The
Natural
Gas
Future of
AN INTERDISCIPLINARY MIT STUDY
MIT Study on the Future of Natural Gas iii
Foreword and Acknowledgements
The Future of Natural Gas is the fourth in a
s...
MIT Study on the Future of Natural Gas v
Study Participants
ERNEST J. MONIZ — CHAIR
Cecil and Ida Green Professor of Ph...
CONTRIBUTING AUTHORS
GREGORY S. MCRAE
Professor of Chemical Engineering (Emeritus),
MIT
CAROLYN RUPPEL
Visiting Scien...
MIT Study on the Future of Natural Gas vii
Advisory Committee Members
THOMAS F. (MACK) MCLARTY, III —
CHAIRMAN
Preside...
MIT Study on the Future of Natural Gas xiii
Abstract
Natural gas is finding its place at the heart of the
energy discus...
natural gas and electricity). Efficiency metrics
should be tailored to regional variations in
climate and electricity su...
Chapter 1: Overview and Conclusions 1
Chapter 1: Overview and Conclusions
PURPOSE AND OUTLINE OF THE STUDY
Despite its ...
HIGH-LEVEL FINDINGS
The findings and recommendations of the
study are discussed later in this chapter, and
covered in d...
Chapter 1: Overview and Conclusions 3
10. International gas trade continues to grow
in scope and scale, but its economic...
The Importance of Natural Gas in the
Energy System
Natural gas represents a very important, and
growing, part of the gl...
Chapter 1: Overview and Conclusions 5
it provided 23% of the produced electricity,
reflecting the higher efficiency of n...
resource base, has become more obvious over
the last few years, radically altering the U.S.
supply picture. We have once...
Chapter 1: Overview and Conclusions 7
The analysis in this study is based on three
policy scenarios:
1. A business-as-u...
challenges in the area of water management,
particularly the effective disposal of fracture
fluids. Concerns with this i...
Chapter 1: Overview and Conclusions 9
A more stringent CO2 reduction of, for exam-ple,
80% would probably require the co...
Natural gas-fired power generation provides the
major source of backup to intermittent renew-able
supplies in most U.S. ...
Chapter 1: Overview and Conclusions 11
end use or “site” energy efficiencies can be
misleading, since it does not take i...
Energy density, ease of use and infrastructure
considerations make liquid fuels that are stable
at room temperature a co...
Chapter 1: Overview and Conclusions 13
MAJOR RECOMMENDATIONS
Analysis of the infrastructure demands
associated with pot...
International natural gas markets are in the
early stages of integration, with many impedi-ments
to further development....
INCLUDING THAT
of allies, could constrain U.S. foreign policy
options, especially in light of the unique
American inter...
Chapter 1: Overview and Conclusions 15
RDD
There are numerous RDD opportunities to
address key objectives for natural g...
CONCLUSION
Over the past few years, the U.S. has developed
an important new natural gas resource that
fundamentally enh...
Chapter 2: Supply 17
Chapter 2: Supply
INTRODUCTION AND CONTEXT
In this chapter, we discuss various aspects of
natural...
Figure 2.1 GIIP as a Pyramid in Volume and Quality. Conventional reservoirs are at the
top of the pyramid. They are of hi...
Chapter 2: Supply 19
Figure 2.2 Illustration of Various Types of Gas Resource
RESOURCE DEFINITIONS
The complex cross-de...
Figure 2.3 Modified McKelvey Diagram, Showing the Interdependencies between
Geology, Technology and Economics and Their I...
Chapter 2: Supply 21
GLOBAL SUPPLY
Production Trends
Over the past two decades, global production
of natural gas has g...
Figure 2.5 Comparison of 1990 and 2009 Natural Gas Production Levels for the Top 10
Natural Gas Producing Nations (as def...
Chapter 2: Supply 23
LNG tankers. Over this 15-year period, global
gas trade doubled, while LNG trade increased
even mo...
Although resources are large, the supply base is
concentrated geographically, with an estimated
70% in only three region...
Chapter 2: Supply 25
SUPPLY COSTS7
Figure 2.9 depicts a set of global supply curves,
which describe the resources of ga...
0 500 1,000 1,500 2,000 2,500 3,000 3.500 4,000 4,500 5,000
UNCONVENTIONAL RESOURCES9
Outside of Canada and the U.S., th...
Chapter 2: Supply 27
UNITED STATES SUPPLY
Production Trends
There is significant geographical variation in
U.S. natura...
Figure 2.12 Regional Breakdown of Annual Dry Gas Production in the U.S. between
2000 and 2009
Tcf of Gas
22
20
18
16...
Chapter 2: Supply 29
Tcf of Gas
1%
7%
21%
Shale 16%
25%
CBM
Tight
Associated
Conventional
14%
9%
11%
2001 20...
U.S. RESOURCES12
Table 2.1 illustrates mean U.S. resource esti-mates
from a variety of resource assessment
authorities....
Figure 2.14b Breakdown of Mean U.S. Gas Supply
Curve by Type; 2007 Cost Base
Conventional
Tight
Shale
CBM
0 100 200 ...
resource growth is a testament to the power
of technology application in the development
of resources, and also provides...
Chapter 2: Supply 33
This high level of variability in individual well
productivity clearly has consequences with
respe...
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El futuro del Gas Natural

El futuro del Gas Natural. Estudio realizado por MIT
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  • 1. The Natural Gas Future of AN INTERDISCIPLINARY MIT STUDY
  • 2. MIT Study on the Future of Natural Gas iii Foreword and Acknowledgements The Future of Natural Gas is the fourth in a series of MIT multidisciplinary reports examin-ing the role of various energy sources that may be important for meeting future demand under carbon dioxide (CO2) emissions constraints. In each case, we explore the steps needed to enable competitiveness in a future marketplace condi-tioned by a CO2 emissions price or by a set of regulatory initiatives. This report follows an interim report issued in June 2010. The first three reports dealt with nuclear power (2003), coal (2007) and the nuclear fuel cycle (2010 and 2011). A study of natural gas is more complex than these previous reports because gas is a major fuel for multiple end uses — electricity, industry, heating — and is increasingly discussed as a potential pathway to reduced oil dependence for transportation. In addition, the realization over the last few years that the producible unconventional gas resource in the U.S. is very large has intensified the discussion about natural gas as a “bridge” to a low-carbon future. Recent indications of a similarly large global gas shale resource may also transform the geopolitical landscape for gas. We have carried out the integrated analysis reported here as a contribution to the energy, security and climate debate. Our primary audience is U.S. government, industry and academic leaders, and decision makers. However, the study is carried out with an international perspective. This study is better as a result of comments and suggestions from our distinguished external Advisory Committee, each of whom brought important perspective and experience to our discussions. We are grateful for the time they invested in advising us. However, the study is the responsibility of the MIT study group and the advisory committee members do not necessarily endorse all of its findings and recommendations, either individually or collectively. Finally, we are very appreciative of the support from several sources. First and foremost, we thank the American Clean Skies Foundation. Discussions with the Foundation led to the conclusion that an integrative study on the future of natural gas in a carbon-constrained world could contribute to the energy debate in an important way, and the Foundation stepped forward as the major sponsor. MIT Energy Initiative (MITEI) members Hess Corporation and Agencia Naçional de Hidrocarburos (Colombia), the Gas Technology Institute (GTI), Exelon, and an anonymous donor provided additional support. The Energy Futures Coali-tion supported dissemination of the study results, and MITEI employed internal funds and fellowship sponsorship to support the study as well. As with the advisory committee, the sponsors are not responsible for and do not necessarily endorse the findings and recommen-dations. That responsibility lies solely with the MIT study group. We thank Victoria Preston and Rebecca Marshall-Howarth for editorial support and Samantha Farrell for administrative support.
  • 3. MIT Study on the Future of Natural Gas v Study Participants ERNEST J. MONIZ — CHAIR Cecil and Ida Green Professor of Physics and Engineering Systems, MIT Director, MIT Energy Initiative (MITEI) HENRY D. JACOBY — CO-CHAIR Professor of Management, MIT ANTHONY J. M. MEGGS — CO-CHAIR Visiting Engineer, MITEI STUDY GROUP ROBERT C. ARMSTRONG Chevron Professor, Department of Chemical Engineering, MIT Deputy Director, MITEI DANIEL R. COHN Senior Research Scientist, Plasma Science and Fusion Center, MIT Executive Director, Natural Gas Study STEPHEN R. CONNORS Research Engineer, MITEI JOHN M. DEUTCH Institute Professor, Department of Chemistry, MIT QUDSIA J. EJAZ Postdoctoral Associate, MITEI JOSEPH S. HEZIR Visiting Engineer, MITEI GORDON M. KAUFMAN Morris A. Adelman Professor of Management (Emeritus), MIT MELANIE A. KENDERDINE Executive Director, MITEI FRANCIS O’SULLIVAN Research Engineer, MITEI SERGEY PALTSEV Principal Research Scientist, Joint Program on the Science and Policy of Global Change, MIT JOHN E. PARSONS Senior Lecturer, Sloan School of Management, MIT Executive Director, Joint Program on the Science and Policy of Global Change and Center for Energy and Environmental Policy Research, MIT IGNACIO PEREZ-ARRIAGA Professor of Electrical Engineering, Comillas University, Spain Visiting Professor, Engineering Systems Division, MIT JOHN M. REILLY Senior Lecturer, Sloan School of Management, MIT Co-Director, Joint Program on the Science and Policy of Global Change, MIT CAROLYN SETO Clare Boothe Luce Postdoctoral Fellow, Department of Chemical Engineering, MIT MORT D. WEBSTER Assistant Professor, Engineering Systems Division, MIT YINGXIA YANG MITEI STUDY CO-CHAIRS
  • 4. CONTRIBUTING AUTHORS GREGORY S. MCRAE Professor of Chemical Engineering (Emeritus), MIT CAROLYN RUPPEL Visiting Scientist, Department of Earth, Atmospheric and Planetary Sciences, MIT vi MIT STUDY ON THE FUTURE OF NATURAL GAS GRADUATE RESEARCH ASSISTANTS SARAH FLETCHER JOHN MICHAEL HAGERTY Exelon – MIT Energy Fellow ORGHENERUME KRAGHA TOMMY LEUNG Cummins – MIT Energy Fellow PAUL MURPHY Total – MIT Energy Fellow ANIL RACHOKONDA KAREN TAPIA-AHUMADA GTI – MIT Energy Fellow IBRAHIM TOUKAN Constellation – MIT Energy Fellow DOGAN UCOK YUAN YAO
  • 5. MIT Study on the Future of Natural Gas vii Advisory Committee Members THOMAS F. (MACK) MCLARTY, III — CHAIRMAN President & CEO, McLarty Associates DENISE BODE CEO, American Wind Energy Association RALPH CAVANAGH Senior Attorney and Co-Director of Energy Program, Natural Resource Defense Council SUNIL DESHMUKH Founding Member, Sierra Club India Advisory Council JOSEPH DOMINGUEZ Senior Vice President, Exelon Corporation RON EDELSTEIN Director, Regulatory and Government Relations, GTI NEAL ELLIOTT Associate Director for Research, American Council for an Energy-Efficient Economy JOHN HESS Chairman and CEO, Hess Corporation JAMES T. JENSEN President, Jensen Associates SENATOR (ret.) J. BENNETT JOHNSTON Chairman, Johnston Associates VELLO A. KUUSKRAA President, Advance Resources International, Inc. MIKE MING Oklahoma Secretary of Energy THEODORE ROOSEVELT IV Managing Director & Chairman, Barclays Capital Clean Tech Initiative OCTAVIO SIMOES Vice President of Commercial Development, Sempra Energy GREG STAPLE CEO, American Clean Skies Foundation PETER TERTZAKIAN Chief Energy Economist and Managing Director, ARC Financial DAVID VICTOR Director, Laboratory on International Law and Regulation, University of California, San Diego ARMANDO ZAMORA Director, ANH-Agencia Nacional De Hidrocarburos While the members of the advisory committee provided invaluable perspective and advice to the study group, individual members may have different views on one or more matters addressed in the report. They are not asked to individually or collectively endorse the report findings and recommendations.
  • 6. MIT Study on the Future of Natural Gas xiii Abstract Natural gas is finding its place at the heart of the energy discussion. The recent emergence of substantial new supplies of natural gas in the U.S., primarily as a result of the remarkable speed and scale of shale gas development, has heightened awareness of natural gas as a key component of indigenous energy supply and has lowered prices well below recent expectations. This study seeks to inform discussion about the future of natural gas, particularly in a carbon-constrained economy. There are abundant supplies of natural gas in the world, and many of these supplies can be developed and produced at relatively low cost. In North America, shale gas development over the past decade has substantially increased assessments of resources producible at modest cost. Consequently, the role of natural gas is likely to continue to expand, and its relative importance is likely to increase even further when greenhouse gas emissions are constrained. In a carbon-constrained world, a level playing field — a carbon dioxide (CO2) emissions price for all fuels without subsidies or other preferen-tial policy treatment —maximizes the value to society of the large U.S. natural gas resource. There are also a number of key uncertainties: the extent and nature of greenhouse gas emission mitigation measures that will be adopted; the mix of energy sources as the relative costs of fuels and technologies shift over time; the evolution of international natural gas markets. We explore how these uncertainties lead to different out-comes and also quantify uncertainty for natural gas supply and for the U.S. electricity fuel mix. The environmental impacts of shale development are challenging but manageable. Research and regulation, both state and Federal, are needed to minimize the environmental consequences. The U.S. natural gas supply situation has enhanced the substitution possibilities for natural gas in the electricity, industry, buildings, and transportation sectors. In the U.S. electricity supply sector, the cost benchmark for reducing carbon dioxide emissions lies with substitution of natural gas for coal, especially older, less efficient units. Substitution through increased utilization of existing combined cycle natural gas power plants provides a rela-tively low-cost, short-term opportunity to reduce U.S. power sector CO2 emissions by up to 20%, while also reducing emissions of criteria pollut-ants and mercury. Furthermore, additional gas-fired capacity will be needed as backup if variable and intermittent renewables, especially wind, are introduced on a large scale. Policy and regulatory steps are needed to facilitate adequate capacity investment for system reliability and efficiency. These increas-ingly important roles for natural gas in the electricity sector call for a detailed analysis of the interdependencies of the natural gas and power generation infrastructures. The primary use of natural gas in the U.S. manufacturing sector is as fuel for boilers and process heating, and replacement with new higher efficiency models would cost-effectively reduce natural gas use. Natural gas could also substitute for coal in boilers and process heaters and provide a cost-effective alternative for compliance with Environmental Protection Agency (EPA) Maximum Achievable Control Technology standards. In the residential and commercial buildings sector, transformation of the current approach to efficiency standards to one based on full fuel cycle analysis will enable better comparison of different energy supply options (especially
  • 7. natural gas and electricity). Efficiency metrics should be tailored to regional variations in climate and electricity supply mix. Within the U.S. market, the price of oil (which is set globally) compared to the price of natural gas (which is set regionally) is very important in determining market share when there is the opportunity for substitution. Over the last decade or so, when oil prices have been high, the ratio of the oil price to the natural gas price has been consistently higher than any of the standard rules of thumb. If this trend is robust, use of natural gas in transportation, either through direct use or following conversion to a liquid fuel, could in time increase appreciably. xiv MIT STUDY ON THE FUTURE OF NATURAL GAS The evolution of global gas markets is unclear. A global “liquid” natural gas market is benefi-cial to U.S. and global economic interests and, at the same time, advances security interests through diversity of supply and resilience to disruption. The U.S. should pursue policies that encourage the development of such a market, integrate energy issues fully into the conduct of U.S. foreign policy, and promote sharing of know-how for strategic global expansion of unconventional gas production. Past research, development, demonstration, and deployment (RDD&D) programs supported with public funding have led to significant advances for natural gas supply and use. Public-private partnerships supporting a broad natural gas research, development, and demonstration (RD&D) portfolio should be pursued.
  • 8. Chapter 1: Overview and Conclusions 1 Chapter 1: Overview and Conclusions PURPOSE AND OUTLINE OF THE STUDY Despite its vital importance to the national economy, natural gas has often been overlooked, or at best taken for granted, in the debate about the future of energy in the U.S. Over the past two or three years this has started to change, and natural gas is finding its place at the heart of the energy discussion. There are a number of reasons for this shift. The recent emergence of substantial new sup-plies of natural gas in the U.S., primarily as a result of the remarkable speed and scale of shale gas development, has heightened awareness of natural gas as a key component of indigenous energy supply and lowered prices well below recent expectations. Instead of the anticipated growth of natural gas imports, the scale of domes-tic production has led producers to seek new markets for natural gas, such as an expanded role in transportation. Most importantly for this study, there has been a growing recognition that the low carbon content of natural gas relative to other fossil fuels could allow it to play a signifi-cant role in reducing carbon dioxide (CO2) emis-sions, acting as a “bridge” to a low-carbon future. Within this context, the MIT study of The Future of Natural Gas seeks to inform the discussion around natural gas by addressing a fundamental question: what is the role of natural gas in a carbon-constrained economy? In exploring this question, we seek to improve general understanding of natural gas, and examine a number of specific issues. How much natural gas is there in the world, how expensive is it to develop, and at what rate can it be pro-duced? We start from a global perspective, and then look in detail at U.S. natural gas resources, paying particular attention to the extent and cost of shale gas resources, and whether these sup-plies can be developed and produced in an environmentally sound manner. Having explored supply volumes and costs, we use integrated models to examine the role that natural gas could play in the energy system under different carbon-constraining mechanisms or policies. It is important to recognize that the study does not set out to make predictions or forecasts of the likelihood or direction of CO2 policy in the U.S. Rather, we examine a number of different scenarios and explore their possible impacts on the future of natural gas supply and demand. Natural gas is important in many sectors of the economy — for electricity generation, as an industrial heat source and chemical feedstock, and for water and space heating in residential and commercial buildings. Natural gas competes directly with other energy inputs in these sectors. But it is in the electric power sector — where natural gas competes with coal, nuclear, hydro, wind and solar — that inter-fuel competition is most intense. We have, therefore, explored in depth how natural gas performs in the electric power sector under different scenarios. We have also taken a close look at the critical interaction between intermittent forms of renewable energy, such as wind and solar, and gas-fired power as a reliable source of backup capacity. We look at the drivers of natural gas use in the industrial, commercial and residential sectors, and examine the important question of whether natural gas, in one form or another, could be a viable and efficient substitute for gasoline or diesel in the transportation sector. We also examine the possible futures of global natural gas markets, and the geopolitical significance of the ever-expanding role of natural gas in the global economy. Finally, we make recommendations for research and development priorities and for the means by which public support should be provided.
  • 9. HIGH-LEVEL FINDINGS The findings and recommendations of the study are discussed later in this chapter, and covered in detail in the body of this report. Nevertheless, it is worth summarizing here the highest level conclusions of our study: 1. There are abundant supplies of natural gas in the world, and many of these supplies can be developed and produced at relatively low cost. In the U.S., despite their relative maturity, natural gas resources continue to grow, and the development of low-cost and abundant unconventional natural gas resources, particularly shale gas, has a material impact on future availability and price. 2. Unlike other fossil fuels, natural gas plays a major role in most sectors of the modern economy — power generation, industrial, commercial and residential. It is clean and flexible. The role of natural gas in the world is likely to continue to expand under almost all circumstances, as a result of its availability, its utility and its comparatively low cost. 3. In a carbon-constrained economy, the relative importance of natural gas is likely to increase even further, as it is one of the most cost-effective means by which to maintain energy supplies while reducing CO2 emissions. This is particularly true in the electric power sector, where, in the U.S., natural gas sets the cost benchmark against which other clean power sources must compete to remove the marginal ton of CO2. 4. In the U.S., a combination of demand reduction and displacement of coal-fired power by gas-fired generation is the lowest-cost way to reduce CO2 emissions by up to 50%. For more stringent CO2 emissions reductions, further de-carbonization of the energy sector will be required; but natural gas provides a cost-effective bridge to such a low-carbon future. 2 MIT STUDY ON THE FUTURE OF NATURAL GAS 5. Increased utilization of existing natural gas combined cycle (NGCC) power plants provides a relatively, low-cost short-term opportunity to reduce U.S. CO2 emissions by up to 20% in the electric power sector, or 8% overall, with minimal additional capital investment in generation and no new technology requirements. 6. Natural gas-fired power capacity will play an increasingly important role in providing backup to growing supplies of intermittent renewable energy, in the absence of a breakthrough that provides affordable utility-scale storage. But in most cases, increases in renewable power generation will be at the expense of natural gas-fired power generation in the U.S. 7. The current supply outlook for natural gas will contribute to greater competitiveness of U.S. manufacturing, while the use of more efficient technologies could offset increases in demand and provide cost-effective compliance with emerging envi-ronmental requirements. 8. Transformation of the current approach to appliance standards to one based on full fuel cycle analysis will enable better com-parison of different energy supply options in commercial and residential applications. 9. Natural gas use in the transportation sector is likely to increase, with the primary benefit being reduced oil dependence. Compressed natural gas (CNG) will play a role, particularly for high-mileage fleets, but the advantages of liquid fuel in trans-portation suggest that the chemical conver-sion of gas into some form of liquid fuel may be the best pathway to significant market penetration.
  • 10. Chapter 1: Overview and Conclusions 3 10. International gas trade continues to grow in scope and scale, but its economic, security and political significance is not yet adequately recognized as an important focus for U.S. energy concerns. 11. Past research, development, demonstration and deployment (RDD&D) programs supported with public funding have led to significant advances for natural gas supply and use. BACKGROUND The Fundamental Characteristics of Natural Gas Fossil fuels occur in each of the three funda-mental states of matter: in solid form as coal; in liquid form as oil and in gaseous form as natural gas. These differing physical character-istics for each fuel type play a crucial part in shaping each link in their respective supply chains: from initial resource development and production through transportation, conversion to final products and sale to customers. Their physical form fundamentally shapes the markets for each type of fossil fuel. Natural gas possesses remarkable qualities. Among the fossil fuels, it has the lowest carbon intensity, emitting less CO2 per unit of energy generated than other fossil fuels. It burns cleanly and efficiently, with very few non-carbon emis sions. Unlike oil, natural gas generally requires limited processing to prepare it for end use. These favorable characteristics have enabled natural gas to penetrate many markets, including domestic and commercial heating, multiple industrial processes and electrical power. Natural gas also has favorable characteristics with respect to its development and production. The high compressibility and low viscosity of natural gas allows high recoveries from conven-tional reservoirs at relatively low cost, and also enables natural gas to be economically recov-ered from even the most unfavorable subsurface environments, as recent developments in shale formations have demonstrated. These physical characteristics underpin the current expansion of the unconventional resource base in North America, and the potential for natural gas to displace more carbon-intensive fossil fuels in a carbon-constrained world. On the other hand, because of its gaseous form and low energy density, natural gas is uniquely disadvantaged in terms of transmission and storage. As a liquid, oil can be readily trans-ported over any distance by a variety of means, and oil transportation costs are generally a small fraction of the overall cost of developing oil fields and delivering oil products to market. This has facilitated the development of a truly global market in oil over the past 40 years or more. By contrast, the vast majority of natural gas supplies are delivered to market by pipeline, and delivery costs typically represent a relatively large fraction of the total cost in the supply chain. These characteristics have contributed to the evolution of regional markets rather than a truly global market in natural gas. Outside North America, this somewhat inflexible pipeline infrastructure gives strong political and economic power to those countries that control the pipelines. To some degree, the evolution of the spot market in Liquefied Natural Gas (LNG) is beginning to introduce more flexibility into global gas markets and stimulate real global trade. The way this trade may evolve over time is a critical uncertainty that is explored in this report.
  • 11. The Importance of Natural Gas in the Energy System Natural gas represents a very important, and growing, part of the global energy system. Over the past half century, natural gas has gained market share on an almost continuous basis, growing from some 15.6% of global energy consumption in 1965 to around 24% today. In absolute terms, global natural gas consumption over this period has grown from around 23 trillion cubic feet (Tcf) in 1965 to 104 Tcf in 2009, a more than fourfold increase. Within the U.S. economy, natural gas plays a vital role. Figure 1.1 displays the sources and uses of natural gas in the U.S. in 2009, and it reveals a number of interesting features that are explored in more detail in the body of this report. At 23.4 quadrillion British thermal units (Btu)1, or approximately 23 Tcf, gas represents a little under a quarter of the total energy supply in the U.S., with almost all of this supply now Supply Sources Demand Sources Petroleum Natural Gas Coal Renewables Nuclear 35.3 19.7 7.7 8.3 4 MIT STUDY ON THE FUTURE OF NATURAL GAS coming from indigenous resources. Perhaps of more significance, is the very important role that natural gas plays in all sectors of the economy, with the exception of transport. Very approxi-mately, the use of natural gas is divided evenly between three major sectors: industrial, residen-tial and commercial, and electric power. The 3% share that goes to transport is almost all associ-ated with natural gas use for powering oil and gas pipeline systems, with only a tiny fraction going into vehicle transport. In the Residential and Commercial sectors, natural gas provides more than three-quarters of the total primary energy, largely as a result of its efficiency, cleanliness and convenience for uses such as space and hot water heating. It is also a major primary energy input into the Industrial sector, and thus the price of natural gas has a very significant impact on the com-petitiveness of some U.S. manufacturing industries. While natural gas provided 18% of the primary fuel for power generation in 2009, Figure 1.1 Sources and Use of Primary Energy Sources in the U.S. with Natural Gas Highlighted (quadrillion Btu), 2009 3% 32% 12% 26% 53% Source: EIA, Annual Energy Outlook, 2009 Transportation Industrial Residential & Commercial Electric Power 23.4 27.0 18.8 10.6 38.6 72% 22% 1% 5% 94% 3% 41% 7% 11% 48% 11% 17% 22% 1% 1% 1% 3% 40% 76% 18% 30% 35% 7% 100% 9% 93% <1% 94.6 Quads Percent of Source Percent of Sector
  • 12. Chapter 1: Overview and Conclusions 5 it provided 23% of the produced electricity, reflecting the higher efficiency of natural gas plants. As will be seen later in this report, natural gas-fired capacity represents far more than 23% of total power generating capacity, providing a real opportunity for early action in controlling CO2 emissions. A Brief History of Natural Gas in the U.S. The somewhat erratic history of natural gas in the U.S. over the last three decades or so provides eloquent testimony to the difficulties of forecasting energy futures, particularly for natural gas. It also serves as a reminder of the need for caution in the current period of supply exuberance. The development of the U.S. natural gas market was facilitated by the emergence of an interstate natural gas pipeline system, supplying local distribution systems. This market structure was initially viewed as a natural monopoly and was subjected to cost-of-service regulation by both the Federal government and the states. Natural gas production and use grew considerably under this framework in the 1950s, 1960s and into the 1970s. Then came a perception of supply scarcity. After the first oil embargo, energy consumers sought to switch to natural gas. However, the combination of price controls and tightly regulated natural gas markets dampened incentives for domestic gas development, contributing to a perception that U.S. natural gas resources were limited. In 1978, convinced that the U.S. was running out of natural gas, Congress passed the Power Plant and Industrial Fuel Use Act (FUA) that essentially outlawed the building of new gas-fired power plants. Between 1978 and 1987 (the year the FUA was repealed), the U.S. added 172 Gigawatts (GW) of net power generation capacity. Of this, almost 81 GW was new coal capacity, around 26% of today’s entire coal fleet. About half of the remainder was nuclear power. By the mid 1990s, wholesale electricity markets and wellhead natural gas prices had been deregulated; new, highly efficient and relatively inexpensive combined cycle gas turbines had been deployed and new upstream technologies had enabled the development of offshore natural gas resources. This contributed to the perception that domestic natural gas supplies were sufficient to increase the size of the U.S. natural gas market from around 20 Tcf/year to much higher levels. New gas-fired power capacity was added at a rapid pace. Between 1989 after the repeal of the FUA and 2009, the U.S. added 306 GW of generation capacity, 88% of which was gas fired and 4% was coal fired.2 Today, the nameplate capacity of this gas-fired generation is significantly under-utilized, and the anticipated large increase in natural gas use has not materialized. By the turn of the 21st century, a new set of concerns arose about the adequacy of domestic natural gas supplies. Conventional supplies were in decline, unconventional natural gas resources remained expensive and difficult to develop and overall confidence in gas plum-meted. Natural gas prices started to rise, becom-ing more closely linked to the oil price, which itself was rising. Periods of significant natural gas price volatility were experienced. This rapid buildup in natural gas price, and perception of long-term shortage, created economic incentives for the accelerated devel-opment of an LNG import infrastructure. Since 2000, North America’s rated LNG capacity has expanded from approximately 2.3 billion cubic feet (Bcf)/day to 22.7 Bcf/day, around 35% of the nation’s average daily requirement. This expansion of LNG capacity coincided with an overall rise in the natural gas price and the market diffusion of technologies to develop affordable unconventional gas. The game-changing potential of these technologies, combined with the large unconventional
  • 13. resource base, has become more obvious over the last few years, radically altering the U.S. supply picture. We have once again returned to a period where supply is seen to be abundant. New LNG import capacity goes largely unused at present, although it provides a valuable supply option for the future. These cycles of perceived “feast and famine” demonstrate the genuine difficulty of forecast-ing the future and providing appropriate policy support for natural gas production and use. They underpin the efforts of this study to account for this uncertainty in an analytical manner. Major Uncertainties Looking forward, we anticipate policy and geopolitics, along with resource economics and technology developments, will continue to play a major role in determining global supply and market structures. Thus, any analysis of the future of natural gas must deal explicitly with multiple uncertainties: s The extent and nature of the greenhouse gas (GHG) mitigation measures that will be adopted: the U.S. legislative response to the climate threat has proved quite challenging. However, the Environmental Protection Agency (EPA) is developing regulations under the Clean Air Act, and a variety of local, state and regional GHG limitation programs have been put in place. At the international level, reliance upon a system of voluntary national pledges of emission reductions by 2020, as set out initially in the Copenhagen Accord, leaves uncertainty concerning the likely structure of any future agreements that may emerge to replace the Kyoto Protocol. The absence of a clear international regime for mitigating GHG emissions in turn raises questions about the likely stringency of national policies in both industrialized countries and major emerging economies over coming decades. 6 MIT STUDY ON THE FUTURE OF NATURAL GAS s The likely technology mix in a carbon-constrained world, particularly in the power sector: the relative costs of different tech-nologies may shift significantly in response to RD&D, and a CO2 emissions price will affect the relative costs. Moreover, the tech-nology mix will be affected by regulatory and subsidy measures that will skew economic choices. s The ultimate size and production cost of the natural gas resource base, and the environ-mental acceptability of production methods: much remains to be learned about the perfor-mance of shale gas plays, both in the U.S. and in other parts of the world. Indeed, even higher risk and less well-defined unconventional natural gas resources, such as methane hydrates, could make a contribution to supply in the later decades of the study’s time horizon. s The evolution of international natural gas markets: very large natural gas resources are to be found in several areas outside the U.S., and the role of U.S. natural gas will be influenced by the evolution of this market — particularly the growth and efficiency of trade in LNG. Only a few years back, U.S. industry was investing in facilities for sub-stantial LNG imports. The emergence of the domestic shale gas resource has depressed this business in the U.S., but in the future, the nation may again look to international markets. Of these uncertainties, the last three can be explored by applying technically grounded analysis: lower cost for carbon capture and sequestration (CCS), renewables and nuclear power; producible resources of different levels and regional versus global integrated markets. In contrast, the shape and size of GHG mitiga-tion measures is likely to be resolved only through complex ongoing political discussions at the national level in the major emitting countries and through multilateral negotiations.
  • 14. Chapter 1: Overview and Conclusions 7 The analysis in this study is based on three policy scenarios: 1. A business-as-usual case, with no significant carbon constraints; 2. GHG emissions pricing, through a cap-and- trade system or emissions tax, leading to a 50% reduction in U.S. emissions below the 2005 level, by 2050. 3. GHG reduction via U.S. regulatory measures without emissions pricing: a renewable portfolio standard and measures forcing the retirement of some coal plants. Our analysis is long term in nature, with a 2050 time horizon. We do not attempt to make detailed short-term projections of volumes, prices or price volatility, but rather focus on the long-term consequences of the carbon mitigation scenarios outlined above, taking into account the manifold uncertainties in a highly complex and interdependent energy system. MAJOR FINDINGS AND RECOMMENDATIONS In the following section we summarize the major findings and recommendations for each chapter of the report. Supply Globally, there are abundant supplies of natural gas, much of which can be developed at relatively low cost. The mean projection of remaining recoverable resource in this report is 16,200 Tcf, 150 times current annual global natural gas consumption, with low and high projections of 12,400 Tcf and 20,800 Tcf, respectively. Of the mean projection, approxi-mately 9,000 Tcf could be developed economi-cally with a natural gas price at or below $4/ Million British thermal units (MMBtu) at the export point. Unconventional natural gas, and particularly shale gas, will make an important contribution to future U.S. energy supply and CO2 emission-reduction efforts. Assessments of the recover-able volumes of shale gas in the U.S. have increased dramatically over the last five years, and continue to grow. The mean projection of the recoverable shale gas resource in this report is approximately 650 Tcf, with low and high projections of 420 Tcf and 870 Tcf, respectively. Of the mean projection, approximately 400 Tcf could be economically developed with a natural gas price at or below $6/MMBtu at the wellhead. While the pace of shale technology development has been very rapid over the past few years, there are still many scientific and technological challenges to overcome before we can be con fident that this very large resource base is being developed in an optimum manner. Although there are large supplies, global conven-tional natural gas resources are concentrated geographically, with 70% in three countries: Qatar, Iran and Russia. There is considerable potential for unconventional natural gas supply outside North America, but these resources are largely unproven with very high resource uncertainty. Nevertheless, unconventional supplies could provide a major opportunity for diversification and improved security of supply in some parts of the world. The environmental impacts of shale develop-ment are challenging but manageable. Shale development requires large-scale fracturing of the shale formation to induce economic production rates. There has been concern that these fractures can also penetrate shallow freshwater zones and contaminate them with fracturing fluid, but there is no evidence that this is occurring. There is, however, evidence of natural gas migration into freshwater zones in some areas, most likely as a result of sub-standard well completion practices by a few operators. There are additional environmental
  • 15. challenges in the area of water management, particularly the effective disposal of fracture fluids. Concerns with this issue are particularly acute in regions that have not previously experienced large-scale oil and natural gas development, especially those overlying the massive Marcellus shale, and do not have a well-developed subsurface water disposal infrastructure. It is essential that both large and small companies follow industry best practices; that water supply and disposal are coordinated on a regional basis and that improved methods are developed for recycling of returned fracture fluids. Natural gas trapped in the ice-like form known as methane hydrate represents a vast potential resource for the long term. Recent research is beginning to provide better definition of the overall resource potential, but many issues remain to be resolved. In particular, while there have been limited production tests, the long-term producibility of methane hydrates remains unproven, and sustained research will be required. MAJOR RECOMMENDATIONS Government-supported research on the fundamental challenges of unconventional natural gas development, particularly shale gas, should be greatly increased in scope and scale. In particular, support should be put in place for a comprehensive and integrated research program to build a system-wide understanding of all subsurface aspects of the U.S. shale resource. In addition, research should be pursued to reduce water usage in fracturing and to develop cost-effective water recycling technology. A concerted coordinated effort by industry and government, both state and Federal, should be organized so as to minimize the environmental impacts of shale gas 8 MIT STUDY ON THE FUTURE OF NATURAL GAS development through both research and regulation. Transparency is key, both for fracturing operations and for water management. Better communication of oil- and gas-field best practices should be facilitated. Integrated regional water usage and disposal plans and disclosure of hydraulic fracture fluid components should be required. The U.S. should support unconventional natural gas development outside U.S., particularly in Europe and China, as a means of diversifying the natural gas supply base. The U.S. government should continue to sponsor methane hydrate research, with a particular emphasis on the demonstration of production feasibility and economics. U.S. Natural Gas Production, Use and Trade: Potential Futures In a carbon-constrained world, a level playing field — a CO2 emissions price for all fuels without subsidies or other preferential policy treatment — maximizes the value to society of the large U.S. natural gas resource. Under a scenario with 50% CO2 reductions to 2050, using an established model of the global economy and natural gas cost curves that include uncertainty, the principal effects of the associated CO2 emissions price are to lower energy demand and displace coal with natural gas in the electricity sector. In effect, gas-fired power sets a competitive benchmark against which other technologies must compete in a lower carbon environment. A major uncertainty that could impact this picture in the longer term is technology development that lowers the costs of alternatives, in particular, renewables, nuclear and CCS.
  • 16. Chapter 1: Overview and Conclusions 9 A more stringent CO2 reduction of, for exam-ple, 80% would probably require the complete de-carbonization of the power sector. This makes it imperative that the development of competing low-carbon technology continues apace, including CCS for both coal and natural gas. It would be a significant error of policy to crowd out the development of other, currently more costly, technologies because of the new assessment of the natural gas supply. Con-versely, it would also be a mistake to encourage, via policy and long-term subsidy, more costly technologies to crowd out natural gas in the short to medium term, as this could signifi-cantly increase the cost of CO2 reduction. The evolution of global natural gas markets is unclear; but under some scenarios, the U.S. could import 50% or more of its natural gas by 2050, despite the significant new resources created in the last few years. Imports can prevent natural gas-price inflation in future years. MAJOR RECOMMENDATIONS To maximize the value to society of the substantial U.S. natural gas resource base, U.S. CO2 reduction policy should be designed to create a “level playing field,” where all energy technologies can compete against each other in an open marketplace conditioned by legislated CO2 emissions goals. A CO2 price for all fuels without long-term subsidies or other preferential policy treatment is the most effective way to achieve this result. In the absence of such policy, interim energy policies should attempt to replicate as closely as possible the major consequences of a “level playing field” approach to carbon-emissions reduction. At least for the near term, that would entail facilitating energy demand reduction and displacement of some coal generation with natural gas. Natural gas can make an important contribution to GHG reduction in coming decades, but investment in low-emission technologies, such as nuclear, CCS and renewables, should be actively pursued to ensure that a mitigation regime can be sustained in the longer term. Natural Gas for Electric Power In the U.S., around 30% of natural gas is consumed in the electric power sector. Within the power sector, gas-fired power plants play a critical role in the provision of peaking capacity, due to their inherent ability to respond rapidly to changes in demand. In 2009, 23% of the total power generated was from natural gas, while natural gas plants represented over 40% of the total generating capacity. In a carbon-constrained world, the power sector represents the best opportunity for a significant increase in natural gas demand, in direct competition with other primary energy sources. Displacement of coal-fired power by gas-fired power over the next 25 to 30 years is the most cost-effective way of reducing CO2 emissions in the power sector. As a result of the boom in the construction of gas-fired power plants in the 1990s, there is a substantial amount of underutilized NGCC capacity in the U.S. today. In the short term, displacement of coal-fired power by gas-fired power provides an opportunity to reduce CO2 emissions from the power sector by about 20%, at a cost of less than $20/ton of CO2 avoided. This displacement would use existing generating capacity, and would, therefore, require little in the way of incremental capital expenditure for new genera tion capacity. It would also signifi-cantly reduce pollutants such as sulfur dioxide (SO2), nitrous oxide (NOX), particulates and mercury (Hg).
  • 17. Natural gas-fired power generation provides the major source of backup to intermittent renew-able supplies in most U.S. markets. If policy support continues to increase the supply of intermittent power, then, in the absence of affordable utility-scale storage options, addi-tional natural gas capacity will be needed to provide system reliability. In some markets, existing regulation does not provide the appropriate incentives to build incremental capacity with low load factors, and regulatory changes may be required. In the short term, where a rapid increase in renewable generation occurs without any adjustment to the rest of the system, increased renewable power displaces gas-fired power generation and thus reduces demand for natural gas in the power sector. In the longer term, where the overall system can adjust through plant retirements and new construc-tion, increased renewables displace baseload generation. This could mean displacement of coal, nuclear or NGCC generation, depending on the region and policy scenario under consideration. For example, in the 50% CO2 reduction scenario described earlier, where gas-fired generation drives out coal generation, increased renewable penetration as a result of cost reduction or government policy will reduce natural gas generation on a nearly one-for-one basis. MAJOR RECOMMENDATIONS The displacement of coal generation with NGCC generation should be pursued as the most practical near-term option for significantly reducing CO2 emissions from power generation. In the event of a significant penetration of intermittent renewable production in the generation technology mix, policy and regulatory measures should be developed to facilitate adequate levels of investment in natural gas generation capacity to ensure system reliability and efficiency. 10 MIT STUDY ON THE FUTURE OF NATURAL GAS END USE GAS DEMAND In the U.S., around 32% of all natural gas consumption is in the Industrial sector, where its primary uses are for boiler fuel and process heat; and 35% of use is in the Residential and Commercial sectors, where its primary applica-tion is space heating. Only 0.15% of natural gas is used as a vehicle transportation fuel. Industrial, Commercial and Residential Within the Industrial sector, there are opportu-nities for improved efficiency of the Industrial boiler fleet, replacing less-efficient natural gas boilers with high-efficiency, or super-high efficiency boilers with conversion efficiencies up to 94%. There are also opportunities to improve the efficiency of natural gas use in process heating and to reduce process heating require-ments through changes in process technologies and material substitutions. Our analysis suggests that conversion of coal-fired boilers in the Industrial sector to high-efficiency gas boilers could provide a cost-effective option for compliance with new hazardous air pollutant reductions and create significant CO2 reduction opportunities at modest cost, with a potential to increase natural gas demand by up to 0.9 Tcf/year. Natural gas and natural gas liquids (NGLs) are a principal feedstock in the chemicals industry and a growing source of hydrogen production for petroleum refining. Our analysis of selected cases indicates that a robust domestic market for natural gas and NGLs will improve the competitiveness of manufacturing industries dependent on these inputs. Natural gas has significant advantages in the Residential and Commercial sectors due in part to its cleanliness and life cycle energy efficiency. However, understanding the comparative cost-effectiveness and CO2 impacts of different energy options is complex. Comparison of
  • 18. Chapter 1: Overview and Conclusions 11 end use or “site” energy efficiencies can be misleading, since it does not take into account full system energy use and emissions (such as the efficiency and emissions of electricity generation). However, quantitatively account-ing for the full system impacts from the “source” can be challenging, requiring a complex end-to-end, full fuel cycle (FFC) analysis that is not generally available to the consumer or to the policy maker. Consumer and policy maker choices are further complicated by the influence of local climatic conditions and regional energy markets. The primary energy mix of the regional generation mix fundamentally affects “site versus source” energy and emissions comparisons. And the local climate has a major influence on the best choice of heating and cooling systems, particu-larly the appropriate use of modern space conditioning technologies such as heat pumps. Consumer information currently available to consumers does not facilitate well-informed decision making. Expanded use of combined heat and power (CHP) has considerable potential in the Indus-trial and large Commercial sectors. However, cost, complexity and the inherent difficulty of balancing heat and power loads at a very small scale make residential CHP a much more difficult proposition. MAJOR RECOMMENDATIONS Improved energy efficiency metrics, which allow consumers to accurately compare direct fuel and electricity end uses on a full fuel cycle basis, should be developed. Over time, these metrics should be tailored to account for geographical variations in the sources of electric power supply and local climate conditions. Transportation The ample domestic supply of natural gas has stimulated interest in its use in transportation. There are multiple drivers: the oil-natural gas price spread on an energy basis generally favors natural gas, and today that spread is at histori-cally high levels; an opportunity to lessen oil dependence in favor of a domestically supplied fuel, including natural gas-derived liquid fuels with modest changes in vehicle and/or infra-structure requirements and reduced CO2 emissions in direct use of natural gas. Compressed natural gas (CNG) offers a signifi-cant opportunity in U.S. heavy-duty vehicles used for short-range operation (buses, garbage trucks, delivery trucks), where payback times are around three years or less and infrastructure issues do not impede development. However, for light passenger vehicles, even at 2010 oil-natural gas price differentials, high incre-mental costs of CNG vehicles lead to long payback times for the average driver, so signifi-cant penetration of CNG into the passenger fleet is unlikely in the short term. Payback periods could be reduced significantly if the cost of conversion from gasoline to CNG could be reduced to the levels experienced in other parts of the world such as Europe. LNG has been considered as a transport fuel, particularly in the long-haul trucking sector. However, as a result of operational and infra-structure considerations as well as high incre-mental costs and an adverse impact on resale value, LNG does not appear to be an attractive option for general use. There may be an opportunity for LNG in the rapidly expanding segment of hub-to-hub trucking operations, where infrastructure and operational challenges can be overcome.
  • 19. Energy density, ease of use and infrastructure considerations make liquid fuels that are stable at room temperature a compelling choice in the Transportation sector. The chemical conversion of natural gas to liquid fuels could provide an attractive alternative to CNG. Several pathways are possible, with different options yielding different outcomes in terms of total system CO2 emissions and cost. Conversion of natural gas to methanol, as widely practiced in the chemi-cals industry, could provide a cost-effective route to manufacturing an alternative, or supplement, to gasoline, while keeping CO2 emissions at roughly the same level. Gasoline engines can be modified to run on methanol at modest cost. MAJOR RECOMMENDATIONS The U.S. government should consider revision to its policies related to CNG vehicles, including how aftermarket CNG conversions are certified, with a view to reducing up-front costs and facilitating CNG-gasoline capacity. The U.S. government should implement an open fuel standard that requires automobile manufacturers to provide tri-flex fuel (gasoline, ethanol and methanol) operation in light-duty vehicles. Support for methanol fueling infrastructure should also be considered. Infrastructure The continental U.S. has a vast, mature and robust natural gas infrastructure, which includes: over 300,000 miles of transmission lines; numerous natural gas-gathering systems; storage sites; processing plants; dis tribu tion pipelines and LNG import terminals. Several trends are having an impact on natural gas infrastructure. These include changes in 12 MIT STUDY ON THE FUTURE OF NATURAL GAS U.S. production profiles, with supplies generally shifting from offshore Gulf of Mexico back to onshore; shifts in U.S. population, generally from the Northeast and Midwest to the South and West and growth in global LNG markets, driven by price differences between regional markets. The system generally responds well to market signals. Changing patterns of supply and demand have led to a significant increase in infrastructure development over the past few years with West to East expansions dominating pipeline capacity additions. Infrastructure limitations can temporarily constrain produc-tion in emerging production areas such as the Marcellus shale — but infrastructure capacity expansions are planned or underway. Demand increases and shifts in consumption and production are expected to require around $210 billion in infrastructure investment over the next 20 years. Much of the U.S. pipeline infrastructure is old — around 25% of U.S. natural gas pipelines are 50 years old or older — and recent incidents demonstrate that pipeline safety issues are a cause for concern. The Department of Trans-portation (DOT) regulates natural gas pipeline safety and has required integrity management programs for transmission and distribution pipelines. The DOT also supports a small pipeline safety research program, which seems inadequate given the size and age of the pipe-line infrastructure. Increased use of natural gas for power genera-tion has important implications for both natural gas and electric infrastructures, includ-ing natural gas storage. Historically, injections and withdrawals from natural gas storage have been seasonal. Increased use of natural gas for power generation may require new high-deliverability natural gas storage to meet more variable needs associated with power generation.
  • 20. Chapter 1: Overview and Conclusions 13 MAJOR RECOMMENDATIONS Analysis of the infrastructure demands associated with potential shift from coal to gas-fired power should be undertaken. Pipeline safety technologies should be included in natural gas RD&D programs. END USE EMISSIONS VERSUS SYSTEM-WIDE EMISSIONS When comparing GHG emissions for different energy sources, attention should be paid to the entire system. In particular, the potential for leakage of small amounts of methane in the production, treatment and distribution of coal, oil and natural gas has an effect on the total GHG impact of each fuel type. The modeling analysis in Chapter 3 addresses the system-wide impact, incorporating methane leakage from coal, oil and natural gas production, processing and transmission. In Chapter 5 we do not attempt to present detailed full-system account-ing of CO2 (equivalent) emissions for various end uses, although we do refer to its potential impact in specific instances. The CO2 equivalence of methane is conven-tionally based on a Global Warming Potential (GWP)3 intended to capture the fact that each GHG has different radiative effects on climate and different lifetimes in the atmosphere. In our considerations, we follow the standard Intergovernmental Panel on Climate Change (IPCC) and EPA definition that has been widely employed for 20 years. Several recently published life cycle emissions analyses do not appear to be comprehensive, use common assumptions or recognize the progress made by producers to reduce methane emissions, often to economic benefit. We believe that a lot more work is required in this area before a common under-standing can be reached. Further discussion can be found in Appendix 1A. MAJOR RECOMMENDATIONS The EPA and the U.S. Department of Energy (DOE) should co-lead a new effort to review, and update as appropriate, the methane emission factors associated with natural gas production, transmission, storage and distribution. The review should have broad-based stakeholder involvement and should seek to reach a consensus on the appropriate methodology for estimating methane emissions rates. The analysis should, to the extent possible: (a) reflect actual emissions measurements; (b) address fugitive emissions for coal and oil as well as natural gas; and (c) reflect the potential for cost-effective actions to prevent fugitive emissions and venting of methane. MARKETS AND GEOPOLITICS The physical characteristics of natural gas, which create a strong dependence on pipeline transportation systems, have led to local markets for natural gas – in contrast to the global markets for oil. There are three distinct regional gas markets: North America, Europe and Asia, with more localized markets elsewhere. The U.S. gas market is mature and sophisticated, and functions well, with a robust spot market. Within the U.S. market, the price of oil, (which is set globally) compared to the price of natural gas (which is set regionally) is very important in determining market share when there is the opportunity for substitution. Over the last decade or so, when oil prices have been high, the ratio of the benchmark West Texas Inter-mediate oil price to the Henry Hub natural gas price has been consistently higher than any of the standard rules of thumb.
  • 21. International natural gas markets are in the early stages of integration, with many impedi-ments to further development. While increased LNG trade has started to connect these mar-kets, they remain largely distinct with respect to supply patterns, pricing and contract struc-tures, and market regulation. If a more inte-grated market evolves, with nations pursuing gas production and trade on an economic basis, there will be rising trade among the current regional markets and the U.S. could become a substantial net importer of LNG in future decades. Greater international market liquidity would be beneficial to U.S. interests. U.S. prices for natural gas would be lower than under current regional markets, leading to more gas use in the U.S. Greater market liquidity would also contribute to security by enhancing diversity of global supply and resilience to supply disruptions for the U.S. and its allies. These factors ameliorate security concerns about import dependence. As a result of the significant concentration of conventional gas resources globally, policy and geopolitics play a major role in the develop-ment of global supply and market structures. Consequently, since natural gas is likely to play a greater role around the world, natural gas issues will appear more frequently on the U.S. energy and security agenda. Some of the specific security concerns are: s .ATURAL GAS DEPENDENCE
  • 22. INCLUDING THAT of allies, could constrain U.S. foreign policy options, especially in light of the unique American international security responsibilities. s .EW MARKET PLAYERS COULD INTRODUCE impediments to the development of transparent markets. 14 MIT STUDY ON THE FUTURE OF NATURAL GAS s #OMPETITION FOR CONTROL OF NATURAL GAS pipelines and pipeline routes is intense in key regions. s ,ONGER SUPPLY CHAINS INCREASE THE VULNER ability of the natural gas infrastructure. MAJOR RECOMMENDATIONS The U.S. should pursue policies that encourage the development of an efficient and integrated global gas market with transparency and diversity of supply. Natural gas issues should be fully integrated into the U.S. energy and security agenda, and a number of domestic and foreign policy measure should be taken, including: t JOUFHSBUJOHFOFSHZJTTVFTGVMMZJOUPUIF conduct of U.S. foreign policy, which will require multiagency coordination with leadership from the Executive Office of the President; t TVQQPSUJOHUIFFõPSUTPGUIF*OUFSOBUJPOBM Energy Agency (IEA) to place more atten-tion on natural gas and to incorporate the large emerging markets (such as China, India and Brazil) into the IEA process as integral participants; t TIBSJOHLOPXIPXGPSUIFTUSBUFHJD expansion of unconventional resources; and t BEWBODJOHJOGSBTUSVDUVSFQIZTJDBMBOE cyber-security as the global gas delivery system becomes more extended and interconnected.
  • 23. Chapter 1: Overview and Conclusions 15 RDD There are numerous RDD opportunities to address key objectives for natural gas supply, delivery and end use: s IMPROVE THE LONG TERM ECONOMICS OF RESOURCE development as an important contributor to the public good; s REDUCE THE ENVIRONMENTAL FOOTPRINT OF natural gas production, delivery and use; s EXPAND CURRENT USE AND CREATE ALTERNATIVE applications for public policy purposes, such as emissions reductions and diminished oil dependence; s IMPROVE SAFETY AND OPERATION OF NATURAL GAS infrastructure; s IMPROVE THE EFlCIENCY OF NATURAL GAS CONVER- sion and end-use so as to use the resource most effectively. Historically, RDD funding in the natural gas industry has come from a variety of sources, including private industry, the DOE, and private/public partnerships. In tandem with limited tax credits, this combination of support played a major role in development of uncon-ventional gas. It has also contributed to more efficient end-use, for example in the develop-ment of high-efficiency gas turbines. Today government funded RDD for natural gas is at very low levels. The elimination of rate-payer funded RDD has not been com-pensated by increased DOE appropriations or by a commensurate new revenue stream outside the appropriations process. The total public and public-private funding for natural gas research is down substantially from its peak and is more limited in scope, even as natural gas takes a more prominent role in a carbon-constrained world. While natural gas can provide a cost-effective bridge to a low carbon future, it is vital that efforts continue to improve the cost and efficiency of low or zero carbon technologies for the longer term. This will require sustained RDD and subsidies of limited duration to encourage early deployment. MAJOR RECOMMENDATIONS The Administration and Congress should support RDD focused on environmentally responsible domestic natural gas supply. This should entail both a renewed DOE program, weighted towards basic research, and a complementary industry-led program, weighted towards applied research, development and demonstration, that is funded through an assured funding stream tied to energy production, delivery and use. The scope of the program should be broad, from supply to end-use. Support should be provided through RDD, and targeted subsidies of limited duration, for low-emission technologies that have the prospect of competing in the long run. This would include renewables, carbon capture and sequestration for both coal and gas generation, and nuclear power.
  • 24. CONCLUSION Over the past few years, the U.S. has developed an important new natural gas resource that fundamentally enhances the nation’s long-term gas supply outlook. Given an appropriate regulatory environment, which seeks to place all lower carbon energy sources on a level competitive playing field, domestic supplies of natural gas can play a very significant role in reducing U.S. CO2 emissions, particularly in the electric power sector. This lowest cost strategy of CO2 reduction allows time for the continued development of more cost-effective low or zero carbon energy technology for the longer term, when gas itself is no longer sufficiently low carbon to meet more stringent CO2 reduction targets. The newly realized abundance of low cost gas provides an enor-mous potential benefit to the nation, providing a cost effective bridge to a secure and low carbon future. It is critical that the additional time created by this new resource is spent wisely, in creating lower cost technology options for the longer term, and thereby ensuring that the natural gas bridge has a safe landing place in a low carbon future. NOTES 1 One quadrillion Btu (or “quad”) is 1015 or 1,000,000,000,000,000 British thermal units. Since one standard cubic foot of gas is approximately 1,000 Btu, then 1 quad is approximately 1 Tcf of gas. 16 MIT STUDY ON THE FUTURE OF NATURAL GAS 2 EIA 2009 Annual Energy Review, Figure 45. 3 Global-warming potential (GWP) is a relative measure of how much heat a given greenhouse gas traps in the atmosphere.
  • 25. Chapter 2: Supply 17 Chapter 2: Supply INTRODUCTION AND CONTEXT In this chapter, we discuss various aspects of natural gas supply: how much natural gas exists in the world; at what rate can it be produced and what it will cost to develop. Following the introduction and definitions, we look at produc-tion history, resource volumes and supply costs for natural gas — first from a global perspective, and then focusing in more detail on the U.S., paying particular attention to the prospects for shale gas. We then discuss the science and technology of unconventional gas, the environ-mental impacts of shale gas development and finally the prospects for methane hydrates. NATURAL GAS AND THE RECOVERY PROCESS The primary chemical component of natural gas is methane, the simplest and lightest hydrocar-bon molecule, comprised of four hydrogen (H) atoms bound to a single carbon (C) atom. In chemical notation, this is expressed as CH4 (the symbol for methane). Natural gas may also contain small proportions of heavier hydrocarbons: ethane (C2H6); propane (C3H8) and butane (C4H10); these heavier components are often extracted from the producing stream and marketed separately as natural gas liquids (NGL). In the gas industry, the term “wet gas” is used to refer to natural gas in its raw unpro-cessed state, while “dry gas” refers to natural gas from which the heavier components have been extracted. Thermogenic1 natural gas, which is formed by the application, over geological time, of enormous heat and pressure to buried organic matter, exists under pressure in porous rock formations thousands of feet below the surface of the earth. It exists in two primary forms: “associated gas” is formed in conjunction with oil, and is generally released from the oil as it is recovered from the reservoir to the surface — as a general rule the gas is treated as a by-product of the oil produc-tion process; in contrast, “non-associated gas” is found in reservoirs that do not contain oil, and is developed as the primary product. While associ-ated gas is an important source, the majority of gas production is non-associated; 89% of the gas produced in the U.S. is non-associated. Non-associated gas is recovered from the forma-tion by an expansion process. Wells drilled into the gas reservoir allow the highly compressed gas to expand through the wells in a controlled manner, to be captured, treated and transported at the surface. This expansion process generally leads to high recovery factors from conventional, good-quality gas reservoirs. If, for example, the average pressure in a gas reservoir is reduced from an initial 5,000 pounds per square inch (psi) to 1,000 psi over the lifetime of the field, then approximately 80% of the Gas Initially In Place (GIIP) will be recovered. This is in contrast to oil, where recovery factors of 30% to 40% are more typical. Gas is found in a variety of subsurface locations, with a gradation of quality as illustrated in the resource triangle in Figure 2.1.
  • 26. Figure 2.1 GIIP as a Pyramid in Volume and Quality. Conventional reservoirs are at the top of the pyramid. They are of higher quality because they have high permeability and require less technology for development and production. The unconventional reservoirs lie below the conventional reservoirs in this pyramid. They are more abundant in terms of GIIP but are currently assessed as recoverable resources — and commercially developed — primarily in North America. They have lower permeability, require advanced technology for production and typically yield lower recovery factors than conventional reservoirs. Conventional Resources Unconventional Resources Conventional resources exist in discrete, well-defined subsurface accumulations (reser-voirs), with permeability2 values greater than a specified lower limit. Such conventional gas resources can usually be developed using vertical wells, and generally yield the high recovery factors described above. By contrast, unconventional resources are found in accumulations where permeability is low. Such accumulations include “tight” 18 MIT STUDY ON THE FUTURE OF NATURAL GAS sandstone formations, coal beds (coal bed methane or CBM) and shale formations. Unconventional resource accumulations tend to be distributed over a larger area than con-ventional accumulations and usually require advanced technology such as horizontal wells or artificial stimulation in order to be economi-cally productive; recovery factors are much lower — typically of the order of 15% to 30% of GIIP. The various resource types are shown schematically in Figure 2.2. Adapted from Holditch 2006 High-Quality Reservoirs Low-Quality Reservoirs Tight Gas Sands Coal Bed Methane Shale Gas Methane Hydrates Volume Increasing Technology/Decreasing Recovery Factor
  • 27. Chapter 2: Supply 19 Figure 2.2 Illustration of Various Types of Gas Resource RESOURCE DEFINITIONS The complex cross-dependencies between geology, technology and economics mean that the use of unambiguous terminology is critical when discussing natural gas supply. In this study, the term “resource” will refer to the sum of all gas volumes expected to be recoverable in the future, given specific technological and economic conditions. The resource can be disaggregated into a number of sub-categories; specifically, “proved reserves,” “reserve growth” (via further development of known fields) and “undiscovered resources,” which represent gas volumes that are expected to be discovered in the future via the exploration process. Land surface Coal bed methane Conventional associated gas Tight sand gas Figure 2.3 illustrates how proved reserves, reserve growth and undiscovered resources combine to form the “technically recoverable resource,” that is, the total volume of natural gas that could be recovered in the future, using today’s technology, ignoring economic constraints. Sandstone Seal Gas-rich shale Conventional non-associated gas Schematic geology of natural gas resource Oil Source: U.S. Energy Information Administration Gas resources are an economic concept — a function of many variables, in particular the cost of exploration, production and transportation relative to the price of sale to users.
  • 28. Figure 2.3 Modified McKelvey Diagram, Showing the Interdependencies between Geology, Technology and Economics and Their Impacts on Resource Classes; Remaining Technically Recoverable Resources Are Outlined in Red Discovered/Identified Cumulative Production The methodology used in analyzing natural gas supply for this study places particular emphasis in two areas: 1. Treating gas resources as an economic concept — recoverable resources are a function of many variables, particularly the ultimate price that the market will pay. A set of supply curves has been developed using the ICF3 Hydrocarbon Supply Model with volumetric and fiscal input data supplied by ICF and MIT. These curves describe the volume of gas that is economically recover-able for a given gas price. These curves form a primary input to the integrated economic modelling in Chapter 3 of this report. 2. Recognizing and embracing uncertainty — uncertainty exists around all resource estimates due to the inherent uncertainty 20 MIT STUDY ON THE FUTURE OF NATURAL GAS associated with the underlying geological, technological, economic and political conditions. The analysis of natural gas supply in this study has been carried out in a manner that frames any single point resource estimate within an associated uncertainty envelope, in order to illustrate the potentially large impact this ever-present uncertainty can have. The volumetric data used as the basis of the analysis for both the supply curve development and the volumetric uncertainty analysis was compiled from a range of sources. In particular, use has been made of data from work at the United States Geological Survey (USGS), the Potential Gas Committee (PGC), the Energy Information Agency (EIA), the National Petroleum Council (NPC) and ICF International. Increasing Economic Viability Sub-economic Economic Technically Recoverable Technically Unrecoverable Unconfirmed Undiscovered Increasing Geologic Knowledge Confirmed Reserves Inferred Reserves/ Reserve Growth Undiscovered Technically Recoverable Resources
  • 29. Chapter 2: Supply 21 GLOBAL SUPPLY Production Trends Over the past two decades, global production of natural gas has grown significantly, rising by almost 42% overall from approximately 74 trillion cubic feet (Tcf )4 in 1990 to 105 Tcf in 2009. This is almost twice the growth rate of global oil production, which increased by around 22% over the same period. Much of the gas production growth has been driven by the rapid expansion of production in areas that were not major gas producers prior to 1990. This trend is illustrated in Figure 2.4, which shows how growth in production from regions such as the Middle East, Africa and Asia Oceania has significantly outpaced growth in the traditional large producing regions, includ-ing North America and Eurasia (primarily Russia). Figure 2.5 compares the 1990 and 2009 annual production levels for the 10 largest gas-producing nations (as defined by 2009 output). In addition to demonstrating the overwhelming scale of the United States and Russia compared to other producing countries, this figure illustrates the very significant growth rates in other countries. The substantial growth of new gas producing countries over the period reflects the relative immaturity of the gas industry on a global basis outside Russia and North America, the expansion of gas markets and the rise in global cross-border gas trade. Between 1993 and 2008, global cross-border gas trade almost doubled, growing from around 18 Tcf (25% of global supply) to around 35 Tcf (32% of global supply). Most of the world’s gas supply is transported from producing fields to market by pipeline. However, the increase in global gas trade has been accelerated by the growing use of Liquefied Natural Gas (LNG), which is made by cooling natural gas to around -162°C. Under these conditions, natural gas becomes liquid, with an energy density 600 times that of gas at standard temperature and pressure — and it can be readily transported over long distances in specialized ocean-going Figure 2.4 Trends in Annual Global Dry Gas Production by Region between 1990 and 2009 Tcf of Gas 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 120 100 80 60 40 20 0 S. C. America Africa Europe Middle East Asia Oceania North America Eurasia Source: MIT; U.S. Energy Information Administration
  • 30. Figure 2.5 Comparison of 1990 and 2009 Natural Gas Production Levels for the Top 10 Natural Gas Producing Nations (as defined by 2009 output) 25 20 15 10 5 0 United States Russia 35 30 25 20 15 10 5 22 MIT STUDY ON THE FUTURE OF NATURAL GAS Canada Iran Norway Quatar China Algeria Netherlands Saudi Arabia 1990 2009 Tcf of Gas Source: MIT; U.S. Energy Information Administration Figure 2.6 Global Cross-Border Gas Trade 0 8.0 26.4 3.0 14.8 1993 2008 LNG Pipeline Tcf of Gas Source: MIT; U.S. Energy Information Administration
  • 31. Chapter 2: Supply 23 LNG tankers. Over this 15-year period, global gas trade doubled, while LNG trade increased even more rapidly, as shown in Figure 2.6. RESOURCES5 Global natural gas resources are abundant. The mean remaining resource base is estimated to be 16,200 Tcf, with a range between 12,400 Tcf (with a 90% probability of being exceeded) and 20,800 Tcf (with a 10% probability of being exceeded). The mean projection is 150 times the annual consumption in 2009. With the exception of Canada and the U.S., this estimate does not include any unconventional supplies. The global gas supply base is relatively imma-ture; outside North America only 11% of the estimated ultimately recoverable conventional resources have been produced to date. Figure 2.7 depicts the estimated remaining recoverable gas resources, together with esti-mated uncertainty,6 broken down by regions as defined by the Emissions Prediction and Policy Analysis (EPPA) model employed in Chapter 3 of this report. Figure 2.8 depicts the geographi-cal distribution of EPPA regions, together with the mean resource estimate for each region. The resources are comprised of three major components defined above: reserves, reserve growth and yet-to-find resources. For the U.S. and Canada, we have also included a fourth category, unconventional resources. As discussed later, due to the very high levels of uncertainty at this stage, we have not included unconven-tional resource estimates for other regions. Figure 2.7 Global Remaining Recoverable Gas Resource by EPPA Region, with Uncertainty Total Reserves 0 1,000 2,000 3,000 4,000 5,000 6,000 Tcf of gas Middle East Russia United States Africa Central Asia and Rest of Europe Canada Rest of Americas EU27 and Norway Dynamic Asia Brazil Rest of East Asia Australia and Oceania China Mexico India Source: MIT analysis based on data and information from: Ahlbrandt et al. 2005; United States Geological Survey 2010; National Petroleum Council 2003; United States Geological Survey n.d.; Potential Gas Committee 1990; Attanasi Coburn 2004; Energy Information Administration 2009 1.0 0.8 0.6 0.4 0.2 0.0 Reserve Growth (Mean) Conventional Undiscovered Gas (Mean) Unconventional Gas (Mean) Low High RRR RRR
  • 32. Although resources are large, the supply base is concentrated geographically, with an estimated 70% in only three regions: Russia, the Middle East (primarily Qatar and Iran) and North America (where North American resources also include unconventional gas). By some measures, global supplies of natural gas are 24 MIT STUDY ON THE FUTURE OF NATURAL GAS even more geographically concentrated than oil supplies. Political considerations and individual country depletion policies play at least as big a role in global gas resource development as geology and economics, and dominate the evolution of the global gas market. Figure 2.8 Map of EPPA Regions, and Mean Resource Estimates Middle East [4670 TCF] Russia [3410 TCF] United States [2150 TCF] Africa [1050 TCF] Eastern Europe and Central Asia [940 TCF] Rest of East Asia [240 TCF] Austria and Oceania [225 TCF] China [210 TCF] India/Mexico [95/50 TCF] Japan [~0 TCF] Canada [820 TCF] Rest of Americas [800 TCF] EU27 and Norway [720 TCF] Dynamic Asia [480 TCF] Brazil [350 TCF] Source: EPPA, MIT
  • 33. Chapter 2: Supply 25 SUPPLY COSTS7 Figure 2.9 depicts a set of global supply curves, which describe the resources of gas that can be developed economically at given prices at the point of export. The higher the price, the more gas will ultimately be developed. Much of the global supply can be developed economically with relatively low prices at the wellhead or the point of export.8 However, the cost of delivering this gas to market is generally considerably higher. In contrast to oil, the total cost of delivering gas to international markets is strongly influenced by transportation costs, either via long-distance pipeline or as LNG. Transportation costs will obviously be a function of distance, but by way of illustration, resources that can be economically developed at a gas price of $1 or $2/million British thermal units (MMBtu) may well require an additional $3 to $5/MMBtu of transport costs to get to their ultimate destination. These high transportation costs are also a significant factor in the evolution of the global gas market. Figure 2.10 depicts the mean gas supply curves for those EPPA regions that contain significant gas resources. Again, this illustrates the significant concentration of gas resources in the world. In contrast to oil, the total cost of getting gas to international markets is strongly influenced by the cost of transportation — a significant factor in the evolution of the global gas market. Figure 2.9 Global Gas Supply Cost Curve, with Uncertainty; 2007 Cost Base Breakeven gas price at point of export: $/MMBtu 20.00 18.00 16.00 14.00 12.00 10.00 8.00 6.00 4.00 2.00 0 Example LNG value chain costs incurred during gas delivery $/MMBtu Liquefaction $2.15 Shipping $1.25 Regasi!cation $0.70 Total $4.10 Volumetric uncertainty around mean of 16,200 Tcf 0 3,000 6,000 9,000 12,000 15,000 18,000 Tcf of gas Low Mean High 20000 15000 1.0 0.8 0.6 0.4 0.2 0.0 Low 12,400 High 20,800 Source: MIT; ICF Global Hydrocarbon Supply Model
  • 34. 0 500 1,000 1,500 2,000 2,500 3,000 3.500 4,000 4,500 5,000 UNCONVENTIONAL RESOURCES9 Outside of Canada and the U.S., there has been very little development of the unconventional gas supply base — indeed there has been little need when conventional resources are so abundant. But due to this lack of development, unconventional resource estimates are sparse and unreliable. Based on an original estimate by Rogner10, there may be of the order of 24,000 Tcf of unconventional GIIP outside North America. Applying a nominal 25% recovery factor, this would imply around 6,000 Tcf of unconven-tional recoverable resources. However, these global estimates are highly speculative, almost completely untested and subject to very wide bands of uncertainty. There is a long-term need for basin-by-basin resource evaluation to provide credibility to the GIIP estimates and, most importantly, to establish realistic estimates of recoverable resource volumes and costs11. 26 MIT STUDY ON THE FUTURE OF NATURAL GAS Given the concentrated nature of conventional supplies and the high costs of long-distance transportation, there may be considerable strategic and economic value in the development of unconventional resources in those regions that are currently gas importers, such as Europe and China. It would be in the strategic interest of the U.S. to see these indigenous supplies developed. As a market leader in this technol-ogy, the U.S. could play a significant role in facilitating this development. RECOMMENDATION U.S. policy should encourage the strategic development of unconventional gas supplies in regions which currently depend on imported gas, in particular, Europe and China. $20.00 $15.00 $10.00 $5.00 $0 Africa Australia and Oceania Brazil China Dynamic Asia Europe India Mexico Middle East Rest of Americas Rest of East Asia Rest of Europe and Central Asia Russia Breakeven Gas Price $MMBtu Africa Australia and Oceania Brazil China Dynamic Asia Europe India Mexico Middle East North America Rest of Americas Rest of East Asia Rest of Europe and Central Asia Russia Figure 2.10 Global Gas Supply Cost Curve by EPPA Region; 2007 Cost Base Source: MIT; ICF Global Hydrocarbon Supply Model
  • 35. Chapter 2: Supply 27 UNITED STATES SUPPLY Production Trends There is significant geographical variation in U.S. natural gas production levels. For the purposes of this discussion of U.S. production, we will use the U.S. EIA pipeline regions (Figure 2.11). Natural gas production in the U.S. has tradi-tionally been associated with the Southwest region and the Gulf of Mexico. However, significant production also takes place in Alaska and in the Central region. In the case of Alaska, the vast majority of the gas is associated with oil production on the North Slope, and due to the lack of an export mechanism, this gas is re-injected to enhance recovery from Alaskan oil fields. These gas production volumes are therefore not included in the national gas production figures reported by the EIA. Small volumes of gas are exported from Alaska to Japan as LNG. Figure 2.12 illustrates the regional breakdown of dry natural gas production in the U.S. since 2000. Some level of production occurs in all eight regions, but the dominance of the Southwest, Gulf of Mexico and Central regions is clearly shown. The dynamics of the produc-tion levels across these major regions have differed appreciably over the past decade. In the Southwest, the largest gas producing region, annual production levels remained relatively flat at about 9.3 Tcf from 2000 to 2005. Since 2005, output from the region has increased, growing by 21% to 11.4 Tcf in 2008. Much of this growth in the latter half of the decade is the result of rapid expansion in the production of gas from shale plays. Figure 2.11 EIA Natural Gas Pipeline Regions for the L48 States; the State of Alaska and the U.S. Offshore Territory in the Gulf of Mexico Form Two Additional Regions Central WA Western MT ND SD NM AR Southwest Midwest Northeast NC Southeast ME VT NH MA RI CT DE PA NY NJ WV MD VA MN WI MI OH IL IN KY SC TN MS AL GA FL LA OK TX IA KS MO NE WY UT CO OR ID AZ CA NV Source: U.S. Energy Information Administration
  • 36. Figure 2.12 Regional Breakdown of Annual Dry Gas Production in the U.S. between 2000 and 2009 Tcf of Gas 22 20 18 16 14 12 10 8 6 4 2 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 Since 2000, the Central region has seen the greatest percentage growth in production among U.S. regions. Annual dry gas output has risen from 2.6 Tcf to 4.5 Tcf, an overall increase of 75%. Unlike the Southwest region, produc-tion from the Central region has grown con-tinuously since 2000, with output increasing from all resource types. In marked contrast, gas output from offshore fields in the Gulf of Mexico has fallen dramatically from approxi-mately 5 Tcf in 2000 to 2.4 Tcf in 2008, the result of fewer new wells being brought online in the Gulf to replace those older wells that are now in decline or have been taken off produc-tion. This decline is an indication of the maturity of the conventional resource base in the Gulf of Mexico. 28 MIT STUDY ON THE FUTURE OF NATURAL GAS PRODUCTION TRENDS BY RESOURCE TYPE IN THE UNITED STATES In a global context, U.S. gas production by type is extremely diverse. Both conventional and unconventional gas output is significant, with the contribution of unconventional gas growing steadily year-on-year. Figure 2.13a plots contributions to production from conventional, unconventional and associated gas. This breakdown illustrates the marked shift towards unconventional resources that has been a feature of gas production in the U.S. over the past decade and more. In 2000, the combined gross production of conventional and associated gas in the L48 states was 14.6 Tcf (71% of total output). By 2009, the combined conventional and associated output had fallen to 11.4 Tcf (52% of the total). In concert with this fall in conventional and associated gas production, there has been continuous expan-sion in the production of unconventional gas, with approximately 4.5 Tcf more unconven-tional gas being produced in 2009 than in 2000. Source: MIT; U.S. Energy Information Administration Western Southwest Southeast Northeast Midwest GOM Central Alaska
  • 37. Chapter 2: Supply 29 Tcf of Gas 1% 7% 21% Shale 16% 25% CBM Tight Associated Conventional 14% 9% 11% 2001 2003 2005 2007 2009 2000 2009 25 20 15 10 5 Historically, tight gas has been the most signifi-cant source of unconventional gas production in the U.S., and is likely to remain so for some time. Tracking tight gas production can be difficult because it can exist in a continuum with conventional gas. However, a review of output from known tight plays shows a growth in annual output from 4.5 Tcf to 5.6 Tcf between 2000 and 2009, an increase from 21% to 25% of total gross production as shown in Figure 2.13b. Commercial production of CBM began at the end of the 1980s, and grew sub-stantially during the 1990s from an output of 0.2 Tcf in 1990 to 1.3 Tcf in 1999. This growth moderated during the last decade, with 2009 CBM output standing at 1.92 Tcf or 9% of the total. Aside from the fall in conventional production, the most striking feature of the gas production in the U.S. this past decade has been the emergence of shale gas. Although shale resources have been produced in the U.S. since 1821, the volumes have not been significant. This situation changed fundamentally during the past decade as technological advances enabled production from shales previously considered uneconomical. Expansion in shale gas output is illustrated in Figures 2.13a and 2.13b. From 2000 to 2009, the contribution of shale gas to overall production grew from 0.1 Tcf, or less than 1%, to 3.0 Tcf, or nearly 14%. This growth is all the more remarkable in that 80% of it was driven by one play, the Barnett shale, located in Texas’ Fort Worth Basin. Activity in other shale plays has also been increasing, with appreciable volumes now being produced from the Fayetteville and Woodford shales in the Arkoma Basin, the Haynesville shale in the East Texas Basin and as of the end of 2009, the Marcellus shale in the Appalachian Basin. Figure 2.13a Breakdown by Type of Annual Gross Gas Production in the L48 U.S. between 2000 and 2009 Figure 2.13b Percentage Breakdown by Type of Gross Gas Production in the L48 U.S. in 2000 and 2009 Source: MIT; HPDI production database 55% 41% 0
  • 38. U.S. RESOURCES12 Table 2.1 illustrates mean U.S. resource esti-mates from a variety of resource assessment authorities. These numbers have tended to grow over time, particularly as the true poten-tial of the unconventional resource base has started to emerge over the past few years. For this study, we have assumed a mean remaining resource base of around 2,100 Tcf. This corresponds to approximately 92 times the annual U.S. consumption of 22.8 Tcf in 2009. We estimate the low case (with a 90% probabil-ity of being met or exceeded) at 1,500 Tcf, and the high case (with a 10% probability of being met or exceeded) at 2,850 Tcf. Table 2.1 Tabulation of US Resource Estimates by Type, from Different Sources 30 MIT STUDY ON THE FUTURE OF NATURAL GAS Around 15% of the U.S. resource is in Alaska, and full development of this resource will require major pipeline construction to bring the gas to market in the L48 states. Given the abundance of L48 supplies, development of the pipeline is likely to be deferred yet again, but this gas represents an important resource for the future. In the L48, some 55% to 60% of the resource base is conventional gas, both onshore and offshore. Although mature, the conventional resource base still has considerable potential. Around 60% of this resource is comprised of proved reserves and reserve growth, with the remainder — of the order of 450 to 500 Tcf — from expected future discoveries. NPC USGS/MMS PGC ICF (2003) (Various Years) (2006) (2008) (2009) L48 Conventional 691 928 966 869 693 Tight 175 190 174 Shale 35 85 616 631 CBM 58 71 108 99 65 Total L48 959 1,274 1,074 1,584 1,563 Alaska Conventional 237 357 194 194 237 Tight – – Shale – – – – CBM 57 18 57 57 57 Total Alaska 294 375 251 251 294 U.S. Conventional 929 1,284 1,160 1,063 930 Tight 175 190 174 Shale 35 85 616 631 CBM 115 89 165 156 122 Total U.S. 1,254 1,648 1,325 1,835 1,857 Proved Reserves 184 245 204 245 245 Total (Tcf) 1,438 1,893 1,529 2,080 2,102 Source: National Petroleum Council 2003; United States Geological Survey 2010; Minerals Management Service 2006; Potential Gas Committee 2007; Potential Gas Committee 2009; Energy Information Administration 2009
  • 39. Figure 2.14b Breakdown of Mean U.S. Gas Supply Curve by Type; 2007 Cost Base Conventional Tight Shale CBM 0 100 200 300 400 500 600 700 800 900 1,000 Source: MIT; ICF North American Hydrocarbon Supply Model Source: MIT; ICF North American Hydrocarbon Supply Model Chapter 2: Supply 31 Figure 2.14a Volumetric Uncertainty of U.S. Gas Supply Curves; 2007 Cost Base Breakeven Gas Price $/MMBtu Low Mean High 0 500 1,000 1,500 2,000 2,500 3,000 Figure 2.14a represents the supply curves for the aggregate of all U.S. resources, depicting the mean estimate and the considerable range of uncertainty. Figure 2.14b illustrates the mean supply curves, broken down by resource type. It clearly shows the large remaining conventional resource base, although it is mature and some of it will require high gas prices to become eco-nomical to develop. These curves assume current 1.0 0.8 0.6 0.4 0.2 technology. In practice, future technology development 3000 will enable these costs to be driven down over time, allowing a larger portion of the resource base to be economically developed. 2500 Figure 2.14b also demonstrates the consider-able potential 2000 of shale supplies. Using a 2007 cost base, a substantial portion of the estimated shale resource base is economic at prices 1500 between $4/MMBtu and $8/MMBtu. As we see in the current U.S. gas markets, some of the shale resources 1000 will displace higher-cost con-ventional gas in the short to medium term, exerting downward pressure on gas prices. Breakeven Gas Price $/MMBtu 40.00 36.00 32.00 28.00 24.00 20.00 16.00 12.00 8.00 4.00 0 Despite the relative maturity of the U.S. gas 1.0 supply, estimates 0.8 of remaining resources have 0.6 continued to grow 0.4 over time — with an acceler-ating 0.2 trend in recent years, mainly attributable to unconventional gas, especially in the shales. The PGC, which evaluates the U.S. gas resource on a biannual cycle, provides perhaps the best historical basis for looking at resource growth over time. According to this data, remaining resources have grown by 77% since 1990, 1200 despite a cumulative production volume during that time of 355 Tcf. 1000 As a subset of this growth process, the appli-cation of horizontal 800 drilling and hydraulic fracturing technology to the shales has caused resource estimates to grow over a five-year period from a relatively minor 35 Tcf (NPC, 2003), to a current estimate of 615 Tcf (PGC, 2008), with a range of 420 to 870 Tcf. This 40.00 36.00 32.00 28.00 24.00 20.00 16.00 12.00 8.00 4.00 0 Tcf of gas 500 0 0.0 Don’t Use This One, has all data, real one is on “chart to cut” Tcf of gas 600 400 200 0 0.0 Don’t Use This One
  • 40. resource growth is a testament to the power of technology application in the development of resources, and also provides an illustration of the large uncertainty inherent in all resource estimates. According to Potential Gas Committee data, U.S. natural gas remaining resources have grown by 77% since 1990, a testament to the power of technology, and an illustration of the large uncertainty inherent in all resource estimates. The new shale plays represent a major contribution to the resource base of the U.S. However, it is important to note that there is considerable variability in the quality of the resources, both within and between shale plays. Production Rate Mcf/day (30-day average) 1.0 0.8 0.6 0.4 0.2 32 MIT STUDY ON THE FUTURE OF NATURAL GAS This variability in performance is incorporated in the supply curves on the previous page, as well as in Figure 2.15. Figure 2.15a shows initial production and decline data from three major U.S. shale plays, illustrating the substantial differences in average well performance between the plays. Figure 2.15b shows a prob-ability distribution of initial flow rates from the Barnett formation. While many refer to shale development as more of a “manufacturing process,” where wells are drilled on a statistical basis — in contrast to a conventional explora-tion, development and production process, where each prospective well is evaluated on an individual basis — this “manufacturing” still occurs within the context of a highly variable subsurface environment. Figure 2.15a Illustration of Variation in Mean Production Rates between Three Shale Plays 9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000 0 Year Haynesville Marcellus Barnett 0 1 2 3 4 5 0.0 Figure 2.15b Illustration of Variation in Initial Production Rates of 2009 Vintage Barnett Wells IP Rate Probability (Barnett 2009 Well Vintage) 0.12 0.10 0.08 0.06 0.04 0.02 0 0 1,000 2,000 3,000 4,000 5,000 IP Rate Mcf/day (30-day avg) IP Rate Probability (Barnett ’09 Well Vintage) 1.0 0.8 0.6 0.4 0.2 0.0 Source: MIT analysis; HPDI production database and various industry sources Source: MIT analysis; HPDI production database and various industry sources
  • 41. Chapter 2: Supply 33 This high level of variability in individual well productivity clearly has consequences with respect to the variability of individual well economic performance.13 This is illustrated in Table 2.2, which shows the variation in break-even gas price as a function of initial productiv-ity for the five major U.S. shale plays. The P20 30-day initial production rate represents the rate that is equaled or exceeded by only 20% of the wells completed in 2009; the P80 represents the initial rate equaled or exceeded by 80% of completed wells. Another major driver of shale economics is the amount of hydrocarbon liquid produced along with gas. The results in Table 2.2 assume dry gas with no liquid co-production; however, some areas contain wet gas with appreciable amounts of liquid, which can have a consider-able effect on the breakeven economics — par-ticularly if the price of oil is high compared to the price of gas. The liquid content of a gas is often measured in terms of the “condensate ratio,” expressed in terms of barrels of liquid per million cubic feet of gas (bbls/MMcf). Figure 2.16 shows the change in breakeven gas price for varying condensate ratios in a typical Marcellus well,14 assuming a liquids price of $80/bbl. It can be seen that for a condensate ratio in excess of approximately 50 bbls/MMcf in this particular case, the liquid production alone can provide an adequate return on the investment, even if the gas were to realize no market value. Table 2.2 Full-Cycle 2009 Well Vintage P20, P50 and P80 30-Day Average Initial Production (IP) Rates and Breakeven Prices (BEP) for Each of the Major U.S. Shale Plays Assuming Mid Case Costs Barnett Fayetteville Haynesville Marcellus Woodford IP BEP IP BEP IP BEP IP BEP IP Mcf/d $/Mcf Mcf/d $/Mcf Mcf/d $/Mcf Mcf/d $/Mcf Mcf/d BEP $/Mcf P20 2700 $4.27 3090 $3.85 12630 $3.49 5500 $2.88 3920 $4.12 P50 1610 $6.53 1960 $5.53 7730 $5.12 3500 $4.02 2340 $6.34 P80 860 $11.46 1140 $8.87 2600 $13.42 2000 $6.31 790 $17.04 Source: MIT analysis

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