00

33.00–36.00

36.00–38.00

4.50–4.80

2000

26.17

31.00–34.00

48.00–53.00

53.00–57.00

6.60–7.10

Year

Nominal $ (4% Inlation after 1990)

*2nd half

In retrospect, our forecast for oil price increases was about 10 years ahead of its time. When the price increase did arrive in about 2005, the problem was brought home in spades, as seen in igure 11–5. The concept we were trying to portray in our 1986 study is shown in igure 11–6. Oil prices then and now are mostly controlled by OPEC and in particular by Saudi Arabia. Speculators also play a role as well as the price of the dollar. Much of what happens to oil prices depends on how much spare capacity has developed among the OPEC countries, as pointed 173

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out in our 1986 study. The spare is affected by OPEC capacity levels but also world demand. Note how capacity grew faster than demand in 1990 after the irst Gulf War. But by 2005, the spare capacity had just about disappeared.

Fig. 11–5 Weekly US spot price FOB weighted by estimated import volume. Source: EIA.

Fig. 11–6 OPEC production and capacity. Source: Petrie Parkman & Co.

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PPC’s 1988 report did not have this much growth in OPEC capacity, but it also did not have the Gulf War of 1991, when oil prices popped up to $40/bbl for a few hours before the government opened the US storage spigot. Wars and instability in the Middle East have had a lot to do with how much available spare OPEC capacity there is. Construction of new oil facilities in the Middle East are critical to maintaining a stable low of oil, if and when world demand starts to accelerate after the tough economic times following the global crash of 2008. Referring back to table 11–1, US gas prices were projected to climb to $6.60–$7.10/Mcf by 1990 from $1.50 to $1.60/Mcf. Figure 11–7 shows that we were about 10 years too early in our projections, as we were with oil. Until the most recent new gas bubble, which began in 2009–10 due the success of shale gas drilling, a ratio of oil price to Mcf of gas of about eight could be expected. BTU parity should be about six to one. Recently, the ratio has been 20–25 and at the time of writing was over 50 to 1, an all-time high.

Fig. 11–7 Monthly US natural gas wellhead price. Source: EIA.

So, why are gas prices so suppressed relative to oil? Answer: there has been too much gas drilling, with too little demand. Figure 11–8 shows OPEC’s spare capacity, including a 2010 estimate by the EIA and a February 2010 estimate by the International Energy Agency. OPEC spare capacity was just 3.3 million b/d. Figure 11–8 explains part of the increase in prices in 1998 in relationship to the sharp fall-off in surplus OPEC capacity in 2007. Note that most of the increase in surplus capacity in 2008 was due to the sharp rise in oil prices and falling demand, during 2007–09. 175

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Fig. 11–8 OPEC spare oil capacity, MMBbls/D

Figure 11–9 shows the historical world oil demand as provided by the EIA and a different forecast by the IEA for 2010 and 2011 as of February 2011. The key question for energy planners is: How will all of this 4 million b/d day increase in demand be met? Will this demand be met at today’s prices of crude, around $80–87/bbl, or will demand be suppressed by prices in 2011 moving above $100/bbl? Or are we already there?

Fig. 11–9 World oil demand, MMBbls/D

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The falling dollar also had an inluence, but table 11–2 shows that the relationship between the market and oil price is stronger than the dollar and oil. This is further illustrated in the last year the dollar and oil correlation seems to have fallen apart, as shown in igure 11–10. Table 11–2 Correlation, oil vs. US dollar, S&P 500, US petroleum inventories. Period

Oil vs. Dollar

Oil vs. S&P

2000–2004

–0.69

2005–2007

–0.57

0.57

2008

–0.85

0.81

2009

–0.92

2010 through April

0.37

0.00

High Low

0.88

Oil vs. US Inventory Low

-0.41 -0.01 -0.33

High

0.91

Low

0.27 0.61

Source: Bloomberg

Fig. 11–10 Relative strength of oil, market, and dollar

Almost all of the growth projected in OPEC capacity in 2010 is coming from Saudi Arabia. Recent events in the Middle East, such as the Egyptian and Libya uprisings, make long-range forecasts for crude extremely speculative. Without stability in the Middle East, we may be looking at the next move of $100/bbl plus. Or we’re already there. In February 2011, analyst Raymond James Energy said most of the world is already at $100/bbl, but because of a lack of capacity out of Cushing, where the WTI is priced, the US WTI is far below world markets. Part of the reason is the inlow of crude to Cushing from Canada and 177

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horizontal drilling in North Dakotas’s Bakken. Historically, until January 2010, the US WTI has been priced at $2–$3/bbl above foreign crudes in London. The problem for US producers has been growing and, as illustrated in igure 11–11, this historical differential has now grown to a record negative differential of $l6.25/bbl with Brent Crude. To better relect on world oil prices, Raymond James forecast Brent Crude at $97.50/bbl for 2011 and $104.5/bbl for 2012. One of the obvious solutions to the differential pricing problem is more pipeline capacity out of Cushing. The $7 billion Keystone Pipeline, coming from Canada to Houston via Cushing, has been held up by the EPA and the Obama Administration, along with others who simply don’t want the line in their backyards. Meanwhile, thousands of jobs are on hold, and America’s energy dilemma continues.

–

–

–

Fig. 11–11 Spread of WTI over/under Brent, January 2004 to January 2011. Source: Raymond James Energy.

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Relating Oil Prices to Gasoline Prices So how do oil prices relate to gasoline prices? From our work in 1992–94 with the First Federal Bank of Texas, we generated the curve shown in igure 11–12, which shows the historical relationship. Note also that there have been periods where the national average price of gasoline has spiked up above the related oil price. This was a good time for reiners, and their “crack spreads” were at high levels. In mid-February 2012, when this chart was prepared, the WTI price for oil was $90/bbl, Brent was $102/bbl, and gasoline was $3.29/gallon. These are national averages, and do not relect higher prices in certain states such as California. At the top of the graph, the correlation suggests that if WTI oil rises to $150/bbl, or Brent, more relective of world prices per this graph, then the national average gasoline price should be somewhere around $4.30/gallon. Yes, the pain at the pump will be severe. As of the middle of March 2012, WTI prices have risen to around $106/Bbl. Brent was priced at $125/bbl, which its the national gasoline price of about $3.81/gal.

Fig. 11–12 Inlation adjusted real oil and gasoline prices

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Natural gas prices do not correlate with crude oil as they have in the past. A key question is whether the operators will be able to curtail gas drilling enough to bring capacity in line with demand or whether they will be require—due to new lease commitments—to drill ahead, with the result a gas bubble and low gas prices. Figure 11–13 shows the US gas rig count. Note the 2010 build up to a peak of 992 rigs. The count remained around 900 until a drop to the 600 rig level in the spring of 2012 as gas prices continued to sink. The mid-March gas price is only $2.30/Mcf with oil prices of $106/ bbl with a resulting all-time high ratio of 40:1, based on the near month future contacts as of March 7, 2011. This is an all-time high, and it compares to BTU parity of six to one. Note: at one time in April this ratio got as high as 50:1. Figure 11–14 shows the improvement in productivity from 2007 of 630 Mcf/ per well to 900 Mcf/well in 2010. Figure 11–14 also shows the estimated onshore 48 supply growth versus rigs drilling.

Fig. 11–13 US gas rig count. Data from Baker Hughes.

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Fig. 11–14 Onshore US natural gas supply growth and rig count1

With gas prices currently in the $2.30–2.50 range per Mcf, the incentive for continued dry gas shale drilling is disappearing. Demand has been reduced somewhat by the overabundant supply as well as the economic weakness in 2009 and early 2010, as shown in igure 11–15. Drilling in the wet-gas areas has contributed to the oversupply of natural gas.

Fig. 11–15 Annual US natural gas consumption. Source: EIA.

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I have reviewed two other 2011 opinions by respected energy analysts. George Little said that his irm Groppe, Long, and Little could see gas prices at $8/Mcf in 2012. Little’s irm is very pessimistic about the accelerated natural gas decline in the Gulf after the 2010 BP incident. Little’s irm also is pessimistic that shale gas will be as big a resource as most people view it. The second opinion I considered came from Raymond James Energy, which forecast $3.75 per Mcf for gas in 2011 and $4.25 per Mcf in 2012. In May of 2012, the 12-month strip price for natural gas was down to $2.50/Mcf. Again, I see it as a matter of perception. If industry perceives a short-term gas price of $8/Mcf, then gas prices will be low due to excess drilling. But if industry perceives the low gas price of $3.75, then the rig count should fall abruptly and gas prices will be higher. What will crude oil and natural gas prices be next year? Predicting future prices for making investment decisions is a major dilemma for most oil and gas companies. Since consumers do not necessarily see the wellhead price, it may be instructive to compare the wellhead price and the retail price. Figure 11–16 shows that there is quite a difference between the price paid by the electric power companies and the price paid by the residential consumer. There seem to be unusual peaks in the summers of 2007 and 2010 that are not necessarily related to wellhead prices.

Fig. 11–16 Average consumer price of natural gas in the US, 2007–2010

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PPC and BP Exploration In 1993 PPC was sponsored by BP Exploration to perform a study titled Lower 48 Gas Supply. This study, with new database systems, allowed us to review the gas supply situation in depth. PPC vice president George Hite and computer whiz-kid Mark Roach performed this study in great depth. Principle conclusions reached were that: 1.

The US is headed for a gas supply shortfall if demand continues to rise.

2.

A price of at least $2–$3 needs to be anticipated in most of the seven regions to yield a satisfactory return that will justify increased drilling. In the Gulf of Mexico offshore, prices as high as $4/Mcf will be required.

Let me detail these conclusions. Regarding the irst conclusion, the winters of 1993/1994 and 1994/1995 should verify the conclusion. Actually, it was the winter of 1996 before prices went over $3/Mcf from $1.60 in the winter of 1993. As igure 11–17 shows, demand in 1991 and 1992 was beginning to rise, but prices had not yet responded. Consider igure 11–18 and note that in 1990, for one month, the price of oil to gas reached 25:1 and averaged only 14.9 for the year. This compares to 50:1 today. Most followers of industry gas prices seem to have forgotten the bad times for natural gas drillers in the past.

Fig. 11–17 US gas consumption vs. price

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Fig. 11–18 Ratio of WTI posted prices to Texas Gulf Coast spot gas prices. Source: Oil & Gas Journal and Natural Gas Clearinghouse.

Regarding the second conclusion, igure 11–19 shows that the price of natural gas on average at $1.51 was not suficient to receive an adequate return when the inding cost of the gas was $1.03. Note that igure 11–19 also shows the Section 102 and 103 FPC-regulated prices which were used to stimulate drilling. In 1991, only one region, the Rocky Mountain region, had inding costs low enough to justify drilling for natural gas in 1990–91.

Fig. 11–19 Economic results—seven regions

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A few other facts show the in-depth nature of our study. There were nine regions and an area breakdown for each region studied as well as the subregions. For each of the subregions shown, a type production curve was developed for each region by year. This type of curve was developed for the recompletions in the region as well. The individual curve for each well was volume weighted by year. The type curve was weighted by the most recent years and used to develop the predictions from each region. This was based on a given rig forecast allocated between the regions, considering historical trends. The inding cost curve for each region was developed over time, the number of active gas rigs was developed, and then an overall production curve was combined into one overall forecast for a certain level of rig activity. Production history for practically every gas well in America was downloaded from a commercial database. Note: this was before the innovation of shale gas drilling with 1–2 mile laterals and new horizontal fracturing technology. A redo of this study today would produce an interesting look at the future of natural gas supplies in America. At the time of the study, the accepted proven reserves for the lower 48 states came to 160 Bcf. However, our study suggested that the nonassociated gas reserves were some 41% larger than those reported by the US Department of Energy. Figure 11–20 shows the importance of a robust drilling program to maintain gas supply in America. Net imports were forecast independently. Special elements included such things as coal seam gas, Wyoming’s LaBarge ield, and the Mobile Bay Field. These were relatively new large projects and did not it the averaging technique. The potential for shale gas had been recognized in 1992 but the real potential was just beginning to be imagined. In igure 11–20, the small blue band represents two small gas-producing areas, including California. The black area was an independent forecast of casing head gas for the seven regions. The red area was the PPC analysis for nonassociated gas wells with no new drilling. Note the sharp drop in forecast gas supply by early 1994. This sharp decline was to be expected since a look back in history showed the sharp drop in production as wells were put on production as shown in igure 11–21. In igure 11–22, we see that there were only 684 rigs running with 52% dedicated to gas drilling or 356 gas rigs in 1993.

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Figure 11–23 shows the lat demand case through 1996, with two rig schedules, the blue case shows rigs constant after 1993 and the red case shows the deliverability developed with the rig rate escalating by 8% per year through 1998 and then 2% per year thereafter. Note that only the irst ive years of the prediction are shown. An interesting point is that the rig count was gas 364 in 1993 which compares to the 600+/- rigs to balance supply today.

Fig. 11–20 Base ixed natural gas supply forecast, lower 48

Fig. 11–21 Lower 48 gas supply history by completion date

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Fig. 11–22 US rotary rig count, active rigs

Fig. 11–23 Lower 48 gross withdrawals—based on a zero percent demand growth case

Figure 11–24 shows a 2% demand growth and a third rig schedule to provide excess deliverability throughout the forecast period. This case includes 1,200 rigs by 1994 up from 684 in 1983. Total resource potential at the time of the 1993 Gas Study was estimated to be between 1065–1295 TCF. Of this amount, only 37–57 TCF was shale gas.

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Fig. 11–24 Lower 48 gross withdrawals—based on a 2% demand growth case

Since the end of 1982, an estimated 520 TCF has been produced, so a large part of the nonproved reserves have been added to the proved reserves. The reported proved gas reserves as of 2008 now stand at 250 TCF. Starting in about 2000, the increased contribution from shale gas is self-evident from igure 11–25.

Fig. 11–25 Annual US nonassociated natural gas, wet after lease separation, proved reserves. Source: EIA.

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Notes 1. Smith, Art, Triple Double Advisors, LLC. 2001. “Fast Balls, Curves, Change Ups and Wild Pitches in the 2011 Oil and Gas Market.” SPEE Luncheon, February 2.

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12 FROM SCHEMES TO SCAMS

D

uring the course of my career, I had the opportunity of serving as an expert witness in a number of legal cases. One of them was a

Ponzi scheme that took place in 1969–70 and involved some high-proile investors who were scammed out of $125 million. The case dragged on for 22 years before it was inally resolved. The oil operator, Homestake Oil Co. of Tulsa, collected money from rich investors to invest in certain heavy oil properties in California’s Santa Maria Basin. Back then, some thermal operations appeared to be working in certain types of heavy oil ields where the API gravity was greater than 16°API. These were not necessarily in the tar ields of the Santa Maria basin, where the API gravity was in the 10–12° range, where more sand was produced than oil. The oil price for the tar at that time was in the $1–$2/bbl range. Each year, Homestake would raise money from investors and give part of that new inancing to the 191

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previous year’s investors to make them think that they were getting a return on their money—a classic Ponzi scheme. The original suit was iled in 1973–74 with the investors alleging fraud during 1970–71. I was contacted in 1985 to testify on the merits or value of steam looding the tar. Homestake had been attempting to inject steam in the Santa Maria Basin. I was asked to testify based on my experience with steam looding at JPR in the early 1960s. Another engineer by the name of Harvey Coonts was hired for his familiarity with the speciic California properties. PPC was hired to present evidence of the values of the properties in 1968–69 for the damages portion of the trial. The trial had been ongoing for 12 years, with Homestake and their oficers eventually found guilty. Our part in the process was to help develop the damages that the court should assess. Unbeknownst to me, the Wall Street Journal had been following this case since its inception. Its investigative reporter David McClintick later published a book on the case called Stealing from the Rich. I was not aware of this book at the time, but it contains a letter that was introduced into evidence at the earlier hearings. The following is a paraphrase of what Homestake’s chief engineer Fred Greer wrote to Homestake CEO Robert Trippett: I have not been feeling too well recently and I have been to a doctor and a psychologist; both have stated I have a case of ulcers and, while they have different cures, there is one common thread, “that is you should rid yourself of your anxiety that is causing the problem.” You and I both know what that is; it is the $25 million that you collected last year from investors and I never spent. Worth noting, by the way, is the fact that the irm’s stationary reads: “Write it, don’t just say it.” The trial was held in the federal court of Tulsa in the spring of 1987, 17 years after the fraud occurred. Trippett served as his own attorney, and said, “My value, which was zero, and his own consultants were way too low and he thought the value should have been at least $40 million.” The jury placed a value of zero on these properties with a price of $1/bbl of oil. That was the end of my involvement in the case, until 1994–95 when I got a call from a lawyer in Washington DC who I could just barely 192

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remember. He said: “Do you remember me?” I said: “Just faintly. A lot of water has passed under the bridge since I worked with you.” He said: “Do you still have your iles on the Homestake case?” I said “No.” He said, “We need to hire you again and retry the case in the Tulsa Federal Courthouse again.” I could not believe what I was hearing, 25 years after the fraud took place. The lawyer said, “After the Tulsa trial in 1987, Mr. Trippett, et al., appealed his case to the 10th Circuit in Denver, and we had to present all your testimony and exhibits again. Trippett lost again but now took his case to the US Supreme Court. The Supreme Court ruled that our case had gone on too long, and applied a statute of limitations and threw out the whole case. The plaintiff’s lawyers knew a few people in Washington who were able to attach a rider to one of those must-pass bills that exempted us from the limitations ruling. So, now the plaintiff’s claim is alive again.” The lawyer continued: “There was an accountant that they did not pin down in the irst trial that signed off on the fraudulent books. Seems this accountant, when he signed the books, had a liability insurance policy that we missed, and we need to retry the case in Tulsa.” I could not believe it. They had another California engineer for me to work with, and they wanted me to go to San Francisco to meet with him and their California attorney. I made the trip, reviewed the iles they sent me, and prepared for my deposition in Tulsa. I gave my deposition, and it went ine. Homestake had hired a brand new engineer who also had to catch up on the case’s 25-year history. We were set to go to trial the next month when I got a call: “Powers, be at rest. We got a multimillion-dollar settlement from the insurance company of the dead accountant. There will be no trial.” The settlement number was under a conidentiality agreement, as most were. But while I do not know the exact number, the total won from all defendants approached the $125 million that was stolen in this oil-patch Ponzi scheme. Considering the time and the value of money, the lawyers were probably paid 25%–30%, while the investors got only a portion of their money back. In an interesting side note, Trippett, a well-known Tulsa oilman, was criminally indicted but spent only one night in jail. Apparently, he did 193

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not steal anything from any Oklahomans, only from rich investors on the West and East Coasts.

Drilling Rights for Pinnacle Reefs Another interesting case that took many years to settle involved the right to drill and explore Pinnacle Reefs in the undrilled portion of the Niagaran Pinnacle Reefs, which extend across northern Michigan. Some of these reefs may be 600 ft thick, but they are relatively small at 80–160 acres. It was a statistician’s dream. Miller Brothers hired a very strong team of engineers, statisticians, and exploration geologists, and the team was led by a very capable lawyer, John C. Jones out of Grand Rapids, Michigan. Pete Rose, former AAPG president, was hired to develop the statistical probability of the number and size of reefs expected to be found under the disputed lease. Even though the leases were legal, the Department of Natural Resources (DNR) refused to grant drilling permits under pressure from environmental groups in Michigan. Miller Brothers, a leading Michigan independent, had obtained the leases in the late 1980s. But by 1985, Miller Brothers was getting concerned that they would never be able to drill the leases, which were within the boundary of the Nordhouse Dunes State Park. That park does include some beautiful white dunes along the seashore of Lake Michigan, but this was not where Miller Brothers planned to drill. The area they planned to drill was not a beauty spot, but that did not bother the environmental groups. One of the Miller Brothers sons gave us a ly over on our irst trip, conirming my observations about beauty spots. The team was assembled and given our assignments. PPC’s job was to take the input from all of the groups and build an economic model. We were to include all of the operating and capital costs, the product price forecasts, and the volumes of oil and gas. Then we were to predict the economic value of what might have been realized, adjusted for risk. Chuck Brittan, one of our engineers, was assigned the task of building the model and did an excellent job, showing damages to the operator and their partners of $47 million. The time came for depositions, and I was off to Michigan. All of the experts on our team were deposed. The state hired the Michigan State 194

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Geological Survey to testify during the irst trial. Our lawyer, John C. Jones, was able to blow the state’s case out of the water, and we then proceeded to trial. This case was tried before a judge in 1987, with no jury involved. The judge awarded the Miller Brothers their $47 million. By this time, though, we also had been hired by the mineral owners who held the leasing rights when the State Park was established. They joined the fray, with a value claim in the $30 million range. We were hired to support their claim. The case was appealed to the Civil Court of Appeals, and in 1989 it was reviewed by a panel of judges, which remanded the case to the lower court. That court ruled that there had been no permanent taking since the leases were still in effect and that the DNR could issue drilling permits any time they wished. They were encouraged to do so immediately. This panel then sent the case back to the lower court where they were charged with determining what the 10-year delay had cost Miller Brothers and their partners in terms of discounted money. There really was not much case law on this particular procedure. We had to develop one from scratch. It needed to include what the oil industry in general could expect on their average return of equity and a price forecast for everything, including product pricing and expenses. It also had to include actual prices and costs that the industry had experienced during the 10-year hiatus. This time the state had hired a geologist from Denver who suggested a maximum claim of just $3 million—a surprising difference from our analysis. By the time of the second trial, the Denver geologists had been dismissed and the state brought in a Harvard economist with a price tag of $400 per hour. We went back to Michigan with Chuck’s model work and gave depositions. On this occasion, our calculations showed damages higher than the irst time: $72 million to the operator and $40 million to the leasers. Again the state protested and their Harvard economist had numbers much lower, similar to what they had before. But the Court of Appeals accepted our calculations and ordered the state to pay our damage model calculations of $120 million, which included the Miller Brothers claim and that of the leasers. The case was appealed to the State Supreme Court of Michigan. The state was looking for a settlement and offered to pay Miller Brothers and their partners $59.5 million and the leaser’s $30 million subject to a vote of approval by the state legislature. The leasers also had to give up their mineral rights on the leases. The legislature met to debate the issue, with the endorsement of Governor 195

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John Engler, and it passed by a vote of 56-44 in the House and 22-13 in the Senate. This proved to be an expensive lesson for the State of Michigan’s taxpayers and the other groups that interfered with the legal rights of citizens and wanted to stop progress in the development of our country’s energy. The federal government, which has made a practice of cancelling legal leases during the Obama administration, should be subject to the same type of penalties.

PPC Defends Exxon I was proud to be called upon to defend Exxon, my old employer, in a lawsuit brought by Wesley West, a well-known name around Houston. We were to be part of a team primarily headed by Core Lab, a much larger consultant from Dallas. We had two primary jobs: to do log analysis to defend Exxon’s position where the original oil-water contact was, and to shed light on why no gas injection project was ever initiated. Houston consultant Miller & Lents, whom we had worked with before, contended that Exxon had imprudently managed the ield by not initiating a gas injection project—one that I apparently was involved with during my time as division reservoir engineer in the East Texas Division in the 1970s. The East Clear Lake ield had a large gas cap with a thin oil column that was mostly depleted at the time. In order to make their damage claim larger, Miller & Lentz attempted to prove that the original oil-water contact was much lower, which would give a much larger oil column than had been accepted for over 20 years by Wesley West and Humble, too. The Wesley West contended that Humble should have implemented a gas injection project a letter from the Baytown District Ofice had recommended back in 1970. That’s when I was division reservoir engineer. So, I was familiar with the situation. Lynn McCoy did the log analysis and conirmed that the original oil-water contact was correct, contrary to Miller & Lents, who were trying to prove that the oil reservoir was much bigger so that they could calculate bigger damages. During my deposition, I think the lawyers thought I had been called to be a fact witness only, since I was employed by Humble at the time of the infamous gas injection recommendation 196

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letter. When the opposing lawyers asked my role, I told them I was pleased to represent Exxon in this case as a consulting engineer and to provide some history of what had happened and why the District recommendation letter had never been acted upon. At that time, they asked for a brief recess, but later returned to continue the deposition. They wanted to see a copy of a letter responding to the District’s request. There was none. As I recalled, the District’s letter was given to one of my division reservoir supervisors to review. He apparently decided that District’s proposed gas injection project was uneconomic. There was a large gas cap compared to the size of the oil column. Apparently, either he or I had called the District and told them the project was not approved. There was no paper trail. Later at the trial, we testiied again. Frank Harmon was able to weave the story of how Miller & Lents was hired to blow up the size of the oil reservoir to make the damages look larger, since some oil was allowed to move into the gas cap as the gas cap was depleted. Lynn McCoy, along with Core Labs, testiied that the original oil-water contact had been established for some 20 years and that it was the same today as it was then. The Jury agreed with Exxon’s position, and Wesley West was awarded nothing in this multimillion-dollar lawsuit. I understood that the Miller & Lents bill was well over $1 million. I have no idea how big Exxon’s bill was. Shouldn’t a judge be required to enter an order to have required Wesley West to have paid all of Exxon’s costs to defend itself? This might do away with frivolous lawsuits such as this one and free up the courts to consider cases that are more reasonable. The Texas Legislature recently passed a law that would have allowed Exxon to do just that.

Crossed by Rubicon In 1992, PPC was hired to defend Amoco in a property trade that had fallen through. Amoco was sued for over $800 million dollars on an $18 million oil deal. No formal written purchase offer was ever submitted by the plaintiff, Rubicon Oil Co. of Houston. The two properties offered for sale by Amoco in 1990 were in the Landers and Winklemen Dome Fields in Wyoming. Both were mature ields that produced 18 bbl of water for every bbl of oil. The ields were in a long decline and were over 197

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60 years old. The lawsuit was iled in Bay City, Texas, but the oilields were in Wyoming. Rubicon’s attorneys got the case transferred to Texas by including in the suit two Amoco engineers who resided in Texas and then dropping from them from the lawsuit as the case went to trial. Amoco had the ield up for sale, and Rubicon, a small Houston independent, called an engineer with Amoco in their Denver ofice and offered to purchase the property for $18 million. This sounded like a reasonable offer to the Amoco engineer who took the call. Rubicon was asked to put the offer in writing and to complete, sign, and return Amoco’s bill of sale. Rubicon never did. Based on a call I got from another lawyer, I was suspicious. He told me that he could not believe I was going to testify in Bay City, Texas, defending Amoco. He told me, “You will lose, and I do not even know what the case is about.” That should been warning enough, but I proceeded. Based on testimony at trial, Rubicon felt that the engineer accepted the offer, which Amoco denied at the trial. In all of my experience in selling properties, I never knew of a mineral interest being sold without a signed written contract by both parties. When we sold properties, we always had a written purchase and sale agreement signed by both parties. Since no records were retained either by me or the defense attorney, I can only report on the outcome. I was called to testify at the end of a four-week trial, but I could not believe what happened from that Friday, when I testiied, until the next Monday. When it came time for my testimony, on the last day of a four-week trial, the attorney, John O’Quinn cross-examined me. I was not in attendance earlier in the trial. He kept referring to my charts as nothing more than pretty pictures. He and the judge decided to throw out about half of my charts, and I could not present them to the jury. The charts were my whole case. That weekend I went to our farm near Crockett, Texas, and drove to town to get a morning newspaper. There it was in big bold headlines: “Bay City Jury awards Houston Independent $417 million.” I could not believe my eyes. That much on an $18 million property? I nearly collapsed with anger, and swore before I died I would do everything I could to try to change how judges are elected in the State of Texas. 198

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It turned out that the jury did ind the plaintiff’s claim a bit outlandish and cut the damages to only $125 million on this $18 million oil deal but did slap Amoco with $250 million in punitive damages and $42 million in lawyers’ fees. It also turned out that Amoco and Rubicon chose to settle out of court for some $50 million. Why Amoco settled, I do not know. I was not privy to their conversations. Maybe the $417 million that they would have to pull out of their bank account to appeal the case was an issue. One inal issue is how Rubicon ever got this issue into the Texas courts. The property was in Wyoming, and Amoco’s ofice was in Denver, Colorado. The plaintiff’s lawyers named a couple of engineers in Amoco’s Houston ofice as defendants in the case. Amoco had operations near Bay City, and the judge hearing the case allowed it to be tried in his court. Subsequently, the plaintiffs dropped the two engineers from the suit as the trial began. Each time we elect judges in Texas, I’m reminded of the RubiconAmoco lawsuit. Most of us never know who the judges are that we elect. Are they bought or not? My suggestion is let a committee of the State Bar pick them subject to recall by a vote of the public and a two-term limit. Never let a lawyer work a case in a courtroom where the lawyer or the lawyer’s company has donated campaign money. These are just some thoughts that I have developed after testifying or giving deposition in 34 separate cases in my 33 years as an independent consultant. One inal point: when I sold PPC in 1995, my company and I were sued over a recommendation of mine concerning a top lease in a West Texas ield. There was no basis for the suit, and—two years later and $180,000 poorer paid for a lawyer to defend it—the plaintiffs dropped the case against me and my company as long as I would not countersue them. My wife and I decided to stop the bloodletting even though I thought I had a good basis to countersue. One inal recommendation: if you ile a suit and then drop the suit, the judge must issue an order that the plaintiffs should pay all of the lawyer and court costs for the defendants who were wrongly sued. In my opinion, this would go a long way toward reducing the number of frivolous lawsuits.

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13 A Traveling Man

A

s an independent consultant I thought exposure to other parts of the world was a necessary part of my business knowledge. I

needed to travel to get a broader understanding of the changing world of energy. My travels took me to Europe, the Middle East, and the former USSR. On balance, these overseas trips built my conidence of the world energy situation, and they also prepared me to develop my thinking on world energy problems, including America’s lack of energy direction.

The Middle East In 1987 I made two trips to the Middle East along with Ron Lantz, my friend from JPR. The trips included a return to the Middle East Oil Show, which had expanded a lot since its start in 1979. It was my hope to sell some copies of our PPC 1986 pricing

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study, while Ron’s purpose was to sell his software. As I recall, we sold one copy to the Abu Dhabi National Oil. Ron and I made a second trip to the region to visit Kuwait, Abu Dhabi, Dubai, Oman, and Saudi Arabia. I thought I had sold my pricing study to Kuwait Oil Co. But as the gentleman was walking with me to the presentation room, he said, “By the way, I do not have management approval yet to pay you for your study.” My face, I am sure, turned like I had been just taken, but I went ahead and made the presentation, hoping he would send me a check. He never did. On the trip to Kuwait City from the airport, there were lashing lights and a road block. Soldiers were looking for bombers who had struck the reinery in Kuwait the night before. Kuwait’s production suffered severely during the irst Gulf War but is back up to 2.5 million b/d. I have heard that Kuwait’s reserves may be overstated by as much as 50%, an estimate made by Petroleum Intelligence based on internal documents of KOC done in 2001 shortly after we made our visit. On our second trip in 1987, Ron and I were able to visit Aramco’s EXPEC center in Dhahran. I saw major changes since my time there eight years before. The petroleum engineers and exploration geologists had all been moved into their new building. I visited with the engineers that I had known in 1977–79. Ron concentrated on meeting with oficers to sell his Eclipse Reservoir Simulation model, among them Sadad Husseini, senior vice president of exploration and production, who said he could envision reservoir engineers sitting before their computer screens and running simulations of reservoirs just as pilots learn to ly a plane. In Abu Dhabi we made a presentation to the national oil company. As I recall, at that presentation the slides we had did not drop in their projector, so that presentation was less than desired. We visited Abu Dhabi, Dubai, Muscat, and Oman before heading home. Figures 13–1 and 13–2 show production charts for the United Arab Emirates and Oman since our visit. To complete the picture from the Middle East–North Africa region, consider igure 13–3, which shows the combined production history of Kuwait, the UAE, Iraq, Iran, and Saudi Arabia.

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Fig. 13–1 UAE production, MBbls/d

Fig. 13–2 Oman production, MBbls/d

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Fig. 13–3 Five Gulf States OPEC production, MBbls/d

Production from the Persian Gulf countries is important, because a key question on the minds of many energy planners is how much more could these key Gulf states produce after Libya’s 1.8 million b/d production shut down in 2011. Libya’s exports are in the range of 1.5 million b/d. That does not seem to present too much of a problem with the Saudis alone holding 3.5–4.0 million b/d. However, if world demand grows by 1.4 million b/d, that begins to present a bit of a dilemma for the world oil consumers. That view was underlined by Raymond James Energy in its weekly report, Feb. 28, 2011: The Libyan crisis currently presents the most serious geopolitical risk to global oil supply in recent memory. With WTI crude prices at the $100/bbl mark for the irst time since 2008, the oil market is fearful not just of continued Libyan production disruptions but the risk of them spreading to Algeria and, in an Armageddon scenario, the Arabian Peninsula. While Libya’s political end game remains far from clear, the rest of OPEC could cope even with a total Libyan shutdown. A concurrent Algerian shutdown would be dificult but generally manageable (albeit with much higher prices). There is simply no precedent for a Saudi-sized supply disruption, and to say that the oil market would go berserk in such a situation is an understatement. All in all, we wouldn’t lose sleep over this 204

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extreme-case scenario, but it would seem that $100+WTI (add ten bucks for Brent) is here to stay, courtesy of the Middle East. I think this statement by RJ Energy summarizes the dilemma well. Figure 13–4 shows the historical production of Libya, as well as internal demand.

Fig. 13–4 Libyan oil production and projection through 2030. Source: The Oil Drum.

Due to hostilities between Iraq and Iran, Ron and I missed the opportunity to visit those two countries. Figure 13–5 shows that over the last 20 years of war, Iraq has not been much of a supplier to the world crude oil supply. If Iraq can get through the crises sweeping other Middle Eastern states, along with the US troop pullout, the next big question for energy planners is whether Iraq can provide the next big growth spurt in OPEC supply. Note that Iraq, through the period of three wars, has averaged only 2.4 million b/d in production, not counting stolen oil or leaks to Iran. One of the big unknowns is what Iraq will be able to produce in the years ahead, given that it has the most potential to grow. As of 2011, the Iraqi government had not agreed on a uniied plan to distribute the oil wealth to the country’s three main groups: the Kurds, the Shia, 205

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and the Sunni. Major oil companies, which have signed joint operating agreements, are willing to gamble that they can make a decent return.

Fig. 13–5 Iraqi oil production MBbl/d, 1965–20101

The Iraqi government talked in terms of 12 million b/d based on the technical service contracts (TSC) it signed in 2010 with such irms as Chevron, BP, ExxonMobil, Petronas, and CNOOC, among others. One question is why the major oil companies are locking to sign contracts in Iraq. The answer is that Iraq is the one place in the world where the large international oil companies can still go to for big reserves and ones that have been recognized for the past 25 years. In June 1987, PPC and R.E. Martin jointly issued a report called Oil Development Outlook in the Middle East. We reported that Iraq had the largest undeveloped oil reserves of all of the Gulf countries, including Saudi Arabia. Iraq’s reported undiscovered reserves were estimated at 32–150 billion bbl with a statistical mean of 77.4 billion bbl. Little exploration has occurred in the last 25 years, and apparently the potential remains. However, the real questions are: When will development come? Will peace and stability reign, allowing it to happen? Once the oil is developed, will the regime coniscate it, as have many others in the past? In 2010, Sadad Husseini presented another view of how fast Iraq’s ramp-up will occur. In igure 13–6, Sadad presents three possible outcomes by 2019: a bear case showing no growth at all; a base case reaching 4 million b/d; and a best case that reaches 7 million b/d. Sadad, who has spent his life in the Middle East, does not see much increase 206

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until 2014—a little late to help with the production shortfall predicted for 2011–14.

Fig. 13–6 Iraqi petroleum capacity increase requires a multi-year ramp-up phase

India presents a whole range of new dilemmas for planners. India’s domestic production went lat at about 700,000 b/d, but the country’s annual demand for petroleum has been increasing at some 4%—similar to China’s demand growth of 5% per year. These two trends of India and China are illustrated igure 13–7. This demand growth creates another problem for countries concerned about Iran’s construction of nuclear weapons, especially those countries that are trying to impose economic sanctions on Iran. Where is a country like India to get its imports in the case of sanction imposed on Iran? As shown in igure 13–8, India imports 17% of its oil from Iran, with 49% coming from other producers in the Gulf region. Meanwhile, the US has thrown its support to India, which has the bomb, and is encouraging US companies to support India’s nuclear ambitions. Under this scenario, will sanctions work? I doubt it. While the US probably had a good objective in the 1990s to become less dependent on oil from the Middle East, the rest of the world became more dependent than ever.

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Fig. 13–7 India’s crude oil production and consumption

Fig. 13–8 India crude imports by country and region. Source: Indian government; The Oil & Gas Year, India 2010.

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Off to the Former Soviet Union This was an exciting trip to a region of the world that in 1989 was still closed to most people from non-communist countries. But things were changing as 1989 marked the fall of the 28-year-old Berlin Wall. I joined 30 others on a trip organized by the People-to-People Organization, whose objective was to improve relationships among people throughout the world. Most of the others also were associated with the oil business and major oil companies, independents and consultants. Among them was Hank Gruy, one of America’s most colorful and well-known consultants. Also on the trip was Saleem Akhter, a long-time acquaintance of mine from Aramco petroleum engineering. Saleem was unique. He was from India, had been trained at the University of Moscow in petroleum engineering, and had worked in Saudi Arabia as a petroleum engineer. At the time, he was working for William Fisher’s Geologic Group at the University of Texas. Saleem was great to have along on the trip since he spoke luent Russian and got us out of more than one scrape. The political climate ranged from cold to warm. For many of the people we visited, we were the irst Americans they had seen. The coldest reception came from the steely-eyed inspection oficer in the arrival line at the Moscow Airport. You thought his eyes were the x-ray machine. The bureaucrats in Moscow were the next coldest. We were delivered to a hotel on the outskirts of Moscow that was built to house the athletes at the earlier World Olympics. It was 25 stories tall, and we were placed on the upper loors. Sometimes it would take 30 minutes to get from your room to the lobby—that assumed that the loor lady was not busy and that you could get your passport on a timely basis. Passports had to be turned in each night we checked into our rooms. There were two men to a room. There were signs of the old days, with anti-American literature planted at most stops for us to read. But many of the people had smiles on their faces when they found out we were Americans. This was also the time that the USSR’s Premier Mikhail Gorbachev introduced many reforms under the name of Perestroika. Russia’s bureaucrats were not with the program. At the irst meeting in Moscow, which lasted about two hours, the bureaucrats mentioned that they had lost several workers in their department, reducing their ability to hold meetings such as this (not 209

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a warm, fuzzy feeling). In 1989, it was reported the Soviets employed about a million workers in their oil and gas industry. During the irst two days, we had two meetings with Russian oil leaders. We made trips around Moscow on a fast train that at that time cost 7.5 cents to ride. The trains, mostly underground, were very eficient in moving Moscow’s seven million residents around the city. On the third day, we were to take an overnight train ride to Bugulma, about 600 miles east of Moscow in the Tartar Republic in the Ural Mountains. This is known as the Vulga-Ural producing region. That morning, we were taken to the air museum, but it was a holiday and the shops were closed. So, the bottled water we were supposed to get was not available. We were taken back to our hotel for lunch and to meet downstairs at 1:30 p.m. After going to our rooms, a black cloud was beginning to form. For most of us, it took some 25 minutes to ride the elevator down to the lobby. We barely caught the bus. The bus driver drove like mad trying to get us to the train in time for departure. When he arrived, we had ive minutes to catch the train on Track Ten. We were at Track One. There were no Russian guides as promised. The bus driver just told us to grab a bag and head out. Some 30 Americans ran to Track 10, but it turned out there was no Track 10. There were only nine tracks. So, we all headed back to the station. The bus driver was still there, with a sheepish grin on his face. He knew his supervisor had sent us to the wrong train station. He called the hotel and asked that they keep the rooms. When we got back, half of the rooms had been given away. We had to double up four men to a small two-bed room. That night they fed us a big dinner on the top of the hotel with a show. They said they would ly us to Bugulma the next day, so our meeting schedule would not change. When we arrived at the airport about noon the next day, they told us that there would be a delay of a couple of hours because of “a big snowstorm” in Bugulma. We were provided plenty of good propaganda to read. At about 4 p.m. they loaded us onto an Aerolot turbo prop plane. The pilot warmed up the engines, then turned them off and came back through the plane and said “still snowing” in Bugulma. What a day! It was back to the big chairs and more waiting. About 6 p.m. they took us for a sandwich. Nine hours later, at about 3 a.m. the next morning, when they said: “Snow storm over and we leave now.” 210

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Sure enough, when we arrived at about 5:30 a.m., the snow was about two feet deep. The black cloud was beginning to lift. We were greeted and welcomed by locals. We were loaded into a brand new bus, and we were given a police escort to the hotel. We were told to be ready to leave by 8 a.m. for an all-day meeting with the local oilmen. What a day! We were dead tired, but promptly at 8:30 a.m. the meeting started, and the presentations lasted all morning. The Russians were all dressed up in suits, coats, and ties, while we looked like a bunch of old, tired oilmen from the West. One proud Russian stood up and said he had met Americans once before. That was in World War II where our respective armies met up on the Elbe River in Germany. The Russian’s chest was covered with war ribbons, and he ended by saying, “Thanks for coming.” The Russians were very hospitable to us, feeding and entertaining us very well with parties in the evening. They also took us on tours of their oil ields, which in some ways reminded me of old pictures in the East Texas ields where there were wooden derricks, but much more snow. Based on my notes at the time, these old oil ields produced about 700,000 b/d oil at an average rate of 30 b/d of oil per well and 1,500,000 b/d of water. There were 150,000 workers in this area. They took us to a very nice sports arena in a nearby city of Almetyevsk about an hour away. They had special programs. The only problem, though, was that there were no toilet seats and newspapers served as wipes. It seems that sometimes in Russia the left hand was not sure what the right hand was doing—a common problem in this centrally managed economy. It was obviously true in their oil patch as well. We had another unique experience. We took a trip to an all-Englishspeaking school. There were about 500 students. We were taken to their classes and then to a large auditorium where we were entertained with dance and music. We were all asked to come to the stage to answer questions about life in America. This was not planned, but it was an interesting experience. On stage, we were 30 oilmen and one woman from America looking out at about 500 students and teachers. All were in similar uniforms. Apart from that, they looked just like our children. They asked questions similar to what our children in America would ask, all in English. They appeared very well mannered. One question that I remember was, “We 211

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note that Gorbachev was selected Man of the Year in 1988. We wonder if your President Bush will be selected Man of the Year in 1989?” I do not remember the answer, but as we left the stage, there was not a dry eye in our group, because we had witnessed youth with same aspirations as our youth have. Then, it was back to Moscow for a few more days with the Moscow chiefs and more touring.

On to Kazakhstan Our next trip was to Guryev (now known as Atyrau), Kazakhstan, to visit the Tengiz Field discovered in 1979. This ield was not yet on production, but it had some 30 rigs running. Travel to Guryev was again a bit of a problem. We were supposed to leave at 11:30 a.m., and we were taken to the VIP room to await our delayed light. This time, it was a delay due to fog. At 8 p.m. we were still waiting, and they decided to take us to dinner. The group decided to go to a hotel, and we checked in at the Hotel Belgrade. The hotel was supposed to give us a room call for a 5:30 a.m. departure. The hotel clerk had all of our passports. No calls were made, so the group got assembled to leave for the airport about 6:00 a.m. We had no Russian guides with us, but we did have Saleem. Some groups caught taxis, but we saw Saleem out in the street waving down a bus. He lashed $30 at the bus driver. Saleem never knew where the bus was originally headed, but he now had us on a bus headed for the airport. This time, we got to the terminal about 20 minutes late for a commercial light to Guryev. But guess what? The Russians held the light because they were missing some 31 Americans. With a fully loaded plane we arrived on a tarmac outside of Guryev to ind the Russian helicopters warming up. It was snowing lightly as we jumped on the three giant Russian helicopters and headed for Tengiz, where we had a light lunch before taking a tour of the ield. During the light, we passed over herds of camels as snow fell, a very strange sight for someone like me, accustomed to seeing camels in the hot deserts of Arabia. Tengiz is located in a very inhospitable place, 1–2 ft above sea level with sub-zero temperatures in winter and 120°F in summer. Before dark, the Kazakhs took us on a tour of the ield in modern motor-driven buses. There was light snow and limited visibility. The 212

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guides explained there were 30 active rigs in the area and they hoped to bring production on in 1990. In fact, it was on about three years later, in 1993, 14 years after it was originally discovered. Production began after the fall of the USSR when Chevron took over operation of the ield. At that time, it took the Russians about 1.5–2.0 years to complete a well. They were working on their irst production module to process and strip the high-sulfur casing-head gas containing 17% H2S. Our tour guide suggested that OOIP was as much as 23 billion bbl, with recoverable reserves of 6–9 billion bbl. The OOIP number was similar to that of the Prudhoe Bay ield discussed earlier. The tour guide took us by the site of the famous T-37 blowout in 1985–86 which had a monument to the one oil ield worker who died in the resulting explosion. The site burned for 14 months, consuming 3.5 million tons of oil, while 1.7 Bcm of gas was either released or burned. The plume was estimated to be more than 600 ft high. Ultimately, the well was killed with teams of Russian experts, along with the American companies Otis and Red Adair Wild Well Specialists. While the Kazakhs had 30 rigs running, none had ever been able to penetrate the base of the 4,500-ft reef after drilling through the salt. The pressures were extremely high at more than 10,000 psi, and bottomhole temperatures were more than 350°F at the subsalt reservoir level. Afterward, I asked whether this was the key to the future oil development for Russia, or was it another Chernobyl? Following the trip, Saleem Akhter and I produced two small reports, one titled “Tengiz: Soviets’ Future” and the other “Perestroika.” A copy of the irst report was acquired by Chevron, which was rumored to be in the running to acquire a working interest position in the Tengiz ield. Sure enough, in 1993 Chevron and the TengiznefteGaz Co. did form the Tengizchevroil Partnership (TCO). Today, ownership is comprised of Chevron 50%, KazMunaiGas 20%, ExxonMobil Kazakhstan Ventures Inc. 25%, and LUKArco 5%. The years 1992–93 were signiicant in the development of the Tengiz ield. In 1992, Kazakhstan became an independent country, free from Soviet and Russian control. In 1993, Chevron formed a 40-year joint venture with Kazakhstan’s government to develop and produce the Tengiz ield. This reef development is more than 4,500 ft thick, and at the time of our trip the Kazakh rigs had never penetrated to the bottom

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of the reef. The reef trap has a very thick salt barrier, which has to be drilled through. I understand that the most recent wells drilled are now taking only 50 days. Unoficially, there were some 125 wells producing 500 million b/d in 2009 from Tengiz. This is up from essentially nothing 20 years ago. As of October 2010 production was as high as 625 thousand b/d. This area boasts several world-class processing facilities, including the world’s highest pressure injection plant, where Chevron plans to reinject about one-third of the produced gas to the reservoir at about 10,000  psi. Another facility here involves sour gas for Chevron and its partners. Oil from the Tengiz ield comes out of the wells hot and at a very high pressure. It also contains a large proportion of gas that is rich in the compound hydrogen sulide, yielding poisonous sulfur. Kazakhstan’s government imposed stricter guidelines for handling sulfur, and in 2006 it threatened TengizChevroil with ines. In 2007, the government imposed a $609 million ine on TengizChevroil. At one time it was estimated that 6 million tons of sulfur were stored on the ground. The violations included slow progress in dealing with vast sulfur stocks at Tengiz. In 2003, the company had reportedly been ined $71 million for open-air sulfur storage, which was reduced to $7 million on appeal. According to Kazakhstan’s Environmental Protection Ministry, more than 10 million tons of sulfur was accumulated near Tengiz oil ield as a by-product of crude oil production. Kazakhstan’s government had also set a requirement to relocate the 3,500 residents of the village of Sarykamys to new homes in the vicinity of Atyrau. The relocation program, funded by TengizChevroil, was done in 2004–06 at a cost of $73 million. As we asked in 1989, was this to be an expanding oil supply or another Chernobyl? Apparently there was no market for the sulfur. Figure 13–9 is an approximate production chart for Tengiz, shown in blue over the last the last 20 years from a variety of sources. Recent data show Tengiz production up some 15% in 2010. The red bars are from the EIA and show its estimate of total Kazakhstan production. Since its independence from the USSR, Kazakhstan has seen nearly 400% growth over the 20 years.

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Fig. 13–9 Kazakhstan and Tengiz production comparison (now up to the 650,000 b/d range).

Chevron expects that Kazakhstan can produce 3.0 million b/d by 2025, but it must irst solve its transportation problem. Pipelines and transport of the crude oil to world ports has been a major problem. In 2010 Chevron announced the expansion of the Caspian pipeline, saying that it is expected to increase exports to 1.4 million b/d from 730,000 b/d with an expenditure of $5.4 billion. The project will be implemented in three phases, with capacity increasing progressively from 2012 to 2015. Chevron said that the project will consist of the refurbishment of ive existing pumping stations, the addition of 10 new pump stations, the replacement of a 55-mile section of the line, and the addition of a third mooring point at the Black Sea terminal port. The pipeline will carry crude from Russian and Kazak ields, including Tengiz, where production is forecast to grow to 780,000 b/d with the new pipeline expansion. Chevron is also negotiating with Kazakhstan about a new $40/ton export tax that was to be implemented on Jan. 1, 2011. Figure 13–10 puts into perspective the production history of Tengiz, Kazakhstan, Independents, and the USSR as a whole. Of interest 215

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is the overall dip in the total production from the former USSR to 8.6 million b/d in 1995 after Perestroika and the reforms were put in place. This decline was setting in as we made our trip to Russia. However, as of 2009, with the modernization of their industry and the infusion of Western capital—to say nothing of a more capitalistic attitude— Russia and the states of the former USSR have been able to rebuild their production to 15.9 million b/d, with 12.9 million b/d coming from Russia and 3.0 million b/d coming from the former Soviet states as of 2009. For energy planners, Russia and the former Soviet countries—along with OPEC—represent one of the dilemmas in pondering the world’s short-term oil supply demand balance.

Fig. 13–10 Former USSR production history

And Then to Europe, Too In the seven years between 1987 and 1995, I took a number of trips to Europe. The irst trip in 1987, taken together with our journey to the Middle East, was to sell our pricing study. We ended up selling it to the Norway’s Statoil. The second trip, sponsored by the Norwegian government, was an invitation to attend a meeting in Oslo to review the 216

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country’s fast-growing offshore oil Industry. That journey also included a trip to the Gulfaks offshore platform, which was in about 400 ft of water (ig. 13–11).

Fig. 13–11 Statoil’s Gulfaks Offshore Platform. Photo by Ole Jørgen, Bratland/ Statoil.

Norwegian engineers were instrumental in designing a whole new design of offshore platforms for the harsh North Sea environment. The concrete base sits on the sea loor and serves as storage tanks. We saw several such platforms under construction in the Stavanger Harbor. Interestingly, the employees lived on the same platform that contained the oil facilities. In addition to enjoying the beautiful countryside, one thing I noticed while traveling around Europe was the small cars and the much higher price of gasoline. The high gasoline taxes were used to support governments and to force people to buy smaller cars. The US price as of February 28, 2011, had risen to $3.31 per gallon. Compare that with Italy, where the price of extra gasoline averaged $6.47 per gallon in 2009. In 1991 Europe’s system of high taxes on motor fuel was beginning to make a lot of sense to me as a means of reducing oil imports to 217

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America. Under our democratic system, it seems that Americans have been “hooked” on cheap motor fuel, even though our country had shifted from being an oil exporter to an oil importer at an alarming rate. Table 13–1 updates gasoline prices around the world as provided by Saleem Akhter. Note that the Norwegians were paying $9 per gallon in early March 2011. Table 13–1 March 2011 gasoline prices

USA

$/Gallon

Cents/Liter

3.70

98

England

5.00

132

Norway

9.00

238

France

8.54

226

Italy

7.56

200

Germany

6.51

172

Pakistan

3.62

96

New Zealand

5.27

139

India

5.27

139

Saudi Arabia

0.85

22

UAE

1.82

48

Iran

2.58

68

South Africa

3.97

105

In 1993 I made another trip to Europe to attend the Oil and Money Show in London. At the meeting I was able to visit with Saudi Arabia’s Oil Minister Ali I. Al-Naimi, who lived just across the street from my family during our 1977–79 stay in the Kingdom. My wife Ruth Nell and I also got to visit Sheik Yamani and his wife. Sheik Yamani was one of the facilitators at the meeting which, on balance, gave me a good overall picture of where the world energy picture was headed. As a follow-up on North Sea production, consider igure 13–12, which gives the historical data for both the UK and Norwegian sectors. In the early 1990s, all was go in the North Sea. The UK and Norway were exploring and bringing on new ields. Both countries enjoyed robust economies. Oil companies and workers poured in from around the world. When I attended the Oil and Money show in 1993, boom times were occurring. However, by about 1996, a plateau set in as the 218

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UK’s portion of the North Sea began to decline somewhat. By 2002, production began to slip from six million b/d, and by 2009 it had declined to 3.8 million b/d, a drop 37% in only seven years. These are the kinds of numbers that proponents of so-called Peak Oil are relying on. Note that there was some lattening of the decline as oil prices boomed in 2008, and new technology was applied similar to that at Prudhoe Bay in Alaska. Recently the Norwegian government announced a couple of viable discoveries of several 100 millions barrels of oil, and there is promise in their polar waters, but these will be very expensive and will take many years to explore and bring online. As I said at the outset, these overseas trips built my conidence of the world energy situation, and they prepared me to develop my thinking on energy problems in America, problems that we turn to now.

Fig. 13–12 North Sea and onshore England production, MBbl/d

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Notes 1. Al Husseini, Sadad I. 2010. “Iraq’s Oil Expansion Challenge.” London Oil and Money Conference, Oct. 12.

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P

owers Petroleum Consultants, Inc. (PPC), undertook a study for the Independent Petroleum Association of America (IPAA)

in the 1990s to warn the White House, Senate, and House about the hazards to the economic health of our country due to increasing oil imports. Over a 12-year period, copies of this report were forwarded to three administrations, as well as to the Department of Energy and the Department of Interior. Gene Ames (ig. 14–1), former chairman of the IPAA and chairman of Venus Oil Company, forwarded my report to James E. Akins, the former US ambassador to Saudi Arabia. After reviewing the report, Mr. Akins sent me a very complimentary letter. But his comments did not leave me very conident that either of us had much chance to inluence the politicians in Washington DC, whether Republican or Democrat. The full text of his letter follows:

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Dear Mr. Powers, Gene Ames sent me a copy of the speech you gave on July 17, 1991, to the Houston Energy Finance Group. He said he thought I would agree with everything you said. I did. I was pleased with your long quotation from my article in Foreign Affairs. You might be interested in knowing that the rest of the article has been widely and favorably quoted, but the section on energy has generally been dismissed as a tired repetition of an old obsession. The accusation is correct, even though I am more convinced than ever that my position is sound. I testiied in the Senate in 1986 about the new oil crises. I said that by 1990 we would be importing at least half of our petroleum needs; the Department of Energy said that level would not be reached before 1992, and I said the difference wasn’t worth quibbling about. But when the DOE said it would embark on a long study to “determine the security implications” of such a development, I ended my relations with the Department with a caustic remark—in testimony—that the study should take about one microsecond. I said that there would be no problem at all in relying upon imported oil—most of which would have to come from the Middle East—provided you could guarantee that there would be no coups d’etat, no revolutions, no wars, no civil disturbances, and no natural disasters in the area, and provided, of course, that our balance of payments would tolerate such a level of imports. In retrospect, I probably erred. Government oficials do not like being made to look foolish, particularly when they are fools. One shouldn’t make enemies gratuitously. Still, I doubt that a softer answer would have led to anything other than the disastrous position we are now in. Frankly, I despair. I see no way to convince the Congress or the people that we are entering a most dangerous period. Strong presidential leadership might change this, but I see no prominent Republican or Democrat who would dare do this today. Do you? You are closer to the ield than I. Do you have any reason for hope other than trust that a wise God will not let us do irreparable damage to the Republic? If you do, I would be most grateful if you would let me know. Sincerely yours, James E. Akins 222

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Fig. 14–1 Gene Ames, former chairman of the Independent Producers Association of America and chairman of Venus Oil Company

The ambassador’s letter came just a year after the irst Gulf War and the drive to eliminate Iraq forces from Kuwait. Figure 14–2 shows the historical oil trade deicit for the time period prior to 1990. Trade deicits in the range of $50–$75 billion from net crude and product import had been experienced the last 15 years. However, based on the government’s own forecast of increasing oil imports and escalating prices, we were concerned that prices and oil imports would go much higher in the years ahead, thus the title of our report: Oil Imports—The Bankrupting of America.

Fig. 14–2 Historical US trade and oil deicits

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Trade Deicits and Oil Imports Figure 14–3 shows the projected trade deicit due to oil imports using the Department of Energy’s 1991 annual report. The resulting net import bill for crude and reined products from the 1991 study were projected to be $319 for 2008 and $350 billion for 2009. The actual bill for 2008 turned out to be, per the EIA, $388 billion and $207 billion in 2009. The lower number for 2009 was due to lower US demand and a signiicant reduction in the price of oil. At today’s Brent price of $115/ bbl, the annualized trade deicit for imported oil is $420 billion on an annualized basis. After the rumor of a Saudi pipeline explosion in March of 2012, Brent crude traded as high $130/bbl. This North Sea oil is really the new world measure for crude oil pricing compared to the historical WTI benchmark, which now trades some $15 to $25/bbl below the Brent price.

Fig. 14–3 Forecast US oil trade deicit—OTA base forecast. Based on 1991 OTA report and 1991 DOE energy outlook based on price forecast. Powers Petroleum Consultants, Inc., Dec. 1991.

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For reference, I have shown what I derived from the 2010 EIA forecast of import prices as well as crude and product volumes over the 10-year period. The EIA forecast import volumes are lat at approximately 10 million b/d over the 10-year period and a nominal price rise by 2020 to $126/bbl up from about $75/bbl today. Unless we have a serious long-term depression ahead, I doubt the EIA’s import prediction and its pricing projections. The key question is what our bill will come to for imported oil. Will America’s oil business drown under a sea of red ink or fall even deeper under a blanket of environmentalist green? That is a major energy dilemma that nobody can answer. Will alternative energy methods become competitive without government subsidies at some time in the decade ahead? Will American consumers be willing to fork out more cash for fuel-eficient cars as mandated by the Obama administration? Or will the rising prices of gasoline and other energy resources force American consumers to buy more fuel eficient cars? Interestingly, GM halted production of its electric vehicle, the Volt, in March 2012 due to poor sales. A tax on gasoline such as the European countries have would have been a much more eficient way for Americans to change their ways, as consumers choose to keep their cars longer rather than downsizing to smaller cars and trucks. But the politicians, both Republicans and Democrats, did not take care of the long-term needs of our country. They were more concerned about getting reelected. Figure 14–4 shows PPC’s independent analysis for future decline. We used the DOE projections to compute the trade deicit. It is interesting to note that US oil production is forecast to grow to 10.8 million b/d in 2020 from 8.6 million b/d in 2007. Our forecast was formulated 18 years ago, but it seems that somehow the sharp decline of prior years has been magically reversed, maybe with ethanol. Or perhaps the EIA is listening to the oil drillers who have found two new major oil plays in the Bakken and the Eagle Ford Shale. Then, again, the offshore oil production decline will be hard to overcome.

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Fig. 14–4 History of US oil supply and demand, and projection. Powers Petroleum Consultants, Inc., in conjunction with IPAA, 1992.

When I review igure 14–5, I am again reminded of Schumacher’s words: “Man will appreciate those most who say ‘Stop, Look, and Listen’ rather than those who say: ‘Look it up in the forecast.’ ” Another warning issued in our 1992 report was the increasing reliance on US oil imports from the Middle East as gasoline consumption continued to grow. This is one area of our forecast that was way off. Today, the US is importing only about 1.5 million b/d from the Middle East, about the same as we were importing at the time of PPC’s 1992 study. China principally has been the beneiciary, as they rapidly moved to secure their increasing appetite for imported oil from the Middle East. Wars between Iran and Iraq, Iraq’s two wars with the US and its coalition partners, and sanctions on Iran all have helped to depress Middle East exports to the US. But this did not necessarily accomplish our objective, since the rest of the world became more dependent on producers in the Middle East. Case in point: India now imports 17% of its oil from Iran. In his election campaign, President Barack Obama stated the objective of weaning the US off oil from the Middle East. India and China would like that, but it will never happen given the wrong direction and energy planning miscues of the Obama administration. Frankly, energy independence in America is a myth and is only used to mislead the voters. However, we can do more than we are currently doing regarding energy policy. 226

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Fig. 14–5 2010 EIA forecast US demand and imports

Mexico, Venezuela Unreliable Turning to South America, the US has two problems with oil supply: Mexico’s declining production and Venezuela’s President Hugo Chavez and his policy of nationalization in the oil industry. Figure 14–6 shows imports from Mexico declining by 39% and Venezuela by 33% during 2004–09.1 Imports from Canada were up just 14%, resulting in an overall loss of 17% from these three sources over the six year period. As pointed out earlier, in 2009 Canada exported 2.3 million b/d to America due to the 1.5 million b/d of tar sands production. Not all of that tar sands production came to the US, but it did allow Canada to achieve the higher level of exports. It was my opinion then, and it is my opinion now, that we need to work on both sides of the equation: we need to reduce demand and increase supply. A gasoline tax proposed in 1992 by presidential candidate Ross Perot would have been the most eficient method for reducing oil import demand, perhaps with a rebate for those below a certain income level. It may be too late now as gas prices, including taxes, are now up over $3.80/gallon nationwide. Some people are even predicting $5/gallon in a couple of years or sooner due to unrest and upheaval in the Middle East. 227

THE WORLD ENERGY DILEMMA

Fig. 14–6 US crude imports from Mexico, Venezuela, and Canada, MBbls/d

On balance, the 1992 IPAA report was well received. I believe it was the irst time the House, Senate, and White House had seen the import deicit put together from the government’s own data. For some, it created a shocking concern for our future. Unfortunately, government inaction through four administrations has done little to make our energy future more secure. On June 13, 2004, I made a presentation to a House Committee on National Security at the request of the IPAA. The presentation had several key points:

228

1.

How many more American lives will be lost in the next war?

2.

Can America afford another war over oil? In my opinion, there was no question that the irst Gulf war was a petroleum war with Iraq’s President Saddam Hussein trying to control oil from the Middle East even as the West was trying to maintain a cheap supply of oil

3.

I pointed out that all ive Middle East leaders along the Gulf are dictators, some better than others, but all of them subject to being deposed by a single shot—some by their enemies and some by their own family members, such as King Faisal, assassinated in 1975 by one of his nephews in Saudi Arabia

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4.

I pointed out that 65% of the free world oil reserves at that time resided in the ive crucial countries surrounding the Gulf. At that time, most of their exports of oil to the West traveled through the Strait of Hormuz, a chokepoint only 19 nautical miles wide. Since 1992, the Saudis have expanded their export capacity by pipeline from the eastern ields to the Red Sea. In 2006, the Saudis said that they export about 25% through Yanbu on the Red Sea. Still, the Strait of Hormuz handles some 15–16 million b/d. Also, the UAE is nearing completion of a 1.5 million b/d pipeline that will bypass the Strait of Hormuz and deliver oil directly to the Indian Ocean

5.

At the hearing, I pointed out that the oil in all ive Gulf countries is contained in an area no larger than Texas and Oklahoma combined

6.

I then revealed the most provocative issue of the entire presentation, suggesting that through the irst Gulf War and the continuing attacks of our airplanes in Southern Iraq we in America could actually be promoting the very terrorism we dreaded. To support my views, I showed the two charts.

Many people can remember the images of destruction to the Iraqi Army on Highway 80 out of Kuwait City after the irst Gulf War. I suggested that the numbers killed could have between 100,000— 600,000, depending upon who you listened to. Assume those who died had 10 relatives close enough to have some feeling for the deceased. That’s somewhere between 1–6 million Iraqis who probably have some bad feelings for us. After this hearing, I heard the number was more like 235,000 from different unoficial sources. We may have lost just 400 troops in the effort to keep Iraq out of Kuwait’s oil ields, but how many terrorists did we create? The question still stands: should America be involved in trying to instill democracy in the Middle East with military force? It is interesting to note that Iraq’s government was in place after our main ighting force was pulled out. Or was that force actually pulled out? One unnamed Army oficer reported that they just changed the name of the unit. Did President Obama send 100,000 troops home or to Afghanistan? Supposedly, all of our troops are withdrawn now. What then? The bombings and the killings are still going on between Iraq’s Shia and Sunni sects. 229

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My thoughts about the oil wars seemed to be strengthened by a statement by former Defense Secretary Robert Gates when he spoke at West Point in February 2012: “But in my opinion, any future defense secretary who advises the president to again send a big American land army into Asia or into the Middle East or Africa should ‘have his head examined,’ as General MacArthur so delicately put it.”2 My prediction was that the Iraq and Afghanistan wars would end in a quagmire. Recently, a retired senior US Air Force oficer—who spent six years in reconstruction in Iraq and Afghanistan—told me that we could not leave Afghanistan fast enough. And regarding Iraq, he warns of what will happen there, particularly with the ongoing unrest in the entire region, when we pull our troops out. “Maybe you were right,” he told me. Unfortunately, I saw little change in the direction of the US energy dependency after my presentations. We increased oil imports until the recession in 2009. Most of us continue to drive big cars. The US government has launched two more wars, and the Palestinian-Israeli conlict remains unsettled. The Middle East is still a cauldron of instability despite our infusion of $2–$3 trillion, and stability in the Middle East is still undetermined. Saudi Arabia did reimburse us $50 billion following the 1991 war with Iraq. The Obama administration has bought Al Gore’s thesis on global warming and that CO2, a by-product of hydrocarbons, is bad. Ron Lantz, my friend, travelling companion, and mathematical modeler of air pollution for most of his life, recently published his opinion on global warming: “My arguments above are not intended to be totally convincing that greenhouse gases are not the primary factor for our current warming cycle but at least these facts should cause any reader to stop and look into these arguments for themselves. I for one, am convinced that there are atmospheric scientists that are distorting their scientiic results for their own purposes, and that is probably a inancial purpose.”3 I’m not convinced that we have had global warming for the last ten years. The winter of 2010–11 broke all kinds of records not only in the US but around the world. In many places, it has been the coldest winter the last 50 years. On April 7, 2007, we in East Texas had the irst-ever snow on Easter.

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Even if we have global warming, I am not convinced that the cause is increased CO2 from using hydrocarbons. I have learned through my years of reservoir simulation, that “garbage in equals garbage out.” I am not so sure that doesn’t apply to the NASA global warming model, but I do not propose to be an expert on global warming. I do know what goes on in my own backyard, and the winter of 2010–11 in Houston was colder than it had been for several years. Could it be that the earth’s surface is getting hotter from the core and that it is not the air that is causing the glaciers to melt? In the end, I feel similar to Robert Bryce, who states his position on the science of global warming in his book Power Hungry: “I do not know who’s right and I don’t really care. What can be demonstrated is that the carbon reduction targets proposed by the US Congress and the Democratic leadership in Congress are pure fantasy.” Bryce goes on to explain his reasons and again points out the fallacies of unproven computer models. For those interested in the opposing view, consider David Archer’s The Long Thaw.

Advising the Ross Perot Presidential Campaign In the summer of 1992, I was contacted by Bill Gayden, chief operating oficer of Petrus Operating, an independent oil and gas company. Owned by the Perot family, Petrus was in the business of acquiring oil and gas properties. Joe Marek, my friend from Exxon, was in charge of Petrus’s acquisition group. Joe was familiar with my work with the IPAA, and he also was aware that I had six 4-inch notebooks crammed with data. He wanted the reports I had been working on. Gayden asked if I’d be willing “to work with him in developing an energy plan for Ross Perot’s run for the presidency.” I said I would. Gayden wanted copies of the IPAA data set and for me to help him make contacts with a few individuals I might know. One was Bill Stevens, a former president of Exxon USA. Stevens agreed to meet with Gayden, and he provided useful input from the perspective of a major oil company prospective. I also arranged for Gayden to contact the former governor of Washington State, Dixie Ray Lee, who had written a great little book called Environmental Overkill: Whatever Happened to 231

THE WORLD ENERGY DILEMMA

Common Sense? Governor Lee, who I met at IPAA, asked which of the three presidential candidates I was talking about. When I told her it was Gayden, who was working on Perot’s Energy Plan, she agreed to help. Lee at one time had served as head of the Nuclear Regulatory Agency, and she was a very knowledgeable person on a whole range of energy matters. I was one of many advisors Gayden was talking to. The Perot Energy plan was developed in about two months. Contrast that to the millions of dollars the Bush Administration spent with our tax dollars that year on energy policy. Ross Perot was one of the few politicians who understood that you had to work on the two sides of the import equation: supply and demand. Perot backed a gradual increase of the gasoline tax, starting at 50 cents/gallon. He also backed rapid development of our offshore resources, and developing the Arctic National Wildlife Refuge (ANWR). He backed building new nuclear plants, too. Perot was not against alternative sources for energy, but he felt that they would have to compete on their own terms in the free-market system. It was not part of his agenda to grant billions of dollars from our grandchildren’s future taxes to private industry to prove up some new technology in a deicit environment. Also not on his agenda was subsidized ethanol, which takes more energy to produce than it generates. The gasoline tax would be used to reduce our growing budget deicit. He supported a modest increase in CAFE Standards, and preferred to tax gasoline to help move the public to drive more fuel-eficient cars. In 1991, we were using more gasoline than we were producing oil. Following are key excerpts from the Perot Energy Plan as developed by the Gayden Energy Planning Group, along with some of my observations

The Problem Over the next 75 years the world supply of fossil fuels (oil, natural gas, and coal) is likely to be seriously depleted. Little is being done to signiicantly plan for a post–fossil fuel economy. On a current basis, we are virtually independent in all energy sources except oil and can expand the use of these resources with the right policies. Oil is the crux of our near-term energy problem and is especially a factor in transportation use. In 1990 we imported 44% of our oil requirements and are projected to be importing over 60% in 2010. Oil is not and has never been a free-market commodity. Our 232

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policies of the last 10 years have allowed the Persian Gulf countries (principally Saudi Arabia) to adopt courses of action that gives them signiicant inluence over the energy policies of the US and the rest of the world. Their policies create harmful price volatility and make investments in other energy sources uneconomic. •

US get 85% of its total energy requirements from fossil fuels.

•

US imported 20% of total energy requirements in 1990, 26% projected in 2010.

•

Over half the US trade imbalance is imported oil ($160 billion in 1990, over $300 billion projected in 2010).

•

US transportation consumption is greater than US oil production.

•

25% of our imported oil is from the Persian Gulf (this has increased more than 400% since 1985).

•

Under present policies, over the next 20 years nuclear and alternative generation of electricity will decline relative to total electricity requirements, leaving us more dependent on fossil fuels.

It is interesting to note that Exxon’s 2012 Energy Outlook predicted that the world would still be getting 80% of its energy from fossil fuels. The Saudis had been a volatile producer in prior decades. Their decisions to curtail production and then to increase production had a major impact on the world oil prices during 1985–88. Before that, of course, they participated in the Arab oil embargo to show their displeasure with US support of the Israelis in the 1970s. Yes, the Saudis have a major impact on the worldwide price of oil. However, during the last two decades, from 1990 through 2010, the Saudis have been a stable supplier of oil to the West with production in the range of 8–9 million b/d. The amount of oil imported to the US from the Middle East has declined over time in line with the Perot Energy plan. But demand for crude oil in other parts of the world has impacted Middle East oil even more. So, the problem still exists on a worldwide basis, and no country is an isolated island when it comes to energy policy

233

THE WORLD ENERGY DILEMMA

Energy Strategy Our national strategy for the near term should be to achieve a stable energy supply that maximizes domestic sources which can be economically produced and diversify our sources of imported oil to reduce our reliance on the Persian Gulf. For the longer term, we have to take deinitive steps to plan for a post fossil fuel economy. Steps to achieve a successful energy strategy: •

Conserve the energy we presently use.

•

Increase use of energy sources which are self-suficient and plentiful in the United States: 1. Natural Gas 2. Nuclear 3. Coal 4. Alternative energy sources, including wind, solar, etc.

•

Take steps to ensure a smooth transition to a post–fossil fuel economy for future generations.

•

Increase petroleum imports from other areas to reduce dependence on the Persian Gulf.

•

Accomplish these goals while resolving reasonable environmental concerns.

Ross Perot is the only presidential candidate since 1992 to understand that one of the ways to break America’s appetite for importing more oil is by raising the price of gasoline, as the Europeans have demonstrated. OPEC and the Saudis may be taking care of the supply problem since 2008, but they have done so at a terrible cost to our economy. Of course, speculators and the value of the US dollar also have played parts in this terrible cost.

Speciic Initiatives on Energy Sources

234

•

Support development of natural gas through continued deregulation and cost-effective tax revisions.

•

Focus on the importance of nuclear power as a source of energy for the future.

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•

Support clean coal technology to eficiently make use of this plentiful energy supply while we are in transition to future energy sources.

•

Reduce our oil production decline by permitting environmentally controlled access to federal lands, cost-effective tax revisions, and continued research on enhanced recovery technology.

•

Create incentive programs to increase research and development of cost effective alternative energy sources for the future.

The Perot Group understood that the US needs to cut consumption. Compared to other countries in the world, we are the oil hog, having grown up on an abundant supply of cheap oil. Figure 14–7 illustrates this point, and it questions where the growing countries of Asia, especially China and India, will get their future supplies.

Fig. 14–7 Oil consumption of barrels per person/annum

In igure 14–7, I have made two predictions where China will stand in 2035. The blue number of 6.5 bbl per person comes from the EIA’s 25-year projection made in 2010. China’s consumption would just about reach Mexico’s historical usage. China’s oil demand will be 18.5 million b/d using the EIA’s forecast of 2.9% annual demand increase. Contrast this to the actual increase in China’s oil demand increase of 5.2% in 2005–09. Remember, this also included the worldwide depression years of 2008–09. Using the 5.2% as the growth rate, this would stretch the 235

THE WORLD ENERGY DILEMMA

system. Note that the red consumption pattern rises to 11.4 bbl per person, which assumes no population growth. If this rate of growth continues for 25-year forecast period, then China’s consumption of oil would reach 29 million b/d—surpassing by far the 18.5 million b/d predicted by the EIA. I do not know if past history is right, but I do not know where the Chinese will get their oil if their economy continues to grow as in the past. Meanwhile, China and India both are becoming very aggressive in the international markets to tie up new oil supplies. China’s national oil companies now are producing more than 1 million b/d outside their own country. Perot’s plan for natural gas has received little attention in the US, and the use of natural gas as a fuel for transportation has gone nowhere. According to a June 28, 2010, report by Raymond James Research, compressed natural gas and liqueied natural gas (CNG and LNG) provide less than 0.17% of the fuel for transportation in the US. We are laggards compared to other countries of the world, as shown in igure 14–8. Compare Pakistan’s nearly two million CNG vehicles with America’s 100,000. In Italy, one can buy cars that run on dual fuels in case of limited access to CNG. But America is way behind on its planning for CNG vehicles. Worldwide, there are 11.2 million CNG vehicles. Natural gas has been retroitted to a few trains rather than running on diesel. Apart from having an ample supply available, vehicles that use CNG produce signiicantly fewer emissions of pollutants.

Fig. 14–8 Natural gas vehicles by country (millions). Courtesy Raymond James.

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Why have we been so slow in picking up on natural gas as a transportation fuel? The main reason is that there has been little push from government—either national or state—to set up a distribution system across the country. Also, just a few years ago natural gas was in tight supply. But what a difference now due to the entrepreneurial spirit of America’s gas industry. Today, only 825 gas stations, or 1% of the nation’s total, have public access to CNG. There will be little progress in this area until there is a strong push to put government pool vehicles on natural gas and to force private marketers to provide CNG. States should mandate all service stations with monthly gasoline sales above a certain minimum to put in dual fueling facilities. Yes, this would cost the station owners but they could then pass the cost along to consumers. A gasoline tax would be another alternative to pay for the change. Meanwhile, there seems to be a gas bubble developing in this country, and natural gas is very cheap at $2.30–$3 compared with oil at $90–$110/ bbl. While Perot knew little about shale gas in 1992, he was aware of the gas bubble as it existed then, and he pushed for it to be used as a transportation alternative similar to the more recent plan put forward by T. Boone Pickens. Figure 14–9 shows the historical gas supply picture as presented by George Littell of Groppe, Long & Littell (GLL). Note the large gas bubble that developed during 1975–95. Since then, supply and demand have been in balance with rising gas prices suficient to meet demand. This igure shows GLL’s historical review of what makes up the US Lower 48’s supply. Note the decline in Canadian imports, which we have counted on for years to make up our deicit. Also note the small supply of LNG, even though there were large investments in new LNG facilities in recent years. At $2.50–$4/cu ft, these facilities just cannot compete and remain shut in. In fact, some are being retroitted for LNG exports. Cheniere Energy Partners has been given approval to build as many as four liquefaction trains to export up to 2.6 billion cu ft/day. The gas can then be exported to any country which has a free trade agreement with the US, including Canada, Mexico, Chile, and Singapore.

237

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Fig. 14–9 US natural gas production

The declines in offshore gas were of concern even before BP’s Macondo blowout, as is the resulting slowdown in offshore drilling. On the positive side, note the sharp buildup in three unconventional resource plays: coal-bed methane, tight gas, and shale gas. Tight gas has come along with the advent of new stimulation proppants such as bauxite and resin-coated sand. Shale gas has come with horizontal drilling and large multistage fracs. The dilemma for energy planners, though, is whether the new technology will provide deliverability of gas suficient to meet increasing demand, especially if gas is used as a transportation fuel. Some believe it will, others do not. While it would appear that natural gas prices are too low to sustain the drilling level of 900 or more gas rigs of the past two years, the extreme cold of the winter of 2010–11 may have provided the incentive to keep on drilling, but gas prices have not yet begun to rise, and the May 2012 rig count is now down in the 600 range and dropping. The gas surplus allowed us to overcome a very cold winter. In 2012, however, a warm winter combined with continued growth in shale gas reserves has again resulted in a large gas bubble. See igure 14–10. 238

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Fig. 14–10 US natural gas storage as of May 4, 2012

What is shale gas? Basically these are the source rocks that have fed the gas traps we were looking for such as vertical wells. Many times in the past we might get a puff of gas, but nothing commercial out of the shale. Today, these new shale wells come in making 3–15 MMcf/d or more due to new technology such as horizontal drilling, fracturing, improved reservoir deinition, and through improved seismic. There is a question of how big the reserves are and at what price they can be developed. At the current price of $2–$3, they are, in my opinion, mostly uneconomic. If the industry realized how low gas prices would plummet, most of the current shale gas reserves would have never been developed. The resource potential is large, but at what price to develop it? My analysis suggests a return of $7–$8 MCf is needed to justify the much higher costs of horizontal shale drilling. In other basins, development will vary depending upon the cost to drill and complete. According to Robert D. Clarke, unconventional gas research manager for consultant Wood Mackenzie, the magnitude of the US shale gas resource is extraordinary: “We estimate the total resource play of the 22 shale plays we currently analyze is 650 TCF of gas equivalent: equivalent to a resource life of 32 years based on total US gas production in 2009. Shale gas production is set to increase from 17% in 2010 to 35% in 239

THE WORLD ENERGY DILEMMA

2020 of total US gas supply.” Exxon has backed up its claim by forking over some $40 billion for its purchase of XTO Energy. It also seems that China is not afraid of the low prices of natural gas or the environmentalists’ blanket of green as they made a $1.1 billion bid for a stake in Chesapeake Energy’s US shale oil and gas ield. Of course, China’s primary incentive is to acquire the technology for application in its own domestic shale basins. Estimates of North American shale gas reserves vary widely, from Arthur Berman’s 124 TCF at 90% probability to Wood Mackenzie estimates of 600 TCF. The political risk seems to be fanned by the environmental activists, the EPA, and the media, who seem to want to cover up energy development in the USA with their blanket of green. Recently the New York Senate voted to ban shale gas drilling in the State of New York, due to concerns about the risk of water contamination. But Elizabeth Ames Jones, former chairman of the Texas Rail Road Commission, took issue with such claims as reported in the July 8, 2010, issue of EP Magazine: Based on the facts, one can be conident that the geology in Texas, combined with safeguards that we require in the drilling of a well, simply do not support the notion that water used in hydraulic fracturing will migrate to a water table. With the many thousands of fracs taking place in Texas, Commission records do not indicate a single documented water contamination case associated with hydraulic fracturing in our state. In addition, John Hanger, Pennsylvania’s chief environmental regulator, said he saw no evidence that the chemicals used in hydraulic fracturing contaminates underground water supplies: “It’s our experience in Pennsylvania that we have not had one case in which the luids used to break out the gas from 5,000–8,000 feet underground have returned to contaminate ground water.” Hanger said that the public and the media appear to have “overestimated the risks of hydraulic fracing.” However, Hanger did say that oficials have found cases of water contamination caused by spills and leaks of drilling material on the surface of so-called “fracing” operations during Pennsylvania’s current drilling boom. A lot of the concern about the shale gas fracing comes from the fact that the chemical composition of speciic frac jobs is considered conidential for proprietary reasons. The industry however has released the general composition, which ranges from acids, sodium chloride, borate salts, and ethylene glycol. 240

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There is also an economic risk associated with shale gas development. For example, Berman talks about operators of Haynesville shale wells in East Texas and Northern Louisiana, which claim reserves as high as 6.5 Bcf, which he claims are much smaller at 2.5 Bcf per well. If Berman is right, then I estimate it will take prices of more than $10/Mcf before it would be economical to drill a Haynesville shale well. That was the price in the boom of 2008. At its peak, the gas price went over $11/Mcf when all the hype was developed about the tremendous potential of the Haynesville Shale. In my analysis, I used a cost of $8.5 million to complete and tie-in a Haynesville horizontal multi-fraced well.

Powers Shale Gas Economics The following is my analysis of what it takes to make shale gas, i.e., dry shale gas, economic in most of shale basins in the US. The bottom line is that for most all of the basins for dry gas it will take $7 to $8/mcf, which explains why companies are curtailing gas drilling as fast as they can. This does not mean that every dry gas well will be a loser, because there are better-than-average sweet spots. Based on my prior experience, the guideline for a gas well to meet a minimal acceptable rate of return is twice the operator’s capital investment. I then applied that to the average drill and complete costs for each basin and reported average reserves to determine what price gas would have to be in each basin to meet my two-times return criteria. The well costs to drill and complete were obtained from Mike Chafin, an engineer with Valence Operating Company.4 The average reserves were obtained from a study by Dan Jarvie in a paper presented at the Spring 2010 TCU Energy Institue.5 Table 14–1 is calculated to show the shale gas minimum price to yield a satisfactory return. Table 14–2 assumes an operator can reduce his investment costs by 25%. Table 14–3 assumes the operator can both reduce his investment costs by 25% and increase the reserves by 25%. Note no average Eagle Ford Shale reserves were included in the referenced resource.

241

$3.00

1.3

Fayette Shale

$2.85

1.3

1.9

Barrnett Shale

Woodford Shale

$ 9.00

$ 5.70

$10.00

$17.00

$ 6.00

$10.00

$MM

0.575

0.575

0.575

0.575

0.575

0.575

$15.65

$ 9.91

$17.31

$29.57

$10.43

$17.39

$MM

13.60

8.00

2.40

6.80

4.00

1.3

3.4

Fayette Shale

Haynesville Shale

2.28

3.60

1.3

1.9

Barrnett Shale

Woodford Shale

7.20

4.56

4.80

8.00

4.00

$MM

$MM

BC

2.6

Basin

Marcellus Shale

Eagleford Shale

5.2

3.3

9.9

3.5

5.8

0.575

0.575

0.575

0.575

0.575

0.575

$MM

12.52

7.93

13.91

23.65

8.35

13.91

4.2

2.6

7.9

2.8

4.6

$3.00

3.9

2.5

7.4

2.6

4.3

3.1

2.0

5.9

2.1

3.5

$4.00

3.1

2.0

5.9

2.1

3.5

2.6

1.7

4.9

1.7

2.9

2.5

1.6

4.7

1.7

2.8

$5.00

2.2

1.4

4.2

1.5

2.5

2.1

1.3

3.9

1.4

2.3

$6.00

2.0

1.2

3.7

1.3

2.2

$3.00 $4.00 $5.00 $6.00 $7.00 $8.00

Invest Cost 2X Invest Frac to OP Rev Required

Table 14–2 Reserves required to get a 2:1 payout at various gas prices

$4.50

$8.50

$5.00

Haynesville Shale 3.4

Eagleford Shale

$5.00

2.6

Marcellus Shale

$MM

Bcf

Basin

Invest Cost 2X Invest Frac to OP Rev Required

Table 14–1 Reserves required to get a 2:1 payout at various gas prices

1.8

1.1

3.4

1.2

2.0

$7.00

1.6

1.0

3.0

1.0

1.7

$8.00

4.25

Haynesville Shale

1.625

2.375

Barrnett Shale

Woodford Shale

Eagleford Shale

1.625

Fayette Shale

Bcf

3.25

Marcellus Shale

Basin

$3.60

$2.28

$4.00

$6.80

$2.40

$4.00

$MM

$ 7.20

$ 4.56

$ 8.00

$13.60

$ 4.80

$ 8.00

$MM

Invest Cost 2X Invest

0.575

0.575

0.575

0.575

0.575

0.575

$12.52

$ 7.93

$13.91

$23.65

$ 8.35

$13.91

$MM

Frac to OP Rev Required

Table 14–3 Reserves required to get a 2:1 payout at various gas prices

4.2

2.6

7.9

2.8

3.7

$3.00

2.5

1.6

4.7

1.7

2.8

$4.00

2.0

1.3

3.8

1.3

2.2

$5.00

1.7

1.1

3.2

1.1

1.9

$6.00

1.4

0.9

2.7

1.0

1.6

$7.00

1.3

0.8

2.4

0.8

1.4

$8.00

THE WORLD ENERGY DILEMMA

What these tables show is that unless an operator in most basins can beat the average costs and/or average reserves, shale gas drilling is probably not economical unless a price of $7–$8/Mcf is obtained. If costs could be reduced by 25% and reserves increased by 25%, a price of $4 to $5/Mcf would justify drilling. I am referring to the volume weighted price over the life of the well. For this analysis, I have applied the following assumptions: 1.

A well needs to return at least two times the cost to drill and complete to be classiied as proitable, based on many years of economic evaluation work.

2.

Net revenue interest of 75% or royalty burdens 25%

3.

Severance tax of 7.5%

4.

Other taxes and operating expense, i.e., 10%

5.

This leaves the operator receiving 57.5% of the revenue to return two times his original investment.

This means that the tremendous shale gas reserves are uneconomic at prices of $3.50–$4/Mcf. But most operators are betting on higher prices to come, or they have condensate in the area they are drilling. Another reason members of the industry continue to drill is the large lease-hold positions they took to maintain their leases in 2008 when the price was $10/Mcf. However, recently the gas rig count has fallen back down to around 600 according to the latest Baker Hughes rig count. These data are primarily for dry gas. These tables do not include liquids, and that can make a signiicant difference in some of these basins. Note that my reserve resource did not have a good average reserve number for the most recent shale trend, the Eagle Ford, which includes three regions, including a dry gas region, one with rich condensate and oil. This basin is in an old oil and gas producing area of South Texas and the shale gas wells were most recently put on production. One way to use these tables would be to calculate an effective gas price including liquids (ig. 14–11). The Eagle Ford shale has several sections of dry gas, rich gas, and oil regions of this large, new play that have been brought about by horizontal drilling and multiple fracture treatments of the tight shale. Leasing in the area has gone from $50/acre in the early days to as high as $4,000/ acre. This is a sea change in our energy picture, as long as politicians 244

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and bureaucrats don’t get in the way of sound gas supply development. Fortunately, technology has caught up with Perot’s vision of using gas as a motor fuel.

Fig. 14–11 Shale gas revenues boosted by inclusion of NGLs and condensate

There are other distracters, too, such as industry experts who do not think we have abundant long-term supplies of natural gas. One of them is consulting irm Groppe, Long & Littell. While GLL show historically that gas supplies in the US have been climbing due to shale gas, the overall decline in conventional gas coupled with their rather pessimistic forecast of shale gas growth beyond a couple of more years leads them to believe that gas prices are going up quickly. This is partially a result of the conventional gas decline accelerating, primarily in the Gulf of Mexico. This acceleration has been aggravated by the recent drilling slowdown in the GOM as a result of the new slowdown in processing drilling permits. It should be noted that the US offshore rig count was now down some 45.7% in February 2010 as opposed to a year before. This trend is most disturbing, and it is likely to continue until the Obama administration 245

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decides to promote offshore deepwater energy growth. This problem was reinforced when Eddie Cousin, a friend of mine, returned from South Korea and reported that two rigs he was working on were being redirected from the Gulf Coast, which they were designed for, to Libya and Brazil. At the November 2010 Pioneer Oil Producers Society meeting, George Littell suggested a sharp rise in natural gas prices from the current $4–$5/ Mcf to the $8 range in 2011 and a sharp peak thereafter as long as oil prices continue higher. In other words, consultants GLL do not see a gas surplus building in America. In my opinion, if the industry perceives gas prices in the $8/Mcf range, they will be in the $4–$5 range. If the industry perceives prices in the $2–$3/Mcf range, then prices will be higher. It is a matter of perception. The current situation regarding gas prices is the same as it was for oil prices in 1986–88. Future prices will be controlled by what industry perceives now. The industry has a tendency to over-drill or under-drill based on its collective perception of the future. For now at least, it appears that the industry perceives the lower price range so perhaps gas prices will be higher. In conclusion, I believe that until the gas rig count comes down, gas prices will continue to be depressed in the $2–$3/Mcf range and stay there.

Perot Petroleum Policy US oil production is declining and imports are rising. The best we can do is latten the decline in production. Initiatives in the oil sector have complex consequences on the relative cost of other energy sources, the proitability of the domestic oil and gas business and the direct cost of transportation. Policy Support: 1. Effective tax revisions to encourage production of existing reserves and drilling for additional reserves. 2. Improved access to public and federal controlled lands, including environmentally controlled exploration and production in ANWR and OCS. 3. Research in enhanced recovery of resources. 246

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In regards to item 1 and 3 of Ross Perot’s oil policy, I do not now support spending government money in this manner, because at current and future prices of oil, I believe this research at $80/bbl can best be done by the private sector. Besides, our government is broke. However, I do believe that item 2 is very important. If the global economy recovers, as some are predicting, the world is going to need every drop of oil it can economically produce. This includes drilling in the deepwater offshore as well as the Alaska National Wildlife Refuge, which has been prohibited for more than 30 years by the US Senate. But covered by the environmentalists’ green blanket, ANWR does not even get a mention in the press or the government policy debate. Only one of the presidential candidates in 2012 brought the subject up, and he is no longer running. Sadad al Husseini reinforced my thoughts in a recent interview. Asked to assume that declines in demand have lattened and that we resume modest growth in demand in a year or so, Sadad said he had been tracking the number of projects for a long time in the Middle East, as well as Russia, Brazil, Africa, and elsewhere: A lot of the information is in the public domain, so there is no mystery there. The International Energy Agency recently reported on the same number. The bottom line is that there are not enough projects. There is not enough new capacity coming on line, within say the next 5–6 years, to make up for global declines. That’s assuming a 6%–6.5% decline for non-OPEC and a 3.5%–4% decline of OPEC. Supporting Sadad’s analysis is igure 14–12 from an Exxon Planning report in 1994. Exxon showed combined world oil and gas production on a daily basis during 1980–90. Exxon showed what would happen if no more investment was made. The decline is the same as Sadad’s assessment nearly 20 years later. The combined oil and gas equivalent barrels decline from 4%–6% per year from existing ields on a worldwide basis. Assuming a rate of 5%, this means the world needs to add 4.25 million b/d of new capacity each year just to offset normal decline. What Sadad is trying to tell the world is based on his review. He just cannot see enough projects being planned. So, in just a few years out— such as 2015–2016—Sadad sees another oil shortage. That’s if demand grows at a normal 1–2 million bbl each year. But if peace and stability do not return to the Middle East quickly, the oil shortage could be on us any day. 247

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Fig. 14–12 World oil and gas production growth and decline without further investment. Source: ExxonMobil Energy Outlook 2004.

The slowdown in deepwater drilling will contribute to the inability to meet world demand, thus precipitating another hike in world oil prices as in 1998 with a resulting recession to follow. The recent blowout in the Gulf of Mexico was a tremendous setback to our expanding capabilities offshore. For two years the Obama administration has dragged its heels and dithered on the expansion of offshore leasing. Before the Macondo blowout, Obama said he would support offshore drilling in certain areas, though not off California. He made no mention of allowing drilling in ANWR, where 15–30 billion bbl of potential exists—similar to Prudhoe Bay. US Secretary of the Interior Ken Salazar has likewise been dragging his heels for two years after cancelling plans by the former Bush administration to expand offshore drilling as well as drilling on some federal leases in Wyoming and Montana. Cancelling the leases because he thought they were too close to National Parks, Salazar is part of the movement to spread the environmentalists’ green blanket across this country.

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Two years later, during the summer of 2010, Obama lifted the ban for most of our offshore except in the politically important state of California. Then, he reinstated the ban on offshore drilling in the east, including both of Florida’s coastlines. In addition to its drilling ban, the Obama administration had essentially shut down offshore drilling in the Gulf of Mexico, where thousands of wells produce about a quarter of our domestic oil. In January 2011, the Obama administration—six months after suspending offshore projects due to the BP blowout—said the companies could resume work three months after the safety rules were put into effect. With such lip-lopping, what is a manager with deepwater prospects to do? Talk about a dilemma! Offshore drilling is too important to America’s future to cover it with the environmentalists’ green blanket. Yes, BP should be required to clean up the mess and pay the Gulf Coast people who have been hurt, which BP has agreed to do. Long-term, however, the offshore industry should not be held hostage to this event, or future generations of Americans will suffer and the current generation will lose jobs. The Gulf of Mexico is not permanently damaged, as evidenced by previous spills, particularly those in warm water. After the Gulf War, by 2006, Saudi Aramco reported that the Arabian Gulf had “made a remarkable recovery.” As reported by the San Francisco Examiner on July 28, 2010, a recent light over the Gulf of Mexico “found little evidence of the oil on the surface.” Now scientists say that much of the leaked oil is disappearing on its own, much of it through evaporation and microbes in the water, which are in a feeding frenzy. For years, these microbes have been cleaning up oil from naturally occurring seeps in the ocean. On October 1, 2010, a report on CNBC said that the EPA had found no oil on the sea loor around the plugged Macondo well. Government oficials should not overreact to problems such as this by passing legislation to prevent companies such as BP, the world’s biggest offshore producer, from cleaning up their act and continuing to drill. Oficials also should not put more bureaucratic red tape in the way preventing others from drilling in our offshore waters. Improved but reasonable safety standards are acceptable. The deepwater offshore is where a large part of the worlds’ oil and gas reserves are to be found, including here in America.

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America’s and the world’s supply of energy is much better off because of our innovation and development of deepwater technology. Other countries, such as Brazil and Norway, have also played important roles. Figure 14–13 shows the advancement of the industry in developing its deepwater technology, and notice that we are at the level of 10,000 ft deep. By example, Brazil has deepwater deployments as deep as 6,600 feet.

Fig. 14–13 Worldwide progression of water depth capabilities for offshore drilling

The importance of deepwater to the world oil supply cannot be overstated. About 6.3 million b/d come from water basins around the world deeper than 1,500 ft. Colin Campbell is the one who broke out the reserves: 6.3 million b/d or 7.5% of today’s worldwide 85 million b/d. Note that there are four major deepwater basins in the world: USA 1.5 million b/d; Brazil 1.7 million b/d, Angola 1.4 million b/d; and Nigeria 1.2 million b/d, along with other miscellaneous basins at 0.7 million b/d. Although Campbell is a proponent of peak oil, he does project that deepwater oil production from current discoveries will grow to 9 million  b/d by 2020. However, his prediction was made before the Macondo blowout and its consequences. Again, the importance of 250

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deepwater drilling to our world oil supply cannot be overemphasized. Messing with deepwater through an increasing sea of red tape, along with America’s continued ban on it, will only hasten the arrival of the next oil crisis. At the time of writing, the future of the offshore deepwater in the US looked more in doubt with the spreading of the environmentalists’ green blanket. On October 9, 2010, a headline in the Houston Chronicle sent chills up my spine: “Disaster in the Gulf—price tag for drilling rules put at $183 million a year—industry oficials say tally may send some players packing.” While I do not profess to be an offshore drilling expert, the words of Interior Secretary Ken Salazar are most discouraging. In announcing the new mandates, the secretary cautioned that oil and gas companies should expect a dynamic regulatory environment, with more mandates on the way. Raymond James Energy (RJE) highlights the seriousness of the matter in terms of offshore drilling companies’ revenue generation, but more importantly what it means for developing our future offshore reserves. In its Oct. 11, 2010, newsletter, RJE said: The main reason for our near-term pessimism is that it appears the current offshore US deepwater moratorium is likely to morph into an “Obamatorium” when the drilling moratorium is technically lifted but drilling does not rebound due to Obama administrationdirected permitting delays. Additionally, ongoing deliveries of (pre-meltdown ordered) rig new-builds mean that offshore drilling capacity is likely to increase in an already oversupplied market. RJE’s main conclusion is that the “Obamatorium” will depress US offshore activity greater and longer than many expect. RJE continues: One only has to look at US offshore rig activity to understand the concept that technically there is no moratorium on shallow water drilling. But, practically speaking, by implementing an impossibly cumbersome permitting process, the administration has effectively killed shallow water activity. RJE notes that there have only been six shallow-water permits issued since the moratorium was imposed, compared to a monthly run rate of 15–30 prior to Macondo. Recently permitting seems to be picking up, and we are just about back to the level before the Obama shutdown. 251

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Shale in Texas, North Dakota Two bright spots in America’s oil picture have occurred due to horizontal drilling together with massive multi-stage fractures of oil-bearing shale. They are the Eagle Ford shale in Southwest Texas and the Bakken shale/sand in North Dakota. Both of these areas are booming in connection with employment, housing, and commerce in general. In 2011 I attended a conference in San Antonio presented by the Texas Alliance of Energy Producers, where it was reported that in the Eagle Ford shale more than 300 new completions had been made, the majority of them for oil, and that there were 2,000 more wells permitted. This new oil area, in my opinion, has the potential to become a million b/d producer in four to ive years. The North Dakota Bakken play also has the potential to also be a million b/d producer. These opinions were reinforced by Tom Petrie of Bank of America Merrill Lynch, a well-known energy consultant, who appeared on CNBC in late February 2011. Petrie opined that the Eagle Ford and the Bakken plays each could be 1-million-b/d ields. Other basins, such as the Permian in west Texas, are becoming more active, so it is not impossible to expect shale oil to contribute 3–4 million bbl/d of new oil in 5–10 years, as long as the price of oil stays in the $100/bbl range. Should oil prices drop as they did in 2008, the shale boom will come to a screeching halt. Recently I heard an Association of Peak Oil (ASPO) forum talk by Arthur Berman, who reports inding and developing costs in the range of $50 to $60 per bbl. The future of shale oil will be very dependent on the price deck or forecast oil operators perceive in the future. Reserves estimates for the Bakken have ranged wildly over the last several years. In April 2008, the United States Geological Survey said the Bakken shale formation is the largest oil accumulation in the US, with 280 billion bbl of OOIP. This led to the circulation of some wild e-mails claiming that the US had more oil than Saudi Arabia. Wrong! Those e-mails failed to point out that the USGS claimed only 6.3 billion bbl of reserves. That 6.3 billion bbl itself represents a large new resource for America, and its development is ongoing at a fever pitch. Other operators who are active in the Bakken area now claim much larger reserves with horizontal drilling and the large fractures being applied. Some say the reserves are even higher. Billionaire oil man Harold Hamm, CEO of Continental Resources, reportedly said the recoverable 252

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oil in the Bakken and Three Forks formations is 20 billion bbl. Whether these numbers have something to do with Hamm’s recent announcement to offer 10 million more shares in Continental Resources, I do not know. In any event, both the Bakken and the Eagle Ford are going to be very interesting new oil plays to watch. The citizens in Texas and North Dakota should be excited about these new oil plays if the two ields grow to 2 million b/d with the resulting positive impact on their economic development. However, due to ongoing decline in other ields and new offshore drilling restrictions, US production in 2015 may be no more that it was in 2011, around 8 million b/d. If oil prices remain as high as they are and the tax structure for the industry is not changed, then it is possible we could see 9 million b/d by 2015. As more basins undergo horizontal drilling programs, we could see as much as 11 million barrels per day by 2015, assuming oil prices stay above $100/bbl. Drop the price back to $60/bbl and all bets are off, as a sharp decline in drilling will occur.

Nuclear This is the most environmentally friendly fuel we have in large quantities. Past technical problems with the disposal of nuclear fuel generated waste have not been resolved in the United States. We generate about 20% of our electricity from nuclear energy compared to 75% for France and 27% for Japan before the meltdown of the Fukushima Daiichi nuclear plant in 2011. Nuclear energy is not dependent upon foreign sources, does not contribute to acid rain or the greenhouse effect, and can supply a substantial portion of our anticipated 32% net increase in electricity requirements over the next 20 years. Policy Support: 1. Simplify the licensing of new nuclear plants. 2. Develop a model reactor including passive safety features that can be mass produced. 3. Break the federal and state logjam on waste disposal. 4. Provide opportunity for a fair return on investment to utilities. 5. Increase public awareness of the long-term need for nuclear energy 6. Support research in the ield of nuclear fusion as a future source of energy. 253

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The destruction of Japan’s Fukushima No 1 nuclear facility in 2011 leads one to an immediate conclusion: caution in the building of nuclear plants. Remember the Biblical warning that a house will fall if it is built on sand—a lesson that suggests never building a nuclear power plant in an earthquake-prone region or near any coast that is subject to hurricane force winds or coastal looding. In fact, I think the same goes for any new power plants regardless of their fuel source. One reaction I hear is to stop construction of all new nuclear plants. It is the same sort of reaction as when BP’s Macondo well blew out. Some people said stop all offshore drilling. It’s a wrongheaded reaction and one more dilemma for world energy planners. What is the world to do? Consider China, which had 25 new nuclear reactors being built at the time of the Japanese disaster. Thanks to the nuclear industry and government direction some 30 years ago, nuclear energy still plays an important role in our in our electric power generation in the US, as shown in igures 14–14 and 14–15. In 1991, Ross Perot realized that nuclear power was an important source of our electrical energy and should be further developed. At that time, 20% of our electric power was nuclear generated. Figure 14–15 shows a slight increase for nuclear power, rising to 21% from 20%, since no new plants have been build for the last 18 years. From Perot’s viewpoint, the growing lack of planning for new power plants to be built in this country was a serious problem.

Fig. 14–14 1991 fuel sources of US electricity generation

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Fig. 14–15 2009 fuel sources of US electricity generation

Figure 14–16 shows US electricity consumption from 1991, the start of the Perot election campaign. Perot was concerned about where this power supply was going to come from, and he recommended nuclear, natural gas, and research on clean coal technology. In the years that followed, electrical consumption rose by 2.3%. But notice how our power demand growth leveled out from 2001–2007, and then with the depression has actually declined in the last two years at about 3% per year. Two new nuclear plants have been proposed and one approved under the Obama administration, and this supply of energy should be pushed for expanded development.

Fig. 14–16 US electric consumption, 1991–2009

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Nuclear waste is a continuing problem that has yet to be resolved in the US. Note the recent shutdown of the Yucca Flats repository project which cost the US government $13.5 billion. The DOE estimated the total costs at $96.2 billion. Very little mention of reprocessing uranium has been made in recent years in the US, although other countries, such as France and Japan, have been doing it successfully for years. Ron Lantz has a few facts on nuclear energy worth noting: 1.

The DOE is proposing a new generation of reactor reprocessing technology.

2.

French reprocessing of fuel rods consists of cooling for three years after removing from reactor; chopping up rods after cooling; dissolving the chopped up rods in HNO3, nitric acid; separating uranium and plutonium chemically from other wastes; casting other wastes into glass logs; placing glass logs into deep geologic storage.

3.

Reprocessing reduces waste volume by factor of 4–5.

4.

Reactor fuel becomes “spent” and does not contain 3%–5% “burnable” uranium.

5.

Spent fuel still has 95% of the uranium it started with.

6.

The 56,000 tons of used fuel stored at nuclear plants has enough energy to power the US for 12 years.

7.

The French plant at La Hague processes 50% spent French fuel and 50% other nations’ spent fuel; it has processed 23,000 tons of spent fuel.

8.

The US claims that reprocessing costs about $1,000/kg more than direct disposal, but that claim is highly questionable since no waste has ever been disposed of directly. Yucca Mountain is closed at present.

Some of these facts are signiicant and require serious study by our energy planners. The French are signiicantly ahead of the US in the handling of their nuclear waste. Note that in 1992, when Perot was talking about nuclear energy, the price of uranium was only about $7/lb and it stayed that way for the next 10 years. In the fall of 2007, there was a spike to $140/lb as China entered the market. The Chinese wanted to secure uranium for their expanding 256

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nuclear program, and the price of oil was beginning its 2008 run. After the 2007 run, uranium fell back to about $60/lb in 2008, and was $43/ lb in 2009 and in 2010. As oil prices have moved recently and demand for uranium has grown, the price moved up to $68.50/lb as oil moved. Another dilemma for planners: how high will the prices go this time? A real beneit of nuclear power for the future is that the price of power per kilowatt is much less affected by the price of fuel. A Finnish study done in 2000 showed relative comparisons on the impact on a change in fuel prices on the power costs between coal, gas, and uranium. For comparison, consider a doubling of the cost of all three fuels. The Finnish study showed that if the gas price doubled, the cost of power would go up 66%, for coal 31% and for nuclear just 9%. Figure 14–17 illustrates the relatively small impact of uranium on nuclear power costs. With our current volatile oil market, this clearly makes the case for nuclear power in the US. Why have we been asleep at the switch for since the Perot Energy Plan was submitted some 18 years ago?

Fig. 14–17 Effect of uranium price on fuel cost

Table 14–4 shows that hydro power is the cheapest, followed by nuclear, and then fossil steam, which includes, coal, oil, and natural gas. Note that gas turbine, solar, and wind supplied only 4% of electric power in 2009. And that was at a cost 3.5 times higher that of nuclear or 2.0 times the cost of fossil fuel in 2008—even with the high fossil fuel prices of 2008.

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Table 14–4 Average power plant costs by type (mills per kilowatt hour). Source: EPA. Plant Type

2008

Operation Nuclear

9.68

Fossil Steam

3.65

Hydroelectric

5.78

Gas Turbine and Small Scale

2.98

Maintenance Nuclear

6.2

Fossil Steam

3.59

Hydroelectric

3.89

Gas Turbine and Small Scale

2.72

Fuel Nuclear Fossil Steam Hydroelectric Gas Turbine and Small Scale

5.29 28.43 – 64.23

Total Nuclear

21.16

Fossil Steam

35.67

Hydroelectric

9.67

Gas Turbine and Small Scale

69.93

Figure 14–18 compares the cost in BTU for coal and natural gas through mid- 2010. It also shows the electric utility costs for industrial, commercial, and residential customers. Coal is up to $2.25/MMBTU and natural gas to the residential customer is a little over $5/MMBTU. Meanwhile, gas prices at the wellhead have languished at the range of $2.30–$3/MMBTU over the inal 6 months of 2010. Table 14–5 is another analysis, offered by the EIA, that estimates the cost of electric power in 2016. This table shows that gas is superior to all other systems of power generation per unit of energy generated. New hydro power sources are not available. Gas with a carbon capture and storage (CCS) beats all other systems and wins out over solar by 225%–350%, even when including a CCS system. Gas with CCS beats wind by 105%–132% depending upon whether it is onshore or offshore. 258

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So why is there all the hype about wind and solar power by the Obama administration? Because of the fear of global warming and what the US should do about it. It is probably wise for America to develop alternatives that spread the country’s energy sources, but they do need to be cost competitive.

Fig. 14–18 Electricity rates and fossil fuel costs

Still, it does appear that green energy has a few problems, too, given the rolling brown-outs in Texas during the winter of 2010–11 due to ice on the wind mills and frozen pipes in some of the power plants. Proposed wind farms and electrical hookups off the US East Coast are expected to cost $5 billion. I wonder what their solution will be for ice on the windmills in a Nor’easter. Google, Inc., owner of the famed Internet search engine, recently announced that it will take 37.5% interest in this project. Wind will be a growing energy source, but it will peak out as coal continues to be the primary fuel for electrical energy, as shown in igure 14–19. 259

69.2 81.2 92.6 22.9 22.4 43.8 41.1 38.5 94.9 130.5 159.9 376.8 224.4 88.0 73.3 103.7

85 85 85

87 87 87 30 30 90 34.4 39.3 21.7 31.2 90 83 51.4

1.7 1.6 2.7 4.7 4.1 11.7 10.4 23.8 6.4 21.8 22.9 9.1 3.5

3.8 5.3 6.3 54.9 51.7 63.0 82.9 70.0 9.4 0.0 0.0 0.0 0.0 0.0 24.9 7.1

23.9 20.4 26.4 3.6 3.6 3.8 10.8 10.8 3.0 8.4 7.4 13.0 10.4 4.8 3.8 5.7

3.6 3.6 3.9 83.1 79.3 113.3 139.5 123.5 119.0 149.3 191.1 396.1 256.6 115.7 111.0 119.9

100.4 110.5 129.3

Sourcc: Energy Information Administration. Annual Energy Outlook 2010. December 2009, DOE/EIA-0383(2009)

Conventional Coal Advanced Coal Advanced Coal with CCS Natural Gas-ired Conventional Combined Cycle Advanced Combined Cycle Advanced CC with CCS Conventional Combustion Turbine Advanced Combustion Turbine Advanced Nuclear Wind Wind—Offshore Solar PV Solar Thermal Geothermal Biomass Hydro

Plant Type

US Average levelled Costs (2008 $/megawatthour) for Plants Capacity Entering Service in 2016 Factor Levelized Fued Variable O&M Transmission Total System (%) Capital Cost O&M (including fuel) Investment Levelized Cost

Table 14–5 Estimated levelized costs of new generation resources, 2016

Clean gas over solar 226%–350%

Clean gas over wind 105%–132%

Gas over nuclear 105%–150%

Gas over goal 113%–139%

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Fig. 14–19 Grid-connected coal-ired and wind-powered capacity, 2003–2035 gigawatts. Source: EIA.

The latest wrinkle is that the Federal Energy Regulatory Commission (FERC) is going to order electricity users to pay to connect to the wind power stations off the East Coast. Figure 14–20 is the 2010 EIA’s estimate of future various energy sources on a worldwide basis. Note how renewable grows in the mind of the EIA but how worldwide use of coal still grows at an even faster rate despite the EPA’s dire predictions. It appears that the EPA has little control over the world growth in coal. Figure 14–21 compares the various sources of projected alternate energy for uses to generate electricity as forecast by the EIA. Notice how wind becomes a major player, as does biomass, while solar continues to be a small player. So why is there all the hype on solar, and why does the government continue dole out money, that it does not have, to the solar industry?

261

Fig. 14–20 World marketed energy use by fuel type. Source: EIA.

Fig. 14–21 Non-hydro electric renewable power generation by energy source, 2008–2035. Source: EIA.

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As this book was going press I noted that, according to the Weekend China Daily Free Press, headlines read “US Orders Tariffs on Chinese Panels,” in order to protect jobs in a generally uneconomic industry, which the US government subsidizes. What is going on here? The US wants to increase the cost of solar panels, which will increase the amount the government spends to get consumers to buy solar panels. Something does not meet the rules of common sense. Biomass also grows. It seems that companies like Exxon must think since it has dedicated about $500 million to develop algae as a fuel. As it looks to diversify its energy portfolio, Exxon announced in July 2009 that it will invest at least $300 million in biotechnology research with Venter’s Synthetic Genomics, Inc., to help develop biofuels made from algae. Note that is investment is being done with private investment not our tax dollars.

Coal We have more than a 250-year supply of coal at present consumption levels. It is our largest single domestic source of energy (32%). Coal accounts for over 55% of the energy used in electricity generation at just 60% of the cost of electricity generated by oil. While coal has certain environmental disadvantages, its ease of access and economic advantages will not allow us to abandon its use in the near future. In addition, we are an exporter of coal and this contributes about $4.5 billion towards our favorable balance of trade. Policy Support: 1. Research of clean-coal technology to reduce emissions. 2. Export of coal and clean-coal technology to generate a favorable balance of payments and help world environmental problems. 3. Regulate for reasonable safety and environmental issues. As pointed out in the Perot Balanced Energy Policy, coal was highlighted as America’s most abundant source of energy with more than a 250-year supply at 1991 consumption levels. Since the Perot Energy plan was proposed, the environmentalists have been trying to throw their blanket of green over the entire US coal industry. I admit that H2S emissions were bad and were taken care of years ago. But CO2 is another question, and the rest of the world is expanding its use of coal 263

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while our government is calling coal an environmental hazard that is dangerous to our health. The atmosphere is owned by the world, not just the US. The failure of the recent meeting in Sweden to come up with a worldwide solution is an indication of the discord on the global warming theory that the Obama administration has bought into. Figure 14–22 shows the growth in the worldwide use of coal, as well as China’s. Note the large buildup in world growth beginning in 2003, when China’s growth exceeded that of the whole world. It seems that in 2009, the Chinese began importing more and more coal to meet their needs in spite of the 2008 recession. Note, too, that all of the world’s growth in coal usage was attributed to China in 2008. China became a net importer of coal on a regular basis, and its imports are projected to grow from here on in. India also is also increasing its coal consumption, as shown in igure 14–23.

Fig. 14–22 World and China annual coal consumption comparison, 2000–2009

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Fig. 14–23 Indian imports of coal, 2001–2015 (est.). Source: AME & RJ.

Raymond James Energy sees the US coal industry as a growth vehicle despite the Obama administration’s attempt to cover it up with their blanket of environmentalist green under the theory of global warming, Yes, coal is in a growth phase in the world, but not here in America from a usage standpoint, as the industry is threatened with a carbon tax. The US government has just doled out about a billion dollars—that it does not have—to build a clean coal plant in Illinois. Would not a tax rebate to a proitable US coal company have been a better way to go? This clean coal grant came at a time when the Illinois Commerce Commission slammed the Tenaska clean coal plant. Actually, the Illinois state legislature also bought into the theory of global warming, and it has forced the state to procure 5% of its electricity from clean coal plants. Since the law caps the residential rates at 2% increase, the overruns will be borne by the state’s industrial producers. The Illinois Commerce Commission also points out that the cost of power from the clean coal plant will be twice the cost of nuclear power. Then the federal government steps in with a billion dollars that it does not have in the form of stimulus money—an interesting contribution right before the midterm election. One other option is to convert coal to liquid hydrocarbons, as done by Accelergy, which uses advanced catalysts and state-of-the-art process technologies to transform natural gas, biomass, and coal into clean liquid transportation fuels. Not long ago, Accelergy secured a license to Exxon’s clean coal liquefaction technology, and it hoped to have a 265

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plant by early 2011. Again, private industry, not government subsidies, developed the technology. Will clean coal ly? I doubt it will after the global warming debate is over, but a lot of utility customers will not be happy in the meantime.

Notes 1. One of the meetings I attended at the recent Offshore Technical Conference was held by PEMEX. PEMEX is now inviting out-of-country companies to enter into joint venture partnerships to operate some of the Mexican ields. They are now in their second round of bids. After 30 or more years this appears to be a major turnaround and opens up many joint venture opportunities in the future. 2. Gates, Robert. 2001. “Text of Secretary of Defense Robert Gates’s Feb. 25, 2011, speech at West Point.” Stars and Stripes, Feb. 27. 3. Lantz, Ronald B. 2010. From Farm to Fortunate through Perseverance. Bloomington, IN: Xlibris, p. 200. 4. Private communication with Mike Chafin, Valence Engineering, September 2010. 5. Jarvie, Dan. 2010. “Assessment of Unconventional Shale Resource Plays Using Geochemistry.” TCU Energy Institute Workshop Handbook, p. 144.

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F

irst, what should not be included? The simple answer is politics, but that is impossible under the dinosaur that has appeared: the

Energy Department, the Interior Department, and the Environmental Protection Agency, as well as numerous congressional committees. The system is broken and out of control when one considers that the three agencies are forecast to cost the US taxpayers—I mean future generations of taxpayers—nearly $70 billion in 2011 compared to only $28 billion per year in 1992 when Perot ran for president. Not only is importing foreign oil bankrupting our country, so is Washington DC’s burgeoning energy bureaucracy. Figure 15–1 shows the last two years of the Bush administration and the irst three years, one actual and two forecast, for the Obama administration through 2011. Throwing more cash—by which I really

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mean debt—on our future generations is not the solution to America’s long-term energy problems. The expansion of these three departments with resulting deicit spending has been a growing problem in the past administrations, both Democratic and Republican. A government whose primary direction is fear of a disputed global warming theory is off course. It needs to be redirected in a way that encourages development of America’s energy resources and a reduction in America’s appetite for energy, particularly liquid hydrocarbons such as gasoline, fuel oil, diesel, and aviation fuel. Energy self-suficiency is a pipe dream of politicians. In fact, due to America’s large energy appetite—which was sustained by abundant cheap energy in the 1950s and 1960s—I do not believe America can become energy self-suficient. But we could do a lot better than we are now.

Fig. 15–1 Budgets of Departments of Energy, Interior, and EPA ($billions). Source: Ofice of Management and Budget, Congressmen Culberson’s Ofice.

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Excess Demand for Liquid Hydrocarbons The primary energy problem for America is our excess demand for liquid hydrocarbons compared to the rest of the world. We are the world’s leading oil hog. Oil was one of the key drivers that helped us win World War II and become the great nation we are today. But we now consume too much compared to what we are producing. We have to work on both sides of the oil equation: we have to reduce demand for liquid hydrocarbons and increase our domestic supply. John Hofmeister, the former president of Shell Oil, hit the nail on the head when he said that there is a basic conlict between Energy Time, which is deined by decades, and Political Time, which is deined by two- and four-year election cycles.1 To reduce the red tape in America’s energy plans, I agree with Hofmeister that our country’s energy planning needs a complete overhaul. It also needs to change course with regard to letting the environmentalists control our energy planning. Even if CO2 is the culprit in global warming, I do not believe that America can solve this problem by itself, especially when one considers the rapid growth of coal demand on a worldwide basis, especially when we are the Middle East of coal resources. Note the recent Kyoto agreement failure in Sweden. Others around the world are questioning this thesis, too. In my opinion, it is star-gazing if one thinks that developing countries of the world such as China and India, among others, would ever sign such an agreement. In summary, after writing this book, my conclusion is that America’s energy policy is sinking under a sea of red tape and covered under a blanket of environmentalist green. That said, we should support Hofmeister’s call for a radical overhaul. With our political system, though, it is doubtful such an overhaul will ever happen.

Perilous Times for America In fact, if just a few steps were taken, they would create hundreds of thousands of new jobs in America. These are perilous times for America, and a major change in our thinking is required without bankrupting our future generation. What should be done?

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Consider the following: 1.

Set up a nonpolitical scientiic taskforce of no more than 10 members from the scientiic community with a target date of January 2013–14. Their aim? To ascertain if global warming is a threat to mankind, if human-generated CO2 is the culprit, and, if so, whether America alone can do anything about it.

2.

Shift the emphasis in Washington DC away from the fear of global warming because of CO2 production to a priority on the development of America’s own energy resources.

3.

Give permission without delay to the XL Pipeline to be built from Canada to Houston. This decision alone should create thousands of jobs and put Americans to work in helping to secure our energy future.

4.

Reorganize the energy planning for this country along the lines of John Hofmeister’s proposal. Review the current red tape that is being added to all segments of the energy industry. Set a target date of July 2013.

5.

Rely on industry, not government, to solve our energy problem by providing tax incentives instead of direct subsidies that the government cannot actually afford.

6.

In 2012, begin reducing the cost of the Environmental Protection Agency as well as the Departments of Energy and Interior by 20% a year. Over four years, this alone would save $45 billion. This also would be a means of offsetting the attack by the Obama administration on the oil and gas industry over long-standing tax incentives to drill and explore for oil in the US.

In an effort to reduce liquid hydrocarbon usage, in 2012 we should impose a 15-cent-per-gallon tax on all transportation fuels in line with the recent Simpson-Bowles deicit reduction plan, with a possible rebate for low-income legal citizens. The rebates would be limited to basic driving needs and only to those who are required to drive a vehicle to work and are working or actively looking for a job. This could generate $45 billion per year. If the Perot 50-cents-per-gallon tax were imposed, it would generate $135 billion a year. Considering the recent hike in gasoline prices, though, it may be too late to get Americans to swallow this.

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On a worldwide basis, all countries need to reduce their demand or growing appetite for using liquid hydrocarbons until more new sources can be brought online. One thing is for sure: all countries of the world need to eliminate subsidies for using liquid hydrocarbons. This includes subsidies for citizens to buy any fuel-ineficient automobiles or trucks as well as subsidies for cheap gasoline, whether you are Saudi Arabia or not. All countries, developed and developing, should consider implementing the policies outlined here. China has long had a practice of subsidizing their citizens with cheap fuel, but as of the middle of 2008, something changed, as shown in igure 15–2. According to a report by the Wall Street Journal on March 7, 2011, “The Indian government is also trying to reduce subsidies on liquid fuel. Last year, it removed price caps on gasoline and has said it will do the same for diesel this year. They are continuing to study the problem.” In this environment, it does not make sense for governments to subsidize their citizens in general, and it affects the worldwide demand for petroleum. A netback to the consumers that absolutely must have fuel to drive back and forth to work may make some sense in certain situations.

Fig. 15–2 China versus US retail gasoline prices. Source: EIA, NDRC, NBS China, China SignPost.

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National Incentive Plan We also need to implement a national incentive program to push natural gas as a major transportation fuel, similar to the Pickens Plan. Government entities, such as state, county, city, and school districts that have fueling stations should be pushed to phase out gasoline leets and possibly diesel leets as well by converting their leets to natural gas, with systems that are dually fueled. This would allow lexibility should a new spike in gas prices arise. This goes for the world as well, but many countries already are away ahead of the US in this area. We should require each state by 2013 to come up with a plan that requires alternate fueling stations at reasonable distances, including electric and natural gas fueling stations, for major fueling stations across America. We should consider requiring intrastate truck lines, and possibly railroads, to begin retiring their gasoline and diesel engines by a certain date or at least require them to be able to use either liquids or natural gas. In the effort to stimulate the production of liquid hydrocarbons, we should immediately open the Alaska National Wildlife Refuge for exploration and development of 15–30 billion bbl of potential reserves or maybe even a billion bbl of oil. We need to push back against the environmentalists’ green blanket, which ANWR has been under for 30 years, with a pipeline capacity of 1.3 million bbl of oil just sitting there. Recent reports suggest the pipeline may even have growing operational problems with rates as low as 500,000 b/d. We must also immediately put the deepwater drilling rigs back to work with reasonable safety requirements. We must let each state regulate their oil and gas operations with their own environmental regulations. Keep the federal government out of it. Progress has been made here after a two-year delay by the administration embargo. We must expand offshore drilling to all prospective waters, including those of California and the Southern Alaska Coast, which were excluded from the latest offshore drilling offerings. We should also expand leasing on state lands onshore. Remove recent restrictions by the interior secretary on certain federal lands near parks. Of course, we should share some of the income from offshore oil and gas 272

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development as way to help with their state budget crises and provide states with an incentive not to ight offshore leasing. We should eliminate all subsidies to all forms of energy production. Let the market dictate which form of energy should be brought online now. This includes the import tax on ethanol as well as subsidies and grants on research for new methods of oil recovery. We should repeal the wind subsidy of 2 cents per kilowatt hour, as the federal government pays out of our grandchildren’s tax dollars. In Texas, this is a 20% subsidy. We should delay any more government spending on clean coal technology. America cannot dictate to the countries of the world which fuels they can or cannot use. We must develop a long-range plan for reprocessing nuclear fuel as France and Japan have done for years. We must streamline the application process for new nuclear plants using a standardized design. We must stop spending tax dollars that we do not have on investigating noncompetitive energy processes. American industry is best left to do research under the free enterprise system given proper tax incentives.

It’s a World Problem Yes, these spending cuts and tax increases would change our way of life. But is the future for our children and grandchildren not worth it? If such steps were taken, they would create hundreds of thousands of new jobs with the free enterprise system leading the way. They also would save wasted tax dollars, reduce liquid consumption, reduce oil imports, and help to pay down our deicit. This is not meant to be a comprehensive energy plan, but a place to start seeking energy development in this country rather than trying to work around the energy roadblocks we have been putting up. Energy planners around the world, and not just in the US, are on a precipice of unknown depth. Yes we are in a major worldwide energy dilemma. Although there now seems to be an adequate supply of oil, the balance could be upset on a minute’s notice by an accident, a single 273

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terrorist bomb, or continued uprisings in the Middle East. Our margin of error is small. I encourage all people around the world to take steps to conserve energy, particularly those of us in the US. Energy is precious, and we need to develop it in a safe, cost-effective manner and we need to conserve it at the same time. The energy problem of our time is not just a US problem. It is a world problem. The US weaning itself from Middle East Oil by itself is not the solution to the problem, because all countries of the world will be dependent for the foreseeable future on Middle East oil. That includes Middle Eastern countries as well, especially those needing the revenue to rebuild their war-torn lands. But events that took place in the Middle East and North Africa in 2011 are not encouraging, as the region could fast become a hotbed of disturbances. The world will be much better off if, somehow, Middle Eastern countries could ind peace and tranquility. They need to learn to live together, to develop the resources with which they are endowed in a peaceful environment. That is something we need to pray for, and something that all countries should do everything in their power to help achieve soon. And I do not mean military power.

Notes 1. Hofmeister, John. 2010. Why We Hate the Oil Companies: Straight Talk from an Energy Insider. New York: Palgrave Macmillan.

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M

y 50 years as a petroleum engineer have enabled my family and me to travel many places around the world. As I mentioned

earlier, Ruth Nell, my wife of 52 years, put up with ten moves, two foreign assignments, and in the process helped raise three wonderful children, Jamie Powers, Lou Ann (Powers) Davenport, and Cheryl Ruth (Powers) Stillson. In this epilogue I want to relate high points of our two foreign assignments, irst to Venezuela and second to Saudi Arabia.

Venezuela At the end of my third year at JPR, I was offered a two-year assignment in Sumatra in Indonesia. Ruth Nell and I agreed to go and had bought enough clothes for Jamie to last two years. After waiting a year for a visa, somebody called me into their ofice and

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said, “Powers, we have another assignment for you, and we would like you to go to an oil ield camp called Quiriquire in Eastern Venezuela.” Chief Engineer Max Sons had requested that Tom Boberg, then head of the lab’s thermal oil recovery, conduct a reservoir study and some type of thermal test in this large, ive billion barrel heavy oil ield. My supervisor explained that Boberg’s wife was pregnant and asked if I would be willing to take the assignment since the Indonesian visa had taken so long. The irst three months would be on bachelor status and then I could come home and take Ruth Nell and Jamie, less than a year old, back to Venezuela with me if the study took longer than three months. He gave me a copy of the temporary overseas assignment (TOA) policy, and I headed home for another discussion with Ruth Nell. She agreed, and I was off to Venezuela with Boberg, then one of the leading experts on thermal methods of oil recovery. They took us to the bachelor quarters, which would be my home for the next three months. The house was on stilts, as the tigers apparently were a problem in the early days. The pillows were stuffed with straw and a bit damp in the humid jungle climate. On occasion, I did see an Iguana sunning himself on the porch. This was to be my home for the next three months. Telephone communication at that time was limited with the US, so most of my communication with Ruth Nell would be by letter, which was quite slow. The irst letter took 12 days. There was no Skype or satellite calls. When I did call, it was on a two-way radio where you had to listen to when the other person stopped talking before you spoke. As time moved on my three months came due, and I told District Manager Frank Chuck that I needed to head home to visit the lab in Tulsa and pick up my wife and son, who I would bring back with me. I thought it would take two more months to complete the project, including the report. Chuck told me in no uncertain terms that he did not think so, that is that Ruth Nell and Jamie would be coming back with me. I pulled out the TOA I had been given in Tulsa, and Frank Chuck said I could be on my way. This was about two weeks before my return, and I called Ruth Nell in Tulsa on the two-way radio. She got the message that she and Jamie would be coming back with me for two or three months. She also understood that they needed to get whatever vaccinations were required immediately. We would be at the jungle camp for two weeks and then 276

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probably head to Caracas for one to two months. By the time I got home, the vaccination program was well underway, but Jamie, less than a year old, was beginning to have a reaction and was turning red from head to toe. We lew to New Orleans for our trip to Quiriquire. We arrived at the airport on a hot humid day. We were told to go to departure lounge and sit there, which turned out to be for four hours. The temperature that day was about 100°F. Jamie was quite uncomfortable with his rash, which we tried to keep covered. Fortunately, Alan Roberts, another lab engineer from Tulsa, was on the same plane to Caracas. He helped a lot with Jamie. After about four hours the airline agent came, and we were told they had split an air condition duct on start up. They would take us and our 11 bags to the Hilton hotel to overnight. By the time we got to the hotel, it was about 8:00 p.m. and we had not eaten. The hotel had a maid come to stay with Jamie. The only problem was that the motel room was full of mosquitoes and equipped with just a can of ly spray. They did provide mosquito netting for the crib. Near the end of dinner the airline agent came by and announced that the mechanics had got the millions of bolts back in place and they would come by our room and pick us up to return to the airport for an 11:45 p.m. departure for Caracas. We were dead tired but ready to go. By this time, there were only a dozen passengers left. On the way to Caracas, we about froze to death. They ixed the air conditioning but could not seem to turn up the heat since the airplane was designed for 80 or more passengers. As we landed in Caracas, the sun was coming up over the mountains. Fortunately, Jamie had slept through most of the night. That was the irst time my wife experienced a soldier standing at the bottom of an exit ramp with a loaded machine gun. This was 1963, four years after the dictator had been thrown out. Some pipelines had recently been blown up and the country was on a nervous footing. The Creole agent met us and helped us get through customs. Jamie passed, as we kept him mostly covered. We got to the Hotel Tamanaco, and collapsed. We slept until about 5:00 p.m. The next morning we lew to Maturin in the Eastern Jungle. When we arrived in Maturin, my host Clyde Walker was nowhere to be seen, and at that time there was no way to call him. It was beginning to get dark, so I did the next best thing: I found a taxi and tried to 277

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explain that we needed to go to Quiriquire oil camp. The driver seemed to understand and headed out. Along the way we passed many huts with no electric lights, and only kerosene lamps could be seen in the windows. There were no street lights for 30 kilometers until we got to the camp gate. It was pitch black with a single guard and had a small light as we drove up. We did get to see lashlights on the road where roadblocks were set up to intercept some pipeline bombers. Everyone was wearing machine guns, and I wondered what my wife was thinking. She never said. As we approached the gate at about 11:30 p.m., the guard wanted to see our papers, but we had none since our host Clyde Walker had failed to show up. Finally, I got him to call Walker who said: “Aw heck, I forgot to pick you up. Go to the bachelor quarters where you were staying, and in a few days we will get you a house. There are two rooms for you.” I think I forgot to tell Ruth Nell we would be sleeping on straw mattresses and pillows with a bit of a musty smell. When I got ready to go to work the next morning and I told her she could get her breakfast across the street. I told her a few food words in Spanish I had learned. I did mention the subject of cockroaches. In Tulsa we did not know about them, but at the open-air Quiriquire Club, they were prevalent. She said: “No way!” But I did warn her not to put Jamie down on the loor since some time the iguanas took over the porch to rest in the sun. Later that morning a couple of American engineers’ wives came by and saved the day: Diane Paxton and Billie Curtis, the wife of production engineer Bill Curtis, who had illed the 50 bbl of tar that I ran steam lood tests on in Tulsa when I irst went to work in 1958. We did get to move into the home of one of the engineers that was available, along with their maid. We were told the maid would take care of everything. All we had to do was allow her to nap in the afternoon because she was pregnant. Next, we were off to Caracas to inish my report, or so I thought. There, we really saw the contrast of the haves and the have-nots. Venezuela had been under a democracy for four years, but things had not changed much. The climate was much nicer than Quiriquire. There no screens, no bugs, and at 3,000 ft it would get cool in the evening as we sat out on the veranda of the Tamanaco Hotel. Caracas Venezuela in 1963 was a beautiful city nestled in a valley. But there were also many

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residents who lived in real squalor, which probably contributed to the rise of Hugo Chavez to power through so-called democratic elections. Ruth Nell’s shopping experience was expanded while in Caracas, where she learned the art of buying gold. I did not appreciate her newfound knowledge, but she purchased her irst gold necklace. I wish she had bought a lot more: the price then was only $35 per ounce compared to more than $1,600 per ounce as of March 2012. I typed the report along with my editor Ruth Nell, and I sent the draft off to Creole management. I was told they liked it and wanted me to present the conclusions to the Creole board of directors. I was on a high; here I was only ive years with the company, and my irst major study looked like a winner. I thought the presentation went well. Nobody told me I needed to clear my report with my bosses in Tulsa. On the night before we were to leave, Caracas had a major jail break; about 400 prisoners had escaped from the Central Jail near the Creole ofice. Everybody was told on the radio to stay off of the streets and to have their papers with them. Our papers were in the Creole ofice, being processed to leave. That night the parting sound of Caracas was the tat-tat of the machine guns rounding up the escapees. The following morning we caught a taxi to the Creole ofice and headed home to Tulsa, where Ruth Nell and I discussed leaving JPR. But the next week I was called in and told that they were very happy with my work and appreciated me taking on the Venezuela assignment.

Saudi Arabia In May 1977 I was told that Exxon wanted me to consider a move from my current assignment as operations manager in Corpus Christi, Texas, to become the chief petroleum engineer for the Arabian American Oil Co. (Armaco) in Saudi Arabia, on loan from Exxon. If I had any interest I was to catch a plane that morning to go to Houston and meet with Exxon Senior Vice President Hugh Goernor. If I liked what I heard, I should have my bag packed to go on to New York City and visit with the Exxon Middle East oficers. This was quite a shock, and I called Ruth Nell to see if she would meet me at the airport with a bag packed for overnight. She did not quite know what to say when I told her the details.

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The meeting with Goerner went well, and the next thing I knew I was on my way to New York City to meet with Exxon’s Middle East Management. I told them I would consider the offer, but I needed to talk to my wife and family. By then, we had three children: Jamie, 15; Lou Ann, 12; and Cheryl, 4. We made the decision to make the move, which meant that we had three months to get ready. We had to get rid of our cars, including a Ford, which was not allowed in Saudi Arabia due to their embargo. We had to place our dog Christy with a veterinarian, as we could not get veriication that a Brittany Spaniel could join us. We also had to decide what we could take or had to store. We took most everything and bought a new Blazer equipped for the desert, with tinted windows. Prior to shipping over, Aramco promised my wife and me a trip to Saudi Arabia to conirm that we still wanted to go, and also—I’m sure— to check us out. In June 1977 we arranged for someone to take care of our children, and we departed for Aramco Headquarters in Dhahran, Saudi Arabia. Upon arrival we were escorted to a nice guesthouse. We were the only ones staying there, and we were well taken care of with numerous houseboys and cooks. After a mix-up with our bags at the airport, we settled in for three days’ orientation. On the irst morning, I was offered a trip by helicopter to visit the new 2 million b/d seawater injection station called Qurayyah. We also visited the Abqaiq processing site, which today processes more than 7 million b/d, or about 9% of the world’s oil production. During the light we could barely see the ground, as the wind was blowing and the dust and sand were illing the air. As I recall, the pilot said that the wind was blowing about 25 knots that day and 30 knots was the maximum we could ly in. I noticed the pilot was looking closely at his map and asked him how long he had been lying in Saudi Arabia, and he said, “Three weeks.” That really did not give me much comfort. He then said that he usually came over for a few months since he did not enjoy lying in bad weather in the US gulf at this time of year. That was the irst of many helicopter lights over the next two years. Meanwhile, back at the house, Ruth Nell also had an exciting day. Aramco housing personnel came by and took her to look at the houses and schools. After lunch she was reading a book, which has been her favorite pastime even to this day. In the afternoon, though, she was interrupted by the houseboys and told she needed to pack up our things. We had to move to another house since a very important visitor was 280

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arriving, and we were in his house. She had no idea what they were saying and continued to read her book. In an hour or so the houseboy knocked on her door all excited that she had not followed his instructions, and he proceeded to start taking things out of the closet and packing her things in the bags. He instructed her to follow, took her to a car, and proceeded to the Hamilton House hotel, which was even nicer than the house. An English-speaking lady asked, “Do you know why you were moved?” The lady then told Ruth Nell that a very special unannounced guest had arrived, and that the house was the one that Oil Minister Sheikh Zaki Yamani stayed at on his trips to the Dhahran Aramco camp. That night I returned to Hamilton House sick from some bad food I had eaten, and they took me to the hospital. Ruth Nell was taken to a company dinner, and she must have made a good impression, since our offer was not withdrawn. I learned my job had been open for six months and that Dick Martin, a British citizen, had been in it during that time. I wondered how that would work out since he was a long-time Aramco employee. But Dick and I became good friends after a while, and I miss our monthly discussions. He is now deceased. Having decided to accept the position, our next two months were a whirlwind, with Ruth Nell preparing for the move and me reading numerous books and reports on Saudi Arabia. In early August 1977 the shippers arrived to load up the new Blazer, a 14-foot sailboat, and 10,000 pounds or more for shipment to Saudi Arabia. The assignment was for two to three years. We took off through New York with a side trip to Woodberry Forest near Charlotte, Virginia, to check out a boarding school for our son Jamie, since he would only be able to attend school one year in Saudi Arabia. Before leaving, we went to Holdenville, Oklahoma, and Winield, Kansas, to visit our families. Then we departed for London, where we spent the night with Exxon friends Dick and Margaret Hill. As we lew over Iraq and Kuwait and arrived in Dhahran, the night sky was illuminated with massive gas lares. My family’s eyes were illed with anticipation. When we arrived at the Dhahran International Airport with more than 500 passengers at 6:30 p.m., the air conditioners were out and the temperature was 105°F. We waited our turn in line. It took a while to process all of us, and inally our time arrived. The passport and visa inspector looked at the ive us and asked, “Which one wife?” I asked, “What do you mean?” 281

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Obviously, I was not communicating very well. I again pointed to Ruth Nell, and then he said, “This one no good.” He pointed to my 12-year old daughter and her visa. “Not stamped right,” he said and told us to stand aside while he proceeded to process the other arrivals. He took us to a room where the visa oficials wait for the next plane to arrive, and I asked him to ind an Aramco representative. He showed up and told us that Ruth Nell, Jamie, and Cheryl could clear customs, but that Lou Ann and I would have to wait until they contacted a passport authority in a nearby town, Dammam. Ruth Nell, along with Jamie and Cheryl, proceeded to clear customs to our overnight quarters. We were told that if they could not ind the customs man, we might have to ly out that night to Bahrain and get it cleared up at the Saudi Embassy. After a while, Lou Ann was feeling very uncomfortable sitting in a room of soldiers with guns and circulating fans. She started to cry, and I tried to comfort her. It reminded me of a scene out of a movie involving the French Foreign Legion. After two hours, we were released to pass customs and we joined up with Ruth Nell and the rest of the family. Our dog Christi was not there yet, and we wondered when she would come. I was told by Aramco’s Houston ofice that the veterinarian holding her should contact their ofice after we had left, and they would arrange to have her shipped. The vet did as requested, but received no reply. After about three weeks, the children were getting nervous, and I called the vet in Corpus Christi. At that time you had to make appointments to call the United States, and there was usually a one-to-two day delay. Finally I got the call through, and he advised me that he had shipped Christi on KLM and that she should have arrived in Dhahran about two hours earlier that evening. One of my engineers took me to the airport, and we checked at the KLM desk. The agent had gone home with a dog nobody picked up. Sure enough, on the manifest there was a Powers dog named Christi de Pharaoh. Next morning we went back, and sure enough there was Christi waiting to be picked up. She was as good as ever, happy to see us and with good care by the KLM agent. She was good to go. On balance, our family had a wonderful experience. We have a different appreciation for the people of the world today. We enjoyed our time in Saudi Arabia 33 years ago. My position placed us in a very nice 2,600-sq-ft house with ten tons of air conditioning. Aramco provided us with all the utilities and maintained the air condition units (ig. E–1). Our house had been freshly painted white throughout, and Aramco 282

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loaned us some temporary furniture. Many other new arriving recruits were placed in temporary facilities in the nearby Arab communities or on the camp in modular housing until their permanent homes were constructed.

Fig. E–1 The Powers family home in Saudi Arabia

Christi was an outdoor dog, but since we had no fence, she was assigned her own room and enjoyed the cool room compared to the outside August temperature of 100°F or more. Getting a fence built for Christi was a bit of a problem. Aramco did not approve fences to kennel dogs, but did approve hedge retaining devices with a gate: problem solved. Shortly after we got there, we decided we needed to go to town to get school supplies for Jamie and Lou Ann, and we asked one of our engineers who lived down the street to take us to town. Cheryl, our four-year old, went with us. As always in August, it was hot and dusty. We were to learn what the Holy Month of Ramadan meant. Little did we expect in Al Khobar there would be no water, no soda pop, or anything to drink. Even though she was only four years old, Cheryl never forgave us 283

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for taking her to Al Khobar during Ramadan. Figure E–2 shows Cheryl before the Al Khobar trip on her irst day in Saudi Arabia.

Fig. E–2 Cheryl Powers on her irst day in Saudi Arabia, 1977

Apart from the entry problems, my family and I had a great time during the two years we lived in Saudi Arabia. The Aramco schools were some of the best, with small classes. During our stay we were able to travel to Taif in the western mountains, which were much cooler than Dhahran in the desert. We also were able to travel to other Middle East countries such as the United Arab Emirates and Bahrain. My wife had a wonderful time, enjoying the beneits of two houseboys, Ali from Bahrain and Kassem from Yemen. Ruth Nell attended the Aramco Women’s Club and had a good time learning about other 284

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women from around the world. Ruth Nell had more time to spend with our family and to entertain at home, as other Aramco families did. One of the projects she got involved with was a garage sale. She made about $300, and our neighbor suggested they go to Al Khubar and see if they could ind some gold. This was a couple of months after I got there, and I had left to go to the US to recruit. Sure enough, Ruth Nell spent that money as quickly she made it, and she was introduced to the gold market, or souk, which was like nothing I had ever seen. The shops were lined with gold, which traded mostly on its weight with little paid for the workmanship. Most of the gold jewelry was imported from Eastern countries, where the wages for craftsman were extremely low. As I recall, the price of gold then was some $330 per ounce versus more than $1,600 today. Aramco had employees from around the world: India, Pakistan, the Philippines, Columbia, Iran, Egypt, as well as a good many Americans. One of petroleum engineers had been trained at the University of Moscow, and I later met up with him many years later on my trip to Russia (see chapter 13). To Westerners there seemed to be little need for security at that time. There was not much crime. If you robbed the gold souk and were caught, you might ind yourself missing a hand. Under these circumstances, the crime rate was low compared to the USA. We also enjoyed attending the fellowship service on Fridays, the Muslim day for religious services. It turns out that the preacher was Pastor Robert Hill, who was married to my third cousin. What a surprise! At that time, we were allowed to have religious services in the school building as long as we locked up all of our Christian service articles afterward. We also were not allowed to recruit Muslims or allow a Saudi to attend our services. Our children had a great broadening experience. Lou Ann had always wanted a horse. Aramco provided a Hobby Farm with trainers and workers to tend to them. A few months after we arrived, we acquired a white Arabian horse named Sharif. Every day after school a bus would pick the students up from the school and take them to the Hobby Farm. Lou Ann loved it and loved her horse. She learned to ride English style and attempted to get Sharif to jump, even if he did not want too. Lou Ann participated in something called a Gymkhana, a fancy name for a horse show. Lou Ann and her horse appear in igure E–3. She was not happy with us after we chose to come back to America a year earlier 285

THE WORLD ENERGY DILEMMA

than planned. She loved it there, went horseback camping in the desert, swimming in Aramco’s wonderful swimming pools, and made many friends in the camp.

Fig. E–3 Lou Ann Powers with her horse Sharif, Saudi Arabia

Jamie also had a good time, although he had to go off to boarding school at the age of 15. Jamie was awarded his Eagle Scout Award in Saudi Arabia (ig. E–4). Aramco had many Boy Scout leaders, many there on bachelor status. Jamie’s troop took a trip to the Caribbean on a schooner. While at Dhahran, Jamie also enjoyed learning to develop photographs in the lab provided by Aramco. Jamie left for boarding school in our second year, but while he was in Saudi Arabia Jamie lived through many interesting experiences and came out of it none the worse for wear. Now he takes his turn as a Cub Scout pack master with his own son, Louie.

286

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Fig. E–4 From left, Ruth Nell, Jamie, and Lou Powers at Jamie’s Eagle Scout award ceremony in Dharan

Both Jamie and Lou Ann enjoyed sailing at the Half Moon Bay club. We could camp there and enjoyed sliding down the dunes straight into the bay. Cheryl does not remember much, being only four when we irst arrived, but she had more time with her mother, and—with the doting houseboys—she lived like a little princess. Ali would ride her to preschool on his bicycle. We had complete conidence in both men, who were in their 50s. Christy would run and hunt for birds in the desert behind every bush, but she would rarely ind one. Christy stayed outside at night when it was cooler, but by 5:00 a.m. when I went to work, she would be at the gate waiting to get into her cool dark room where she rested during the day. Camping in the desert was one unusual activity we did (ig. E–5). We took the whole family to the desert south of Dhahran with our neighbors, the Martins. Other than our two cars, there was nobody else to be seen. After setting up our tent and getting our ire started, it was cool in the winter time, about 40–50°F. We took off in our Blazers to ride the dunes. The only problem was that I forgot the key to the tracks on the front bumper and had to walk about a mile and a half back to get another set at camp after we got stuck in the sand on the top of a dune. It was strangely quiet. There was not another person for as far as the eye could see. That night it really got cool as the winds began to whip up. 287

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Fig. E–5 Camping in the Saudi Arabian desert

Aramco had a nice vacation schedule. Besides the allotted six weeks, we could earn extra time off for putting in additional hours, the irst time we ever experienced that. We got to take two great trips, including one to Germany, Switzerland, Norway, Denmark, and France—a very broadening experience in more ways than one. As we approached the second year in Saudi Arabia, Ruth Nell and I were having concerns about our future, some to do with my work and some for our family, especially being away from our son another year. We were not necessarily boarding school parents, although many so-called Aramcons did ine with it. Toward the spring of 1979, our planning for the future had become pretty pressured. The four shareholders of Aramco were feeling a need for more input as their grip was disappearing. One week, our group was preparing for a big meeting with the Aramco oficers who were going to meet with Sheikh Yamani. We as a family were planning to leave that week for a trip to meet my sister and brother-in-law lying into Switzerland from the States. Family vacations were always very important, but my boss instructed me not to go after my sister’s plane had already left the States. I argued that Dick Martin had things under control, and that I would not be missed. 288

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I called my sister in Switzerland after she landed, and told her that we would still come, but maybe a week later. The next Friday, my boss, Ruth Nell, and I were having dinner at the house of a Saudi, and we were all sitting on the couch. My boss told me about their meeting in Riyadh and that he would still need us to make more computer runs for another trip to Riyadh next week. He said that the managers talked about me on the trip back that afternoon, and as a group they decided I could go on and make my trip, leaving Sunday. But then he said, “I do not want you to.” Again I said, “Martin and his group could handle it with no problem.” Ruth Nell and I both looked at the loor, and I turned to him and said, “I heard what you said, but my family is irst in my life and I have to go.” My wife would tell you this trip was one of the most strained in our life. Maybe that was the beginning of my decision to leave Aramco and ultimately Exxon after 21 years. We decided to leave in April 1979, and I told my boss. In July, we still had not heard where our next assignment would be, even though my replacement, Ed Price, was in the Kingdom waiting to get into our house. Since Exxon had not told us three weeks prior to our leaving, I told Aramco to ship our possessions to Houston, and Exxon would have to reship it to wherever I was sent. The writing was on the wall. The next week a call came for me to call New York. That is where my next assignment would be. Ruth Nell and I cancelled our trip home through the Far East and took a few days off in Europe before going to New York. After being offered an assignment in New York, though, Ruth Nell and I agreed to resign. We did not know what our next step would be after 21 years with Exxon and afiliated companies. Fortunately, these were “boom times” in the oil patch, and the worry about inding a job did not really bother me at that time. Our family had been blessed with a fast, exciting learning trip in Aramco and the Kingdom of Saudi Arabia. Today I am happy to report the progress that Saudi Aramco has made in preserving their future for years ahead.

289

INDEX A Abqaiq ield, 27, 28, 87, 95 Arab D reservoir, 106, 109 depletion, 106 horizontal drilling for bypassed oil, 107, 108 overview, 106–109 production history (1940–2010), 107, 108 Saudi Aramco, 89, 91 size, 97 ultimate recovery of oil-in-place, 106, 107 Abu Dhabi National Oil, 202 Accelergy, 265–266 Adair, Red, 72 Advanced Research Center (ARC), 135 Afghanistan war, 229, 230 Ain Dar/Shedum area (Ghawar ield), 99 depletion status, 101, 102 oolitic limestone, 101 overview, 101–103 production history, 101–102 rock properties, 100 Akhter, Saleem, 209, 213 Akins, James E., 221–223 Alaska Arctic National Wildlife Refuge, 47–48, 247, 272 North Slope production, 48 Algeria, 204 alluvial fan, 24 alternative energy. See also US alternative energy EIA forecast of electricity generation by, 261, 262

291

THE WORLD ENERGY DILEMMA

Ames, Gene, 221, 222, 223 Amoco, 197–199 Anderson, Jack, 117 Arab D reservoir, 92, 103 Abqaiq ield, 106, 109 Saudi Aramco and, 92, 109 Arabian American Oil Co., 87, 279. See also Aramco Arabian Peninsula, 204 Aramco, xiv, 171, 279. See also Saudi Aramco Congressional hearings (1970s) on Saudi Arabia and, 117–118 world oil prices (1970s) and, 117 Archer, David, 231 ARCO. See Atlantic Richield Arctic National Wildlife Refuge (ANWR), 47–48, 247, 272 Armstrong, Ann, 75, 164, 165 Armstrong, Barclay, 164 Armstrong, John, 164, 166 Armstrong, Major, 35 Armstrong, Tobin, 75, 164, 165 Armstrong Ranch, 169–170 Exxon and, 164, 165 Kingsville Production District and, 33, 35, 36 overview, 164–166 Patterson, Powers & Associates, Inc. and, 164, 165 Association of Peak Oil (ASPO), 252 Athabasca tar sands, 18, 29–30 Atlantic Richield (ARCO), 44, 158, 159, 161, 163

B Bahrain, 11 Bakken shale (North Dakota), 252 Barron, Oscar, 77 Bell, John, 49 Berman, Arthur, 240, 241, 252 biofuels, 6, 263 biomass, 6, 261, 263 blowouts. See also BP Gulf of Mexico blowout Kingsville Production District, 72–73 Tengiz Field, 213 Boberg, Tom, 18, 22, 23, 276 Borregos ield, 37, 42–43 Boyd, Don, 156–159, 162 BP Gulf of Mexico blowout (Macondo blowout), 45, 47, 238 US offshore drilling and, 248–249, 251, 254

292

Brazil offshore oil industry, 250 Brent Crude oil prices (March 2012), 179 WTI spread over/under, 178 British Petroleum Oil Company (BP), 27, 206 BP Exploration and PPC, 183–188 Gulf of Mexico Macondo blowout, 45, 47, 238, 248–249, 251, 254 Prudhoe Bay ield and, 44, 45, 120 Brittan, Chuck, 139, 194, 195 Bryce, Robert, 231 Bullock, Jerry, 34, 38, 44 Bush administration, 248, 267

C Campbell, Colin, 250 Canada, 6 oil production (1993–2008), 32 US oil imports from, 32, 227, 228 Canadian tar sands Athabasca, 18, 29–30 heavy oil production forecasts, 29–30 production and US oil imports, 227 Candelaria ield, 170 Carter Oil Co., 19, 20 Caspian pipeline, 215 Center for Strategic and International Studies (CSIS), 128 Chafin, Mike, 241 Chavez, Hugo, 28, 227, 279 Chevron, 206 Caspian pipeline and, 215 Tengiz Field and, 213–215 China auto sales growth, 6, 7 coal consumption growth (2000– 2009), 264 gasoline prices, 271 natural gas prices and, 240 nuclear energy and, 257 oil consumption, 235 solar power panels, 263 China oil demand, xiii, 14 EIA forecast of, 6–7 growth, 207 from Middle East, 226 Chuck, Frank, 276 Church, Frank, 117, 118 Clarke, Robert D., 239 clean coal, 265–266 Clinton, Hillary, 32 coal. See also US coal

INDEX

China consumption growth (2000–2009) of, 264 clean, 265–266 conversion to liquid hydrocarbons, 265–266 India consumption and import growth of, 264–265 Perot Energy Plan and, 263–266 supply, 263 world consumption growth (2000–2009) of, 264 world energy use forecast of, 261, 262 Coastal States, 169 Coates, Keith, 27 Conference on Trade and Finance, 1 Conoco, 138 ConocoPhillips, 29, 44 Conroe Oil Field, 58 cumulative production (1930– 2010), 60–61 Denbury Resources Inc. and, 61–62 oil sands logs and upper Cockield gas sands, 59–60 structure map, 59 summary of, 65 Continental Resources, 252, 253 Coontz, Harvey, 192 Core Lab, 196, 197 Cousin, Eddie, 246 Covey, George, 93 Crawford, Gary, 138 Creole Oil, 22–26, 277, 279 Crowder, Bert, 49, 77 Cushing, 177–178

D Davis, Art, 90, 92 deepwater offshore drilling, 247, 249–250 growth, 9 slowdown, 248 technology, 250 US moratorium on, 251 world oil supply and, 250, 251 Denbury Resources Inc., 61–62 Dhahran, 89, 91, 128, 131, 202, 279 directional drilling EXPEC management of, 132 Saudi Aramco, 132, 134 directional wells Haradh, 112 Saudi Aramco, 112, 132, 133 Saudi Aramco multilateral, 132, 133

Dowling, Keith, 145 drilling. See also speciic drilling topics inill, 47 parameters for Kingsville Production District, 42 rights for Pinnacle Reefs case, 194–196 Saudi Aramco, 90–91

E Eagle Ford shale (Texas), 244, 252, 253 East Clear Lake ield, 196 East Seven Sisters (Duval County, Texas) apparent gas-in-place from Gorman, 159 ARCO and, 158, 159, 161, 163 bottomhole pressures, 159–160 fracing, 161 Gorman Gas Unit production history (1983–2010), 159, 161 Gorman Tract, 156, 158, 159, 161 Hazelwood Gas Unit production history (1982–2010), 162 Hazelwood Unit, 158, 161–162 overview, 156–164 production, 158–161 P/Z vs. cumulative production, 159–160 royalty sales, 159, 161–163 sale leases, 157, 158, 163–164 East Texas Division (Humble and Exxon), 84, 119, 145 Civil Engineering Department, 77, 78, 80–82 Conroe Oil Field, 58–62, 65 Division Engineering Management, 79–80 Division Gas Engineering, 77–78, 79 East Texas Oil Field, 51–55, 65 groups, 77 Hawkins Oil Field, 55–58, 65, 81 Katy Gas Field, 66–69, 80 key oil and gas ields, 52 overview, 49, 51, 64, 65, 77 Production Engineering, 81–82 Reservoir Engineering, 77, 78, 81 Webster (Friendswood) Oil Field, 62–66 East Texas Oil Field, 44, 119 deepening activities, 53, 54 Humble East Texas Division, 51–55, 65 north and south cross sections, 53–54

293

THE WORLD ENERGY DILEMMA

production history, 52–53 summary of, 65 water advance over 50 years, 55 Eclipse, 131, 202 economics oil recovery, 21–22 US shale gas, 239, 241–246 Edmondson, Tom, 90 Egypt, 12 El Paistle Deep ield, 39, 40 energy. See also speciic energy topics development and US deicits, 14–15 future concerns, 10–11 sources and global warming, 14 Energy, Raymond, 177 Engler, John, 196 Environmental Overkill: Whatever Happened to Common Sense? (Lee), 231–232 Environmental Protection Agency (EPA), 31, 178, 240, 267–268, 270 environmentalists Pinnacle Reefs drilling rights case and, 194 US coal and, 263–264 US energy development and, 240 US offshore drilling and, 249, 251 EP Magazine, 240 Europe gasoline prices, 217, 218 tour of, 216–219 Exploration and Petroleum Engineering Center (EXPEC), 128, 129, 131, 202 directional drilling management by, 132 reservoir simulation room, 130 Saudi Aramco Advanced Research Center, 135 Exxon, 27, 28, 36, 37, 38, 71, 87, 120, 124, 137, 240, 263, 279, 289. See also Humble Oil and Reining Armstrong Ranch and, 164, 165 clean coal liquefaction technology, 265–266 Energy Outlook, 233, 247, 248 Houston Lighting and Power and, 79–80 industrial pipeline system, 78, 79, 84–85 Kingsville Production District and, 73 PPC defense of, 196–197 Production Research, 78, 138, 151

294

Sarita S.K. East B Lease Account 2 and, 139–141, 148–154 Venezuela and, 28–29 Exxon Industrial Gas System (EIGS), 84–85 Exxon USA, 231. See also East Texas Division; Kingsville Production District; South Texas Division Corpus Christi District, 82, 84 Humble Oil and Reining as, 75–76 ExxonMobil, xiv, 18, 34, 57, 206 Kazakhstan Ventures Inc., 213 liquid supply forecast (2004), 3–4 liquid supply forecast (2010), 4, 5 liquid supply forecast (2012), 4, 5 percentage of energy supply forecast (2012), 6 world oil and gas ields decline analysis by, 9

F Federal Energy Regulatory Commission (FERC), 261 Federal Power Commission (FPC), 144, 159 Finch, Mickey, 66, 68 Flatt, Jim, 49, 71, 73 fracing East Seven Sisters, 161 shale gas, 240–241 water contamination and, 240 fuel sources. See also US fuel sources world energy use forecast by, 261, 262 Fukushima nuclear plant meltdown, 253, 254

G Gadhai, Muammar, 11 gas. See also speciic gas topics irm royalty audits, 166–167 future supply and demand, 238 Khuff, 91 tight, 238 gas prices. See natural gas prices gasoline prices China, 271 Europe, 217, 218 inlation adjusted (1974–2012), 179 oil prices relation to, 179–182 US, 11, 217, 218, 227, 271 world, 218

INDEX

Gates, Robert, 128, 230 Gayden, Bill, 231, 232 Gayden Energy Planning Group, 232 Ghawar ield, 95 Ain Dar Dome, 98 Ain Dar/Shedum area, 99, 101– 103 depletion, 99, 100 Haradh, 99, 103–105 overview, 97–100 production level, 99 regions, 99–100 reserves, 99 rock properties, 99, 100 size, 97–98 three-dimensional structure map, 97 water injection system, 98 water management, 99 as world’s largest oil ield, 97 global warming causes and validity of, 230–231 debate, 266 energy sources and, 14 Obama administration and, 264, 265, 268 world solution to, 264 Goerner, Hugh H., 119, 279, 280 Golding, Bert, 90 Gorbachev, Mikhail, 209 Gore, Al, 230 Granberry, R. C., 82 Greer, Fred, 192 Groppe, Long, and Littell (GLL), 182, 237, 245 Gruy, Hank, 209 Gulf of Mexico BP Macondo blowout, 45, 47, 238, 248–249, 251, 254 recovery, 249 Gulf War (1991), 223 Kuwait production and, 202 oil price impact of, 175 as oil war, 228 promotion of terrorism, 229 Gulfaks offshore platform, 217

H Hafner, John, 138, 169 Hamm, Harold, 252–253 Hanger, John, 240 Haradh (Ghawar ield), 99 directional wells, 112 downhole monitoring systems, 105 oil production ramp-up, 103, 104

overview, 103–105 relative unit well costs, 105 rock properties, 100 water production simulation, 104 Harmon, Frank, 197 Harper, Steven, 32 Hawkins Oil Field, 55 Dexter sand structure map, 56 inert gas injection facilities, 81 Lewisville and Dexter Sands log structure, 57 production history, 58 summary of, 65 Head, Hayden, 164, 165 Headington Oil, 151–154, 169–170 heavy oil JPR investigation of, 19–21 production in Canadian tar sands, 29–30 Hickman, Richard, 49 Hicks, Bob, 38 Hite, George, 139, 183 Hofmeister, John, 269, 270 Holditch, Stephen A., 123 Homestead Oil Co. of Tulsa Ponzi scheme, 191–194 Homsely, Frank, 42 horizontal drilling, 47 Abqaiq ield, 107, 108 for bypassed oil, 107, 108 Saudi Aramco, 132 shallow, 18 horizontal wells, 18 fractures in, 129, 130 vertical wells compared to, 103, 104 House Committee on National Security, 228–229 Houston Energy Finance Group, 222 Houston Lighting and Power, 79–80 Huff and Puff, 18 Humble Oil and Reining, 25, 139, 196. See also East Texas Division; Kingsville Production District; South Texas Division division reservoir engineer, 49 as Exxon USA, 75–76 “Goals and Objectives” program, 36 Houston headquarters, 28, 35–36, 40–49 Major Field Study Group (MFSG), 49, 55, 57, 60, 64, 77, 78 Prudhoe Bay ield, 44–47 Systematic Reservoir Management (SRM) reviews, 49

295

THE WORLD ENERGY DILEMMA

Humble Research Laboratory, 27 Hunt, Caroline, 145 Huppler, Jack, 79 Hussein, Saddam, 228 Al-Husseini, Sadad, 122, 126, 127, 131, 202, 206, 247

I independent consultant case studies, 137–168 Independent Petroleum Association of America (IPAA), 223, 231, 232 PPC study (1992) for, 221, 228 India, 271 coal import and consumption growth, 264–265 Iran sanctions and, 207 India oil demand, 14, 207 imports by country and region, 208 imports from Iran, 208, 226 production, 207 production and consumption (1999–2009), 208 Indian Ocean pipeline, 229 Intercomp, 137 International Energy Agency (IEA), xiii, 176 Iran, 2, 10, 13 India oil imports from, 208, 226 Iraq and, 205 oil production (1990–2008), 204 Iran oil sanctions, xiv, 14 India and, 207 Iraq, 2, 228. See also Gulf War (1991) Iran and, 205 Kuwait and, 223 oil company contracts with, 206 oil reserves, 206 Iraq oil production capacity increase (2006–2020), 206, 207 future of, 205–206 Middle East instability and, 13–14 1965–2010, 205, 206 1990–2008, 204 OPEC oil supply and, 205 Iraq war, 229, 230

J Japan, 15 Fukushima nuclear plant meltdown, 253, 254

296

Jarvie, Dan, 241 Jersey Production Research Co. (JPR), 25, 27–29, 87, 107 heavy oil investigation, 19–21 oil recovery, 18 reservoir engineering school, 21 Venezuela Quiriquire oil ield assignment, 22–26, 28, 37, 275–279 Jitcoff, Andrew, 166 Jones, Elizabeth Ames, 240 Jones, John C., 194, 195

K Katy Gas Field Cockield aquiier, 69 Cockield sands general structure, 67 map, 66 plant, 80 production history, 67, 68 reserve study, 68–69 Kazakhstan Environmental Protection Ministry, 214 oil transportation problem, 215 Tengiz Field, 212–216 tour of, 211–216 Kazakhstan Ventures Inc. (ExxonMobil), 213 Kenedy Ranch, 75, 169, 170 Keystone XL pipeline, 30–32, 178 Khuff gas, 91 Khurais ields, 95, 109–110, 129 King, Roy, 145 King Ranch, 33, 35, 37, 38, 164, 166 King Ranch Gas Plant, 82, 83, 84 Kingsville Barbeque, 73 Kingsville Production District, 28, 41, 82 Armstrong Ranch and, 33, 35, 36 assistant district manager, 71, 139 blowouts, 72–73 Borregos ield, 37, 42–43 boundaries, 33–34 deep Frio pay, 38–40 district budget, 73, 74 district reservoir engineer, 34–35 drilling parameters, 42 El Paistle Deep ield, 39, 40 Exxon and, 73 irst responders, 72–74 King Ranch, 33, 35, 37, 38, 82, 83, 84, 164, 166 oil and gas ields, 33–34

INDEX

ranches, 74–75 rules and laws, 36–37 Sarita East Deep Field, 39–40 stuck wells, 38 Krause, Mark, 49, 56, 60, 64, 77 Kuwait, 2 Iraq and, 223 oil reserves, 8, 202 production (1990–2008), 204 production and Gulf War, 202 Kuwait Oil Co., 202

L Lake Michigan, 194 Landers and Winkleman Dome Fields, 197–198 Lantz, Ron, 131, 201, 202, 205, 230, 256 Ledbetter, Bob, 21 Lee, Dixie Ray, 231–232 Lewis, Stanley, 77, 80 Libya oil exports, 204 oil production and projection (to 2030), 205 Libya crisis (2011), 11 oil prices impact from, xiv, 204 OPEC and, 204 Persian Gulf production after, 204 Raymond James Energy on, 204–205 Saudi oil production and, 13, 204 world oil supply impact from, 204 liquid hydrocarbons coal conversion to, 265–266 subsidies for, 271 US usage of, 269, 270 Littell, George, 182, 237, 246 The Long Thaw (Archer), 231 Lower 48 Gas Supply study, 183–188

M MacKenzie, Wood, 239, 240 Macondo blowout. See BP Gulf of Mexico blowout Major Field Study Group (MFSG), 49, 55, 57, 60, 64, 77, 78 Manifa, 133–134 Mantor, Dave, 78 Marek, Joe, 66, 69, 164, 231 Martin, Richard E. “Dick,” 89–90, 171, 206, 281, 288 McClintick, David, 192 McCoy, Lynn, 138, 196, 197

McEvoy, 73 McNichol, Kevin, 139 McQueen, Jerry, 38, 142 Merryman, Andy, 139 Mesa Petroleum, 173 Mexico oil ields, 266 US oil imports (2004–2009) from, 227, 228 US oil supply and, 227 Meyer, Randy, 84 Michigan State Geological Survey, 194–195 Middle East energy issues, 201–208 Oil Show, 201 US instillation of democracy in, 229 Middle East instability Iraq production and, 13–14 oil capacity development and, 13–14 oil prices and, 10, 177, 205 OPEC oil capacity and, 175 US gasoline prices and, 227 US oil imports and, 222, 226, 230 Middle East oil China demand for, 226 producing countries, 2–3 US dependency on, 207, 230 US gasoline consumption and imports of, 226 US imports of, 226, 233 world oil demand for, 207, 226, 233, 274 Miller, Judd, 72, 79 Miller & Lents, 196, 197 Miller Brothers, 194, 195 Mills, Herbert G. and Martha, 138, 169 Moore, Bill, 28 Motiva, 31 motor fuel consumption in US, 13 natural gas as, 13, 236–237, 272 multilateral wells, directional, 112, 132

N Al-Naimi, Ali I., xiv, 1 natural gas. See also speciic natural gas topics annual wellhead price (1970– 2009), 80 demand, xiii as growth fuel of future, 9 as motor fuel, 13, 236–237, 272

297

THE WORLD ENERGY DILEMMA

North America development of, 10 in Perot Energy Plan, 236–237 vehicle numbers by country, 236 world resources of, 9–10 natural gas prices, 238. See also US natural gas prices China and, 240 FPC control of, 144 natural gas price forecasts relation to, 182 oil prices relative to, 175 rising, 150 natural gas price forecasts dilemma of, 182 natural gas prices relation to, 182 1988, 173 2012, 182 Nell, Ruth, 25, 26, 75, 76, 138, 218, 275–282, 285, 287, 289 Newield Oil & Gas, 154–155 Nordhouse Dunes State Park, 194 North America, natural gas development, 10 North Sea oil, 218–219, 224 Norway, 216 offshore oil industry, 217, 218– 219, 250 Statoil, 216–217 nuclear energy. See also US nuclear energy China and, 257 French handling of waste from, 256 Fukushima nuclear plant meltdown and caution towards, 253, 254 oil demand and, 15 uranium reprocessing and prices, 256–257

O Obama, Barack, 32, 226, 229 Obama administration, 178, 196, 225, 226, 230, 245, 255, 267 global warming and, 264, 265, 268 US alternative energy and, 258– 259 US offshore drilling and, 248–249, 251 O’Conner, Jack, 78 offshore drilling. See also deepwater offshore drilling; US offshore drilling water depth capability progression, 250

298

offshore gas declines, 238 deepwater, 249 offshore oil deepwater, 249 Gulfaks platform, 217 reserves, 250 Safaniya ield, 113–114 offshore oil industry advancement, 250 Brazil, 250 Norway, 217, 218–219, 250 Offshore Technical Conference, 266 oil. See also speciic oil topics bypassed, 107, 108 embargo (1973–1974), 118 irm royalty audits, 166–167 shale, 252–253 Oil and Money Show, 218 oil capacity. See also Saudi oil capacity development and Middle East instability, 13–14 oil companies. See also speciic oil companies Iraq contracts with, 206 oil consumption. See also US oil consumption by country, 235 oil demand. See also speciic oil demand topics India, 14 nuclear energy and, 15 Oil Development Outlook in the Middle East (PPC and Martin), 206 oil ields. See also speciic oil ields ultimate recovery from six large US, 119–120 Oil Imports—The Bankrupting of America, 223 oil industry offshore, 217, 218–219, 250 Soviet Union, 210 Venezuela nationalization of, 227 oil industry fundamentals media on, xiv oil prices and, xiv–xv oil prices gasoline prices relation to, 179– 182 Gulf War and, 175 inlation adjusted (1974–2012), 179 Libya crisis impact on, xiv, 204 Middle East instability and, 10, 177, 205 Middle East peace and, 10

INDEX

natural gas prices relative to, 175 oil industry fundamentals and, xiv–xv political stability and, 177 spike (2008), 3 US dollar and market vs., 177 oil price forecasts dilemma of, 182 1988, 173 oil price studies overview, 170–178 PPC, 171–175, 201–202 oil recovery. See also ultimate recovery economics, 21–22 JPR, 18 Saudi Aramco, 134 Saudi oil ields, 123 from tar, 18–19 thermal, 24 Venezuela conglomerate reservoir, 23–24 Webster Oil Field history of, 65 oil reserves. See also speciic oil reserves topics Iraq, 206 Kuwait, 8, 202 Middle East oil-producing countries, 3 non-OPEC countries, 1 spurious reserve revisions, 8 oil wars Gulf War (1991) as, 228 of US, 228, 229–230 Oman, 2, 202 production (1990–2008), 203 OPEC oil demand vs. maximum sustained capacity, 172 supply and Iraq oil production, 205 OPEC oil capacity. See also Saudi oil capacity demand vs. maximum sustained, 172 Middle East instability and, 175 production (1975–2005) and, 174 Saudi Arabia and, 177 spare (2006–2010), 175–176 OPEC oil production capacity (1975–2005) and, 174 cuts (2003–2007), 3 free world demand for, 172 Persian Gulf countries (1990– 2008), 204 O’Quinn, John, 198 Organization of the Petroleum

Exporting Countries (OPEC), xiii, 1, 12 ExxonMobil liquid supply forecast (2004) for, 3–4 ExxonMobil liquid supply forecast (2010) for, 4, 5 Libya crisis and, 204 Saudi Arabia and, 170 world oil demand and, 175 world oil prices and, 171, 173–174 Orinoco tar sands, 18, 29

P Parallel Oil, Water, Gas Reservoir Simulator (POWERS), 106 Parker, Bill, 73 Parr, Charlie, 49 Parse, Bob, 84 Pattern, James, 139–140 Patterson, J. K. “Jim,” 27, 137–139 Patterson, Powers & Associates, Inc. (PPA), 137–139 Armstrong Ranch and, 164, 165 property sales, 148 Patterson-Powers and Associates, 27 Pecan, 138 PEMEX, 266 People-to-People Organization, 209 Perkins, Fred, 38, 40 Perot, Ross, 164, 232, 237, 254, 267 Perot Energy Plan, 231 coal and, 263–266 energy strategy, 234 key excerpts and observations, 232–266 natural gas in, 236–237 overview, 231, 232 petroleum policy, 246–251 shale gas economics, 241–246 shale gas in, 237 speciic initiatives on energy sources, 234–241 on US energy dilemma problem, 232–233 US gasoline tax proposal, 227, 232, 234 US nuclear energy and, 253–258 Perot presidential campaign, advising, 231–232 Persian Gulf countries dictators subject to assassination, 228 policies of, 233 world oil reserves and, 229

299

THE WORLD ENERGY DILEMMA

Persian Gulf countries oil production after Libya crisis, 204 1990–2008, 204 Peters, Carl, 34, 71, 74–75, 82, 164 Petrie, Tom, 252 petroleum Perot Energy Plan policy on, 246–251 resources growth, 9 petroleum engineering, xiii, xiv, xv, 17, 90, 91, 275, 279. See also Exploration and Petroleum Engineering Center Petroleum Intelligence, 202 Petroleum Intelligence Weekly, 8 Petronus, 206 Petrus Oil, 164, 231 Pickens, T. Boone, 173, 237, 272 Pierson, James, 166 Pinnacle Reefs drilling rights case, 194–196 Pioneer Oil Producers Society, 246 pipelines Caspian, 215 Exxon industrial pipeline system, 78, 79, 84–85 Indian Ocean, 229 Keystone XL, 30–32, 178 Red Sea, 229 Trans-Alaska, 45, 47 political stability oil prices and, 177 Saudi oil supply and, 128, 135 Ponzi scheme (Homestead Oil Co. of Tulsa), 191–194 Posgate, Jimmy, 41, 43, 44 Powers, Cheryl Ruth, 76, 275, 280, 282–284, 287 Powers, Jamie, 75, 275–279, 282, 283, 286, 287 Powers, Lou Ann, 75, 275, 280, 282, 283, 285–287 Powers Petroleum Consulting Co. (PPC), 138–139, 146, 165, 169 BP Exploration and, 183–188 Exxon defense by, 196–197 Homestead Oil Co. of Tulsa Ponzi scheme and, 192–193 IPAA study (1992), 221, 228 lawsuit against, 199 Lower 48 Gas Supply study by, 183–188 Oil Development Outlook in the Middle East, 206 oil price studies, 171–175, 201– 202

300

Pinnacle Reefs drilling rights case and, 194–195 property sales, 148, 164 US natural gas supply study by, 183–188 US oil supply, demand and projection report (1992), 225– 226 Price, Ed, 122, 289 production. See speciic production topics Prudhoe Bay ield, 27 BP and, 44, 45, 120 discovery, 44–47 engineer and geologist tools used in, 46–47 Humble Oil and Reining, 44–47 overview, 120 production history, 46, 120–121 size, 97, 98, 107, 119 technology, 120

Q The Quest (Yergin), 4 Quiriquire oil ield camp JPR assignment in, 22–26, 28, 37, 275–279 report on, 25–26, 28 Qurayyah Plant, 89, 109, 128 seawater intake canal, 93

R Rawl, Larry, 28 Raymond James Energy (RJE), 177, 178, 182, 236, 265 on Libya crisis, 204–205 on US offshore drilling, 251 Red Sea pipeline, 229 reserve. See speciic reserve topics reserve studies Katy Gas Field, 68–69 Salt Creek Field, 145–147 Sarita S.K. East B Lease Account 2, 139–144, 148 reservoir simulation Eclipse model, 202 EXPEC, 130 Saudi Aramco, 103, 104, 105, 131, 132 3D, 120, 131 training, 27 Richardson, Joe, 49, 55, 57, 60 rigs. See also US rigs Saudi Arabia, 134 Saudi Aramco, 134, 135

INDEX

Ringer, Lewis, 162, 163 Roach, Mark, 139, 183 Roberts, Alan, 277 Rogers, Fred, 72, 73, 74 Rose, Pete, 194 Rosewood Resources, 145, 171 Royal Dutch Shell, 8 royalty audits, 166–167 royalty interest (RI), 168 royalty sales East Seven Sisters, 159, 161–163 Sarita S.K. East B Lease Account 2, 148–151 Rubicon Oil Co. of Houston case, 197–199 Russia, and world oil demand, 216 Ryon, Mitch, 72

S Safaniya ield, 95 overview, 113–115 production capacity, 114 as world’s largest offshore ield, 113–114 Salazar, Ken, 248, 251 Salt Creek Field (West Texas) oil column thickness in canyon limestone, 145 overview, 145–147 production history (to 2010), 146 recovery, 146–147 reserve study, 145–147 Santa Fe Ranch, 169 Santa Maria Basin (California), 191– 192 Sarita East Deep Field, 40 electric log from, 39 Sarita S.K. East B Lease Account 2 (Kenedy Country, Texas) Exxon and, 139–141, 148–154 Headington Oil and, 151–154 major trapping fault, 139, 140 Newield Oil & Gas and, 154–155 overview, 139–144, 148–155 production, 139, 149, 152–153, 155 production history, 149, 150, 155 reserve study, 139–144, 148 royalty sales, 148–151 sands and faults, 141–142 total ield production (1968– 2005), 152 well gas-in-place log analysis, 142–143

well production history (1968– 1980), 140–141 Saudi Arabia, 2, 10, 11, 202, 228 Congressional hearings (1970s) on Aramco and, 117–118 engineer and geoscientist training, 128 issues facing, 126, 127–128 OPEC and, 170 OPEC oil capacity and, 177 standard of living, 125 United States and, 128 US ambassador to, 221–223 world oil prices and, 170, 173 Saudi Aramco, 31, 279 abandonment of 16 million b/d plans, 93–94 Abqaiq ield, 89, 91 Arab D reservoir and, 92, 109 chief petroleum engineer assignment, 279 in Dhahran, 89, 91, 131, 279 directional drilling, 132, 134 directional multilateral wells, 112, 132 directional wells, 112, 132, 133 drilling, 90–91 engineers, 89 EXPEC Advanced Research Center, 135 foreign worker dismissals, 93–94 horizontal drilling, 132 Khuff gas exploration, 91 oil recovery, 134 overview, 87–89 Petroleum Engineering, 90, 91 pipe corrosion, 92 production, 114–115, 119 Production Engineering, 89, 90, 91 production history (1945–2009), 87–88 Ras Tanura district ofice, 89 Reservoir Engineering, 89–90 reservoir simulation, 103, 104, 105, 131, 132 rig level (2000–2010), 134, 135 Saudi oil capacity projections, 134 Saudi oil production projections, 132–133 Saudi reserves and, 89–91, 118, 119, 121–124, 127 seawater injection, 92–93, 94, 98 shareholders, 87–88, 93, 117, 118, 288 Shaybah ield, 111, 112, 113 Tech Service lab, 90, 92 technology, 109, 131

301

THE WORLD ENERGY DILEMMA

upstream projects (2009), 135 water injection, 134 Saudi gas, 132 ields, 96 plants, 119 Saudi oil exports and Red Sea pipeline, 229 policies, 233 revenue, 125 rigs, 134 surplus, 126 Saudi oil capacity, 125, 126 target (1977), 117 Saudi oil capacity projections EIA, 124–125 Saudi Aramco, 134 Saudi oil ields. See also Abqaiq ield; Ghawar ield; Safaniya ield; Shaybah ield key, 95 Khurais ields, 95, 109–110, 129 major ields, 95–115 overview, 95 recovery, 123 total oil-in-place, 123 ultimate recovery of large, 120 Saudi oil production, 3, 94, 95, 114– 115 decline, 124 increase (1986), 170 Libya crisis and, 13, 204 1990–2008, 204 policies, 233 rate (1945–2009), 124–125 world oil prices and, 13 Saudi oil production projections EIA, 124–125 historical, 124–127, 132–133 Sadad Husseini on, 126, 127 Saudi Aramco, 132–133 Saudi oil supply, xiv future issues, 127–128 political stability and, 128, 135 Saudi reserves, 1, 17, 95, 126 assessing, 89–91, 118–124 current, 121–124, 127 depletion, 95, 96, 127 over time, 121, 122 Saudi Aramco and, 89–91, 118, 119, 121–124, 127 Saudi reservoirs description zonation of major, 131 technology, 119, 128–131 Schaefer, George, 138 Schumacher, E. F., 4, 226 seawater injection

302

Qurayyah Plant, 89, 93, 109, 128 Saudi Aramco, 92–93, 94, 98 seismic surveys 2D, 129 3D, 120, 129, 169, 170 4D, 47, 120, 170 shale gas, 185. See also US shale gas dry, 241, 244 fracing, 240–241 overview, 239–240 in Perot Energy Plan, 237 technology, 239 shale oil, 252–253 Shaybah ield, 95 camp in Rub’ al-Khali Desert, 111 directional wells, 112 overview, 110–113 production capacity, 112–113 Saudi Aramco, 111, 112, 113 structure with large gas cap, 111 Shefield, J. K., 27 Sinclair, Richard, 161 Slider, Slip, 21 Sohio, 44 solar power. See also US solar power panels from China, 263 Sons, Max, 22, 24, 25, 26, 37, 276 South Texas Division (Exxon USA), 28, 34, 42, 71, 140. See also Kingsville Production District Corpus Christi District, 82, 84 employees, 82 Exxon gas pipeline system emergency, 84–85 overview, 82–83 Soviet Union oil and gas industry, 210 oil ields, 211 production history of former, 215–216 tour of, 209–211 world oil demand and countries of former, 216 Standard Oil Co. of New Jersey (SONJ), 18, 22–26 Statoil (Norway), 216 Gulfaks offshore platform, 217 Stealing from the Rich (McClintick), 192 steam-assisted gravity drainage (SAGD), 18, 19 Stevens, W. D. “Bill,” 40, 42, 71, 73–74, 231 Stevenson, W. M., 171 Strait of Hormuz, 229 strontium sulfate, 92, 94

INDEX

stuck wells, 38 Swenson, Carl, 77 Systematic Reservoir Management (SRM) reviews, 49

T tar, oil recovery from, 18–19 tar sands Canadian, 18, 29–30, 227 Venezuela Orinoco, 18, 29 Taylor, Ken, 84 Taylor, Monte, 77, 78, 81 Taylor, Pete, 138 TCU Energy Institute, 241 technology. See also seismic surveys Eclipse, 131 engineer and geologist tools, 46–47 Prudhoe Bay ield, 120 reservoir simulation (3D), 120, 131 Saudi Aramco, 109, 131 Saudi reservoir, 119, 128–131 shale gas, 239 Teming, Kaku, 109 Tengiz Field (Kazakhstan), 212 Chevron and, 213–215 oil production, 213–216 reports on, 213 T-37 blowout (1985–1986), 213 TengizChevroil, 214 Tenneco, 173 Texas Alliance of Energy Producers, 252 Texas Gulf Coast, 184 Texas judges, 198–199 Texas Railroad Commission (TRC), 37, 240 Tom East Field, 169 Trans-Alaska Pipeline (TAP), 45, 47 Trippett, Robert, 192, 193–194 Turcotte, Andrew J., 139–140, 144, 148, 153, 154 Turcotte, Denise, 144

U ultimate recovery of large Saudi oil ields, 120 of oil-in-place in Abqaiq ield, 106, 107 from six large US oil ields, 119– 120 unconventional resources growth, 9

United Arab Emirates (UAE), 2 Indian Ocean pipeline, 229 production (1990–2008), 202, 203, 204 United Kingdom, North Sea production, 218–219 United States (US) ambassador to Saudi Arabia, 221–223 deicits and energy development, 14–15 dollar and market vs. oil prices, 177 economy and oil imports, 221, 223–227 Middle East democracy instillation by, 229 Middle East oil dependency of, 207, 230 motor fuel consumption, 13 natural gas wellhead price (1979– 1982), 144 oil wars of, 228, 229–230 Saudi Arabia and, 128 security and oil imports, 222 world oil prices and, 12–13 uranium prices, 256–257 reprocessing, 256 US alternative energy cost competitiveness and problems, 258–261 EIA forecast of electricity generation by, 261, 262 Obama administration and, 258–259 US coal clean coal subsidies, 265 environmentalists and, 263–264 growth, 265 overview, 263 Perot Energy Plan and, 263–266 policy support, 263 supply, 263 US electricity generation by, 259, 261, 263 US Congress Church committee, 117, 118 hearings (1970s) on Aramco and Saudi Arabia, 117–118 House Committee on National Security presentation, 228–229 US Department of Energy, 221, 267– 268, 270 US oil trade deicit forecast (1975– 2020), 224

303

THE WORLD ENERGY DILEMMA

US Department of Natural Resources (DNR), 194 US Department of the Interior, 221, 267–268, 270 US drilling. See also US offshore drilling for shale gas, 240 US natural gas supply and, 185 US electricity consumption (1991–2009), 255 costs estimate by fuel source (2016), 258, 260 rates and fossil fuel costs, 258, 259 US electricity generation by coal, 259, 261, 263 EIA forecast of alternative energy, 261, 262 by fuel source (1991), 254 by fuel source (2009), 255 from nuclear energy, 254–255 by wind power, 259, 261 US energy development and environmentalists, 240 future and government inaction, 228 independence as myth, 226 power plant costs by type, 257–258 US energy dilemma, 178, 273–274. See also Perot Energy Plan fossil fuels in, 232–233 House Committee on National Security presentation on, 228–229 liquid hydrocarbon usage in, 269, 270 oil as crux of, 232–233 Perot Energy Plan on problem of, 232–233 politics in, 267–269 US Energy Information Administration (EIA), 176 alternative energy electricity generation forecast, 261, 262 electricity costs by fuel source (2016) estimate, 258, 260 forecast of China oil demand, 6–7 Saudi production and capacity projections, 124, 125 US oil imports and demand forecast (2007–2020) by, 226– 227 US oil imports forecast (2010) by, 225 US oil pricing (1981–2009) data from, 147 world energy use by fuel source forecast, 261, 262

304

US energy plan national incentive plan, 272–273 overview, 267–269, 273–274 steps needed for, 269–271 US fossil fuels costs and US electricity rates, 258, 259 in US energy dilemma, 232–233 US fuel sources costs of various, 257–258 US electricity costs estimate (2016) by, 258, 260 US electricity generation (1991) by, 254 US electricity generation (2009) by, 255 US gasoline consumption, and Middle East oil imports, 226 US gasoline prices, 11, 217, 218, 271 Middle East instability and, 227 US gasoline tax, 225, 270 Perot proposal for, 227, 232, 234 US oil demand reduction by, 227 US Geological Survey (USGS), 252 US natural gas lat demand case (1992–1996), 186, 187 historical production, 237, 238 requirements vs. deliverability (1992–1996), 188 US natural gas consumption annual (1950–2010), 181 US natural gas prices (1950–1990) vs., 183 US natural gas prices, 246 average consumer (2007–2010), 182 consumer vs. power company, 182 economic results by region (1982– 1991), 184 forecast (1988), 173, 175 monthly wellhead price (1975– 2010), 173, 175 US natural gas consumption (1950–1990) vs., 183 US oil prices ratio to, 183–184 wellhead price (1979–1982), 144 wellhead price (1979–1995), 151 wellhead price (1995–2005), 153 wellhead price (to 2009), 155, 156 US natural gas rigs count (1973–2010), 185, 187 count (1992–1996), 186, 187, 188 count (2000–2012), 180 US natural gas supply, 245–246 base ixed forecast (1975–2005), 186

INDEX

drilling and, 185 growth and rig count, 180–181 history (1975–1992), 186 PPC study of, 183–188 storage (2012), 239 surplus, 181, 238 US nuclear energy electricity generation from, 254–255 overview, 253 Perot Energy Plan and, 253–258 plant construction, 254, 255 policy support, 253 waste and disposal, 256 US Nuclear Regulatory Agency, 232 US offshore drilling BP Gulf of Mexico blowout and, 248–249, 251, 254 deepwater moratorium, 251 environmentalists and, 249, 251 Obama administration and, 248– 249, 251 Raymond James Energy on, 251 shallow water, 251 US oil regulations, 251 ultimate recovery from six oil ields, 119–120 wars over, 228 US oil consumption, 13 need to cut, 235 2006–2009, 235 US oil demand EIA forecast (2007–2010) for US oil supply and, 226–227 gasoline tax to reduce, 227 need to reduce, 227 US oil supply, projection and, 225–226 US oil imports from Canada, 32, 227, 228 costs, 225 EIA forecast (2010) for, 225 EIA forecast (2007–2010) for US oil demand and, 226–227 from Mexico, Venezuela and Canada (2004–2009), 227, 228 from Middle East, 226, 233 Middle East instability and, 222, 226, 230 US economy and, 221, 223–227 US gasoline consumption and Middle East, 226 US oil trade deicit and, 224–226, 228 US security and, 222

US oil prices 1961–1989, 170 1981–2009, 147 forecast (1988), 173 US natural gas prices ratio to, 183–184 weekly spot price (to 2010), 174 WTI, 12, 179 US oil supply Mexico, Venezuela and, 227 need to increase, 227 US oil demand, projection and, 225–226 US oil trade deicit DOE forecast (1975–2020), 224 historical, 223 US oil imports and, 224–226, 228 US rigs natural gas, 180, 185–188 offshore, 245–246 US shale gas, 185, 188 drilling and water contamination, 240 Eagle Ford, 244 resource magnitude, 239–240 supply, 245 US shale gas economics, 239 minimum price for return, 241, 242 Perot Energy Plan and overview of, 241–246 reserves required for various payouts, 241–244 revenues boosted by liquids, 244, 245 risks, 241 US shale oil Bakken, 252–253 Eagle Ford, 252, 253 US solar power cost competitiveness, 258 EIA forecast of electricity generation by, 261, 262 panel tariffs on China, 263 US wind power cost competitiveness and problems, 258–261 US electricity generation by, 259, 261

V Venezuela, 6, 14. See also Quiriquire oil ield camp Exxon and, 28–29 oil industry nationalization, 227

305

THE WORLD ENERGY DILEMMA

Orinoco tar sands, 18, 29 US oil imports (2004–2009) from, 227, 228 US oil supply and, 227 Venter’s Synthetic Genomics Inc., 263 Venus Oil Company, 221, 223

W Walker, Clyde, 23, 24, 277 Walker, Jack, 79 Wall Street Journal, 192, 271 water contamination fracing and, 240 US shale gas drilling and, 240 water injection. See also seawater injection Ghawar ield, 98 Saudi Aramco, 134 Webster (Friendswood) Oil Field, 62 management scheme, 64 production history (1937–2004), 63 recovery history (to April 2011), 65 structure map, 63 summary of, 65 wells. See also directional wells; horizontal wells production of Sarita S.K. East B Lease Account 2, 140–141 stuck, 38 vertical, 103, 104 wellhead setup, 72 Wells, Emmet, 41, 44 West, Wesley, 196 West Texas Intermediate (WTI), 177 oil prices (1974–2012), 179 oil prices (2002–2011), 12 posted prices ratio to Texas Gulf Coast spot gas prices, 184 spread over/under Brent, 178 Whitson, Bob, 58, 61 Willman, Bert, 26 wind power. See also US wind power world energy use forecast of, 261, 262 Winning Through Intimidation (Ringer), 162, 163 Wolfe, Frank, 78 Woody, Dale, 25, 26, 27, 41–44, 71 working interest (WI), 139, 168 world coal consumption growth (2000– 2009), 264 gasoline prices, 218

306

solution to global warming, 264 world energy dilemma, 1–15, 201, 273–274 use by fuel source forecast, 261, 262 world gas ields decline, 9 natural gas resources, 9–10 production without more investment, 247, 248 world oil decline, 9 production without more investment, 247, 248 world oil demand, xiii, xv, 271 former Soviet Union countries and, 216 growth and consumers, 204 for Middle East oil, 207, 226, 233, 274 OPEC and, 175 Russia and, 216 spare capacity and, 173–174 2006–2011, 176 world oil supply and, 11 world oil prices Aramco and 1970s, 117 OPEC and, 171, 173–174 rising, 12 Saudi Arabia and, 170, 173 Saudi oil production and, 13 United States and, 12–13 world oil reserves, 8 Persian Gulf countries and, 229 world oil supply deepwater offshore drilling and, 250, 251 Libya crisis impact on, 204 world oil demand and, 11 Wright, Harold, 41–44, 51 Wright, Mike, 35, 36

X XTO Energy, 240

Y Yamani, Zaki, 118, 119, 124, 128, 170, 218, 281, 288 Yergin, Daniel, 4

Z Zagar, Jack, 122, 123, 124, 126, 127