Description
Prudent development of North American crude oil and natural gas resources should begin with a reliable understanding of the resource base, particularly as that understanding has changed significantly in recent years. It had been widely assumed for decades that natural gas and oil production potential in North America was in terminal decline.
CHAPTER 1 - RESOURCES AND SUPPLY 43
Abstract
Prudent development of North American crude
oil and natural gas resources should begin with
a reliable understanding of the resource base,
particularly as that understanding has changed
signifcantly in recent years. It had been widely
assumed for decades that natural gas and oil pro-
duction potential in North America was in termi-
nal decline. Tis belief was shared by governments,
the public, and even the oil and gas industry, and it
was one of the main flters through which energy
supply and security issues were examined. To
support this view, many observers referred to the
Hubbert curve* delineating resource depletion, a
theory that was frst demonstrated by analyzing
conventional oil production in the United States.
On the natural gas side, the perception of immi-
nent declining supply led to expectations that
North America would soon be importing lique-
fed natural gas (LNG) to meet domestic demand,
and thus to the construction of several new LNG
regasifcation and import terminals in the United
States and Canada.
However, the widespread deployment of recent
advances in drilling and completion technologies,
in particular horizontal drilling and multi-stage
hydraulic fracturing, have dramatically changed
the outlook and prospects for North American
natural gas and oil supply potential. Tis chapter
describes the revised potential for North Ameri-
can gas and oil supply, identifes the technology
innovations responsible for expanding resource
potential, and examines the implications for
resource development. It sets out recent ranges
of assessments of the natural gas and oil recov-
erable resource base in the United States and
Canada, and looks at how these resources may be
prudently developed, leading to productive capac-
ity potential, depending on choices made in three
areas: (1) access and regulatory regimes; (2) sus-
tained technology development; and (3) success in
managing environmental impact and risk, within
the context of whether the size of oil and natural
gas resources is near the high or low end of cur-
rent understanding.
Te outline of the Resource and Supply chapter
is as follows:
y Summary and Key Findings
y North American Oil and Natural Gas Resources
y Analysis of North American Oil and Natural Gas
Resource and Production Outlooks
y Prospects for North American Oil Development
y Prospects for North American Gas Develop-
ment
y North American Oil and Natural Gas Resource
Development Prospects to 2050.
Chapter One
Cuuoe Ott nNo Nniuunt Gns
Resouuces nNo Suvvtv
* Te Hubbert curve was frst proposed by geologist M. King
Hubbert in a 1956 paper for the American Petroleum Insti-
tute. It hypothesizes that fossil fuel production follows
a symmetrical bell-shaped curve, with peak production
occurring when about 50% of the estimated ultimate recov-
erable resource has been produced. Tis approach correctly
predicted the peak of U.S. conventional oil production
around 1970 but has proved less reliable in other geogra-
phies and for other hydrocarbon resource types.
44 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
INTRODUCTION AND SUMMARY
Summarics and Kcy Findings
Supply Summary
Te North American crude oil and natural gas
resource and supply system is a complex network that
includes several major components: (1) the natural
endowments or physical store of oil and/or natural
gas in the subsurface; (2) the commercial quantities
of crude oil and natural gas that can be produced from
the overall subsurface source rock using known or
expected technologies; (3) access to oil and natural
gas resources through drilling wells or surface mining;
and (4) the physical network of crude oil and natural
gas pipelines to transport crude oil and natural gas
to refneries and natural gas processing centers and
to end-use consumers. Included in this chapter is an
evaluation of the principal types of crude oil and natu-
ral gas supply within the United States and Canada, as
well as those new areas of oil and natural gas resource
types that could become available for development
and production by the middle of this century. Tese
include:
y Arctic oil and natural gas (United States, Canada,
and Greenland)
y Ofshore United States and Canadian oil and natu-
ral gas (non-Arctic)
y Onshore natural gas (including conventional and
unconventional sources)
y Onshore conventional oil (including enhanced oil
recovery [EOR] operations and opportunities)
y Unconventional oil (including Canadian and U.S. oil
sands, oil shale, and tight oil)
y Methane hydrates.
(Tis study does not include a detailed review of
oil and gas resource and development potential in
Mexico, although hydrocarbon prospects in that
country are described in a topic paper that is avail-
able on the National Petroleum Council (NPC) web-
site [www.npc.org] and briefy summarized later in
this chapter. Mexico is geographically part of North
America and is recognized as an important crude
oil supplier to the United States as well as a current
importer from the United States of approximately
1 billion cubic feet per day [Bcf/d] of natural gas.)
Te principal focus of this analysis is the United
States and Canada. Both countries are major oil and
natural gas producers with very signifcant future oil
and gas supply potential. Tis chapter describes and
analyzes the infrastructure systems that make these
resources available to markets. It covers the cur-
rent situation as well as a framework for developing
infrastructure needs over the next several decades.
For natural gas, the infrastructure system includes
feld gathering systems, gas processing facilities, gas
storage felds, and long distance high-capacity trans-
mission pipelines. Natural gas liquids infrastruc-
ture is also discussed, given the potential for growth
in liquids, such as ethane, propane, and butane,
extracted from produced natural gas. Tis study
does not report on local utility distribution pipeline
systems that deliver natural gas to residential, com-
mercial, and industrial customers. In the case of oil,
infrastructure to transport produced crude oil from
production areas to refneries is also assessed. Te
parallel NPC study on Future Transportation Fuels,
referred to in the Preface, will assess refnery capac-
ity, upgrading, and downstream infrastructure for
refned products, which are not within the scope of
this study.
Environmental questions related to oil and natu-
ral gas production and transportation are discussed
in detail in Chapter Two, Operations and Environ-
ment, although their critical importance to enabling
the development of supply potential in most areas is
described here.
Data Sourccs
Multiple data and analysis sources inform this
chapter. It relies frst on existing, publicly available
studies to compare and contrast resource estimates
and production views to 2050. In addition, the
Resource & Supply Task Group conducted a confden-
tial survey of proprietary outlooks, primarily from oil
and gas companies and specialized energy consulting
groups, to add additional breadth and depth to the
source material. Details include:
y Public Data. Approximately 50 publicly available
energy outlooks from government, industry, and
consultant sources were examined. Te U.S. and
Canadian governments provided integrated energy
outlooks – e.g., the Energy Information Adminis-
tration (EIA), the National Energy Board of Canada
(NEB), the International Energy Agency (IEA), the
CHAPTER 1 - RESOURCES AND SUPPLY 45
Figure 1-1. North American Natural Gas Resources Can Meet Decades of Demand
United States Geologic Survey (USGS), and the
Bureau of Ocean Energy Management, Regulation
and Enforcement (BOEMRE).
y Proprictary Data. More than 80 energy and con-
sultant companies received a request to complete
a comprehensive resource, production, and supply
chain survey. More than 25 industry and consul-
tant templates were returned. Te public account-
ing frm Argy, Wiltse & Robinson, P.C. received,
aggregated, and protected the proprietary data
responses. Te aggregation resulted in 12 unique
outlook cases.
Rcsourcc Summary
Natural gas resource assessments have recently
increased as a result of technologies that can produce
gas economically from source rock (such as tight gas,
shale gas, and coalbed methane) in ways previously
not feasible (the so-called “shale gas revolution”).
Although these sources of natural gas have been
known for many years, the application of certain
technologies, including drilling horizontal wells and
hydraulic fracturing, has enabled resource assess-
ments to include much higher volumes of gas in
the technically recoverable categories. Tis change,
above all, has transformed the outlook for natural
gas supply in North America from one of declining
domestic supply and increasing imports, to one of
abundant supply from within the region for decades
to come, most likely at moderate cost.
A 2011 Massachusetts Institute of Technology
(MIT) study on North American natural gas analyzes
the range and cost of natural gas resources. Te MIT
study lays out a number of diferent cases based on
various assumptions, from which this study has
chosen three to illustrate the sustainability of the
resource at current or greatly expanded market size.
Tese cases are summarized in Figure 1-1, where the
horizontal axis shows total ultimately recoverable
natural gas resources, under the three cases, and the
vertical axis shows wellhead cost of supply (not to
be confused with the market price of natural gas, in
which many other factors come into play). Te three
cases featured here are the mean resource estimate
with current technology (in green), the mean resource
estimate with advanced technology (in blue), and the
high resource estimate with advanced technology
3
6
8
4
10
0 1,000 2,000 3,000
W
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Figure 1-1. North American Natural Gas Resources Can Meet Decades of Demand
ALSO used as Fig. ES-3
RANGE OF
CUMULATIVE
DEMAND
2010–2035
TRILLION CUBIC FEET
LOW
DEMAND
HIGH
DEMAND
Notes: The vertical axis represents estimated wellhead cost of supply. The cost of supply can vary over time and place, in light of
diferent regulatory conditions, diferent technological developments and deployments, and other diferent technical
conditions. In none of these cases is “cost of supply” to be interpreted as an indicator of market prices or trends in market
prices, since many factors determine prices to consumers in competitive markets.
MIT = Massachusetts Institute of Technology.
Source of MIT information: The Future of Natural Gas: An Interdisciplinary MIT Study, 2011.
MIT MEAN RESOURCE CASE
MIT ADVANCED TECHNOLOGY CASE
MIT HIGH RESOURCE TECHNOLOGY CASE
46 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
(in red). Because these technologies were viewed as
advanced when the MIT study was developed but are
now considered standard by the industry, they do not
take into account future technology improvements.
Figure 1-2 highlights a number of natural gas
resource assessments from more than a decade and
clearly shows the diference between estimates before
and after unconventional gas began to be understood
in the mid-2000s. Over an even longer period, it has
been generally observed that oil and natural gas recov-
erable resource estimates tend to increase.
Te range of future technically recoverable natu-
ral gas resources used here is between 1,900 and
3,600 trillion cubic feet (Tcf), representing about 25%
of global natural gas resources. Tis does not include
potentially vast resources of methane hydrates pres-
ent in the Gulf of Mexico and in the North American
Arctic, some of which could become economically
producible in the 2035–2050 time frame if develop-
ment of technologies for production and environmen-
tal impact management is successful.
North America is home to world-class crude oil
resources in several diferent basins and plays.
Te mean undiscovered technically recoverable oil
resources potential in the U.S. lower-48 ofshore is
estimated at nearly 60 billion barrels, of which pro-
duction has only begun in one area, the central and
western zones of the Gulf of Mexico, with scope for
signifcant further development in other ofshore
zones. Te Arctic, another world-class resource area,
contains an estimated 100 billion barrels of recov-
erable oil (and an additional equivalent amount in
recoverable natural gas). Te Alberta oil sands have a
recoverable oil potential of more than 300 billion bar-
rels. Tese resources are relatively concentrated, but
onshore conventional oil also has signifcant recover-
able oil resources, estimated at close to 80 billion bar-
rels, not including the potential for tens of billions
of barrels present in low saturation and residual oil
zones. Recent growth in unconventional “tight oil”
production has highlighted a short to medium term
resource that could be as high as 34 billion barrels.
In the long term, oil shale plays, such as those in the
Green River formation in Colorado, Utah, and Wyo-
ming, are known to have an enormous amount of
kerogen-rich oil shale deposits. Developing new com-
mercially viable technology that heats the kerogen oil
shale to produce recoverable oil could yield producible
resources estimated at 800 billion barrels.
Production Potcntial
Te United States and Canada are signifcant pro-
ducers of both natural gas and crude oil, among the
top world producing countries. Te United States
now surpasses Russia as the top natural gas producer
in the world, as can be seen in Figure 1-3. Canada and
the United States together now produce over 40%
more gas than Russia and provide 25% of global gas
supply. (Since the North American market represents
about 25% of global gas demand, the region can now
be considered self-sufcient in natural gas, unlike
other major gas-consuming economies around the
world, such as Western Europe, Japan, and China).
Te United States and Canada also produce
crude oil at a globally signifcant scale. As shown in
Figure 1-4, the United States is the third largest pro-
ducer, behind Russia and Saudi Arabia. Te U.S. and
Canada together now produce 10.5 million barrels
per day, or about 4% more oil than Russia. Figure 1-4
shows the positions of the United States and Canada
among the top producers. Mexico also features promi-
nently in this list, although this study does not detail
Mexican oil production prospects. “Oil” as represented
in this chart includes crude oil, condensate, and natu-
ral gas liquids.
Success in achieving production levels of this mag-
nitude has been built over many years of developing
technologies, exploring new plays and improving
operating practices, and has created a strong platform
for enhanced production potential during the next
several decades. However, the oil and natural gas
industry must adhere to sound risk mitigation and
prudent environmental management practices and
the marketplace must be allowed to function within a
framework of appropriate access and regulation.
Making Rcscrvc Dcvclopmcnt Choiccs
Tis study has examined the potential for resource
development and production potential from all the
identifed major current and future sources of natu-
ral gas and oil production in North America. Te
objective was to identify the level of production that
could be achieved by 2035, in a high potential envi-
ronment in which: (1) reasonable resource access
will be available; (2) appropriate regulation will be
applied; (3) industry will continue improvements
in production and environmental operating prac-
tices; and (4) there will be sustained research and
CHAPTER 1 - RESOURCES AND SUPPLY 47
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48 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-4. United States and Canada Are Among Leading Oil Producers
M
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Figure 1-4. United States and Canada Are among Leading Oil Producers
WAS Figure ES-4
Source: BP Statistical Review of World Energy.
RUSSIA SAUDI
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EMIRATES
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Figure 1-3. United States and Canada Are Among Leading Natural Gas Producers
Figure ES-1. United States and Canada Are Among Leading Natural Gas Producers
0
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USA RUSSIA CANADA IRAN NORWAY QATAR CHINA ALGERIA SAUDI
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INDONESIA
Source: BP Statistical Review of World Energy.
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CHAPTER 1 - RESOURCES AND SUPPLY 49
development of new technologies and techniques to
support development of additional resources that
will become available over the long term (such as
oil shale and methane hydrates).
Tis high potential is then contrasted with a lim-
ited production potential over the same time frame,
should resource development be subject to con-
straints, including lack of access, increased regula-
tory barriers, lower resource potential, or lack of
technology-related research and development. Nei-
ther of these extremes represents the most likely out-
come, which is likely to be a point between the two.
Te limited and high potential cases show the impact
of resource development choices made in investment
and public policy.
Te range of oil supply potential in the United
States and Canada for each signifcant supply source
is shown in Figure 1-5, compared with that source’s
production in 2010.
For both crude oil and natural gas, the end points
for the range of potential for each resource type are
not intended to be additive, since both market needs
and investment focus will determine the actual mix
of resource development. Te ranges indicate which
supply sources can have the most impact over the
time frame covered by this study, and which could be
most afected by the choices made in either the con-
strained or unconstrained cases.
North American oil production growth potential can
come from a number of sources, including Canadian
oil sands, the U.S. ofshore (including the Gulf of Mex-
ico), tight oil, EOR, Arctic exploration and oil shale (in
that order of scope and development lead time). Te
point – and the opportunity – is that further develop-
ment of these sources could lead to lower overall future
declines in total U.S. and Canadian oil production.
Potential for growth of these sources is summa-
rized as follows:
y Arctic oil has the scope to grow from a level of about
0.6 million barrels per day to a range of 0.3–0.9 mil-
lion barrels per day by 2035 and considerable scope
for further expansion post-2035.
y Ofshore, non-Arctic U.S. and Canadian oil pro-
duces about 1.8 million barrels per day and could
produce between 1.8 and 2.3 million barrels per day
Figure 1-5. More Resource Access and Technology Innovation
Could Substantially Increase North American Oil Production
2010 2035 LIMITED 2035 HIGH POTENTIAL
ONSHORE CONVENTIONAL
OFFSHORE
ARCTIC
NATURAL GAS LIQUIDS OIL SANDS
TIGHT OIL
OIL SHALE
UNCONVENTIONAL OIL
{
}
0
10
20
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
Figure 1-5. More Resource Access and Technology Innovation Could Substantially Increase
North American Oil Production
ALSO used as Figure ES-6
Note: The oil supply bars for 2035 represent the range of potential supply from each of the individual supply sources and types
considered in this study. The specifc factors that may constrain or enable development and production can be diferent for
each supply type, but include such factors as whether access is enabled, infrastructure is developed, appropriate
technology research and development is sustained, an appropriate regulatory framework is in place, and environmental
performance is maintained.
Source: Historical data from Energy Information Administration and National Energy Board of Canada.
50 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
by 2035, depending on choices made to expand
access and lease availability to new ofshore zones
and on the pace of technology development.
y Onshore, non-Arctic conventional oil in the United
States and Canada contributes about 3.4 million
barrels per day. Access, technology and availabil-
ity of CO
2
for EOR are key factors that could lead
to a decline to around 1.5 million barrels per day
by 2035 or an expansion to over 4 million barrels
per day by 2035, with these factors also playing
into longer term potential.
y Unconventional oil has several categories; each is
at a diferent stage of development.
? Te largest unconventional oil production
comes from the Canadian oil sands in Alberta.
Tese produce about 1.5 million barrels per
day and by 2035 could reach between 3 and 6
million barrels per day, depending on the pace
of development as infuenced by access, the
regulatory environment, and technology and
supply chain issues.
? Heavy oil in Canada is a mature resource that
produces about 0.4 million barrels per day, and
by 2035 this could decline to about 0.15 million
barrels per day or stabilize to maintain current
output levels.
? Tight oil, such as that produced in the North
Dakota/Montana Bakken play, is an emerging
resource type, which has ramped up to about
0.4 million barrels per day within the past three
or four years. Tis type of production is likely to
grow to between 2 and 3 million barrels per day,
depending on access to new plays and continued
technology development, and the pace at which
new drilling can ofset decline rates of existing
production.
? U.S. oil shale, predominantly represented
by the huge deposits identifed in the Green
River Formation in Colorado, is a longer-term
development prospect. While there have been
historical attempts at production and some
research projects have been underway in recent
years, there is no commercial production today.
It is uncertain whether this can be developed
by 2035, so its potential ranges from zero to an
upside of 1 million barrels per day within this
time frame. In a success case, this resource would
continue to grow production over a much longer
period post 2035. Development of economic
production technologies is the key requirement
for this play, with access and appropriate environ-
mental risk management also playing a key role.
? Oil sands resources also exist in the United
States, primarily in Utah, but these are not yet
developed. Tey represent somewhat diferent
challenges than the Alberta oil sands and are
signifcantly smaller, but represent another
longer-term potential prospect. By 2035, the
range of output is estimated at between zero and
0.15 million barrels per day, again with longer-
term growth prospects if initial activities are
successful.
For natural gas, the main components of supply,
current and potential, are illustrated in Figure 1-6.
Recent technology advances have enabled the
development of widespread and large-scale tight gas
and shale gas resources across North America.
Te study group estimated that between fve and
nine decades of production at moderate cost at today’s
market size is available from the resource base, as
currently understood, if production development can
continue to use critical horizontal drilling and hydrau-
lic fracturing technologies. Natural gas supply poten-
tial can be augmented and extended with improve-
ments in technologies to increase recovery factors or
new technology development to tap into new resource
types, such as methane hydrates.
Te dominant source of U.S. and Canadian natural
gas production in the near, medium, and long terms
is likely to be onshore unconventional gas, such as
tight gas, shale gas, and coalbed methane, as is cur-
rently the case. In addition, other sources can play an
important role:
y Onshore, non-Arctic gas in the United States and
Canada currently produces 24 Tcf per year. By
2035, this could grow to around 36 Tcf as required
by the market, if onshore gas development is facili-
tated by an appropriate business environment and
regulatory framework, but could decline to around
18 Tcf if development is constrained by regulatory,
access, or technology restrictions.
y Arctic gas, currently stranded because of lack of
pipelines to market, does not contribute to current
supply apart from a small quantity for local market
consumption in Alaska. Depending on whether one
or more natural gas pipelines are developed from
CHAPTER 1 - RESOURCES AND SUPPLY 51
the Alaska North Slope and the Mackenzie Delta,
the 2035 Arctic production could range from 0 to
2.7 Tcf.
y Ofshore, non-Arctic natural gas currently contrib-
utes about 1.7 Tcf, almost exclusively from the U.S.
Gulf of Mexico. Tis has declined in recent years as
the resources available from the shallow water con-
tinental shelf have matured. Looking out to 2035,
the range of potential ofshore supply is estimated
at between 2.2 and 4.8 Tcf on the high side, depend-
ing mainly on the success of new Gulf of Mexico play
types and the pace and scope of opening of access to
new ofshore zones, particularly the eastern Gulf of
Mexico and ofshore Atlantic and Pacifc zones.
Substantial methane hydrate resources have also
been identifed, particularly in the Gulf of Mexico
and portions of the Arctic. Tese could be available
for development in the long term, beginning in the
2030–2050 period, leading to production of 1–10 Tcf
per year by 2050, and with the potential for sustained
growth over the remainder of the century.
Tis domestic supply potential has completely trans-
formed the outlook for imported LNG to North Amer-
ica. LNG regasifcation capacity of about 18.5 Bcf/d
was developed at multiple locations in the United
States and Canada over the past decade with capac-
ity to supply almost one-third of current mar-
ket demand, anticipating expanded need for gas
imports. Although this capacity may not be used to
the extent foreseen, it will play a valuable role in pro-
viding fexibility of supply sources and supporting
energy security. With expanded U.S. and Canadian
supply potential, LNG export options are now being
considered.
Infrastructurc
Te 2007 NPC Hard Truths study described infra-
structure as a key link in the chain, connecting sup-
ply to markets, and found that knowledge of existing
infrastructure and planning for new infrastructure
capacity could fall short of meeting market needs.
Sufcient natural gas midstream infrastructure,
including gathering systems, processing plants, trans-
mission pipelines, storage felds, and LNG termi-
nals, is crucial for efcient delivery and functioning
markets. Insufcient infrastructure, can contribute
to price volatility, delivery bottlenecks, stranded gas
supplies, and reduced economic activity.
Figure 1-6. North American Natural Gas Production Potential
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
TIME
TECHNICAL COMPLEXITY
010
2030
3040+
1020
ONSHORE CONVENTIONAL + UNCONVENTIONAL
2010 20352050
LOW HIGH
HYDRATES
ARCTIC
OFFSHORE GULF OF MEXICO + ATLANTIC/PACIFIC
Note: North American oil and gas resource types have varying capabilities to infuence future supply requirements. This chart
demonstrates the growth potential and technical complexity required to develop each resource. Relative bubble sizes and
vertical scale indicate supply potential for each resource type in current and future views. The bubble color provides an
indication of the technical complexity required to develop each resource. While many of the resource types have growth
potential under the right regulatory and market conditions, those most likely to underpin future demand are what today are
considered “unconventional” oil and gas.
Figure 1-6. North American Natural Gas Production Potential
52 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Tis study has examined infrastructure for both
natural gas and crude oil in North America and con-
cluded that expansion and regional change in supply
sources will require new infrastructure development
over the next several decades, including more than
30,000 miles of long-distance natural gas pipelines
and up to 600 Bcf of natural gas storage capacity, a
scale of expansion that is consistent with historical
rates of system growth.
Market signals and existing regulatory structures
have been efective in bringing about appropriate
infrastructure expansions. In particular, regulatory
frameworks implemented by the Federal Energy
Regulatory Commission (FERC) in the United States
and the National Energy Board in Canada have sup-
ported expansion of natural gas storage and pipeline
systems in recent years, and should facilitate pru-
dent development of new infrastructure expansions
in the future. As these agencies do not oversee oil
pipeline permitting, developers must navigate mul-
tiple jurisdictions to construct new crude oil pipe-
lines. Permitting has usually been completed with-
out undue delay, but large-scale pipelines needed to
supply markets from new or growing supply sources
such as in Alaska or Alberta will require a more inte-
grated approach.
New infrastructure will be required to move natu-
ral gas from regions where production is expected to
grow to areas where demand is expected to increase.
Not all areas will require new gas pipeline infra-
structure, but many (even those that have a large
amount of existing pipeline capacity) may require
new investment to connect new supplies to markets.
In recent years, natural gas producers and marketers
have been the principal shippers on these new “sup-
ply push” pipelines. Tese “anchor shippers” have
been willing to commit to long-term, frm contracts
for natural gas transportation service that provide
the fnancial basis for moving forward with these
projects. Looking ahead, producers should continue
to be motivated to ensure outlets for their gas sup-
plies via pipelines. Abundant and geographically
diverse shale gas contributes to a competitive natu-
ral gas market if connected to adequate storage and
delivery systems.
A recent Interstate Natural Gas Association of
America (INGAA) Foundation study on North
American Midstream Infrastructure through 2035
found that the United States and Canada will require
annual average midstream natural gas investment of
$8.2 billion per year, or $205.2 billion (in real 2010
dollars) total, over the nearly 25-year period from
2011 to 2035 to accommodate new gas supplies, par-
ticularly from the prolifc shale gas plays, and growing
demand for gas in the power-generation sector. Tis
capital investment requirement includes mainlines,
laterals, processing, storage, compression, and gath-
ering lines.
Kcy Findings
y Tere is signifcant potential for sustained produc-
tion at current or higher levels for natural gas and
oil in the United States and Canada resulting from
recent developments in technologies and increased
understanding of the resource base. Declines in
production, expected until fairly recently, would
come as a result of policy choice, not as a conse-
quence of resource limitations. Growth is now a
real opportunity, particularly in natural gas produc-
tion. Prospects for mitigating overall oil declines
are improving and, if access for development and
delivery improves, new sources of North American
oil supply could be developed.
y Te public and policymakers need to be better
informed on the scale of resources available and
the implications to security, competitiveness, and
commercial opportunity, to help reverse the long-
standing perception that North American oil and
natural gas is in decline or unavailable for develop-
ment.
y Natural gas and oil producing plays and new supply
resource opportunities provide a rich and diverse
portfolio of options to support North American
oil and gas markets for decades to come. A port-
folio approach to resource development requires
sustaining current and near-term sources of
production, while creating the conditions for lon-
ger-term options to be exercised with technology
advances, and when environmental practices and
market conditions are right. It would be a mistake
to neglect segments of the portfolio because near-
term production from a current source is strong.
y Much higher assessments of recoverable natural
gas resources in the United States and Canada, now
totaling around 3,000 Tcf or more, have given this
region the opportunity to be largely self-sufcient
in natural gas for many years. A portfolio of options
exists, including: sustaining current large-scale
CHAPTER 1 - RESOURCES AND SUPPLY 53
gas production from the Gulf of Mexico and from
onshore conventional and unconventional gas,
while also opening access; crafting appropriate reg-
ulatory frameworks; and developing technologies
and production techniques to enable new sources of
supply, including from Arctic exploration, new of-
shore areas, and methane hydrates. Importantly,
the newly identifed large natural gas resources
appear to have a moderate cost of supply, underpin-
ning the competitiveness of natural gas with other
energy sources.
y U.S. and Canadian oil production, despite its
high levels, currently falls well short of satisfying
demand in the region. Te North American oil
supply potential discussed here does not indicate
U.S. and Canadian oil production could grow suf-
fciently to bridge this gap, unless there are also
signifcant declines in demand for oil. Energy
security considerations must, therefore, be met by
openness to trade and investment with a diversity
of crude oil producers around the world. However,
a strong portfolio of U.S. and Canadian oil develop-
ment options exists to cover current and near-term
production and long-term development prospects.
If these options are exploited, there are grounds
for optimism that North America can continue to
be a major crude oil producer to 2050 and beyond,
meeting a signifcant proportion of its market
needs. In a reasonably unconstrained case, the
United States and Canada could produce up to
15–18 million barrels per day by 2035, potentially
a much higher proportion of regional demand than
today. However, if future development were con-
strained it is likely that production would fall even
further below market needs, requiring greater
dependence on imports. Near and medium term
production potential comes from the ofshore
Gulf of Mexico, U.S. and Canadian conventional
onshore oil production, the Alberta oil sands and
the emerging production from tight oil plays. In
the medium to long term, signifcant development
options have been identifed in new ofshore areas,
the Arctic, and possibly U.S. oil shale and oil sands.
y Higher end supply potential ranges described in
this study must meet four prerequisites:
? Sound and prudent development practices that
balance responsible environmental impact risk
management and mitigation with the economic
and energy security benefts of hydrocarbon
production.
? Access to the resource, where the industry
can demonstrate that sound and prudent
development practices will be deployed in all
cases. Tis includes creating and sustaining a
framework for access in itself as well as the terms
and conditions of access such as length of leases
and other lease stipulations.
? Predictable regulatory regimes that can evolve
with advancing technology and best practices
to allow long-term investment decisions within
a predictable framework. Onshore, the federal
government should defer to robust state
regulations, recognizing that state regulators are
often more familiar with regional geology and
environmental conditions. Ofshore, the federal
government should seek input from the natural
gas and oil industry in development of any new
regulations, since industry expertise can inform
the regulatory process and avoid unintended
consequences such as delays in bringing needed
supply online.
? Sustained technology development and deploy-
ment, appropriate for each resource type and
geographic and geologic setting, covering
development and production techniques and
environmental risk management. Oil and natural
gas companies are able to develop appropriate
technologies for accessible, prospectively
commercial areas, while longer term resource
opportunities may require partnership with
government agencies and academic institutes to
ensure sustained technology development eforts
occur.
Summary of Scopc and Objcctivcs
To summarize the scope and objectives of this
chapter as they have been discussed earlier, the funda-
mental question here is how the oil and gas resources
in the United States and Canada can be developed to
meet long-term market needs, using a development
model that ensures energy security and prudent envi-
ronmental risk management, while bringing the ben-
efts of continued and expanded development of sig-
nifcant resources within the region.
Tis chapter focuses on the hydrocarbon develop-
ment potential in the United States and Canada.
Demand issues and operational management and
environmental questions are addressed in separate
chapters of the report.
54 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Tis work examines the principal oil and gas pro-
ducing areas within the United States and Canada and
new areas or types of oil and gas resource that could
become available for development and production by
the middle of the century. Tese include:
y Te Arctic (U.S., Canadian, and Greenland Arctic
regions)
y Ofshore U.S. and Canada (non-Arctic)
y Onshore natural gas
y Onshore conventional oil (including EOR opera-
tions and opportunities)
y Unconventional oil (including Canadian and U.S. oil
sands, oil shale, and tight oil)
y Methane hydrates.
Te scope of this work includes studies of current
and future infrastructure needs for both oil and nat-
ural gas, as hydrocarbon development can only pro-
ceed if there is a way to transport produced volumes
to market. Terefore, we have examined the cur-
rent pipeline system for crude oil between the major
U.S. and Canadian producing regions and the major
refning centers, analyzed future pipeline needs, and
described the regulatory and investment framework
necessary for future pipeline development. Tis cov-
ers the major crude oil pipeline systems that deliver
to refneries, but does not cover refned product
pipeline systems downstream of the refning facili-
ties. For natural gas, the analysis covers major inter-
state transmission pipeline infrastructure, as well
as gas storage and processing facilities, but does not
address lower-pressure local utility natural gas pipe-
line distribution systems. Natural gas liquids infra-
structure needs are also included within the scope of
this analysis.
Although LNG is discussed in one of this study’s
topic papers, it is not a major focus of this work.
However, LNG is referenced within this chapter,
both as a source of imported natural gas as well as a
potential future option for developing export capac-
ity.
Te objectives of this chapter are to:
y Describe the current best level of understanding of
the technically recoverable resource base for U.S.
and Canadian oil and natural gas available for devel-
opment in the frst half of this century.
y Describe the range of production potential until
2035 for each of the identifed oil and gas resource
types and regions. Tis range sets out to encompass
a reasonably unconstrained production pathway, in
which technological and development choices facil-
itate development and today’s regulations are not
signifcantly tightened, down to a reasonably con-
strained production pathway in which regulatory
choices, access limitations, or a slower pace of tech-
nological development create barriers to develop-
ment. Expected development pathways lie between
these two limits.
y Describe the key current and future advances in
technologies that will allow development and pro-
duction of this region’s oil and gas resources, and
comment on the role of innovation led by the U.S.
oil and gas sector and public research initiatives in
expanding global oil and gas resource potential.
y Assess current and future major infrastructure
requirements to support oil and gas development
and describe the key factors that could either enable
or delay new infrastructure or modifcation of exist-
ing pipeline delivery systems and natural gas stor-
age facilities.
y Describe how oil and gas production potential could
develop to 2050 and beyond, through technological
improvement and/or access to new resource types.
y Frame the implications of the oil and gas resource
development potential identifed for investors and
policymakers.
Te contents of this chapter are supplemented
and completed by a set of detailed topic papers on
each of the major study areas, available on the NPC
website.
Summary of Mcthodology
Te NPC constituted a task group within the
broader scope of this study to specifcally focus on
oil and gas resources and productive potential within
North America. Te Resource & Supply Task Group
divided the work among nine specialized subgroups,
each focusing on a specifc portion of the study. Te
subgroups are as follows:
y Oil and gas resources and resource assessments
y Analysis of data and studies collected for the pur-
pose of this study
y Arctic oil and gas (onshore and ofshore)
CHAPTER 1 - RESOURCES AND SUPPLY 55
y Ofshore (non-Arctic) oil and gas
y Onshore gas
y Conventional onshore oil, including EOR
y Unconventional oil
y Oil infrastructure
y Natural gas infrastructure.
In addition, smaller groups or individuals were tasked
with researching and writing focused white papers on
particular subjects that were not included within the
framework of the main subgroups. Tese white papers
cover the following topics:
y LNG
y Methane hydrates
y Mexican oil and gas supply
y Natural gas liquids (NGLs).
In order to develop a sound assessment of the
range of possible outcomes for North American oil
and gas resources and production, together with the
key challenges and enablers to this development, two
approaches were taken in parallel – analysis of existing
public studies and a confdential survey of private, pro-
prietary studies.
Tere are numerous public, government, and indus-
try organizations that have made macroeconomic and
energy demand, supply, and infrastructure outlooks
assessments. While some have made available to the
public, many companies develop their own internal
analysis as a support for their long-term investment
strategies.
Te Resource & Supply Task Group established a data
and studies subgroup to collect and analyze as much
accessible existing resource data as possible. Teir
objective and evaluation methodology was designed
to capture the wide spectrum and range of outlooks,
including the underlying assumptions and supply
challenges identifed by various organizations. Tis
subgroup also designed and conducted a confdential
survey of private organizations, primarily oil and gas
companies and consulting groups, using an auditable
procedure to capture respondents’ and industries’
views and insights. Te auditable process protected
the proprietary data of survey respondents and survey
results were aggregated to ensure confdentiality (indi-
vidual responses couldn’t be directly attributed to any
particular source). Te survey results added important
data and insights to the public studies record. Govern-
ment organizations such as the Energy Information
Administration, the U.S. Geological Survey, the Bureau
of Ocean Energy Management, the National Energy
Board of Canada, and the International Energy Agency
also contributed data and time to this work.
Te resources and resource assessment team estab-
lished appropriate resource defnitions to be used in
the study, described the sources for resource assess-
ments, and commented on the diferences between
resource assessments coming from diferent organi-
zations. Tis team studied a range of resource assess-
ments from government, academic, and private sector
sources. Understanding the nature of resource assess-
ments and the range of resource potential is considered
a crucial component for the development of long-term
national energy policy, and this subgroup set out to
document and explain the best current understanding
of this area.
Oil and gas development potential and driving
forces can vary signifcantly between regions and
resource types. For this reason, the NPC study estab-
lished specialized subgroups for each of the major
resource types (Arctic, ofshore, onshore gas, conven-
tional oil, and unconventional oil). Each subgroup
was stafed by expert contributors, specialized in that
particular resource area, from the oil and gas industry,
academia, government, and consultancies. Te sub-
groups developed a set of complete and credible esti-
mates of current production and future production
potential of each area based on specifc technologies,
resource size estimates, hydrocarbon development
practices and regulatory frameworks as applicable
in each resource type and area. Tus the individual
teams developed a consistent and credible view of
supply potential that could in most cases go into
more depth and detail than the information provided
through the data and studies analysis.
Finally, two subgroups were established to discuss
current and future oil and natural gas infrastructure
development. Te oil infrastructure subgroup ana-
lyzed the crude oil pipeline system, from major North
American producing basins to major refning centers.
Te natural gas infrastructure subgroup analyzed
major interstate pipeline systems, natural gas storage
capacity, and gas processing plants, and discussed nat-
ural gas liquids infrastructure to the extent that this
may infuence natural gas development. Both infra-
structure groups were tasked with describing current
infrastructure networks as well as the ability of the
56 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
system to evolve to meet future needs, either because
of expansion of supply or because of regional shifts in
supply patterns across North America.
Each subgroup was asked to structure its work to
respond to a set of framing questions defned early in
the study (see “Framing Questions” in Text Box). Sub-
groups met regularly at focused meetings or workshops
with wider participation to advance their research and
analysis and to formulate conclusions and implications.
Subgroup leaders and/or their representatives par-
ticipated in Task Group meetings to share and review
progress and to comment on broader aspects of the
study. Each subgroup prepared a topic paper specifc to
its area, which explores issues in greater detail than can
be included in this summary chapter. Te topic papers
are available on the NPC website.
Te remaining sections of this chapter explore the
analysis and evidence that has led to these fndings,
and give more detail on the specifc enablers and chal-
lenges relevant to each component of North American
oil and gas supply and its supporting infrastructure.
NORTH AMERICAN OIL AND
NATURAL GAS RESOURCE
ENDOWMENT
Te objective of this section is to provide detailed
background about resource assessments, described
in the section above; defne the hydrocarbon related
terms prevalent in the assessments; summarize the
fnding of the key public assessments; and set down
key fndings from the material.
Hydrocarbon Rcsourcc Asscssmcnt
Uscs and Dc?nitions
Usc of Rcsourcc Asscssmcnts
Oil and natural gas resource assessments serve a
variety of fundamental needs of consumers, policy-
makers, land and resource managers, investors, regu-
lators, industry planners, and others. Governments
utilize resource assessments to exercise responsible
Framing Questions
Te Resource & Supply Task Group (as with
the work of the study as a whole) was designed
to answer a set of framing questions. Te ques-
tions were formulated early in the study process,
tested and refned with input from the study lead-
ership, and then became the basis to guide the
specifc work processes and outputs from each of
the specialized subgroups. Te framing questions
were also used over the course of the study as a
test to determine whether newly identifed issues
were within the overall scope and objectives of
the work.
Te following framing questions were used to
guide the research and analysis of the Resource &
Supply Task Group.
y What is the scope of technically recoverable
conventional and unconventional oil and gas
resources available in the United States and
Canada, according to most recent estimates?
y How much of these oil and gas resources can
be translated into productive capacity by 2050
under reasonable technical and economic
assumptions?
y What are the main drivers or assumptions
behind existing North American oil and gas sup-
ply projections?
y What factors could signifcantly increase or
decrease the productive potential of these
resources (e.g., geology, geography, access, tech-
nology, non-environmental regulation, etc.)?
y What could be the particular contribution of
each of the major types of oil and gas resource
considered in this study and what specifc devel-
opment challenges may they face?
y How will sufcient infrastructure (gathering sys-
tems, gas processing plants, crude oil, gas pipe-
lines, and gas storage) be developed to link these
resources to the market?
Te framing questions have allowed this sup-
ply analysis to focus on the key areas of resource
scope, hydrocarbon development pathways, pro-
duction potential, technology and innovation, and
the diverse set of enablers and challenges that can
help achieve the potential of the domestic oil and
natural gas resources available or constrain their
development below their potential contribution.
CHAPTER 1 - RESOURCES AND SUPPLY 57
stewardship on public lands, to estimate future rev-
enues to the government, and to establish energy,
fscal, and national security policies. Te petroleum
industry and the fnancial community use resource
estimates to establish corporate strategies and make
investment decisions. Regulatory organizations such
as government energy ministries, corporation com-
missions, and the Bureau of Land Management and
Bureau of Ocean Energy Management of the U.S.
Department of the Interior utilize resource estimates
in designating acreage for leasing and drilling.
Hydrocarbon Dc?nitions
Pctrolcum is a collective term for hydrocarbons in
the gaseous, liquid, or solid phase; in other words –
natural gas, crude oil, NGLs, and bitumen. Te hydro-
carbon resource endowment includes crude oil, natu-
ral gas, and NGLs. Following are defnitions for the
diferent forms of petroleum:
1
y Crudc Oil is defned as a mixture of hydrocarbons
that exists in a liquid phase in natural underground
reservoirs and remains liquid at atmospheric
pressure after passing through surface separation
facilities.
y Natural Gas is a mixture of hydrocarbon compounds
existing in the gaseous phase or in solution with oil
in natural underground reservoirs at reservoir tem-
perature and pressure conditions and produced as a
gas under standard temperature and pressure condi-
tions. Natural gas is principally methane, but may
contain ethane, propane, butanes, and pentanes, as
well as certain non-hydrocarbon gases, such as car-
bon dioxide, hydrogen sulfde, nitrogen, and helium.
y Natural Gas Iiquids are those portions of the
hydrocarbon resource that exist in the gaseous
phase when in natural underground reservoir con-
ditions, but are liquid at surface conditions (that
is, standard temperature and pressure conditions:
60º F/15º C and 1 atmosphere) or at higher pressure
and/or lower temperature conditions. Te NGLs
are separated from the produced gas and liquefed
at the surface in lease separators, feld facilities, or
gas processing plants.
Oil and gas accumulations are usually treated sepa-
rately in the assessment process. Gas-to-oil ratios
(GOR) are calculated for each accumulation to identify
1 American Petroleum Institute, “Standard Defnitions for
Petroleum Statistics,” 1995.
the proportions of the two major commodities (oil or
gas). An oil accumulation is commonly defned as hav-
ing a GOR of less than 20,000 cubic feet of gas per bar-
rel of oil at standard temperature and pressure; a gas
accumulation is defned as having a GOR equal to or
greater than 20,000 cubic feet of gas per barrel of oil.
Rcscrvcs are those quantities of petroleum antici-
pated to be commercially recoverable by application of
development projects to known accumulations from a
given date forward under defned conditions (such as
prevailing economic conditions, operating practices,
and government regulations). Reserves must sat-
isfy four criteria: they must be discovered, recoverable,
commercial, and remaining based on the development
project(s) applied. Reserves are further subdivided as
Proved, Probable, or Possible, also commonly referred
to as P1, P2, or P3, respectively, in accordance with
the level of certainty associated with the estimates
and their development and production status.
Rcsourccs are those quantities of petroleum esti-
mated, as of a given date, to be potentially (or tech-
nically) recoverable from known or undiscovered
accumulations, exclusive of Reserves. Such resources
are classifed by some as Contingent or Prospective
Resources depending on whether the accumulation is
known or undiscovered, respectively.
In-Placc and Tcchnically Rccovcrablc Rcsourccs
– oil and gas reserves and resources in known or yet
to be discovered accumulations represent at a given
time only the technically recoverable portion of the
in-place oil or gas endowment. Failure to clearly char-
acterize an announced resource estimate as in-place,
technically recoverable, or economically recoverable is
a common occurrence of which users of resource esti-
mates must always be wary. Developments in tech-
nology as well as geologic understanding of a reser-
voir or commodity can make previously uneconomic
resources economic and commercially viable. Exam-
ples of such progress include the development of coal-
bed gas, tight gas and shale gas reservoirs, shale oil
reservoirs, deeper conventional targets, and ofshore
deepwater development. In addition, improvement of
recovery factors can take place over time, thus grow-
ing the resource estimate for a given reservoir.
Undiscovcrcd Rcsourccs are postulated to exist
outside of known accumulations on the basis of geo-
logic knowledge and theory. Examination of size char-
acteristics of known accumulations, together with an
analysis of how many have already been discovered, is
58 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
used to project numbers and sizes of those which may
remain to be discovered. Tis is the general manner in
which conventional, undiscovered resources are esti-
mated or assessed. Often, when there are few or no
data for the basin or region under study, analogs to
known petroleum regions, including their character-
istics and properties, are used to estimate resources.
Te predicted volumes to be found in the undrilled
population of potential accumulations refect esti-
mated undiscovered resources. Tese estimates must
take into account the average prospecting success
rate, number of undrilled remaining prospects, and
the predicted size characteristics for the future dis-
coveries. Te results of such analyses carry a much
greater uncertainty (wider range of volumetric out-
comes) than the uncertainty associated with remain-
ing reserves in existing felds because there are fewer
data on which to base the estimate.
It must always be kept in mind that resource esti-
mates are snapshots in time. Since the earth has a
fnite endowment of liquid hydrocarbons, from which
we produce more and more each year, the logical con-
clusion would be that the estimates for what remains
to be found should be going down, but this is not the
case. Usually, resource estimates conducted by an
individual organization tend to increase over time
owing to some combination of the availability of more
and better data, new acreage that was previously inac-
cessible or incorrectly considered non-prospective, or
new play types (such as shale gas or subsalt oil) made
feasible by technological progress.
Convcntional and Unconvcntional Hydrocar-
bon rcsourccs. In most contemporary defnitions,
a primary diference between “conventional” and
“unconventional” liquids is viscosity, that is, a fuid’s
resistance to fow. Enormous deposits of potentially
productive liquid hydrocarbons exist in nature that
cannot fow under either reservoir or surface condi-
tions – an unconventional resource. Tis category
includes huge deposits of low viscosity oil and bitu-
men deposits (oil sands) in western Canada. Te volu-
metric potential of these deposits may dwarf that of
conventional accumulations.
Te following defnitions refect these viscosity-
based diferences, and other relevant diferences:
y Convcntional Oil: Petroleum found in liquid form
fowing naturally or capable of being pumped with-
out further processing or dilution.
y Unconvcntional Oil: Heavy oil, very heavy oil, oil
shale, and oil sands are all currently considered
unconventional oil resources. Most have a high
viscosity and fow very slowly (if at all) and require
processing or dilution to be produced through a
wellbore. However, not all unconventional oil is
heavy. Te defnition of unconventional oil can also
include such resources as tight oil, which has low
viscosity, but which is not produced using conven-
tional techniques. Some unconventional oils may
also require special transportation and refning
technology.
y Hcavy Oil: Heavy crude oils are understood to
include only those liquid or semiliquid hydrocar-
bons with a gravity of 20
o
API or less. Tese include
fuel oils remaining after the lighter oils have been
distilled of during the refning process.
y Vcry Hcavy Oil: Very heavy oil is defned as having
a gravity of less than 10
o
to 12
o
API.
y Oil Shalc: A fne-grained sedimentary rock contain-
ing kerogen, a solid organic material. Te kerogen in
oil shale can be converted to oil through the chemi-
cal process of pyrolysis. (“Oil shale” is unrelated to
liquid petroleum produced from wells drilled into
more thermally mature shales, that is sometimes
called “shale oil.”)
y Oil Sands: Also referred to as bituminous sands, oil
sands are a combination of sand, water, and bitu-
men. Bitumen is a semisolid, degraded form of oil
that will not fow unless heated or diluted with
lighter hydrocarbons.
y Continuous Typc Rcsourccs (c.g., shalc gas,
tight gas, coalbcd mcthanc): Some organizations,
such as the USGS, use the term continuous accu-
mulation to defne those unconventional oil and
gas resources that are economically produced but
are not found in conventional reservoirs such as
coalbed gas, tight gas sands, shale gas, and many
of the tight oil plays. Continuous accumulations
are petroleum accumulations (oil or gas) that have
large spatial dimensions and indistinctly defned
boundaries, and which exist more or less indepen-
dently of the subsurface water column. Another
key diference between conventional and uncon-
ventional accumulations is that some of these
(shales and coals) are both source rock and reser-
voir rock.
CHAPTER 1 - RESOURCES AND SUPPLY 59
North Amcrican Hydrocarbon Rcsourcc
Classi?cation Systcms
Several diferent classifcation systems have been
developed to systematically describe and label mea-
sured and estimated hydrocarbon resource volumes
according to two or three of the principal uncertain-
ties (primarily geologic and economic uncertainty,
and sometimes commercial status). Tough these
systems have many similarities as well as overlaps,
each was developed with its own intended estimation
focus. Each also has its own terms that do not always
have exact equivalents in the other system’s lexicons.
Te principal systems in use are the following, and
each is described in detail in Topic Paper #1-1, “Oil
and Gas Geologic Endowment,” which is available on
the NPC website.
y Te Potential Gas Committee classifcation system,
introduced in 1964
y Te McKelvey system, dating from 1972
y Te United Nations system, adopted by the United
Nations in 2004
y Te Petroleum Resources Management System,
developed by several collaborating organizations
and approved by the Society of Petroleum Engi-
neers in 2007.
Unccrtainty
Signifcant uncertainties are an inherent part of
resource estimation. Te best-constructed methodol-
ogies have two key elements: (1) they directly address
the resulting estimates’ principal uncertainties; and
(2) they are transparent regarding the assessment
methodology. Tese factors are critical for users to
understand exactly what the assessments represent.
What constitutes a resource has changed over time.
Twenty years ago, coalbed methane was not a viable
part of the U.S. energy mix. It now accounts for about
8% of domestic natural gas production. Technological
developments and developments in geologic and engi-
neering understandings continually move the edge of
what makes a resource a reserve.
Te history of the petroleum industry is replete
with instances of overly pessimistic predictions and
“good” resource-related surprises. Salient U.S. exam-
ples include:
y “Experts” predicted at the beginning of the last cen-
tury that the modern domestic oil era, initiated in
Pennsylvania during the mid-1800s, would soon
end owing to lack of sufcient resources. Instead,
major fnds in other places soon proved them wrong,
such as the 1901 discovery of Spindletop Field in
the Texas Gulf Coast region, and the 1890–1920s
discoveries of several large felds in California’s Los
Angeles and San Joaquin basins.
y Many believed in the early 1940s that oil and gas
either did not exist in, or could not be produced
from, the open ocean – until 1947 that is, when
Kerr-McGee used a platform-plus-barge combina-
tion to drill the frst successful well out of sight of
land in the Gulf of Mexico.
y Similarly pessimistic views that production from
the large California oil felds would dwindle to a
trickle due to resource exhaustion have been repeat-
edly negated by technological advancements. Such
advances include the introduction of waterfood-
ing prior to the 1960s and, more importantly, the
application of thermal recovery methods to heavy
oil reservoirs since the 1960s.
y Few “experts” held out hope that oil and gas could
exist in deep water (over 5,000 feet) at great sub-
seabed depths (on the order of 30,000 feet total
vertical depth) until Shell’s 1986 Mensa prospect
discovery proved they did.
y Te late 1980s advent of large-scale coalbed meth-
ane production was virtually unheralded, and there-
fore unanticipated.
y Te late 1990s advent of large-scale natural gas
and NGLs production from massively hydrauli-
cally fractured organic-rich shales, initiated in the
Barnett Shale of Texas’ Fort Worth Basin, was also
unanticipated.
y Although small-scale hydraulic fracturing of oil-
bearing “shale” formations such as California’s
Monterrey Formation began in the 1980s, the
adaptation of combined horizontal drilling and
massive hydraulic fracturing as originally developed
for gas in the Barnett Shale, to productive develop-
ment of the oil-bearing Bakken Formation of Mon-
tana, North Dakota, Saskatchewan, and Manitoba,
was also unheralded and unanticipated until its
rapid adoption and expansion began in 2001.
Tis long and continuing history of unanticipated
“good” resource-related surprises begs the ques-
tion as to what currently ignored and discounted
60 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
oil and gas resources might have the potential to
provide similar surprises in the future. Given his-
tory’s lessons about scientifc and technological
progress, perhaps consideration ought be given
to establishment of a small but highly compe-
tent efort dedicated and resourced specifcally
to (1) identify and characterize those oil and gas
resources not yet being quantitatively estimated
(using both open-source and disclosure-protected
proprietary data and information), and (2) iden-
tify, analyze, summarize, and status-assess ongoing
and/or needed R&D activities, basic or applied, that
may hold promise for rendering these resources
technically and then economically producible at
some time well into the future. Possibilities include
enhanced recovery of residual oil (both bypassed
and difuse) from old felds, oil shale conversion, and
methane hydrate production, all of which are already
being researched to varying degrees. Tis study
includes a formal recommendation along these lines
(see Executive Summary, Core Strategies).
Ovcrvicw of Rcccnt and Currcnt
North Amcrican Oil and Gas
Rcsourcc Asscssmcnts
Resource assessments are conducted by govern-
ment agencies, the private sector, and academic and
professional organizations in the United States and
Canada. Only publicly available (i.e., nonpropri-
etary) assessments were examined by the Resources
Subgroup. Most assessments were robust, transpar-
ent, and well documented. Each had a slightly dif-
ferent purpose or focus, and therefore provided a
unique perspective on North American resources.
Resource estimates for North America span the
spectrum of resources and reserves. Te principal
resource assessments evaluated for this study were
the following:
y Minerals Management Service (now Bureau of
Ocean Energy Management, Regulation and
Enforcement)
y IHS Energy
y Potential Gas Committee
y U.S. Geological Survey
y USGS Circum-Arctic Resource Appraisal
y Geological Survey of Canada
y Canada-Nova Scotia Ofshore Petroleum Board
y Canada-Newfoundland and Labrador Ofshore
Petroleum Board
y Canadian Association of Petroleum Producers
y Alberta Energy and Utilities Board
y Alberta Energy Resources Conservation Board
y National Association of Regulated Utility Commis-
sioners
y Advanced Resources International
y ICF International (input to MIT study on the Future
of Natural Gas).
Kcy Findings and
Obscrvations
Resource estimates for North America vary widely
across a broad spectrum of resources and reserves.
Tere are good reasons for the diferences, includ-
ing studies with diferent purposes, and also include
factors such as use of diferent methodologies, inclu-
sion or exclusion of reserves growth, inclusion of
only selected basins or reservoirs, inclusion of dif-
ferent types of hydrocarbons (e.g., crude oil only vs.
all liquids), variations in assumptions about tech-
nology and economics (e.g., including current tech-
nology vs. assuming future advances in exploration
and completion technology), and difering minimum
feld sizes.
Resource assessments are conducted by govern-
ment agencies, the private sector, and academic and
professional organizations in the United States and
Canada. Only the government agencies provide a
comprehensive set of assessments, covering oil and
gas, onshore and ofshore, conventional and uncon-
ventional, and so on.
Signifcant uncertainties are inherent in resource
estimation. Te best-constructed methodologies
directly address the resulting estimates’ princi-
pal uncertainties, and transparency regarding the
assessment methodology and assumptions underly-
ing the estimates is critical for users to understand
exactly what they represent.
A better understanding of reserves growth is
required for all types of oil and gas resources, espe-
cially those that are emerging.
Small changes in recovery efciency (percentage of
oil in place that will ultimately be produced), indi-
vidually and cumulatively, will continue to have a
CHAPTER 1 - RESOURCES AND SUPPLY 61
signifcant impact on the size of technically and eco-
nomically recoverable resources. Present and future
R&D could also result in additional production from
older felds. In addition, support of feld trials of
new and advanced technologies is critical to advanc-
ing new methods needed to grow North American oil
and gas supply.
Mature onshore areas in the United States and
Canada have some, but limited, conventional
opportunities. CO
2
EOR, assuming anthropo-
genic sources are available, has the potential for
substantial additional oil production. Offshore
North America conventional resources still have
significant potential, especially the Gulf of Mexico.
There is potential, as well, in the offshore Atlantic
and Pacific. The Arctic holds very large potential,
undiscovered resources.
Te role of unconventional resources in the North
American energy endowment will continue to have a
growing and profound impact on the future energy
supply outlook. Onshore unconventional resources,
in particular, will be very important. Shale gas,
Canadian oil sands, tight gas, tight oil, gas hydrates,
and possibly oil shale are expected to provide further
scope for additions to reserves.
Tere are many unknowns regarding unconven-
tional, ofshore, and Arctic sources. Additional data
and information are required to make informed pol-
icy and commercial decisions about these potential
resources.
ANALYSIS OF RESOURCE AND
PRODUCTION OUTLOOKS AND
STUDIES
Ovcrvicw
As was clear in the previous sections, an important
element of the work done for this study was to col-
lect and analyze data and outlooks published by gov-
ernmental agencies, independent forecasting groups,
industry associations, or others, as well as data sup-
plied on a confdential basis by individual companies.
Tis section presents a detailed view of the ranges of
outlooks for future North American oil and gas sup-
ply that were analyzed in this process and the insights
gained.
Te objective of the Data and Study Analysis Team
was to understand and interpret the:
y Uncertainty surrounding the size of North Ameri-
ca’s conventional and unconventional oil and natu-
ral gas resource base, as refected in published anal-
yses and proprietary data and forecasts
y Challenges and enablers to convert this resource
endowment into production and supply volumes
that can help meet the future energy needs of
North America.
Te Data and Study Analysis Team comprised
diverse skill sets, experiences, and expertise from
participants from large integrated energy compa-
nies (e.g., Chevron, ExxonMobil, Shell); major inde-
pendent oil and gas producers with representatives
of the American Natural Gas Alliance (e.g., Encana,
Questar); large industry service companies (e.g., Hal-
liburton); consultant companies (e.g., ICF Interna-
tional, Nehring Associates, Wood Mackenzie); and
U.S. and Canadian government agencies.
In conducting a “study of studies,” the Team evalu-
ated a broad, diverse range of energy outlooks. Te
study scope was limited to North America with focus
on the 2010–2050 time frame. Data were collected
from public, government, industry, and consultant
sources. Approximately 50 publicly available energy
outlooks were examined. Te U.S. and Canadian gov-
ernments provided integrated energy outlooks – e.g.,
the Energy Information Administration, the National
Energy Board of Canada, the International Energy
Agency, the United States Geologic Survey, and the
Bureau of Ocean Energy Management, Regulation
and Enforcement.
More than 80 energy and consultant compa-
nies received a request to complete a comprehen-
sive resource, production, and supply chain survey/
template. More than 25 industry and consultant
templates were returned, and then aggregated to
maintain the confdentiality of the individual com-
pany’s proprietary data. Te aggregation resulted in
12 unique outlook cases compiled for this study.
Te current North America oil resource and sup-
ply situation is relatively straightforward. Canada
and Mexico are currently exporting oil into the U.S.
markets and the only question is whether their
resource base/supply capacity can continue to be
meet internal demand while also enabling exports.
U.S. production, plus Canadian exports to the United
62 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
States, have not been sufcient to meet the more than
20 million barrels a day that are consumed today.
Terefore, the analysis focused on whether the
resource base and future production capacity could
reach internal demand levels, and/or how large the
domestic/import supply gap could grow to in the
future. Te results suggest that North American
production capacity will likely not grow fast or large
enough to meet the growing needs for oil in the
region.
Te North American gas resource and supply situa-
tion has changed in recent years. Te industry’s rela-
tively recent application of horizontal drilling com-
bined with hydraulic fracturing has led to a greater
understanding of the potential magnitude of the U.S.
and Canadian recoverable resource base, now believed
to have grown considerably (perhaps two and a half
times or more over estimates from as recently as
2003). In the last decade, there was a perception that
domestic supplies could not meet internal demand
requirements and signifcant volumes of LNG imports
would be required to satisfy demand. Tus, our goal
was to assess if there are sufcient, afordable domes-
tic gas resources that can be utilized to meet all poten-
tial demand scenarios. Te spread in demand out-
looks for the gas (20 to 40+ Tcf/yr) refect:
y Low side cases – low economic growth and/or cur-
tailing energy use to minimize carbon emission and
other environmental impacts
y “Mid” cases that refect a historical percentage
share in the overall fuel mix and moderate economic
growth consistent with historical rates
y High side cases that contemplate increased pen-
etration in the power and even transportation sec-
tors. Tis also would likely improve the resultant
environmental impact for these demand growth
scenarios and/or reduce the liquid import gap that
has both economic and energy security advantages
for the United States.
Te supply outlooks studied here seem to fall into
three general types of future scenarios: (1) Tere are
constrained supply cases corresponding to a more
stringently regulated industry environment, and/or
curtailment of access/development of new opportuni-
ties; (2) Te vast majority of the outlooks (spectrum of
“mid” cases) refect iterations of industry, public, and
government “business as usual” cases, where economic
growth and product prices will be the primary determi-
nants of market needs and investment in new supply;
(3) Te high production cases will require considerable
alignment among industry, government, and public
stakeholders towards a common, shared, long term
vision for the future direction of the energy sector.
Te oil cases require signifcant long-term commit-
ments to diversifying the portfolio of North Ameri-
can supply areas; early and increased data collection
to understand the new play areas (some currently in
moratoria areas); research and technology to assess
the commercial viability and development of large
Rockies unconventional oil resources; and a new
long-distance pipeline network (targeting U.S. Gulf
Coast refners or for crude oil export to Asia Pacifc
via a Western Canadian facility/port) to support the
growth potential of Canadian oil sand production.
Te low and mid gas supply cases are likely to be
driven by similar conditions to the oil outlooks
described above; however, the high gas production
scenarios are associated with natural gas serving an
increasing gas share of the overall energy mix in the
United States and Canada including in the power and
transportation sectors. We have assessed the indus-
try requirements and fundamentals to achieve this
possible paradigm shift for gas, and while we believe it
is feasible from a resource base and industry capabil-
ity standpoint, considerable alignment and coopera-
tion between industry, government, and public stake-
holders will be required to ramp up production rapidly
and sustain 30 to 40 or more Tcf/yr production levels
for future decades.
A Rangc of Asscssmcnts
Given the wide range of assessments from diverse
groups, made over a number of years and covering var-
ious geographic areas, developing a view of potential
resources and development potential is a critical and
complex process. Confdence is gained by compar-
ing resource estimates to better understand the data
available and the input assumptions. Tose that
assessed onshore oil may use diferent assumptions
from those assessing ofshore gas; those that made
an assessment fve years ago may have diferent data
than an assessment done a year ago. Furthermore,
some assessments may include conventional and
unconventional hydrocarbons while others may not.
Te estimates and assumptions can be further veri-
fed by comparison with industry activity and perfor-
mance. A promising resource that attracts little inter-
est or activity may be either optimistically assessed or
CHAPTER 1 - RESOURCES AND SUPPLY 63
activity is restricted because of policy or operational
constraints. Greater confdence in resource estimates
leads to greater confdence in future energy supply’s
potential from the diferent sources studied.
Estimating a future resource is challenged by the
fact that most of the resource is hidden deep in the
subsurface, often in deep water or even beneath Arc-
tic ice. Some areas have moratoria on drilling or the
collection of seismic data such that even rudimentary
estimates are difcult to achieve. Tat said, much of
the world’s thick sequences of sediments do contain
oil and gas, and therefore, by analogue with producing
areas, we can project at least the existence of oil and
gas, if not their quantities even in unexplored areas.
Where known commercial accumulations occur we
can identify additional, on-trend, undrilled features
that are likely to be productive, but even here the full
extent of the hydrocarbon province and accumula-
tion sizes are far from precisely known. In existing
felds where the volumes of in-place oil or gas is bet-
ter understood, there are complicating factors such as
variations in permeability, communication with the
borehole and reservoir energy issues that make the
amount that is recoverable uncertain. Industry activ-
ity and performance is another leading indicator of
the underlying assumptions and fundamentals associ-
ated with the existing resource estimates. In addition
to these “below ground” uncertainties there are many
“above ground” factors such as demand, cost, infra-
structure, policy, environmental factors and the rate
of technology development that may limit or enable
the benefcial extraction of the resource.
For these reasons, resource outlooks and forecasts
vary on the nature and amount of available resources.
Te tables and charts included in this section capture
this uncertainty by stating ranges as observed in the
data collection from academic, industry, and govern-
mental sources. Te ranges attempt to capture 80%
of the values presented; therefore, there are outliers
that extend beyond what is shown here. Tese ranges
represent irreducible uncertainty due to the inherent
variability of the assumptions rather than variations
in fundamental data.
Tese resource estimates are further qualifed by
observations of what the industry can do and is doing
now. Tese “resource–industry activity” comparisons
have three categories:
1. Robust resource estimate and demonstrated
commerciality (for example: shale gas, Gulf of
Mexico oil, oil sands and possibly tight oil).
Interrupting development of these resources
means going to less robust, more technically
challenging and more expensive resource types.
2. Less robust resource estimate with limited or
no industry access (e.g., Arctic, Pacifc, Atlantic,
and Eastern Gulf of Mexico). Tese areas need
sufcient study and data collection to understand
their potential. Seismic surveys and drilling will
enable more accurate resource estimates, which
may be much smaller or greater than currently
known. Industry frst needs to fully demonstrate
its readiness and capability to explore and develop
that resource in ways that protect workers,
safeguard the environment, and provide a positive
return on capital. Only when industry has won
the confdence of government and public is this
possible and, even then, may depend on other
considerations of political process.
3. Least robust resource estimate, wherein industry
has access but little activity (e.g., kerogen oil
shale to oil, EOR using anthropogenic CO
2
, deep
ofshore gas). Tese are more uncertain. Tey
may be the next big resource opportunity or they
may always be just one step away from being a
commercial reality. Government and industry
need to develop policies and technologies that
increase the probabilities of these potential
resources contributing to future production.
From this analysis, it is likely that some resources
will dominate early because of their abundance,
access, availability, and relative cost, while others
will play a supporting role and be available for later
development. Usually lower cost natural gas and oil
resources are developed before moving to higher cost
resources as lower cost sources are depleted, within
the constraints of access and the availability of appro-
priate and cost-efective technology.
Natural Gas
With abundant supplies in the United States and
Canada, North America is amply supplied with
natural gas to meet domestic demand over the next
several decades even at growing production levels.
Tis is largely driven by recent advances in horizon-
tal drilling and hydraulic fracturing that have allowed
gas to be extracted from shale and low permeability
formations. As a result of these advances, estimated
future resources are large and growing. Currently
64 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
the range is 1,500 to 4,000 Tcf for the United States
and 500 to 1,250 Tcf for Canada. Tese numbers
have grown rapidly in recent years (from 100s of Tcf)
and may grow further as more of these new plays
are tested. Tis potential is being realized as seen in
recent production increases.
Tere may be opportunities to augment these sup-
plies with Arctic natural gas if infrastructure is devel-
oped. Another possible upside to gas supply may
come from ofshore exploration in the little explored
moratorium areas and in the long term, methane
hydrates. Overall natural gas supply is driven by
unconventional shale gas and tight gas (without
these, natural gas production would still be in decline).
But other important resources will be important
contributors in the longer term.
Crude Oil
Oil production has been in long-term decline, but
Canadian oil sands, deepwater Gulf of Mexico oil, and,
with less certainty, tight oil could help slow or even
arrest the decline as seen over the last year or two.
Onshore U.S. conventional discoveries peaked in 1938
and the industry has adapted by moving to the Arctic,
ofshore, oil sands and now tight oil. Oil sands have
the largest upside, as only 70 of the 170 billion barrels
of oil potential are currently under development.
Additional oil resources may come from enhanced
oil recovery. For example, the 35 to 80 billion barrels
of oil onshore U.S. is largely due to new advances in
EOR. A larger and longer-term upside resource may
come from heating kerogen shale deposits (some-
times called oil shale). Tis requires heating the rock
to accelerate maturation of organic material and con-
verting it to oil and gas.
Crudc Oil
Rcsourcc Estimatcs
Te United States’ oil resource base has increased
over time due to technology enhancements and a
greater understanding of new “frontiers.” Te U.S. oil
in place endowment (the broadest possible defnition
of the resource) for conventional reservoirs is about
11% of the world’s total, while the country’s uncon-
ventional reservoirs are 23%. Adding in Canada’s
unconventional bitumen endowment, thought to be
in excess of two trillion barrels, would increase this
percentage.
While U.S. crude oil production peaked in the early
1970s at around 9.6 million barrels per day, except for
the start-up of Prudhoe Bay and periods of high oil
prices, it has been on a downward slope (44% from
the peak) since 1985 (Figure 1-7). In total, the United
States imports about half its petroleum liquids con-
sumption of nearly 20 million barrels per day – equiv-
alent to about a quarter of the world’s liquid demand.
Current and recent data and studies indicate that
the remaining North American resource base is likely
to be in excess of 500 billion barrels.
In the U.S. resource base table (Table 1-1), we have
included three industry cases that represent the range
of remaining resource estimates received from indus-
try, plus the most recent EIA-released data, as of the
time of this study. Te industry’s assessment of the
United States’ remaining resource base ranged from
106 to 270 barrels, which is almost entirely contained
in conventional reservoirs at this point. Te United
States’ remaining technically recoverable conven-
tional resources are only 6% of the world’s total. Te
United States has produced about 200 billion barrels
of its original oil in place. To date, that is about 17%
of all oil produced in the world. Tere are still remain-
ing North American resources that can provide signif-
icant recoverable totals if technical and environmen-
tal issues can be addressed (Table 1-2).
Te largest remaining North American oil resource
potential is the unconventional Canadian oil sands
(150–300+ billion barrels of recoverable resources)
and U.S. Rockies shale kerogen plays (over 1 trillion
barrels in place). Te U.S. unconventional Rockies oil
plays, while having signifcant in place volumes, need
considerable research, experimentation, technology
advancements, and the resolution of above ground
environmental challenges before technically recover-
able resources can be realized. Moreover, these issues
all need to be addressed to assess the commercial via-
bility before proceeding with large-scale production
projects that could materially impact the oil supply
situation. Tis is not expected until after 2030.
In 2010, Canadian oil sands were already contribut-
ing around 1.5 million barrels per day and could grow
to over 5 million barrels per day out beyond 2030,
which could represent approximately 40–50% of all
U.S. and Canadian crude oil production. Infrastruc-
ture expansion to transport this heavy crude to suit-
able upgrading facilities and refneries will be neces-
sary to achieve these large growth aspirations.
CHAPTER 1 - RESOURCES AND SUPPLY 65
Te Gulf of Mexico is a world-class petroleum sys-
tem with approximately 50 billion barrels of remain-
ing potential. A considerable amount of this potential
is located in the lower permeability, Paleogene play
(with commercial viability/attractiveness still uncer-
tain) and in a number of new play types that have less
overall total potential than the current Miocene deep-
water play. Te Miocene play producing felds are the
largest contributors to the current 1.5 million barrels
per day production level in the Gulf of Mexico. Future
supply outlooks from the Gulf of Mexico range from
1 to 3 million barrels per day and largely refect the
uncertainty regarding industry drilling activity lev-
els and acreage availability in future lease sales that
has arisen since the tragic Macondo oil spill in the
deepwater Gulf of Mexico. While there is signifcant
Figure 1-7. U.S. Crude Oil* Production’s Downward Trend
0
4
8
12
16
1970 1975 1980 1985 1990 1995 2000 2005 2010
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
* Crude oil and condensate.
Sources: Energy Information Administration’s AEO2010 Reference Case and International Energy Outlook 2009.
OIL IMPORTS FROM ELSEWHERE
OIL IMPORTS FROM MEXICO
OIL IMPORTS FROM CANADA
U.S. OIL PRODUCTION
Figure 1-7. U.S. Crude Oil* Production’s Downward Trend
Table 1-1. Oil Resource Base (Billion Barrels)
EIA NPC Study
AEO2011 Low Scenario Mid Scenario High Scenario
Lower-48 Ofshore Conventional 57 40 65 100
Alaska (onshore and ofshore) 48 25 40 55
Lower-48 Onshore Conventional 80 35 50 85
Unconventional (“tight oil”) 34 5 10 15
Shale Kerogen … 0 0 10
Oil Sands … 1 2 5
U.S. Total Remaining 219 106 167 270
Sources: Energy Information Administration’s Annual Energy Outlook 2011 (AEO2011); and NPC Industry Survey, Aggregated Data.
66 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
near- to mid-term potential in other lower-48 of-
shore areas (e.g., world class petroleum system – of-
shore California) and the U.S. and Canadian Arctic
(80–100 billion barrels overall), new regulatory and
permitting requirements plus acreage access will drive
activity levels in these areas.
Finally, the liquid-rich areas in the shale plays and
the Bakken/Tree Forks and Monterey tight oil res-
ervoirs have been actively pursued by industry over
the last fve years. Production has grown to around
400 thousand barrels a day from these plays. Te
current resource assessment of the tight oil plays is
6–34 billion barrels. Production levels could grow
signifcantly, to 2–3 million barrels per day in the
future. Additionally, it is still unclear how much
crude oil and condensate versus natural gas liquids
will ultimately be recovered from the shale gas plays.
Te individual crude oil and condensate production
rates for new wells are relatively low after the steep
initial decline in the frst year of production; however,
they are proftable and contributing to growth in the
lower-48 onshore sector. As the U.S. onshore conven-
tional oil feld production levels continue to decline,
the increased “tight oil” activity may partially ofset
this decline in the next 10 to 20 years.
Te only other area that could contribute material
volumes to ofset natural feld declines in the mature
U.S. lower-48 onshore, which is producing around
3 million barrels a day, is from enhanced oil recovery
resulting from injecting carbon dioxide (CO
2
) into the
reservoir. Te industry has been successful in recov-
ering additional oil from older felds by applying this
technology and utilizing natural sources of CO
2
. Tere
is considerable debate as to how much additional oil
can be recovered from the felds that haven’t been
fooded with CO
2
as some of these are not suitable,
while others are currently not “connected” to a natural
source of CO
2
, requiring infrastructure development
in these felds. While anthropogenic (man-made
CO
2
) capture, transportation, injection and storage
for enhanced oil recovery is another potential source
of CO
2
, there is signifcant uncertainty regarding
the cost of supply, regulatory requirements, and con-
struction of new onshore CO
2
pipelines necessary for
commercial project viability.
More detail on the regional and play-type oil
resource profles can be found in oil-related topic
papers, including Topic Paper #1-2, “Data and Studies
Evaluation,” available on the NPC website.
Production Outlooks
In addition to published outlooks, the Data and
Study Analysis Team obtained a wide range of indus-
try and consultant views on oil resources and pro-
duction supply capacity to develop its outlook on
Table 1-2. High Potential North American Oil Resources
Resource Type Resource Potential Resource Development Enablers
Canadian Oil Sands Recoverable Resource Potential =
150–310 billion barrels; future
production levels possibly in excess of
5+ million barrels per day
Long-distance pipeline and infrastructure
project to U.S. Gulf Coast or Canadian
West Coast?
U.S. Gulf of Mexico Oil Recoverable Resource Potential =
40–60 billion barrels; future near- and
mid-term production levels of 1.5–3.0
million barrels per day?
Resumption of pre-Macondo deepwater
drilling activity levels; Paleogene reservoir
performance and commerciality
U.S. and Canadian Tight
“Shale” Liquid Plays
Recoverable Resource Potential =
10–20 billion barrels; future North
American production levels possibly in
excess of 1+ million barrels per day
Hydraulic Fracturing; resource intensive –
people, equipment, materials; How much is
crude oil/condensate (refned transportation
products) vs. natural gas liquids
New U.S. Lower-48
Ofshore & U.S. and
Canadian Arctic Areas
Recoverable Resource Potential =
80–100 billion barrels; mid-term
(e.g., U.S. West Coast) and longer-term
(e.g., Arctic) production levels in excess
of several million barrels per day
Opening of moratoria areas and data
collection; timely exploration/development
program approvals
CHAPTER 1 - RESOURCES AND SUPPLY 67
production. In this section, we examine both govern-
ment and industry outlooks and assumptions to pro-
vide perspective on the future.
Te total U.S. production volumes in the EIA refer-
ence case and the industry mid case were relatively
similar by 2035, as seen in Figure 1-8. Te industry/
consultant mid case oil total production forecasts
were lower by 1 million barrels per day than the EIA’s
Annual Energy Outlook (AEO) 2011 forecast in 2035.
Consequently, the industry’s oil production com-
pound average growth rate (CAGR) from 2009 until
2035 was 0.1% versus 0.3% in the AEO2011 Refer-
ence Case. Generally, the industry’s median case
showed lower growth for the onshore sector than the
EIA’s reference case.
Te industry was more bullish for the ofshore;
however, there is uncertainty regarding assumptions
for future activity levels in the ofshore (lower-48 and
Arctic) following the Macondo oil spill in the deepwa-
ter Gulf of Mexico in April 2010. Te 2011 EIA ref-
erence case and industry views were relatively simi-
lar for growing production in the Arctic. Tis likely
represents general alignment on the relatively high
supply costs anticipated for future exploration and
development projects in the Arctic and the perceived
challenges associated with ofshore drilling.
Te industry’s high case U.S. production levels were
signifcantly greater than the EIA’s AEO2011 refer-
ence case, with a 2.3% CAGR. In this case, industry
cited big production gains in Alaska and ofshore,
no doubt based on the assumption of increased
acreage access in areas that are currently under
moratoria. Consultant studies on the behalf of
various U.S. government agencies suggested there
are between 30 and 50 billion barrels that are inac-
cessible to industry. Finally, we also compared the
range of industry cases with the IEA World Energy
Outlook Current Policies case. Te IEA production
output levels generally coincided with the low indus-
try case.
NGL production may be an increasingly important
source of liquids produced in the United States and
Canada, particularly as shale gas focused companies
shift activity towards some of the more liquids-rich
gas plays. Te Data Study Analysis Team obtained
some industry/consultant U.S. NGL outlooks. Te
Figure 1-8. U.S. Oil Production by Type: Industry High/Med/Low Survey Responses versus AEO2011 Reference Case
0
4
8
2009 2025
AEO2011
LOW
2025 INDUSTRY 2035 INDUSTRY
MED HIGH
2035
AEO2011
LOW MED HIGH
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
KEROGEN
CONVENTIONAL OFFSHORE
CONVENTIONAL ONSHORE
ARCTIC
Sources: Energy Information Administration’s AEO2010 Reference Case and International Energy Outlook 2009.
Figure 1-8. U.S. Oil Production by Type: Industry High/Med/Low Survey Responses
versus AEO2011 Reference Case
68 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
industry’s mid (2.3 million barrels per day) and high
(2.9 million barrels per day) forecasts in 2030 span
either side of the AEO2011 forecast of 2.7 million
barrels per day, while the industry’s low (2.0 million
barrels per day) forecast is relatively fat through
2030.
Te study team received a wide range of industry/
consultant views regarding future Canadian oil pro-
duction. Te industry mid case oil total production
forecasts were lower than EIA’s forecast, and also
below IEA’s forecast total in all years. At 1.9%, indus-
try’s median Canadian oil production CAGR from 2009
until 2030 was just slightly less than IEA at 2.0%, but
well below the EIA’s Reference Case Canadian oil pro-
duction CAGR at 2.9%. Te industry/consultant high
scenario provided a 2.8% CAGR, just below EIA’s ref-
erence case CAGR estimate. In all the cases, conven-
tional oil production from the onshore and ofshore
was projected to decline due to the high feld decline
rates and relatively small remaining potential in both
Western Canada and the ofshore (Atlantic). More-
over, no signifcant production was anticipated in the
Canadian Arctic, probably a result of the high supply
cost of these large, remaining resources, along with
the absence of infrastructure or cost-efective trans-
portation mechanisms to get these remote resources
into the marketplace.
Te major diferences between the cases in
Figure 1-9 are predominantly due to the range of pro-
duction levels for the Canadian oil sands. Te indus-
try’s median case is only 3.6 million barrels per day – a
signifcant 600 thousand barrels per day below the
agency forecasts of commercially available resource
plays in North America. Even the industry’s high
case at about four million barrels per day is below
both the EIA and IEA cases at 4.2 million barrels per
day. Clearly, industry is more conservative about
overcoming the above ground challenges to rapidly
increase production, especially in light of the addi-
tional pipeline infrastructure that will be required
to either bring additional volumes down the refners
on the U.S. Gulf Coast (e.g., the currently proposed
Keystone XL project) or consider exporting crude oil
to Asia Pacifc, which would require a new infrastruc-
ture network from Alberta to the Canadian west
coast, and export facilities.
Figure 1-9. Industry Forecast of Canadian Oil Production by Type versus EIA and IEA Totals
Sources: Energy Information Administration (EIA) Annual Energy Outlook 2010 (AEO2010) and International Energy Outlook
2010 (IEO 2010); International Energy Agency (IEA) World Energy Outlook 2010 (WEO 2010).
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID
HIGH
2.0 2.2 2.4 2.6 1.4 2.1 2.8 3.2 3.6 2.1 2.8 3.4 4.0
0
2
4
6
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
INDUSTRY OIL SANDS
INDUSTRY CONVENTIONAL OFFSHORE
INDUSTRY CONVENTIONAL ONSHORE
INDUSTRY ARCTIC
EIA TOTAL OIL IEO 2010
IEA TOTAL OIL WEO 2010*
ACTUAL
* New Policies Case.
Figure 1-9. Industry Forecast of Canadian Oil Production by Type versus EIA and IEA Totals
CHAPTER 1 - RESOURCES AND SUPPLY 69
In summary, the future of North American future
oil supplies in the near to medium term is heavily
dependent on the U.S. ofshore (40–100 billion bar-
rels “economically” recoverable resources) and Cana-
dian oil sands (150–310 billion barrels of “economi-
cally” recoverable resources). Existing oil production
from Alaska also delivers a signifcant near-term
contribution amounting to over 10% of U.S. crude
oil production, and maintaining this production has
an important role in the time until Arctic exploration
can deliver new oil supply. Production from EOR,
tight oil, shale oil, and liquids from coal or natural gas
will contribute some growth volumes. More impor-
tantly, if U.S. federal government regulation prevents
access to the U.S. ofshore resources, or constrains
transport of Canadian oil sands production, then
North American oil production could decline.
Te U.S. and Canadian combined total conven-
tional oil production (Figures 1-10 and 1-11) has
undulated from 8.4 million barrels per day in 1995,
to 7.5 million barrels per day in 2005, to 8.1 mil-
lion barrels per day in 2010. Te EIA is forecasting
that conventional oil sectors will slowly trend down
to 7.3 million barrels per day in 2035. However,
EIA shows Canadian oil sands production grow-
ing signifcantly and driving total North American
oil production to over 11 million barrels per day
by 2035. When comparing EIA’s U.S. and Canada
oil production forecast with IEA’s and the indus-
try’s, the EIA case is the most optimistic, with the
exception of the industry’s high case. Te IEA is
forecasting 2030 U.S. and Canadian production
1.5 million barrels per day lower than EIA. Te
industry’s median case ends up being about the same
in 2030 as IEA’s, whereas its low case forecasts only
7.3 million barrels per day, a full 3.6 million barrels
per day lower than EIA’s forecast.
Natural Gas
Rcsourcc Estimatcs
Historically, North American gas production
has generally kept pace with growing consumption
requirements. Canadian production has continued
to exceed demand, while just in the past decade
the United States and Mexico have received LNG
imports in addition to the pipeline gas from within
North America to supplement their domestic supply
base. As a result of drilling technology advances and
the emergence of the recent “game changing” shale
gas plays, the gap between U.S. demand and produc-
tion is closing rapidly and likely to reduce greatly the
future need for LNG imports (see Figures 1-12 and
1-13).
North America contains both conventional and
unconventional oil and gas resources. Until the last
decade, most oil and gas resource estimates largely
included conventional in place and recoverable vol-
umes. Te vast majority of historical production
from North America has been from conventional res-
ervoirs and our understanding of both the in-place
and ultimate recoverable volumes is more mature
than for unconventional accumulations.
While the size of the North American conventional
resource base is relatively well understood, our knowl-
edge of the unconventional gas endowment is growing
rapidly given increased industry activity and focus on
shale and tight gas. Te gas assessments of the ulti-
mate, technically, commercially, remaining recover-
able resource base for both Canada and United States
vary considerably (Table 1-3). Tis is largely a func-
tion of the vintage of the assessments and whether
they included the most recent data and insights from
the unconventional gas sector, especially shale gas.
Te ultimate remaining recoverable resources for the
United States ranged from 1,000 to 4,500 Tcf of gas,
while Canada ranged from 500 to 1,250 Tcf of gas.
Te United States has produced around 1,140 Tcf,
which suggests it has consumed around 20 to 40%
of the total domestic gas endowment based on the
range of collected data. Canada has produced around
175 Tcf, which is around 10% to a quarter of its
total gas resource base. If Canada used its domestic
supplies for only internal demand requirements at
current consumption rates, this would be equivalent
to 140 to 360 years of domestic supply.
Te U.S. conventional, remaining recoverable
resource base is approximately 25 to 40% of the total
remaining natural gas volumes in the United States
and ranges from 515 to 1,160 Tcf of gas. Te cur-
rent EIA (2011 reference case) assessment of over
1,000 Tcf of gas is at the upper end of the indus-
try estimates and may suggest a diference of views
regarding the technical and commercial viability of
some of the remaining conventional resource base.
Te EIA and industry have a relatively similar view
of the conventional onshore, with the low and mid
cases for industry ranging from 215 to 290 Tcf and
70 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-11. U.S. and Canadian Oil Production Cases
* Includes condensate, natural gas liquids, and refnery gain.
0
2
4
6
8
10
12
14
2010 2015 2020 2025 2030
IEA* U.S. + CANADA OIL PRODUCTION
INDUSTRY HIGH OIL PRODUCTION
INDUSTRY MEDIAN OIL PRODUCTION
INDUSTRY LOW OIL PRODUCTION
EIA U.S. + CANADA* OIL PRODUCTION
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
Sources: International Energy Agency (IEA) World Energy Outlook 2010; Energy Information Administration (EIA)
Annual Energy Outlook 2010.
Figure 1-11. U.S. and Canadian Oil Production Cases
Figure 1-10. U.S. and Canadian Oil Production Forecast
0
4
8
12
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
1980 1990 2000 2010 2020 2030 2040
* Includes condensate, natural gas liquids, and refnery gain.
Source: Energy Information Administration’s International Energy Outlook 2010.
CANADIAN UNCONVENTIONAL PRODUCTION
CANADIAN CONVENTIONAL PRODUCTION*
U.S. CONVENTIONAL PRODUCTION
U.S. + CANADA CONVENTIONAL
Figure 1-10. U.S. and Canadian Oil Production Forecast
CHAPTER 1 - RESOURCES AND SUPPLY 71
FIgure 1-12. U.S. Natural Gas Production and Consumption
0
10
20
1981 1986 1991 1996 2001 2006 2011
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
DRY GAS PRODUCTION
CONSUMPTION
Source: Energy Information Administration’s AEO2011 Reference Case.
Figure 1-13. Canadian Natural Gas Production and Consumption
0
2
4
6
1980 1985 1990 1995 2000 2005 2010
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
DRY GAS PRODUCTION
CONSUMPTION
Source: Energy Information Administration’s AEO2011 Reference Case.
Figure 1-12. U.S. Natural Gas Production and Consumption
Figure 1-13. Canadian Natural Gas Production and Consumption
72 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
the EIA (2011 reference case) was 290 Tcf. Tis is
probably the most mature exploration and produc-
tion area in North America. Te industry remaining
recoverable resource range for the ofshore region
was 160–375 Tcf and the EIA (2011 reference case)
was at the upper end at 320 Tcf. Te vast majority of
the remaining resources are located in the Gulf of
Mexico with estimates ranging from 200 to 300+
Tcf, with the Pacifc and the Atlantic Coast each
around 20 to 30+ Tcf. Te 2011 EIA reference case
had the highest estimate of the Arctic remain-
ing recoverable gas of 418 Tcf, which exceeded the
industry’s range of 130–345 Tcf and the Potential
Gas Committee (2008) assessment of 194 Tcf. Te
largest remaining recoverable resources in the Arc-
tic are located in the Alaska North Slope and include
the approximately 35+ Tcf already discovered, plus
additional exploration and growth potential bring-
ing the total potential to over 100 Tcf. Te Chukchi
Outer Continental Shelf (OCS) (~90 Tcf), Beaufort
(~30 Tcf), and Bering Shelf (~20 Tcf) also may con-
tain material gas resources. Finally, various consul-
tants (ICF International 2008, Science Applications
International Corporation/Gas Technology Institute
Table 1-3. Natural Gas Resource Base
(Trillions of
Cubic Feet)
PGC 2008
(2010)
EIA
AEO2011
Low Scenario* Mid Scenario*
High
Scenario*
Produced 1,140
U.S. Total Remaining 2,074 (2,170) 2,543 1,500 2,300 4,000
Arctic 194 290 130 210 345
Lower-48 Ofshore
Conventional
869 446 160 260 375
Lower-48 Onshore
Conventional
352 215 290 440
Tight Gas 455 200 350 550
Shale 616 (687) 862 700 1,000 1,800
(Lower-48) Coalbed
Methane
99 (159) 138 90 120 150
NEB 2010 Low Scenario* Mid Scenario*
High
Scenario*
Produced 175
Canada Total* Remaining 1,027 500 900 1,250
Ofshore Conventional 100 85 100 105
Arctic 116 45 75 125
Onshore Conventional 115 100 145 185
Tight Gas 104 40 70 100
Shale Gas
(NEB doesn’t include
Montey)
82 (+>200–
400+)
200 400 600
Coalbed Methane 34 30 80 140
* Low-High range based on spread of all data.
Sources: Potential Gas Committee (PGC) 2008 and 2010; Energy Information Administration’s Annual Energy Outlook 2011
(AEO2011); National Energy Board of Canada (NEB) 2010; and NPC Industry Survey, Aggregated Data.
CHAPTER 1 - RESOURCES AND SUPPLY 73
[SAIC/GTI] 2010), at the request of the U.S. govern-
ment agencies, have estimated between 100 and
300 Tcf of the remaining recoverable gas in the United
States is located in moratoria areas, with 100+ Tcf
in the lower-48 ofshore and onshore (largely Rock-
ies) and up to 20+ Tcf in the Arctic. Te ofshore
and Arctic gas resources that have so far been esti-
mated in the moratoria areas are all in conventional
reservoirs.
Te United States’ unconventional, remaining
recoverable resource base is around 60 to 75% of the
total remaining gas volumes in the United States and
ranges from 990 to 2,305 Tcf of gas. Te most recent
EIA estimate for remaining unconventional recover-
able gas is over 1,000 Tcf with industry’s mid sce-
nario around 1,400 Tcf.
Te U.S. lower-48 is estimated to have in-place
coalbed methane resources of 700 Tcf, of which the
remaining, economically resource base ranges from
70 to 150 Tcf with an expected value/most likely esti-
mates of 100–120 Tcf. Coalbed methane is a relatively
small component of the total unconventional gas
resource base. Te vast majority of the coalbed meth-
ane recoverable resources are located in the Rockies
(50–90 Tcf) in the San Juan and Powder River basins;
with the East Coast, Gulf Coast, and Mid-Continent
regions ranging from 5 to 10+ Tcf each.
Te tight gas remaining recoverable resources in
the EIA 2011 reference and mid industry scenarios
are around 350 Tcf, with a range of 200 to 520 Tcf.
Approximately 120 Tcf of tight gas has been pro-
duced, which leaves anywhere from 65 to 85+% of
the resource base that is yet to be developed and can
contribute signifcant annual supply volumes towards
future North America gas demand. Te largest
remaining resources are in the Rockies (with expected
value/most likely estimates around 200+ Tcf), largely
in the Greater Green River, Uinta, Piceance, and
San Juan basins. Tere is also material (in excess of
50+ Tcf) resource potential in the Gulf Coast
(e.g., Mesozoic plays in East Texas and South Texas
Tertiary plays), East Coast (e.g., Appalachia), and
Mid-Continent (e.g., Granite Wash) regions.
U.S. shale gas is a potential game changer, with
most recent industry resource estimates ranging from
700 to 1,800 Tcf (Table 1-4), with the EIA reference
and industry mid case at about 1,000 Tcf (Table 1-3).
Shale gas has been the predominant driver in renewed
optimism about the U.S. gas resources and supplies
for the future.
Te Canada conventional, remaining recoverable
resource base is approximately a third of the total
remaining gas volumes in Canada and ranges from
230 to 415 Tcf of gas (see Table 1-3). Te industry
mid scenario and the NEB (reference) cases were
very similar (approximately 325 Tcf). Te range for
the ofshore region is relatively narrow at 85–105
Tcf and almost all of the resources are located in
the Atlantic. Te range for the onshore region for
the industry scenarios was 100–185 Tcf, with rela-
tively close agreement between the industry low
and mid cases with the NEB reference case of 115
Tcf. Te remaining onshore gas volumes are located
almost entirely in Western Canada. Te greatest
uncertainty for the conventional sector lies in the
Arctic region. Te NEB estimate of 116 Tcf was at
the high end of the industry range of 45–125 Tcf.
Te Arctic areas identifed with the largest remain-
ing potential include the Mackenzie Delta/Canadian
Table 1-4. U.S. Shale Gas Most Likely
(Mean, Average, etc.) Recoverable Resources
Regions & Plays
Range for Navigant
2008, PGC 2008,
EIA AEO2011,
ANGA 2010 Estimates
East Coast 70–613
Gulf Coast 90–350
Mid-Continent 110–205
Rockies 45–75
Marcellus 177–546
Haynesville 34–251
Eagle Ford 20–68
Barnett (Fort Worth Basin) 26–168
Fayetteville (Ark. & Okla.) 21–52
Woodford (Ark. & Okla.) 12–28
Mancos (Uinta) 11–21
Sources: America’s Natural Gas Alliance (ANGA) 2010 Studies;
Energy Information Administration (EIA) AEO2011; Navigant
Consulting for the American Clean Skies Foundation: “North
American Natural Gas Supply Assessment,” July 2008; and
Potential Gas Committee (PGC) 2008.
74 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Beaufort (~60 Tcf) and the Arctic Islands/ Sverdrup
Basin (~35 Tcf).
Te Canada unconventional, remaining recover-
able resource base is approximately two-thirds of the
total remaining gas volumes in Canada and ranges
from 270 to 840 Tcf of gas. Te NEB and industry
believe there is around 150 Tcf of remaining recov-
erable resources in coalbed methane and tight gas
reservoirs in the mid/reference cases. Additionally,
the incremental upside for coalbed methane plus
tight gas in the industry high scenario was less than
100 Tcf. Tese plays types are located almost entirely
in Western Canada close to the existing infrastructure
network.
Canadian shale gas is another potential game
changer. Te industry estimate of remaining recover-
able resource potential estimates of 200–600 Tcf could
be almost half of the remaining gas resource potential
for Canada. Tese plays are in the early development
phase and thus we can expect the “mean” or most
likely values and the range to be better delineated as
we get additional well and production performance
data over the next decade. Whereas in conventional
reservoirs where as much as 95% of the natural gas
can be recovered, the ultimate recoverable volume
from shale reservoirs may reach up to 20–30% of
the in-place resource, with recovery from some less
rich reservoirs down below 10%. Cretaceous, Juras-
sic, Triassic, Mississippian, and Devonian shales are
potential targets with the largest resource potential
located in Western Canada.
In summary, the outlook for North America natu-
ral gas production has changed dramatically in just
the past few years. Te gas resource base in both the
United States and Canada is believed to have increased
signifcantly and will have profound impacts on the
North American energy market from an economic,
energy security and environmental standpoint. Te
gas resource base does not appear to be a limiting fac-
tor on bringing new North American supplies to mar-
ket. Estimates of technically recoverable shale gas are
highly likely to change over time as new information
is gained through drilling, production, and technolog-
ical and managerial development.
Production Outlooks
Only in the most optimistic, high-side cases were
the outlooks for U.S. conventional production lev-
els forecast to increase above the current 10 Tcf/yr
(Figure 1-14). Te amount of new conventional gas
wells required to simply maintain production levels
continues to increase over time and industry has been
focusing its capital in lower cost and/or higher pro-
ductivity wells in other sectors (e.g., unconventional
and ofshore supply regions). Recent exploration
discovery sizes have been small, wildcat success rates
have been low, and much of the remaining resource
potential is in small feld fractions in the U.S. lower-48
onshore conventional sector.
Tere is a wide range in the future productive capac-
ity of the lower-48 ofshore, with current production
levels of around 2.5 Tcf/yr falling to 1.5 Tcf/yr in 2035
in the low-side cases and rising as high as 3.2 Tcf in
the high-side cases. While initial fow rates from of-
shore wells can exceed 50 million cubic feet per day
(MMcf/d), these wells have steep decline rates and
thus active drilling programs to replenish supplies are
needed to maintain and grow production. We inter-
pret the outlooks for decline in U.S. lower-48 ofshore
production levels in the cases we collected from indus-
try to refect concerns about the resumption of his-
torical drilling activity levels in the Gulf of Mexico and
the timing of access to new areas in the Gulf, Pacifc,
and Atlantic.
Te Arctic (Alaska) region currently is producing
less than 0.3 Tcf/yr; however, there are consider-
able discovered (in excess of 35+ Tcf) and additional
undiscovered resources that could supply in excess of
2+ Tcf/yr if the necessary infrastructure was in place
to move gas into the U.S. lower-48 markets. As with
the Mackenzie project in the Canadian Arctic, the tim-
ing of the Alaska pipeline project continues to slip and
most outlooks now question whether these supplies
will be entering the market before 2035, a major devi-
ation from past studies that foresaw Arctic gas online
as early as this decade.
By the 2020s, more than 60% of the total U.S. gas
supplies are likely to come from domestic, unconven-
tional resources. Te studies indicate that the small-
est unconventional resource contributor will be coal-
bed methane, with current production levels around
2 Tcf/yr, and future production capacity ranging from
1.5 to 2.5 Tcf/yr by 2035. Tree quarters of the cur-
rent production is from the Rocky Mountains, with
the lion’s share from the San Juan and Powder River
basins. Te majority of regional data for the coal-
bed methane sector suggested the approximately
0.5 Tcf/yr of production from the Gulf Coast, East
CHAPTER 1 - RESOURCES AND SUPPLY 75
Coast, and Mid-Continent regions will likely be dif-
fcult to sustain till 2035. Te vast majority of the
remaining resource potential is situated in the Rock-
ies. Te San Juan and Powder River basins have
been producing for more than 25 years and most of
the readily accessible resources have been developed.
Coalbed methane developments are not without
above ground challenges, including the disposal of
water removed from the producing wells, the surface
footprint/impact on landowners and local communi-
ties and unintended loss of methane into the atmo-
sphere (e.g., underground mining). Fortunately, these
issues can be monitored and have been managed to
minimize their impact. Industry and the government
agencies continue to evaluate new technologies and
approaches to protect the environment and maximize
operational best practices.
Tight gas reservoirs are currently producing more
than 6 Tcf/yr and almost all the outlooks indicated
that supplies could grow from this sector. Although
the lowest cost, tight gas “sweet spots” have been
developed, there are still considerable feld in-fll
and additional exploratory opportunities that can
be pursued and relatively easily tied into the exist-
ing regional infrastructure. In 2008, the Rockies and
Gulf Coast each produced around 2 Tcf/yr, while the
Mid-Continent contributed around 1 Tcf/yr.
Most outlooks anticipate Gulf Coast tight gas
production will decline in the future, with the larg-
est possible increases by 2035 from the Rock-
ies. Operators have been actively developing tight
gas felds for over 10–15 years and working with
the government (state and federal) agencies and
local communities to address issues that arise. Te
primary focus area is continued environmental
protection, with water use and management being the
most pressing issue from industry, public, and gov-
ernment perspectives.
U.S. and Canadian tight and shale gas are likely
to make up more than 60% of the remaining total
resource base and will be the driver for gas production
growth and energy self sufciency/security objectives
in the future. U.S. shale gas production has grown
from about 1 Tcf/yr in 2006 to currently in excess of
4 Tcf/yr. Continued shale gas exploration and devel-
opment over the next 5–10 years will help further
Figure 1-14. Representative U.S. Conventional Gas Production Cases
0
4
8
12
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
2009
LOW
2015
MID
HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID HIGH ACTUAL LOW
2035
MID HIGH
CONVENTIONAL OFFSHORE
CONVENTIONAL ONSHORE
ARCTIC
Source: NPC Industry Survey, Aggregated Data.
Figure 1-14. Representative U.S. Conventional Gas Production Cases
76 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
reduce the current uncertainty over the long term for
the U.S. and Canadian resource base. While conven-
tional, coalbed methane and tight gas developments
are becoming increasingly costly and/or complex,
“lower” cost shale developments provide potential
to grow U.S. and Canadian production. If the higher-
end recoverable resource estimates are afrmed, a
robust production plateau can be maintained for
many decades. In the mid and high industry cases in
Figure 1-15, shale gas production is anticipated to
grow to more than 10 Tcf/yr by 2035. Te main chal-
lenges associated with large-scale shale gas develop-
ments are potential concerns about water use/man-
agement associated with the hydraulic fracturing
applications required to produce commercial quanti-
ties of gas from shale reservoirs, and other surface
impacts.
In all cases studied, the Canadian onshore conven-
tional sector production output is expected to decline
over the next 20 years (see Figure 1-16) and con-
tinue the trend of declining production (in excess of
1 Tcf/yr) over the last 10 years. Tese supplies are
almost entirely in Western Canada, and we anticipate
industry will continue to maximize ultimate recovery
from these plays; however, most new additions will be
small pool sizes around existing felds or infll drill-
ing projects. Te rate of decline in the existing res-
ervoirs/felds in Western Canada is greater than 10%
per annum. Without large, new discoveries, it will be
impossible to reverse this trend. Deep, high pressure,
and/or sour gas remaining resources/opportunities
are likely to be higher cost developments and may not
attract investment in light of lower cost unconven-
tional plays in the area.
Future gas production capacity from the Canadian
ofshore (Atlantic) is believed to be relatively small
(less than 0.2 Tcf/yr). Unless large new discoveries
are made in the Atlantic (e.g., Orphan basin), this area
is unlikely to have a material impact on Canada’s con-
ventional production capacity.
Te only area that can provide substantive new
conventional gas volumes is the Canadian Arctic;
however, there is considerable diversity of views as
to when this generally “higher” cost gas will enter
the market. Te anticipated Mackenzie gas project
Figure 1-15. Representative U.S. Unconventional Gas Production Cases
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID
HIGH ACTUAL LOW
2035
MID HIGH
0
10
20
30
SHALE GAS
COALBED METHANE
TIGHT GAS
Source: NPC Industry Survey, Aggregated Data.
Figure 1-15. Representative U.S. Unconventional Gas Production Cases
CHAPTER 1 - RESOURCES AND SUPPLY 77
timing has slipped considerably since the frst NPC
North America gas study in 1999, largely a result of
the challenges associated with building a large export
pipeline from the discovered felds (with signifcant
follow-up potential in the Arctic) to existing Western
Canada infrastructure.
Unconventional gas production is expected to of-
set the overall decline for the conventional sources in
Canada (Figure 1-17). Shale gas is the potential game
changer and is anticipated to grow from the 0.1 to
1.5 Tcf/yr (low) to 2.4 Tcf/yr (high) by 2030. Coal-
bed methane production is anticipated to be between
0.3 Tcf/yr and 0.6 Tcf/yr in the above scenarios by
2030. While it is difcult to distinguish the transi-
tion from conventional to tight and shale gas reser-
voirs in Western Canada, the perception is that there
is more remaining resource potential to exploit tight
and shale gas in the study time frame than conven-
tional sources.
All the outlooks collected indicated that Canadian
gas production will exceed even the largest inter-
nal demand requirement scenarios (up from 2.8 to
4 Tcf/yr), and, therefore, the main driver for Cana-
dian output will be “pull” from the United States and
other export markets. Most outlooks suggested that
without shale gas and in some instances Arctic gas
production, Canadian gas production is likely to
continue its decline from historical levels. Both the
industry “mid” and reference cases indicate that
Canadian conventional, tight gas, and coalbed meth-
ane supplies would likely decline to around 4 Tcf/yr
by 2025. Te industry view was more optimistic
about the contributions likely from shale gas plays,
whereas the NEB saw the Arctic gas and pipeline com-
ing into play earlier than industry.
Te combined outlooks from all sources for U.S. and
Canadian production potential over the next two and
a half decades (as seen in Figure 1-18) indicate rea-
sonable scope for continued growth in production to
the high 30s Tcf level. Clearly, actual growth rates will
depend just as much on market factors as on supply
potential, but the outlooks show there would be scope
for supply to support quite signifcant market expan-
sion, which would bring economic and energy security
as well as greenhouse gas benefts.
Figure 1-16. Representative Canadian Conventional Gas Production Cases
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID HIGH
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
ACTUAL
0
1
2
3
4
Source: NPC Industry Survey, Aggregated Data.
CONVENTIONAL OFFSHORE
CONVENTIONAL ONSHORE
ARCTIC
Figure 1-16. Representative Canadian Conventional Gas Production Cases
78 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-17. Representative Canadian Unconventional Gas Production Cases
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID HIGH
YEAR
ACTUAL
0
1
2
3
4
5
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
SHALE GAS
COALBED METHANE
TIGHT GAS
Source: NPC Industry Survey, Aggregated Data.
Figure 1-18. Industry Estimates of Potential Natural Gas Production from North American Supply Sources
0
10
20
30
40
2000 2005 2009 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
Sources: Energy Information Administration’s AEO2010 Reference Case; and International Energy Agency’s WEO 2010.
CANADA SHALE HIGH
CANADA SHALE MID
U.S. ARCTIC MID
U.S. SHALE HIGH
U.S. LOWER48 SHALE MID
U.S. LOWER48 CONVENTIONAL + TIGHT + CBM MID
2010 AEO LG DEMAND
2010 WEO FP DEMAND
Notes: CBM = coalbed methane; LG = low growth; FP = future policies; WEO = World Energy Outlook.
Figure 1-17. Representative Canadian Unconventional Gas Production Cases
Figure 1-18. Industry Estimates of Potential Natural Gas Production
from North American Supply Sources
CHAPTER 1 - RESOURCES AND SUPPLY 79
Dcvclopmcnt Challcngcs and Enablcrs
While the gas base resource is large, there are chal-
lenges to delivering U.S. and Canadian gas production
growth. A long-term approach is necessary to address
the energy trade-ofs that will provide the optimal
solution for North America’s energy future. Follow-
ing is a brief discussion of these challenges at various
stages along the value chain. All were identifed by
respondents to the confdential data survey as issues
of concern. A typical development path is outlined in
Figure 1-19.
Resource Access is essential to sustaining and grow-
ing production. Since most unconventional gas plays
are on private rather than government held acreage,
several issues pertain: many conventional ofshore
opportunities in the lower-48 states and Alaska are
currently not available to industry; recent proposed
lease sales in the Gulf of Mexico have been delayed
and cancelled in the Alaska OCS; and the lease “expiry”
clock is winding down on currently held acreage. Con-
sultant studies done on the behalf of the various U.S.
government agencies have estimated that between
100 and 300 Tcf are currently in moratoria areas inac-
cessible to industry.
Opportunity Identifcation/Research & Technology
Development is the enabler to unlock future oppor-
tunities. Industry will typically focus its resources
(people, funding) in the areas it believes will have
the most commercial impact. For example, although
the Atlantic, Pacifc, and some Arctic ofshore is cur-
rently inaccessible, modern methods of seismic data
collection and interpretation would help improve
our understanding of their resource potential and
the commercial viability of these areas, which can
only help shorten the time between opening them
up and the production of oil and gas.
In the E&P Project Planning and Execution area, per-
mitting and compliance with all regulatory require-
ments is becoming increasingly difcult and time con-
suming. In the ofshore sector, industry is actively
seeking to begin operating again in the Gulf of Mex-
ico deepwater and pursue exploratory activities on
leases in the Arctic. However, signifcant delays are
Figure 1-19. A Typical Production Pathway
IDENTIFICATION OF TECHNICALLY VIABLE ENERGY RESOURCES
ASSESSMENT OF RESOURCE BASE SIZE AND COMMERCIAL VIABILITY/DOABILITY
RESOURCE OPPORTUNITY, ACREAGE, ETC. ACCESS
EXPLORATION VALIDATE; QUANTIFY; DECISION POINT TO TRIGGER LARGE DEVELOPMENT INVESTMENTS
PROJECT DEVELOPMENT INDUSTRY CAPACITY PEOPLE, MATERIALS, EQUIPMENT, ETC.; CAPITAL AVAILABILITY;
PROJECT MANAGEMENT PRACTICES; PERMITTING
INFRASTRUCTURE/TRANSPORTATION TO END USERS AVAILABILITY;
TIMING OF NEW TRANSPORTATION ROUTES/NETWORKS
PRODUCTION OPERATIONS BEST PRACTICES
Figure 1-19. A Typical Production Pathway
80 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
being encountered, likely delaying future production
volumes. A timely solution is needed and coopera-
tion between government ofcials, industry, and the
public that can accelerate resolution to this challenge
would be welcomed.
Since an increasing share of future production will
be from shale and tight oil and gas opportunities that
require hydraulic fracturing, all permitting/opera-
tional/regulatory concerns regarding unconventional
gas and tight oil must be addressed in a timely manner
to continue allowing volumes to grow from these large
resources. Water cycle management is one of the most
important focus areas that will enable exploratory
and development activities. In addition to provid-
ing a clear, timely process to drill and complete wells,
industry and other stakeholders should continue
to explore innovative ways to reduce water use and
improve recycling and disposal technology/practices.
Additional surface, air, and other areas are being stud-
ied by industry and government agencies. However,
there is a need to apply the most cost-efective solu-
tions that help reach an optimal balance for economic,
environment, and energy security considerations.
Industry Capacity needs to be evaluated on a total
energy system basis, since increased activity in
any one sector or area may only result in a shift in
resources, rather than a material increase in the oil
and gas industry’s ability to grow total supplies.
As originally noted in the 2007 NPC Hard Truths
report, the oil and gas industry is facing a consider-
able human resource challenge. Nearly 50% of the
workforce will be eligible for retirement in the next
10 years and fewer university graduates have entered
the workforce over the past generation. Industry and
government have roles to play in helping to rebuild
the science and engineering capabilities and commu-
nicating the benefts of employment with oil and gas
companies. An increased focus on training younger
employees is essential, especially if activity levels con-
tinue to increase, with an emphasis on operational
best practices, safety and environmental protection
in order to address the retirements of many highly
experienced industry personnel.
While growth in the gas sector can be partially ofset
by shifting resources from other parts of the industry,
the system could become stretched or incapable of
meeting a high growth scenario in the unconventional
gas and tight oil areas, Canadian oil sands, expansion
of E&P in the ofshore and Arctic, and fnally resource
intensive plays like oil shale in the Rockies. Growth
in all these areas would put a large strain on people,
materials, and equipment.
Industry/Government/Public Cooperation can be the
linchpin to work through obstacles and/or challenges
to our energy future. Te most rapid and efective
way to resolve issues is to work together to under-
stand the fundamentals; quantify the benefts and
concerns; openly discuss the trade-ofs with all con-
cerned stakeholders; and then jointly support and
proceed with a “solution” to accelerate energy “gains”
(that should include increased efciency/reduction in
energy use, increased supply, increased environmen-
tal protection, and increased energy security).
One way to improve the data sharing and knowledge
of the fundamentals would be to work through exist-
ing organizations to develop a more systematic pro-
cess for governments, industry, and public to collect,
discuss and share data that would be kept in a well-
managed repository. Improving full-cycle, energy
value chain modeling (tools, data, interpretation, and
workshops) could expand a more rounded discussion
of alternative energy visions, strategic directions, and
overall energy policy options. Periodic studies by the
industry, government committees, and public institu-
tions are both helpful and useful.
PROSPECTS FOR NORTH
AMERICAN OIL DEVELOPMENT
Ovcrvicw
Both the United States and Canada are major oil
resource-holding and -producing countries on a global
scale and have been for many years. However, since
the United States is also a large oil importer, the
focus of attention has been on reducing imports and
improving energy security by demand-side measures,
such as efciency standards for vehicles, rather than
supply-side measures, such as enabling domestic oil
supply development in new areas. Tis section of the
report sets out the opportunities for continued North
American oil development and production activities
at scale. Major producing areas now contributing sig-
nifcant volumes of crude oil to North American sup-
ply are profled, such as the ofshore Gulf of Mexico,
the Alberta oil sands, and the multiple producing
basins focusing on conventional oil distributed across
the United States and Canada. Opportunities for sus-
taining and growing these sources are examined and
CHAPTER 1 - RESOURCES AND SUPPLY 81
assessed. In addition, emerging and new sources of
crude oil in the region are examined. Tese include new
exploration in the Arctic regions of the United States
and Canada, the emerging tight oil plays, the poten-
tial from ofshore zones where access has been under
development restrictions, and the potential emergence
of new unconventional oil sources such as U.S. oil shale.
Each major heading in this section describes one seg-
ment of this portfolio of current and future oil supply,
and includes an overview of the context and produc-
tion history, where applicable. Also included are the
key technologies required for development, the poten-
tial production pathways to 2035 and beyond, and an
outline of the key fndings. Te section concludes with
an overview of the crude oil pipeline network required
to deliver this supply to market. Each of these topics
is described in more detail in the topic papers to this
report, available on the NPC website.
O?shorc
Dcvclopmcnt and Production History
and Contcxt
U.S. Lower-48 O?shore
Ofshore oil and gas development and produc-
tion have been on the rise in North America over an
extended period. In the U.S. lower-48, federal OCS oil
production has increased its contribution to total U.S.
production from less than 1% in 1954 to more than
30% in 2009. Te expansion of ofshore development
and production is ascribed overall to technological
progress keeping pace with more challenging ofshore
environments leading to larger feld discoveries in
ever-increasing water depths.
Currently, U.S. lower-48 ofshore oil and gas produc-
tion is restricted to the Gulf of Mexico, with a minor
contribution from the Pacifc OCS region (about 4%
of U.S. ofshore production). Much of the Eastern
Gulf of Mexico is expected to be restricted to drilling
until the year 2022, and the Pacifc and Atlantic OCS
areas were restricted from leasing consideration up
until 2008. For the purposes of this study, oil and gas
development on the Alaska OCS is included as part
of the Arctic region, rather than in the U.S. ofshore
region.
From its beginning in late 1940s, the U.S. federal
ofshore oil and gas industry has grown tremen-
dously. In 1954, federal ofshore crude oil and con-
densate production was around 2.5 million barrels or
nearly 7,000 barrels per day. Tat fgure peaked at
around 600 million barrels in 2002 or 1.64 million
barrels per day, accounting for 29% of total U.S. crude
oil and condensate production. A surge in Gulf of
Mexico deepwater oil production led to an increase of
OCS crude oil production to around 591 million bar-
rels in 2009 or 1.62 million barrels per day; account-
ing for 30% of total U.S. oil production. Figure 1-20
shows ofshore oil production as a percentage of total
U.S. production from 1960 to 2009.
Te move to deep water was made possible by con-
tinuous advancements in technologies that permit-
ted drilling and development in these environments.
Examples of these advancing deepwater technology
“frsts” in the Gulf of Mexico include the frst fxed
platform, “Cognac” installed in 1979 at water depth of
1,023 feet, while the tallest steel jacket “Bullwinkle,”
considered the economic limit for this fxed plat-
form type, was installed in 1989 at water depth of
1,353 feet. Te frst tension leg platform, “Joliet” was
installed in 1989 at water depth of 1,760 feet, fol-
lowed by “Neptune,” the frst Spar/Subsea platform
installed in 1997 in a water depth of 1,930 feet. On
the ultra-deepwater front, Herschel/Na Kika/Fourier
was the frst Floating Production System installed in
water depth of 6,950 feet in 2003. Te frst Floating
Production Storage and Ofoading system in the Gulf
of Mexico is scheduled for frst production in 2011 at
the Cascade and Chinook prospects in 8,800 feet of
water. According to the Minerals Management Ser-
vice (MMS) report on deepwater Gulf of Mexico, in
February 1997, there were 17 producing deepwater
projects, up from only 6 at the end of 1992. Since
then, industry has been rapidly advancing into ultra-
deepwater, and many of these anticipated felds have
commenced production. At the end of 2008, there
were 141 producing projects in the deepwater Gulf of
Mexico, up from 130 at the end of 2007.
2
In March of 2010, Shell started production at the
Perdido Spar complex in the Western Gulf of Mexico,
and overtook the Independence Hub by setting the
record for production in the deepest water. Moored
170 miles ofshore in 7,817 feet of water, with sub-
sea wells in up to 9,627 feet of water, peak production
should achieve 130 thousand barrels of oil equivalent
per day.
2 Richardson et al., Deepwater Gulf of Mexico 2008: America’s Of-
shore Energy Future, U.S. Department of the Interior, Minerals
Management Service, 2008, OCS Report MMS 2008-013.
82 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Development of the deepwater frontier (water
depth greater than 1,000 feet) is responsible for
increasing overall OCS crude oil and natural gas pro-
duction since 2000. In fact, the year 2000 marks
a transition from predominantly shallow water
oil production to deepwater production. In 2000,
annual deepwater crude oil production amounted to
271 million barrels, while shallow water production
was 252 million barrels. By 2007, annual crude oil
production from the shallow water had dropped to
140 million barrels while in deepwater regions of the
Gulf of Mexico production rose to 328 million bar-
rels. Since 2005, the deepwater Gulf of Mexico has
contributed about 70% of the total Gulf of Mexico
OCS crude oil production. Tis trend is expected to
continue as more discoveries and drilling activities
occur in the deepwater and ultra-deepwater areas of
the Gulf of Mexico.
Given this history, the deepwater area of the Gulf
of Mexico represents an important part of U.S. oil
supply, and it is viewed as one of the most important
world oil and gas provinces. All this has been made
possible by means of technological breakthroughs
that have allowed oil and gas companies to operate
out in these harsh and challenging environments.
Te advent of drill ships capable of drilling in water
depth up to 10,000 feet and deeper reservoirs, along
with the subsea completion technology and the Hub
system have greatly contributed to the expansion of
ofshore oil and gas development and production.
Subsea tieback technology coupled with innovative
subsea technology also increase the ability of the
industry to develop and produce more oil and gas
in felds that would not otherwise be economical.
Accounting for approximately 290 productive wells
in deep water, subsea systems continue to be a key
Figure 1-20. Federal Outer Continental Shelf (OCS) Oil as a Percentage of Total U.S. Production, 1960–2009
0
0.4
0.8
1.2
1.6
O
I
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R
O
D
U
C
T
I
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N
M
I
L
L
I
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N
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A
R
R
E
L
S
P
E
R
D
A
Y
0
10
20
30
P
E
R
C
E
N
T
FEDERAL OCS FEDERAL OCS PERCENTAGE OF TOTAL U.S. PRODUCTION
1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
YEAR
1961 – First subsea well completed
1988 – Deepest fxed platform installation – Bullwinkle
1996 – First SPAR completed – Neptune
2006 – Installation of Independence hub in Gulf of Mexico
2002 – Deepest pipeline constructed at 7,209 feet
2010 – Completion of construction of frst foating production
storage and ofoading in Gulf of Mexico
1
2
6
1989 – First U.S. tension leg platform – Jolliet at 1,760 feet
– 3D seismic processing begins
– Subsalt drilling begins
2003 – Discoverer Deep Seas drillship hits frst well deeper
than 10,000 feet
3
4
1997 – Longest tieback constructed – Mensa 5
7
8
9
1 2 3 4 5 6 7 8 9
Figure 1-20. Federal Outer Continental Shelf (OCS) Oil
as a Percentage of Total U.S. Production, 1960–2009
CHAPTER 1 - RESOURCES AND SUPPLY 83
component in the success of the industry in deepwa-
ter regions of the Gulf of Mexico.
Additional development potential exists in areas
that have largely been under exploration and develop-
ment moratoria for most of the past two decades, in
particular the Eastern Gulf of Mexico and the Atlantic
and Pacifc OCS. Estimates of the undiscovered tech-
nically recoverable resources of crude oil in U.S. of-
shore moratoria areas vary from 18.2 to 63.0 billion
barrels. In contrast, the BOEMRE mean estimates
of total U.S. lower-48 ofshore undiscovered techni-
cally recoverable oil are 59.3 billion barrels.
3
Although
these estimates include a wide range of assumptions,
their sheer magnitude demonstrates that a signifcant
resource base remains available for future ofshore oil
production.
Canada O?shore
In Canada, ofshore hydrocarbon production
comes exclusively from its Atlantic margin, with nat-
3 Minerals Management Service, “Assessment of Undiscovered
Technically Recoverable Oil and Gas Resources of the Nation’s
Outer Continental Shelf, 2006,” February 2006.
ural gas and oil being produced in Nova Scotia and
Newfoundland ofshore.
In ofshore Newfoundland, production in the
Jeanne d’Arc Basin of the Grand Banks started in
1997 with the Hibernia feld followed by the Terra
Nova and White Rose felds in 2002 and 2005, respec-
tively. From an initial annual production of 1.3 mil-
lion barrels in 1997, production reached 97.7 million
barrels in 2009, with a peak production of 134.5 mil-
lion barrels in 2007. In 2009, average daily produc-
tion was 340 thousand barrels per day. Cumulative
oil production reached 1,125 million barrels in April
2010 (Figure 1-21).
While Canadian ofshore production and develop-
ment plans are confned to the Newfoundland and
Nova Scotia sectors of the Atlantic margin, explora-
tion activities (seismic and drilling) are planned in
both areas and their less explored domains (Lauren-
tian, Sydney, Orphan, and Flemish Pass sub-basins)
that are under the Canada-Nova Scotia Ofshore
Petroleum Board (CNSOPB) or Canada-Newfound-
land and Labrador Ofshore Petroleum Board
(CNLOPB) rules.
Figure 1-21. Total Monthly Oil Production – Ofshore Newfoundland and Labrador
0
2
4
6
8
10
12
14
1997 1999 2001 2003 2005 2007 2009 2011
M
I
L
L
I
O
N
B
A
R
R
E
L
S
NORTH AMETHYST
WHITE ROSE
TERRA NOVA
HIBERNIA
Source: Canada-Newfoundland and Labrador Ofshore Petroleum Board.
Figure 1-21. Total Monthly Oil Production – Ofshore Newfoundland and Labrador
84 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Te Gulf of St. Lawrence has been recently evalu-
ated to host an in-place best estimate (P50) of
41 Tcf of gas and 2,500 million barrels of oil, largely in
Carboniferous reservoirs. A signifcant gas discovery
(77 Bcf) was made in this basin in 1970. Except for
restricted zones under the jurisdictions of CNSOPB
or CNLOPB, most of the Gulf area is under a de facto
moratorium. Te non-regulated area is currently the
subject of jurisdiction discussions between the federal
and provincial governments. Areas under the juris-
diction of the CNSOPB and CNLOPB are, however,
open for exploration. Seismic acquisition is planned
in the CNLOPB area in 2011.
Te Georges Bank area (ofshore Nova Scotia) is
evaluated to host 3,500 million barrels of in-place
oil resources. Te area is currently under an explora-
tion moratorium, which has been recently extended
to 2015.
Te Pacifc margin of western Canada is under a
de facto moratorium, though no ofcial legislation
has been put in place. Tere have been no discoveries
in this area, and the best estimate (P50) indicates the
presence of in-place resources of 43.4 Tcf of gas and
9,800 million barrels of oil.
Of all the areas under legislated or de facto mora-
toria, the Gulf of St. Lawrence is the one most likely
to be opened for exploration in the next 5 to 10 years.
Production Pathways
Potential production from the ofshore areas can be
infuenced by a variety of factors including technology
progress, access to ofshore leases, the economic envi-
ronment, infrastructure development, environmental
risk management capabilities, and geology. Here we
set out a reasonably unconstrained production poten-
tial and contrast it with a more constrained view,
thus defning the range for U.S. lower-48 ofshore oil
production.
Te unconstrained case is characterized by a
favorable economic environment with buoyant oil
demand, increased access to ofshore lands, and
accelerated technological progress. Conversely, the
constrained case assumes lower oil demand, limited
access to ofshore zones, and slower technological
improvement.
In particular, alternate cases published in the
Energy Information Administration’s Annual
Energy Outlook are based on scenarios and sensi-
tivities with expanded ofshore access, accelerated
technology deployment and high oil price environ-
ments. Production of oil in U.S. lower-48 ofshore
increases from 1.7 million barrels per day in 2010 to
2.3 million barrels per day in 2035, in the high oil
price case, according to the fnal results of AEO2011
(Figure 1-22).
Te bulk of the expected increase in U.S. ofshore
oil production is likely to come from new discover-
ies in deepwater and ultra-deepwater regions of the
Gulf of Mexico, such as the Lower Tertiary trend.
Te Lower Tertiary is recognized as a huge resource
with the potential for long-life projects of up to 30 to
40 years and the opportunity to enhance recoveries
through advancing technology.
Te AEO2011 Low Oil Price case provides insight
into the lower or more constrained development
pathway. Production of oil decreases from 1.8 mil-
lion barrels per day in 2010 to 1.4 million barrels of
oil per day in 2035. Tat level could be even lower
if more restrictive operational safety requirements
and legislative policies were passed and imple-
mented, following the 2010 Macondo oil spill in the
deepwater Gulf of Mexico. Tis occurrence would
afect the rate of development and production of
deepwater and ultra-deepwater oil and gas prospects
in general, and the lower tertiary trend in particu-
lar. Te overall efect would be to increase drill times
along with exploration and development costs, and
thus slow signifcantly expected production over the
next 10 years and dampen long-term output from the
U.S. ofshore. Production could be 20% lower by 2035
if long-term moratoria were reinstated as a result of
the Macondo oil spill in the deepwater Gulf of Mexico
and no development takes place outside the central
and western Gulf of Mexico.
Kcy O?shorc Tcchnologics
Over the past 100 years, the petroleum industry
has demonstrated an ability to develop breakthrough
technologies that made a signifcant impact on fnd-
ing and producing oil and gas. Drilling rigs, wireline
logging, logging while drilling, geophysical surveys,
subsea systems, and enhanced oil recovery, to name
a few, have fueled an incredible century of progress.
Tey provide diverse examples of efective existing,
emerging, and future technologies that will expand
CHAPTER 1 - RESOURCES AND SUPPLY 85
the frontiers of exploration and production. Cer-
tainly each of them continues to play a critical role
in increasing production growth in North America.
But industry is now faced with continuing and even
growing challenges in the ofshore, trying to grow
production in deep water, often with poor subsurface
images, in remote areas with limited infrastructure,
in deeper, often hostile, high pressure high temper-
ature environments, and fnally doing all of this in
a basin that is becoming more mature. Te Gulf of
Mexico is one of the most important regions in the
United States for energy resources and infrastructure,
accounting for just under 30% of total U.S. oil pro-
duction and 13% of total natural gas production.
Figure 1-23 illustrates that over 70% of that of-
shore oil production in the Gulf comes from deep
water, accounting for almost a quarter of U.S. oil
production – and the amount is rising.
Future, successful exploration and development
in both maturing open and currently restricted
OCS areas will be critical to maintain North Ameri-
can oil and gas production. Operations must be con-
ducted with improved safety measures while con-
trolling costs. Tackling these challenges will involve
continued use of existing technologies. To improve
success and increase production and recovery, espe-
cially in the Gulf of Mexico Lower Tertiary, develop-
ment of new technologies will be necessary to ensure
challenges are overcome.
Topic Paper #1-3, “Ofshore Oil and Gas Supply,”
associated with this report, builds of the excel-
lent commentary made in the two technology topic
papers that accompanied the 2007 NPC study Hard
Truths: Facing the Hard Truths about Energy. Te frst
of these papers, “Exploration Technology,” identi-
fed fve technology areas in which future develop-
ments have the potential to signifcantly impact
exploration results over the next 25 years. Te sec-
ond, entitled “Deepwater,” identifed four top pri-
ority deepwater-specifc technological challenges
most important to future deepwater development.
Te following is a summary of the key technologies
from the papers.
Figure 1-22. Projection U.S. Lower-48 Ofshore Oil Production
0
1
2
2.5
2010 2015 2020 2025 2030 2035
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011 AEO2011 REDUCED OCS ACCESS 2011)
AEO2011 HIGH OCS 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-22. Projection U.S. Lower-48 Ofshore Oil Production
86 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
“Exploration Tcchnology” Topic Papcr
4
y Core Technology Areas:
? Seismic
? Controlled Source Electromagnetics (CSEM)
? Interpretation Technology
? Earth Systems Modeling
? Subsurface Measurements.
y Auxiliary Technologies – Future developments or
applications that have the potential to signifcantly
impact exploration results by 2030:
? Drilling Technology
? Nanotechnology
? Computational Technology.
4 Cassiani et al., “Exploration Technology,” Topic Paper, National
Petroleum Council Study, Hard Truths: Facing the Hard Truths
about Energy, 2007.
“Dccpwatcr Tcchnology” Topic Papcr
5
y Top Priority Deepwater-Specifc Challenges:
? Reservoir Characterization
? Extended System Architecture
? High-Pressure and High-Temperature (HPHT)
Completions Systems
? Metocean Forecasting and Systems Analysis.
y Related topics discussed in other reports:
? Subsalt imaging
? Gas to Liquids
? Arctic.
y Other Important Deepwater Technologies Consid-
ered:
? Infrastructure life extension
5 Conser et al., “Deepwater,” Topic Paper, National Petroleum
Council Study, Hard Truths: Facing the Hard Truths about
Energy, 2007.
Figure 1- 23. Annual Oil Production Trend from Ofshore Shallow and Deepwater Ofshore Outer Continental Shelf
0
100
200
300
400
500
1978 1980 1985 1990 1995 2000 2005 2010
V
O
L
U
M
E
M
I
L
L
I
O
N
S
O
F
B
A
R
R
E
L
S
YEAR
DEEPWATER GULF OF MEXICO OIL PRODUCTION
SHALLOW WATER GULF OF MEXICO PRODUCTION
Source: Bureau of Ocean Energy Management, Deepwater Gulf of Mexico 2009: Interim Report of 2008 Highlights,
OCS Report MMS 2009-016.
Figure 1-23. Annual Oil Production Trend from Ofshore Shallow and Deepwater Outer Continental Shelf
CHAPTER 1 - RESOURCES AND SUPPLY 87
? Virtual prototyping
? Unconventional options.
Tese papers also provided suggestions and options
for accelerating development and use of technol-
ogy and identifed two issues critical to successful
development of oil and gas resources in ever-harsher
environments. Tese are: (1) future marine technol-
ogy leadership and (2) valuing technology to enable
access.
Te “Ofshore Oil and Gas Supply” topic paper
accompanying this report (available on the NPC web-
site) evaluates technologies that will enable growth
of ofshore production for the next 40 years, based
on discussion among the Ofshore Subgroup mem-
bers, colleagues within our respective companies
and organizations, as well as extensive literature
search, including the 2007 NPC study Hard Truths
Technology Topic Papers. To prioritize technologies,
two surveys were submitted to professionals in the
various key disciplines of geology, geophysics, petro-
physics, reservoir engineering, drilling engineering,
completion, and production engineering for feed-
back. Te frst survey asked the participants to rate
oil and gas production capacity growth challenges
and enablers that are included in the 2010 NPC
Petroleum Resource Template. Te second survey
was based on the 2007 NPC Hard Truths topic papers
and asked participants for feedback on the previ-
ously identifed core technologies listed above and
any additional ones that would signifcantly impact
growth in production, concluding with a ranking
of the technologies. Not surprisingly, the surveys
showed that many of the priorities have not changed
from the previous topic papers and the diferences of
note are due primarily to the focus on ofshore deep
water.
Key changes from the 2007 report include mov-
ing Drilling and Computational Technology from the
auxiliary level to the core level and the addition of
Improved and Enhanced Oil Recovery, where a large
target of recoverable remaining oil in place exists.
Extended Architecture is central to any discussion
on the growth of oil and gas production and is dis-
cussed together with including Completions and Digi-
tal Fields. High-Pressure High-Temperature (HPHT)
Completions Systems certainly remains a key tech-
nology category, but in this report will be tackled as
HPHT environment in the various core technologies
that it impacts. Te only technology no longer on the
core list is CSEM. Although that tool can reduce the
exploration risk in CSEM-suitable settings, it was not
ranked at the level of the other core technologies and
would now be included at the auxiliary level. Of fnal
note, a brief update on the status of industry plans for
containment is included under the Drilling Technol-
ogy section of the “Ofshore” topic paper. As such, the
updated list of core technologies that will be critical to
oil and gas capacity growth ofshore are:
y Scismic – Utilization of man-made acoustic waves
to image the subsurface geology has been a game
changer, allowing industry to unlock the explora-
tion potential of the deepwater Gulf of Mexico and
optimize the development of discoveries. Tech-
nical advances in imaging algorithms, processing
fows and acquisition geometries are underway
that could make improvements in imaging neces-
sary to expand existing and emerging hydrocarbon
bearing trends as well as identify new ones.
y Computational Tcchnology – A key enabling
technology. While not invented by the oil and gas
industry, studies have concluded that this indus-
try has propagated digital technologies, altered its
management and organization, and changed the
way people connect to the data far more than any
other industry. Te value delivered from the accom-
panying technologies in this list would not be pos-
sible without it.
y Intcrprctation Tcchnology – Has played a sig-
nifcant role in the impact of 3D seismic on success
rates. With the adaptation of tools used in other
industries, such as medical imaging, interpreters are
now able to visualize and interpret data much faster.
Tey are not limited to thinking in 3D, but literally
can visualize in 3D, or “climb into” the data set.
y Earth-Systcms Modcling – Encompasses geology,
hydrology, climatology, and other applied sciences
involved in studying the earth as an integrated
system. Earth systems modeling joins basin and
petroleum system modeling together to quantita-
tively model a sedimentary basin’s deposition, ero-
sion, and heat fow history together with essential
elements of the Petroleum System (source, overbur-
den, reservoir, seal) and critical processes (trap for-
mation, generation and migration, accumulation,
preservation) during the evolution of a sedimen-
tary basin.
6
6 L. B. Magoon and W. G. Dow, Te petroleum system—From
source to trap, American Association of Petroleum Geologists
Memoir 60, Tulsa, Oklahoma, 1994.
88 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Drilling – Industry has come a long way from the
days of dropping a heavy bit down the hole to chisel
away the soft rock formations. In 1909, the two-
cone rotary bit unlocked the full potential of the
rotary drilling system, allowing for the efcient
drilling of wells in much deeper, harder rock envi-
ronments. Further advances followed with direc-
tional and horizontal drilling, top drives, and rotary
steerable assemblies. Te trend for conventional oil
and gas discovery has been to drill in environments
that were previously inaccessible. Traditionally this
means drilling deeper into hotter and higher-pressure
zones and to do so in ever more extreme environ-
ments such as ultra-deepwater. Historically the
only way to access these zones is to get bigger rigs,
stronger steel, and more durable tools and there is
little reason to believe this trend will not continue.
New rigs coming out are capable of drilling in up to
12,000 feet of water and 40,000 feet total depth.
y Subsurfacc Mcasurcmcnts – At the turn of the
20th century, oil industry pioneers began to
search for ways to obtain information about what
the drill bit was encountering. Tis led to devel-
opment of core sampling and mud-analysis of
the wellbore cuttings (mud logging) that came to
the surface. Beginning in 1978, one of the most
infuential technologies for drilling and subsur-
face measurement occurred when Teleco intro-
duced the frst commercial measurement while
drilling (MWD) tool, enabling operators to know
the location of their well while drilling. Within a
decade, Schlumberger introduced the other criti-
cal technology, logging while drilling, or LWD,
which allowed geoscientists to get petrophysical
measurements, similar to openhole wireline logs,
immediately after the bit drilled the formation.
Tis information can then be viewed essentially in
real time on the rig and back onshore in the ofce,
allowing for more timely decisions.
y Rcscrvoir Charactcrization – Involves building
a high-resolution geologic model of the reservoir
that incorporates characteristics key to reservoir
storage and production of hydrocarbons. It con-
sists of a geometric description of the boundary
surfaces, faults, bedding geometries, and a 3D dis-
tribution of reservoir properties such as permeabil-
ity and porosity. Robust reservoir characterization
is critical to predicting and monitoring the produc-
tion behavior in increasingly complex reservoirs
with fewer more costly direct well penetrations.
y Extcndcd Systcm Architccturc – In shallower
water, options for developing the extremities of
felds not reachable by directional drilling from an
existing platform or where costs would not justify
the installation of one or more platforms, drove
the development of subsea well systems and their
accompanying tiebacks. In deep water, this led to
the development of Tension Leg Platforms (TLPs),
semi-submersible foaters and spars that act as
hubs to collect production from multiple subsea
well systems for processing and transportation via
pipeline to shore. Today the term extended system
architecture applies to the combination of these
facilities and includes fow assurance, well control,
power distribution, and data communications to
improve recovery and extend the reach of produc-
tion hubs to remote resources.
y Improvcd and Enhanccd Oil Rccovcry – Boosting
the recovery factor of world’s felds just 1% has the
potential to cover three years of worldwide produc-
tion. Tis increased productivity of hydrocarbons
is known as Enhanced Oil Recovery (EOR) and
Improved Oil Recovery (IOR). Technology for these
types of recovery processes is already in place at
many felds around the world, with EOR primarily
onshore. Techniques for IOR include: waterfood;
subsea processing and pumping such as sea foor
separation, gas lift, multiphase pumps, and electric
submersible pumps; horizontal and multilateral
drilling to expose more of the formation or multiple
formations to the open hole; improved perforation
and stimulation methods; advanced logging proce-
dures; and optimal placement of wells.
7
y Mctoccan Forccasting and Systcms Analysis –
Integrated models to predict both above and below
surface “weather” and engineering system response.
Te ability to characterize and predict the behavior
of the oceans is essential for safe conduct of explo-
ration and production operations ofshore. Te
ability to predict near term conditions for the seas
and currents is necessary to plan and conduct safe
drilling and production operations in the marine
environment and to respond to any hydrocarbon
spill incident.
Kcy Findings
y Oil development and production in the U.S.
lower-48 ofshore is signifcant, and the expecta-
tion is that a production growth trend will extend
7 S. A. Ali, “Mature Field Revitalization,” Technology Focus: Jour-
nal of Petroleum Technology, January 2009.
CHAPTER 1 - RESOURCES AND SUPPLY 89
to the year 2050. Te Ofshore Subgroup expects
ofshore oil production to increase to the year
2035 by an average annual growth rate range of
0.2% to 0.9%.
y According to the AEO2011, crude oil production in
the U.S. lower-48 ofshore is expected to rise up to
2.3 million barrels per day in 2035 in the high oil
price case.
y Beginning around 2020 and extending to the year
2050, the bulk of oil production in the U.S. lower-
48 ofshore is expected to originate from the deep-
water Gulf of Mexico, in the emerging Lower Ter-
tiary trend and the extension of existing and new
trends into areas that are currently poorly imaged.
Also, we expect additional impacts on production
from increased access to the Pacifc, and the Atlan-
tic ofshore regions.
y Government policies favorable to accessing more
U.S. lower-48 ofshore lands are needed to allow
for the occurrence of the oil and gas development
and production growth rates mentioned above.
y A slowdown and a postponement of ofshore oil
and gas development and production are expected
if more stringent operational safety requirements
and environmental policies are implemented in
the OCS following the Macondo oil spill in the
deepwater Gulf of Mexico.
y Technological progress and innovation are the key
factors that would enable development and produc-
tion of oil and gas in new frontier regions located in
deep water and in deeper reservoirs. Most notably,
technologies adapted to the high-pressure high-
temperature (HPHT) environment, delivery rates,
and reduction of drilling costs are the key drivers
for the huge oil and gas resources hosted in the
Gulf of Mexico Lower Tertiary formations. Tese
formations have potentially greater than 15 billion
barrels of recoverable oil reserves, some of which is
located in areas of at least 60 miles from the near-
est infrastructure. Te challenges of this environ-
ment cross multiple disciplines and advances in
technologies associated with seismic imaging,
completion and casing design, subsea production
equipment, subsea processing, and high integrity
pressure protection systems, while underway, need
to continue, if not accelerate. HPHT applications to
10 thousand pounds per square inch (ksi) and 250oF
are common in today’s market and the envelope has
pushed out to 15 ksi and 400oF, with some limited
gaps. However, now the envelope is being pushed
even further to 20–30 ksi and >400oF in the shal-
low water gas play of the Lower Tertiary trend.
y Seismic innovative technologies that allow for
better imaging of the subsalt horizons in the Gulf
of Mexico are pivotal to the expansion of hydro-
carbon resources via additional newer discover-
ies. Tese include imaging algorithms, acquisition
geometries, and inclusion of more azimuths in pro-
cessing and retention of high frequencies.
y An extrapolation of the top 500 supercomputer per-
formance lists predicts Exascale computing capabil-
ity with a 1,000-fold increase in processing capa-
bility within 10 years. With some seismic vendors
today approaching the level of computing capability
seen with the national computers on the top 500
list, it will be exciting to see what challenges can be
conquered with the Exascale computing level, such
as near real-time seismic imaging.
y Tere is a need to reduce drilling costs so that many
more exploration wells can be drilled, allowing com-
panies to test more concepts and perhaps encour-
age more improved and enhanced oil recovery
programs. Dual gradient drilling is one such con-
cept scheduled to be implemented in the deepwater
Gulf of Mexico this year.
y Subsea technology and extended architecture sys-
tems will boost production of ofshore oil in remote
and challenging environments of the deepwater
and ultra-deepwater areas, which lack the basic
infrastructure needed to produce and to transport
the hydrocarbons to shore.
y Te ofshore feld of the future, which we are not far
from today, will have multiple satellite felds pro-
duced via subsea completions and long tiebacks to
hub facilities. Te subsea manifolds will be equipped
with remote power and communication ability, so
remote surveillance and control functions are avail-
able at the hub as well as the onshore production
center. Smart equipment will be deployed on the
seafoor and downhole that will accept commands
from the ofshore hub or onshore center to improve
reservoir production efciency. Sophisticated mod-
els of the reservoir, well, and processing systems will
be kept up to date and running online, so surveil-
lance is a “manage by exception” process. Field opti-
mization will be regularly reviewed and based on
analysis so that asset managers can make decisions
when opportunities are encountered, instead of pro-
ducing to a plan that may be months to years old.
90 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Tere have been signifcant advances in subsurface
measurement over the last decade, but the demand
for increased resolution and data will require
improved real-time transmission methods. Te
need to improve downhole fuid characterization
and reservoir parameter data for in situ properties,
and to monitor wells down-hole for longer periods
will be critical to predicting feld performance in
more challenging environments.
y Improved and enhanced oil recovery techniques
could reach an additional 44 billion barrels of oil
equivalent left in discovered felds at abandonment.
Tis is based on data from more than 80 felds and
450 reservoirs developed in the Deepwater Gulf of
Mexico Research Partnership to Secure Energy for
America project 07121-1701, entitled “IOR of the
Deepwater Gulf of Mexico.”
y In the U.S. lower-48 ofshore, newer geologic plays
and trends such as the Lower Tertiary and deeper
reservoirs are expected to contribute to current and
near future production of crude oil and natural gas.
y Canadian ofshore production of oil is lower in com-
parison to the U.S. lower-48, and is confned to the
eastern shore in Newfoundland and Nova Scotia.
Removal of the imposed and the de facto moratoria
will provide better opportunities for increasing of-
shore oil development and production in ofshore
Canada.
Arctic
History and Contcxt
For the purposes of this study, the Arctic is defned
as those areas in Alaska, Canada, and Greenland sub-
ject to ice and permafrost conditions, rather than sim-
ply those areas north of the Arctic Circle. Greenland
is included, even though it is a territory of the king-
dom of Denmark, as any future oil production from
Greenland would very likely be supplied to the U.S.
and/or Canadian oil markets. Te map in Figure 1-24
shows the areas in Alaska, Canada, and Greenland
covered in this portion of the study, within the red
dotted line.
Te Arctic study area is estimated to contain over
7 billion barrels of discovered undeveloped and over
90 billion barrels of mean, risked, technically recov-
erable undiscovered volumes of oil and NGLs. Tese
LABRADOR
NEWFOUNDLAND
U.S.
CANADA
GREENLAND
STUDY AREA
ARCTIC CIRCLE
INTERNATIONAL
BOUNDARY
BEAUFORT
CHUKCHI
NORTH
ALASKA
BERING
SHELF
PACIFIC MARGIN
SOUTH ALASKA
CENTRAL
ALASKA
MACKENZIE
DELTA/
CENTRAL
BEAUFORT
CANADA NORTH
ONSHORE BASINS
ARCTIC ISLANDS/
SVERDRUP BASIN
EAST CANADA
WEST GREENLAND
EAST
GREENLAND
RIFT BASINS
NORTH GREENLAND SHEARED MARGIN
Figure 1-24. Arctic Subgroup Study Area
ARCTIC CIRCLE
Sources: Bureau of Ocean Energy Management, Regulation and Enforcement; Canada-Newfoundland Ofshore Petroleum Board; IHS
Inc.; National Energy Board of Canada; and United States Geological Survey.
Figure 1-24. Arctic Subgroup Study Area
CHAPTER 1 - RESOURCES AND SUPPLY 91
volumes are highlighted on the map in Figure 1-25,
which indicates their location by basin, and are
described in Finding 1 later in this section. Additional
information can be found in Topic Paper #1-4, “Arctic
Oil and Gas,” available on the NPC website.
Figure 1-26 shows how the crude oil resources
described above are distributed among Alaska, Can-
ada, and Greenland and highlights the amount of
undiscovered oil resources that lie in areas currently
under moratoria or otherwise unavailable for leas-
ing. Tese are world-scale resources, which will need
to be validated by exploration and development drill-
ing activity in order to enable production from the
2025–2050 time frame.
Te long history of onshore and ofshore oil and
gas leasing/licensing and exploration drilling in the
Arctic region has resulted in discovery of signifcant
oil and gas reserves, some of which have been devel-
oped and produced, most notably the giant oil and
gas feld at Prudhoe Bay on the Alaska North Slope
and the large oil and gas felds (onshore and ofshore)
in Cook Inlet, Alaska, as well as numerous stranded
discoveries (no development/production facilities or
pipelines). Experts expect the region to contain sig-
nifcant yet-to-be-found volumes, based on numer-
ous government agency estimates and supported
by industry interest (leasing/licensing, historical
2D seismic and modern but limited 3D seismic, and
renewed attempts to secure regulatory permission
to drill particularly in the ofshore). Most of these
volumes are expected to be ofshore, beneath the
continental shelf.
Following is a brief summary of the development
and production history for the most signifcant of the
main Arctic areas under consideration.
North Alaska Onshore
Exploration of this region began in 1909 with dis-
covery of active oil seeps in the Cape Simpson area
of what is now the Northwest National Petroleum
Reserve–Alaska (NPR-A). In 1945, the frst explora-
tion drilling resulted in non-commercial fnds until
the discovery of the giant Prudhoe Bay Field in 1968
(15 billion barrels oil and 27 Tcf gas recoverable).
Notes: Discovered undeveloped plus mean risked, technically recoverable, undiscovered volumes by basin. Prospective basins
highlighted in green for Alaska, in yellow for Canada, and in blue for Greenland.
BBO = billion barrels of oil; BBNGL = billion barrels of natural gas liquids.
A
RCTIC CIRCLE
1.3
0 0.2
0.1
1.7
0
0.7
0
16.7
0.8
15.4
0.7
9.9
0.1
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0.6
0
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0
1.4
0.2
8.9
8.1
5.9
0.9
4.8
0.7
2.7
0
BBO + BBNGL
BBO
BBNGL
INTERNATIONAL BOUNDARY
DISPUTED ZONE
Figure 1-25. Arctic Oil and Natural Gas Liquids Resources
Figure 1-25. Arctic Oil and Natural Gas Liquids Resources
92 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Prudhoe Bay helped drive the construction of the
Trans-Alaska Pipeline System (TAPS), completed in
1977, and ushered in a new era of exploration. Over
400 exploration wells have been drilled in this region,
mostly in the North Slope Coastal Plain, and have
resulted in the discovery of numerous felds, many
of which are currently producing. Te northern dis-
coveries are primarily oil and gas, while the south-
ern discoveries are largely non-associated gas with
some possibility of oil. Natural gas is not exported
due to the lack of a gas pipeline and most of the gas is
re-injected back into producing reservoirs to enhance
oil recovery. Prospective areas outside the North
Slope Coastal Plain (NPR-A, North Slope Foothills,
and the Arctic National Wildlife Refuge, 1002 Area
[ANWR 1002]) are signifcantly underexplored.
North Alaska O?shore
Exploration drilling in the federal portion of the
Beaufort Sea area began in earnest following the
1968 discovery of the Prudhoe Bay Field (onshore)
and the completion of TAPS in 1977. Te frst ofer-
ing occurred in a joint federal/state lease sale held
in 1979. Tis and subsequent OCS lease sales, the
most recent of which was held in 2007, have allowed
access to waters beyond the three-mile limit. Explor-
atory eforts since 1970 (~90,000 miles of 2D seis-
mic and 30 exploration wells) have yielded four
discoveries that have been deemed capable of pro-
duction and have been termed signifcant discov-
eries by BOEMRE and the Alaska Division of Oil &
Gas. Tree of these discoveries, Hammerhead (Sivul-
liq), Sandpiper, and Liberty, are completely in OCS
waters but have not yet been developed. Te fourth
discovery, Northstar, underlying both federal and
state waters, has been developed and producing oil
since 2001.
With respect to the Chukchi Sea, in the early 1980s,
BOEMRE (formerly MMS) determined that this area
had a large resource potential and that long-term
oil pricing would support exploration and develop-
ment. BOEMRE held the frst lease sale (Sale 109)
covering this prospective area in 1988, ofering more
than 25 million acres. Industry drilled fve explora-
tion wells from 1989 to 1991, and demonstrated a
working petroleum system with strong afnities to
Figure 1-26. Split of Arctic Oil Potential (not Including Natural Gas Liquids)
Note: Discovered undeveloped plus undiscovered (mean risked, technically recoverable).
GREENLAND
AVAILABLE 17%
CANADA
AVAILABLE
20%
ALASKA
AVAILABLE
37%
ALASKA
MORATORIA
AREA 13%
ALASKA POTENTIALLY
AVAILABLE FOR LEASE 4%
CANADA
UNAVAILABLE 6%
GREENLAND
UNAVAILABLE 2%
ALASKA'S TOTAL SHARE 55%
CANADA'S TOTAL SHARE 26%
GREENLAND'S
TOTAL SHARE
19%
Figure 1-26. Split of Arctic Oil Potential (not Including Natural Gas Liquids)
CHAPTER 1 - RESOURCES AND SUPPLY 93
the North Slope and Beaufort Sea regions. Four of
the fve wells contained reservoirs with oil and gas
“pay,” as defned by BOEMRE, and the ffth well-
demonstrated oil and gas shows. Tese wells were
drilled 60 miles or more of of the coast in water
depths ranging from 137 to 152 feet. Although none
of the prospects were deemed commercial at the
time, existence of a working petroleum system was
demonstrated.
Canadian North
In the Canadian North, oil and gas exploration
dates back to the recognition of oil seeps in the 1700s
and the 1920 discovery of the Norman Wells oil
feld (0.3 billion barrels oil recoverable). Te late
1940s and 1950s saw increased exploration in the
southern portion of the Northwest Territories.
Exploration then moved northward above the Arc-
tic Circle, frst into the Mackenzie Delta in 1960,
then the Arctic Islands and Sverdrup Basin in 1961
and the Canadian Beaufort Ofshore in 1972. Many
signifcant oil and gas felds (Parsons Lake, Taglu,
Niglintgak, Drake Point, Adlartok, Tarsiut, Issung-
nak, Amauligak, and Kopanoar accumulations) were
found. Tese discoveries were the result of an exten-
sive exploration efort that resulted in 213 wells
drilled in the onshore Mackenzie Delta, 174 wells
in the Arctic Islands/Sverdrup Basin, and 87 wells
in the ofshore Canadian Beaufort. Drilling activ-
ity in these areas subsided in the late 1980s, but
high global energy prices in 2004–2008 combined
with the proven occurrence of oil and gas renewed
industry’s interest in this region. Canadian Beau-
fort licensing rounds in 2007–2010 drew signifcant
industry interest. Six exploration licenses covering
three million acres were issued to ExxonMobil/Impe-
rial, BP, ConocoPhillips, and Chevron for working
commitment of 1.89 billion Canadian dollars. Explo-
ration activities commenced in 2008-2009 with the
acquisition of 3D seismic data and exploratory drill-
ing may commence as soon as 2014.
Canadian East
Te Labrador-Newfoundland Shelf region ofshore
is one of two promising areas within the Canadian
East. It contains the Saglek, Hopedale, Hawke,
Orphan, Jeanne d’Arc, and Flemish Pass ofshore
basins. Tese basins reside along the Continen-
tal margin in water depths ranging from less than
100 meters to greater than 3,000 meters. Explora-
tion in this ofshore region began in 1966. Wildcat
drilling started in 1971 and continued through 1984.
Discoveries along the Newfoundland portion of this
margin yielded signifcant oil and gas reserves in the
Jeanne d’Arc Basin including the giant Hiber-
nia (1979), Hebron/Ben Nevis (1981), Terra Nova
(1983), and White Rose (1984) felds. Development
of the Hibernia feld, as well as the Terra Nova and
White Rose felds, has resulted in the cumulative
production of 1 billion barrels of oil as of 2009 and
development of Hebron/Ben Nevis is planned. In
2004, a second wave of licensing and exploratory
drilling began in this region in the Flemish Pass and
Orphan Basin areas. Several wells have been drilled
with an announced discovery in the Flemish Pass
area. Another promising area, described below, is the
Canadian portion of the Bafn Bay region, an area
shared with Greenland.
Greenland
Te West Greenland-East Canada Province includes
the ofshore region of eastern Canada and western
Greenland from approximately latitude 63° north to
80° north. Oil seeps have been sampled and described
from Nuussuaq Peninsula, Disco Island, and Fossilik
outcrops on the west coast of Greenland and have
been reported at Scott Inlet on the Canadian side.
Tirteen exploration wells (three wells on the Cana-
dian and ten on the Greenland side) have been drilled
in this area and several have demonstrated the pres-
ence of hydrocarbons. Licensing of numerous tracts
has continued on the Greenland portion of the basin
with the most recent licenses being awarded in 2010.
Cairn Oil drilled three exploration wells on their
ofshore licenses in 2010 and announced that two
wells had encountered thermal gas and that one well
encountered oil. Cairn has returned to this region in
2011, and is currently drilling additional exploration
wells on their licenses.
Te East Greenland Rift Basin also looks very prom-
ising, based on a recent USGS assessment. Greenland
intends to hold the frst licensing round for this of-
shore region in 2012. Licenses in this region will fea-
ture a 16-year term.
Tcchnology
Hydrocarbon resources identifed in the Arctic
region are mainly conventional oil and gas for which
exploration, appraisal, and production technologies
94 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
are well understood and widely available for regions
residing in shallow water (less than 100 meters)
and those areas not impacted by signifcant icebergs
(such as the continental shelves of the Alaska OCS
and the Canadian Beaufort and Grand Banks region).
Technology has not been a limiting factor in the
development of the Alaska North Slope, (both onshore
and in State waters), in Cook Inlet in southern Alaska
(onshore and ofshore), ofshore on the Newfound-
land-Labrador shelf, and for exploration activity in
the Chukchi and Beaufort Seas and ofshore Green-
land. In the Arctic, however, as in other regions, the
deployment of technology particularly needs to take
into account the protection of sensitive ecosystems
from an environmental standpoint.
Awareness of environmental imperatives has led to
signifcant technological advances by the oil indus-
try, in order to achieve safe resource extraction with
minimal disturbance to the environment. To cite
two examples among many: the oil and gas indus-
try developed the Rolligon that allows heavy loads
to be carried across the Arctic tundra with minimal
ground pressure and disturbance; and horizontal-
and extended-reach drilling technology that makes it
possible to drill multiple wells from a single pad at
less cost and with a smaller environmental footprint
than the traditional multiple pad approach.
Te certainty that technology and related practices
to prevent and mitigate environmental risks associ-
ated with the Arctic will continue to be enhanced
led the Arctic Subgroup to conclude that technology
is not likely to limit onshore or ofshore exploration
and development, except in regions where water
depths exceed 100 meters or where signifcant iceberg
management is necessary. Near-term advances in
ofshore pipeline trenching will be important across
the Arctic, especially in deepwater conditions (over
100 meters of water depth) such as the Continental
Slope region of the Canadian Beaufort, Labrador, or
Greenland. Advances in iceberg management will also
be important for Greenland and portions of the Cana-
dian Atlantic ofshore. Te history of the region indi-
cates that innovation will continue as new challenges
are identifed. Tere are many Arctic producing felds
on land today, and safe development and production
of ofshore Arctic reserves has occurred since the late
1960s (Cook Inlet and Northstar Field, Alaska; Hiber-
nia, Canada; and Sakhalin, Russia) demonstrating
that resource extraction can occur in the midst of sen-
sitive ecosystems.
Since the Arctic region is primarily defned by harsh
ice conditions that afect drilling operations and envi-
ronmental risk management, the Arctic Subgroup
undertook an assessment of the severity and impact
of ice conditions across the various Arctic basins stud-
ied here. Te study draws on the experience of over
450 existing wells ofshore in the western Arctic, as
seen in Figure 1-27.
Ofshore basins where this activity has taken place
experience all three dominant types of ice conditions
(land-fast ice, pack ice, and icebergs). Table 1-5 sum-
marizes the key characteristics of each basin. Ice
conditions impact most aspects of exploration and
development activities and technology, including
seismic acquisition, drilling equipment, well design,
and support feet (including oil spill response capa-
bilities). Te study team used these parameters
to develop a comparison across all Arctic basins,
including those located north of Norway and Russia,
of the technology and development challenges asso-
ciated with ice-regime impacts. Tis comparison is
summarized in Figure 1-27.
Figure 1-28 illustrates the wide range of technical
and operational challenges that are present through-
out the major global Arctic basins. Tis assessment
shows that these challenges have been met at both
the exploration and development phase.
Arctic ofshore exploration is centered in North
America and the industry has demonstrated its
ability to function through the full range of Arctic
operating conditions with more than 450 existing of-
shore wells. Experience in the Arctic spans a period
from the 1960s to the present day, and so it comes as
no surprise – though for many in the general public
it may – that industry has accomplished a wealth of
successful operating experience in diverse Arctic of-
shore conditions. Te strength of experience gained
in challenging operating environments such as in
the Canadian Beaufort Sea and the Labrador Sea
(Canada) should build confdence that industry has
the tools, procedures, and know-how to operate safely
throughout the ofshore Arctic.
Arctic ofshore production history refects the same
level of success as demonstrated through the drilling
of over 450 exploration wells. While this screening
assessment only cites major production centers such
as the Grand Banks (Canada) and Sakhalin (Russia),
there are other examples such as the Cook Inlet region
(south Alaska) and the various near-shore production
CHAPTER 1 - RESOURCES AND SUPPLY 95
1
2
3
4
5
6
7
1
2
3
4
5
6
7
CHUKCHI SEA 5 WELLS
U.S. BEAUFORT SEA 58 WELLS
CANADIAN BEAUFORT SEA 89 WELLS
CANADIAN ARCTIC ISLANDS 160 WELLS
LABRADOR 29 WELLS
GRAND BANKS 129 WELLS
SOUTHWEST GREENLAND 6 WELLS
~450 ARCTIC OFFSHORE WELLS
Figure 1-27. Wells Drilled in the Ofshore Arctic
5
58
89
160
29
129
6
Figure 1-27. Wells Drilled in the Ofshore Arctic
Figure 1-28. Ice Regime Development Comparison
BARENTS
SEA
GRAND
BANKS
SW
GREENLAND
KARA
SEA
CHUKCHI
SEA
SAKHALIN LAPTEV
SEA
LABRADOR BEAUFORT
SEA
NW
GREENLAND
NE
GREENLAND
INCREASING DEGREE OF DIFFICULTY
Notes: Signifcant levels of oil and gas production are already being produced from Arctic basins such as the Grand Banks (Canada)
and Sakhalin (Russia) in both pack ice and pack ice/iceberg operating environments.
Signifcant operating experience has been successfully gained in several of the more challenging Arctic basins (i.e., U.S. Chukchi
and Beaufort, ~35 wells in open water to pack ice; Canadian Beaufort, ~90 ofshore wells in both open water and pack ice; and
Labrador, ~30 ofshore wells in pack ice and pack ice/iceberg operating environments.
A strong history of successful exploration and production operations across a wide range of Arctic operating conditions and
challenges has demonstrated that industry can explore and develop oil and gas safely in the Arctic.
Figure 1-28. Ice Regime Development Comparison
96 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
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CHAPTER 1 - RESOURCES AND SUPPLY 97
facilities along the U.S. Beaufort Sea coastline (North-
star). Tese projects have demonstrated the ability
for industry to design production facilities in keep-
ing with the regulatory and environmental challenges
that existed in these areas, and thus allow the safe and
efcient production of oil and gas reserves from the
Arctic ofshore.
Fifty years of oil and gas development history in the
ofshore Arctic marks a period of continuous improve-
ment and development that has guided safe, success-
ful Arctic operations in all the major Arctic ofshore
ice environments. Ofshore Arctic operating capabil-
ity is a North American success story that is poorly
understood and appreciated, despite the fact that it
has been ongoing for over half a century.
Potcntial Production Pathways
Given that no overall North American Arctic sup-
ply outlooks could be found in the public domain
(although there are a few basin-specifc analyses for
portions of Alaska and the Canadian Arctic), the Arc-
tic Subgroup developed three consensus cases: Rea-
sonably Constrained, Most Likely, and Reasonably
Unconstrained (Table 1-6). Te adjective “reason-
ably” is used with care; it does not imply that all con-
straints are either turned on or turned of at either
end of the scale. Tese cases represent the Subgroup’s
informed view of what may happen to Arctic develop-
ment through 2050, given economic, regulatory, and
environmental constraints that either are less or more
favorable to such development.
Te three cases each outline a diferent production
scenario for major current or future developments.
Large, remote severely stranded resources (e.g., Cana-
dian Arctic Islands, NE Greenland Rift Basin, etc.) are
not included.
Te most likely production outlook for the Arctic
indicates a 2035 production potential of 0.77 million
barrels per day (282.5 million barrels per year). Tis
includes a normal decline of current Alaska North
Slope production to 0.28 million barrels per day,
augmented by new discoveries on the North Slope, in
the Chukchi and Beaufort Seas, and in Alaska state
waters, totaling 0.3 million barrels per day. Arctic
Canada would provide a further 0.2 million barrels
per day, split between Grand Banks production and
new discoveries in the Canadian Beaufort and Mack-
enzie Delta areas.
Te constrained case outlook assumes that new
exploration activity would not occur because of a
variety of restrictions on access and permitting,
and the only remaining production would be from
currently producing felds that will be in decline
over this period. Total remaining production in
2035 would be just 0.33 million barrels per day
(120 million barrels per year), split between the
Alaska North Slope (if the TAPS pipeline is still in
operation) and the Grand Banks area of Canada. Fur-
ther declines post-2035 would ultimately lead to the
closure of the TAPS oil pipeline as available supply
falls below the assumed operational minimum vol-
umes of about 200 thousand barrels per day. It is
Table 1-6. Three Potential Arctic Oil Production Pathways
Reasonably
Constrained Case
Most Likely Case Reasonably
Unconstrained Case
No Chukchi, Beaufort OCS,
or Canadian Beaufort production
North Alaska onshore, Chukchi
and Beaufort OCS, and Canadian
Beaufort production; 15% resource
developed by 2050
North Alaska onshore, Chukchi and
Beaufort OCS, and Canadian Beaufort
production; 25% resource developed
by 2050
Trans-Alaska Pipeline System
(TAPS) ofine 2030+/-
TAPS ~300 thousand barrels per day TAPS ~500 thousand barrels per day
Grand Banks oil current decline
only Hebron developed
Grand Banks oil slow decline
few satellites developed
Grand Banks fat oil production
No East Canada “Bafn Bay” or
West Greenland oil
No East Canada “Bafn Bay” or West
Greenland oil
East Canada “Bafn Bay” and
West Greenland oil; 10% resource
developed by 2050
98 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
estimated that this could occur around 2045, making
any subsequent development reliant on new infra-
structure.
In the upside case, with a higher level of resource
development in the new ofshore areas of the Arctic,
particularly ofshore the Alaska North Slope, total
production by 2035 could be as high as 0.88 million
barrels per day (322 million barrels per year). Half a
million barrels per day of this could come from high
potential developments in the Beaufort and Chukchi
seas.
It should be noted that the Arctic Subgroup’s oil
production forecast for Alaska may be conservative,
as compared to a published analysis by Northern Eco-
nomics that suggests the U.S. Beaufort and Chukchi
OCS regions are capable of signifcant production,
collectively exceeding 1.0 million barrels per day
(~399 million barrels per year) in 2035 (Table 1-7 and
Figures 1-29 and 1-30), if the undiscovered hydro-
carbon resource assessment reported by BOEMRE is
validated by future exploration and appraisal drilling.
Kcy Findings and Rccommcndations
Tis section summarizes the main fndings and
recommendations of the Arctic Subgroup and applies
primarily to the U.S. Arctic.
Despite its remoteness and harsh operating condi-
tions, safe development of the Arctic region is pos-
sible and essential for meeting U.S. energy goals.
Finding 1 describes the huge portion of America’s
energy that resides in the Alaskan Arctic, but explo-
ration needs to occur now in order to arrest the pro-
duction decline that could threaten viability of the
existing Trans-Alaska Pipeline for crude oil. Findings
2 and 4 note that the limiting factor in recovery of
the Arctic’s vast energy resources is not necessar-
ily technology, but rather regulatory uncertainty
and risk of litigation from groups opposing drilling
and development activity (especially in the United
States). Finding 3 describes specifc U.S. challenges
associated with carrying out an efective and safe
exploration and appraisal program in the Arctic, given
the present 10-year lease terms, since only 70–105
days (ofshore) and 70–150 days (onshore) are realis-
tically available for such activities each calendar year.
Other fndings discuss the impact of the Jones Act,
lack of infrastructure, and how the United States is
falling behind other nations.
Tis study supports the idea that action by the
U.S. federal government is warranted, if these critical
resources are to be validated and safely developed in
a prudent manner for America’s beneft. Or, to put
it in more specifc terms, the main consequence com-
mon to the majority of the following fndings and
recommendations is that the huge resource base, as
described by the U.S. Geological Survey, Bureau of
Ocean Energy Management, Regulation and Enforce-
ment, National Energy Board of Canada, Geological
Survey of Canada, and the various State and Pro-
vincial government resource agencies for the North
American Arctic region, will not be available when
needed in the 2025–2050 time frame or afterwards if
the status quo is maintained.
Finding 1: Te North American Arctic (United
States, Canada, and Greenland) has a large (world
scale) discovered undeveloped hydrocarbon resource
base (6.4 billion barrels oil, 0.9 billion barrels natu-
ral gas liquids, and 73 Tcf gas)
8
and a very large
undiscovered resource base (80.1 billion barrels oil,
11.1 billion barrels natural gas liquids, and 595 Tcf
gas).
9
Development lead times are very long (histori-
cally, 10 to 20 years or longer from discovery to frst
production).
10
Rccommcndation 1: To ensure the future energy
security of the United States, near- and medium-term
exploration drilling by industry should be promoted
by the U.S. government to validate the resource esti-
mates and identify the most promising regions.
Finding 2: Exploration and development technol-
ogy, both onshore and ofshore, is not expected to be
a limiting factor in future development of conven-
tional U.S. Arctic resources, within the time frame
of this study. Areas for further innovation and tech-
nological advances will be required in areas where
water depths exceed 100 meters or regions that
require iceberg management capability (Greenland).
8 Mean, discovered, technically recoverable volume estimate.
Tese discovered volumes are remote to existing development
and production infrastructure. References for all quoted vol-
umes cited in Sections IV, V, VI, and VII of Topic Paper #1-4,
“Arctic Oil and Gas.”
9 Mean, risked, technically recoverable, undiscovered, yet-to-fnd
volumes. References for all quoted volumes cited in Sections
IV, V, VI, and VII of the “Arctic” topic paper.
10 Tomas et al., “Alaska North Slope Oil and Gas: A Promis-
ing Future or an Area in Decline? Addendum Report,” 267 p,
U.S. DOE/NETL/Arctic Energy Ofce, April 2009. Tables 2.5
and 2.6.
CHAPTER 1 - RESOURCES AND SUPPLY 99
Table 1-7. Summary of Alaska OCS Development Scenarios and
Oil and Gas Production Forecasts
Beaufort Chukchi
North
Aleutian
Total
Resource Size (Mean)
Oil and condensates (billion barrels) 5.97 8.38 0.71 15.06
Gas (trillion cubic feet) 15.94 34.43 7.65 58.02
Exploration
Exploration/Delineation Wells 47 43 10 100
Exploration Rig Seasons 31 27 8 66
Development
No. of Ofshore Production Platforms 7 4 2 13
Ofshore/Onshore Pipelines (miles) 235 680 300 1,215
Shore Bases/Facilities
Marine Terminal Yes Yes Yes
Liquefed Natural Gas (LNG) Facility No No Yes
Production Facility Yes Yes Yes
Support Base Yes Yes Yes
Production
Year 1st Oil Flows 2019 2022 2021
Year 1st Gas Flows 2029 2036 2022
No. of Producing Fields 7 4 2 13
Total Cumulative Volume Produced (through 2057)
Oil & Gas (billion barrels of oil equivalent) 6.34 6.16 1.29 13.69
Oil & Condensates (billion barrels) 5.10 4.79 0.39 10.18
Gas (trillion cubic feet) 6.96 7.78 5.08 19.82
Daily Peak Production
Oil & Condensates (barrels per day) 1,165,707 565,472 105,074
Gas (million cubic feet per day) 883 1,421 661
Note: Northern Economics’ resource size estimates are from the 2006 Minerals Management Service Resource Assessment.
The numbers shown in the table are the mean undiscovered economically recoverable resource estimates, assuming resource
commodity prices of $60 per barrel of oil and $9.07 per thousand cubic feet of natural gas.
Source: Northern Economics in association with the Institute of Social and Economic Research, University of Alaska, Economic
Analysis of Future Ofshore Oil and Gas Development: Beaufort Sea, Chukchi Sea, and North Aleutian Basin, prepared for Shell
Exploration and Production, March 2009.
100 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-29. U.S. Beaufort Sea Outer Continental Shelf Production Forecast
0
200
400
600
800
1,000
YEAR
B
A
R
R
E
L
S
O
F
O
I
L
A
N
D
C
O
N
D
E
N
S
A
T
E
P
E
R
D
A
Y
T
H
O
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S
A
N
D
S
0
200
400
600
800
1,000
M
I
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I
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N
C
U
B
I
C
F
E
E
T
O
F
G
A
S
P
E
R
D
A
Y
OIL AND CONDENSATE GAS
Source: Northern Economics, Inc. estimates based in part on Minerals Management Service (MMS) scenarios in Beaufort Sea Planning
Area Oil and Gas Lease Sales 186, 195, and 202: Final Environmental Impact Statement. OCS EIS/EA MMS 2003-01, February 2003.
2017 2022 2026 2030 2034 2038 2042 2046 2050 2054 2058
Figure 1-30. U.S. Chukchi Sea Outer Continental Shelf Production Forecast
0
200
400
600
2017 2022 2026 2030 2034 2038 2042 2046 2050 2054 2058
YEAR
B
A
R
R
E
L
S
O
F
O
I
L
A
N
D
C
O
N
D
E
N
S
A
T
E
P
E
R
D
A
Y
T
H
O
U
S
A
N
D
S
0
400
800
1,200
1,600
M
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
O
F
G
A
S
P
E
R
D
A
Y
Source: Northern Economics, Inc. estimates based in part on Minerals Management Service (MMS) scenarios in
Chukchi Sea Planning Area, Oil and Gas Lease Sale 193 and Seismic Surveying Activities in the Chukchi Sea:
Final Environmental Impact Statement. Volume I: Executive Summary, Sections I through VI. OCS EIS/EA MMS 2007-026.
OIL
GAS
Figure 1-29. U.S. Beaufort Sea Outer Continental Shelf Production Forecast
Figure 1-30. U.S. Chukchi Sea Outer Continental Shelf Production Forecast
CHAPTER 1 - RESOURCES AND SUPPLY 101
Tere are numerous Arctic producing felds on land
and safe development and production of ofshore
Arctic reserves has occurred globally since the late
1960s, which collectively demonstrates that resource
extraction can occur in the midst of sensitive eco-
systems. Innovation will continue as new challenges
are identifed.
Rccommcndation 2: Industry has always risen to
the challenge, and if allowed, they will continue to
advance elements of Arctic exploration and develop-
ment technology to reduce the operational footprint
and safely produce oil and gas. We recommend a
reasonable set of policies and regulations that allow
industry to continue prudent exploration and devel-
opment in the Arctic and to proceed with technology
advances. Near-term advances in ofshore pipeline
trenching will be important across the Arctic espe-
cially in prospective regions with deepwater condi-
tions (>100 meters) such as the Continental Slope
region of the Canadian Beaufort or Greenland.
Advances in iceberg management will also be impor-
tant for Greenland and portions of the Canadian
Atlantic ofshore.
Finding S: Te existing 10-year lease terms are
not long enough to ensure sustained exploration
and appraisal of material Arctic oil and gas resources
in the U.S. Arctic basins. Infrequent lease sales,
lengthy, multifaceted permitting procedures, a high
incidence of litigation and a required sequential set
of data-gathering and permitting activities coupled
with short drilling windows (onshore winter and
ofshore summer) reduce the ability to identify,
appraise, and develop economic volumes in this
short time span.
Rccommcndation S: Adopt a licensing system for
Alaska that is similar to, but improves upon, Canada
or Greenland’s system in recognition of the limited
seasonal operating period, particularly for the U.S.
federal ofshore areas (70–105 days per year). Can-
ada ofers large tracts (versus 3-square mile blocks)
with a work commitment bid that covers 9 years if a
well is drilled within the frst 5 years (still problem-
atic and should be extended given the challenges of
the Arctic and the new regulatory requirements), and
is extended indefnitely if producible hydrocarbons
are discovered on the tract. Greenland ofers similar-
sized tracts and exploration terms and is extending
the initial license term to 16 years for its NE Green-
land ofshore round that will be held in 2012.
Finding 4: Tere is no clear, dependable, regulatory
path for gaining approval of submitted exploration
or development permit applications. Tis is due to
a multitude of U.S. government agencies/regula-
tory bodies that have overlapping authority, and
each have their own independent permit review and
approval schedule.
Rccommcndation 4: Streamline regulatory per-
mitting processes and promote collaboration and
coordination of the numerous federal agencies/
regulatory bodies, to avoid redundant analyses and
jurisdictional overreach. A coordinated approach
would provide predictable project scheduling and a
more efcient use of human resources within the fed-
eral government and industry.
Finding 5: Te Merchant Marine Act of 1920 (the
Jones Act, codifed in 2006) was established to regu-
late cabotage (the coastal shipping of cargo and pas-
sengers) within the United States. Te Act requires
cabotage in U.S.-fagged, constructed, owned and
operated vessels. Te Jones Act rules on tankers
and support vessels mandate largely unavailable and
uncompetitively priced ships, unduly increasing the
cost of operations in the U.S. Arctic. Few U.S.-fagged,
ice-classed vessels are available for U.S. Arctic of-
shore operations, so either exemptions are required
to allow the use of foreign-fagged vessels that are able
to meet U.S. Arctic shipping standards, or excessive
delays and costs (three times the capital and operat-
ing expense dollars to build and operate a U.S.-fagged
feet) will be incurred to comply with this statute.
Rccommcndation 5: Continue to provide exemp-
tions to the Jones Act for the non-U.S.-fagged,
ice-class vessels used in U.S. Arctic exploration
and appraisal operations. Tis will ensure that ice-
class vessels are available at competitive rates given
the long lead times required for Arctic ofshore
operations.
Finding 6: Alaska Coastal communities only
receive tax revenue from onshore facilities related
to oil and gas development in the onshore and State
waters areas of Alaska, which leads to local opposi-
tion of OCS exploration and development in the U.S.
Arctic.
Rccommcndation 6: Te U.S. should consider a
federal revenue sharing program for the Alaska state
and local coastal governments of potentially impacted
communities, perhaps initiating a program similar in
102 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
mechanism to the Gulf of Mexico Energy Security
Act in which 37.5% of the revenue from new Gulf
of Mexico leases after 2007 is distributed to local
coastal political subdivisions.
11
Finding 7: Oil tanker transport from the Arctic to
consumer markets is currently a viable export method.
Year-round tankering of crude oil from the Arctic to
market will likely be a viable cost-efective alternative
to pipeline transport in the future. Tankering ofers
greater fexibility of evacuating crude oil from mul-
tiple onshore or ofshore development facilities than
new pipelines. Lower transport costs increase the
economic viability of projects, and therefore, increase
the production potential.
Rccommcndation 7: Prepare for this transporta-
tion option in the future. Te United States needs
to catch up with, and then expand, technological
advances, which when combined with the possibility
of more open seas later within the time frame of this
study, will provide for America’s energy needs. In the
long term, America may lose the TAPS due to dimin-
ishing fow (2030 to 2045 time frame) unless immedi-
ate eforts are made to fnd and develop more oilfelds
to stem the decline in oil production and maintain
adequate fow in the pipeline. Failure to act will result
in the loss or serious deferment of any oil potential
until well beyond the 2050 horizon.
Onshorc Oil
Dcvclopmcnt and Production: History
and Contcxt
U.S. Lower-48 Onshore
In 2010, the U.S. lower-48 onshore produced
3.1 million barrels of crude oil and condensate per day,
or about 56% of total U.S. oil production. Between
1990 and 2005, production declined at about 4% per
year. Starting about 2004, higher oil prices incen-
tivized higher levels of investment activity and pro-
duction subsequently fattened and then increased
somewhat. In some regions, enhanced oil recovery
technologies (also known as tertiary recovery or
EOR), particularly steam-injection and gas-injection,
have maintained oil production rates in mature felds
11 Bureau of Ocean Energy Management, Regulation and
Enforcement, “Gulf of Mexico Eneregy Security Act,” http://
www.boemre.gov/ofshore/GOMESARevenueSharing.htm.
at levels higher than would have otherwise occurred.
Figure 1-31 illustrates the total production trend and
contribution of EOR projects.
Te outlook for future oil production in the lower-
48 onshore region is dependent upon both primary
and EOR resource development. Expanded oil pro-
duction from oil-bearing shale and low permeability
formations, especially those not yet under develop-
ment, is critical to mitigating the general decline in
onshore production. Te development and applica-
tion of advanced EOR technologies to mature felds
enables the extension of feld economic life with mini-
mal exploration risk, adding additional supply at the
margin.
Although the onshore segment accounts for only
36% of 2010 U.S. oil production, it accounts for
only 52% of the traditional U.S. oil resource base.
Te onshore lower-48 is estimated to hold only 14%
of total U.S. undiscovered oil resources, with the
remaining 86% located in Alaska, the U.S. ofshore,
and unconventional (tight oil) reservoirs. Tese esti-
mates, summarized by region in Table 1-8, illustrate
the exploration maturity of the conventional onshore
relative to other segments of supply.
About one quarter of the onshore lower-48 resource
base consists of undiscovered oil resources, indicat-
ing that the onshore lower-48 resource base has been
largely discovered and produced. Total U.S. oil pro-
duction peaked in 1970 at 9.6 million barrels per day,
which at that time came mostly from onshore lower-
48 oil felds. Tus, future oil production in the lower-
48 onshore region will depend heavily on the degree
to which oil can be recovered from existing and aban-
doned oil felds. Further recovery of oil from these
felds will largely depend upon the economic viability
of incremental development and enhanced oil recov-
ery, which are driven by oil price, technology, and
regulatory policy.
Table 1-8 estimates do not include potentially pro-
ducible oil resources that exist below the oil-water-
contact point where a formation holds mostly oil and
a little water to a deeper layer holding mostly water
and little oil. Tese deeper zones are called “oil-to-
water transition zones” and “residual oil zones.”
Residual oil zones (ROZ) have not had a long history
of production testing at a commercial scale (nine
are in ongoing feld tests), but have physical proper-
ties similar to oil-bearing zones that have been pro-
duced through primary and secondary techniques.
CHAPTER 1 - RESOURCES AND SUPPLY 103
Conservatively, these ROZs hold tens of billions of
barrels of oil in place and provide additional targets
for recovery using EOR technology.
EOR oil production has increased as primary and sec-
ondary production has declined (Figure 1-32). In 1986,
EOR production accounted for only 10% of onshore
lower-48 oil production. From 2000 through 2008,
EOR averaged about 20% of the total. Figure 1-32 and
Table 1-9 illustrate the contribution of specifc tech-
nologies to enhanced recovery production over time.
Termal EOR has historically been the most signifcant
due to the very successful application of steam injec-
tion to the large, heavy oil felds in Southern Califor-
nia. However, thermal production continues to decline
as these reservoirs deplete. Chemical EOR has not had
widespread application to date; the felds using “other
gases” are predominantly in the Arctic and ofshore
arenas. In contrast to these technologies, production
from CO
2
EOR has steadily increased as projects have
been implemented or expanded.
Te conventional oil felds in the onshore United
States started out with about 500 billion barrels of
oil in place. After primary and secondary produc-
tion, over 300 billion barrels still remain as targets
for EOR and incremental feld development projects.
Volumes in the ROZ provide additional targets. Te
CO
2
component appears most promising for signif-
cant expansion of production from this large target,
but will require new sources of pure and afordable
carbon dioxide. Most CO
2
currently used in EOR is
from natural sources with limited growth opportu-
nities. Major volumes from man-made or anthro-
pogenic CO
2
sources would be needed to realize the
potential of this resource in a large way.
Canada
Canada onshore conventional (light/medium) oil
production, including condensates and enhanced oil
recovery production, has steadily declined in recent
years, dropping from about 1.1 million barrels per
day in the 1990s to 0.7 million barrels in 2010. Tis
accounts for about 20% of total Canadian oil pro-
duction, which is increasingly dominated by oil sand
operations. Volumes include a small amount of “tight
oil” production from extension of the Bakken play
into Canada and application of that technology in
other areas of the country. Figure 1-33 provides the
Figure 1-31. U.S. Lower-48 Onshore Oil Production, 1986–2010
0
2
4
6
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
ENHANCED OIL RECOVERY TERTIARY
PRIMARY AND SECONDARY OIL PRODUCTION
Sources: U.S. Energy Information Administration and the Oil & Gas Journal’s Biennial Enhanced Oil Recovery surveys.
Figure 1-31. U.S. Lower-48 Onshore Oil Production, 1986–2010
104 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
recent historical trend and a projection indicating few
changes are expected in the components of this sup-
ply area.
Light/medium crude oil resources remain concen-
trated in the traditional producing provinces in west-
ern Canada with potential reserves estimated in the
range of 7 to 8 billion barrels (Table 1-10).
Past Canadian EOR production has contributed
only modestly to onshore conventional oil production.
In 2010, EOR volumes totaled about 65,000 barrels
per day, accounting for 9% of conventional onshore
production. EOR’s share, however, could grow if EOR
production either remains constant or grows and
if non-EOR conventional production continues to
decline. Production from both carbon dioxide and
chemical fooding has increased in recent years with
the Weyburn CO
2
and Pelican Lake polymer projects
making signifcant contributions. Original oil in place
for onshore conventional light/medium was about
80 billion barrels. Of this, some 50 to 60 billion
barrels are expected to remain after primary and
secondary production and provide a target for EOR
development.
Table 1-8. U.S. Technically Recoverable Oil Resources
As of January 1, 2009
(Billion Barrels)
Region
Proved
Reserves
Inferred
Reserves
Undiscovered
Resources
Total
Percent
Undiscovered
Onshore
Conventional Oil
Northeast 0.2 0.2 0.7 1.1 64%
Gulf Coast 1.5 3.1 6.5 11.0 59%
Mid-Continent 1.2 7.1 5.4 13.6 40%
Southwest 4.8 23.4 2.6 30.7 8%
Rocky Mountains 2.5 6.7 2.1 11.3 18%
West Coast 2.6 7.3 2.3 12.1 19%
Subtotal 12.7 47.6 19.5 79.9 24%
Tight & Shale Oil NA 2.5 31.6 34.1 93%
Onshore Lower-48
Subtotal
12.7 50.1 51.1 113.9 45%
Alaska &
Ofshore Lower-48
7.8 12.4 84.7 105.0 81%
U.S. Total 20.6 62.5 135.8 218.9 62%
Conventional Onshore
Lower-48 as a Percentage
of Total U.S.
62% 76% 14% 36%
Notes: NA = Not Available; shale and tight oil proved reserves are included in the regional proved reserve volumes. Crude oil
resources include lease condensates but do not include natural gas plant liquids or kerogen. Undiscovered oil resources in areas
where drilling is ofcially prohibited are not included. For example, this table does not include the Arctic National Wildlife Refuge
undiscovered oil resources of 10.4 billion barrels. Undiscovered resources in this table are “technically recoverable,” which is the
estimated volume of oil that can be produced with current technology. “Proved reserves” are those reported to the Security and
Exchange Commission as fnancial assets. “Inferred reserves” are expected to be produced from existing felds over their lifetime,
but which have not been reported as proved reserves.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2011 Projections.
CHAPTER 1 - RESOURCES AND SUPPLY 105
Figure 1-32. Total U.S. Enhanced Oil Recovery Production, 1986–2010
0
200
400
600
800
1,000
1986 1990 1994 1998 2002 2006 2010
T
H
O
U
S
A
N
D
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
OTHER GASES
CARBON DIOXIDE
CHEMICAL/POLYMER
THERMAL
Sources: Oil & Gas Journal’s Biennial Enhanced Oil Recovery surveys.
Figure 1-32. Total U.S. Enhanced Oil Recovery Production, 1986–2010
Figure 1-33. 2005–2025 Canada Onshore Light/Medium Oil Production by Province, Plus Pentanes and Condensates
0
0.50
1.00
2005 2010 2015 2020 2025
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
PENTANES AND CONDENSATES
OTHER ONSHORE
SASKATCHEWAN
ALBERTA
HISTORICAL PROJECTED
Source: Canadian Association of Petroleum Producers, Canadian Crude Oil Production Forecast 2011–2025, June 2011.
Figure 1-33. 2005–2025 Canada Onshore Light/Medium Oil Production by Province,
plus Pentanes/Condensates
106 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Table 1-9. U.S. Enhanced Oil Recovery Production, 2000–2010
By Technology Category (Thousand Barrels Per Day)
EOR Technology Category 2000 2002 2004 2006 2008 2010
Thermal Injection EOR
Steam 418 366 340 287 275 273
In Situ Combustion 3 2 2 13 17 17
Hot Water 3 3 4 2 2
Total Thermal EOR 421 371 345 304 294 292
Chemical Injection EOR
Polymer/Chemicals 2 0 0 0 0 negligible*
Other negligible negligible negligible 0 0 0
Total Chemical EOR 2 negligible negligible 0 0 negligible
Gas Injection EOR
Hydrocarbon Miscible
and Immiscible
125 95 97 96 81 81
CO
2
Miscible 189 187 206 235 240 272
CO
2
Immiscible negligible negligible negligible 3 9 9
Nitrogen 15 15 15 15 20 9
Total Gas EOR 329 297 318 349 350 371
Total U.S. EOR Production 752 668 663 653 644 663
Total Onshore Lower-48
EOR Production
†
626 574 566 557 563 582
Total Onshore Lower-48
Oil Production
3,078 2,758 2,628 2,660 2,769 3,087
Total Onshore Lower-48 Oil
Production, excluding EOR
2,452 2,184 2,062 2,103 2,206 2,505
EOR Percentage of
Total Onshore Lower-48
Oil Production
‡
20% 21% 22% 21% 20% 19%
* A table entry of “negligible” indicates that the production volume was less than 0.5 thousand barrels per day.
† All hydrocarbon miscible and immiscible enhanced oil recovery (EOR) production is located either in Alaska or the
ofshore Gulf of Mexico and was subtracted from U.S. total to calculate onshore lower-48 EOR oil production.
‡ Based on Total Onshore Lower-48 EOR Production, which excludes hydrocarbon EOR production.
Sources: Oil & Gas Journal’s Biennial Enhanced Oil Recovery Project Surveys; and U.S. Energy Information Administration.
CHAPTER 1 - RESOURCES AND SUPPLY 107
Production Pathways
To develop boundaries of a supply range for con-
ventional onshore oil and enhanced oil recovery, rel-
evant technologies and issues were grouped into cat-
egories. For each of these, scenarios for limited and
high potential cases were developed. A production
profle for each pathway was developed qualitatively to
get a directional view of that boundary over the next
25 years. For the United States, production catego-
ries of primary plus secondary, CO
2
EOR, and other
EOR were considered separately, and then summed.
For Canada, conventional light oil was considered as a
total production stream made up of existing (virtually
all primary + secondary) and new CO
2
EOR. Adjust-
ments were made to exclude tight oil production as
this is addressed in the unconventional supply section.
Te factors that were considered for the high poten-
tial pathway are shown in Table 1-11. And the fac-
tors driving the limited potential case are shown in
Table 1-12.
Figure 1-34 illustrates the estimated supply
fairway for onshore conventional oil for the U.S.
Table 1-10. Canada Potential Light/Medium
Conventional Oil Resources, as of 2006
Region
Light/Medium
Crude Oil
(Billion Barrels)
Percentage
of Total
Alberta 5.7 65%
British
Columbia
0.5 6%
Saskatchewan 1.1 13%
Subtotal –
Onshore
7.3 84%
Eastern
Ofshore
1.4 16%
Total Canada 8.7 100%
Source: Natural Resources Canada, “Canada’s Energy
Outlook: The Reference Case 2006,” Ottawa, Canada, 2006,
page 35. Table US1.
Figure 1-34. Supply Fairway for North American Onshore Conventional/Enhanced Oil Recovery
0
1
2
3
4
5
2005 2010 2015 2020 2025 2030 2035
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
Note: Reference Case based on Energy Information Administration and Canadian Association of Petroleum Producers data,
reduced for estimated unconventional production.
REFERENCE CASE ACTUAL HIGH POTENTIAL PATH LIMITED POTENTIAL PATH
GAP DUE TO
UNCONVENTIONAL
ADJUSTMENT
Figure 1-34. Supply Fairway for North American Onshore Conventional/Enhanced Oil Recovery
108 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Table 1-11. Factors Considered for the High Potential Case
Technology or Issue Description
Technology (1)
y Reservoir characterization,
stimulation, and management
y Sweep efciency gains
y Downhole monitoring and hori-
zontal well diagnosis
y Technology transfer enabled
y Impacts both primary/secondary
and enhanced oil recovery
Existing tools for reservoir characterization, simulation and overall
management practices continue to be implemented, increasing project
inventory in existing felds. There is continued improvement in sweep
efciency, translating to higher oil recovery and better use of injectants such
as carbon dioxide, steam and chemicals. Gains in downhole monitoring are
made, allowing data analysis that adds to recovery process improvement.
Importantly, diagnosis of horizontal well performance improves, allowing
those wells to produce to their ultimate potential.
Public/private partnerships grow, enabling technologies to develop and be
shared among operators and resource owners. Widespread movement to
digital formats for public data continues, improving cycle time for project
screening and development. Institutions at all levels encourage job market
entrants to consider technical roles in the industry.
Technology (2)
Advanced well operations
Advanced well operations of horizontal drilling and fracturing continue
their growth throughout the United States with appropriate regulatory
intervention and minimal local opposition. Incremental technology
improvements are developed which allow additional resource plays to be
exploited prudently and economically.
Low Oil Saturation Zones Low/residual oil zones are widely recognized by industry and government
as potential targets for both hydrocarbon production and carbon storage.
State and federal geological agencies undertake systematic assessments of
low oil saturation zones that have been drilled but largely overlooked in the
past. Results from projects currently underway in the Permian Basin become
models for other areas.
Focused eforts (either public or private) to develop new alternative
technologies to CO
2
fooding in these zones progress. Mechanisms to share
these throughout the industry are in place.
Carbon Dioxide
Includes greenhouse gas, capture
costs, and legal framework
An aggressive carbon capture and sequestration (CCS) efort develops, in
which worldwide and U.S. policies are implemented, which incent capture
and storage of large CO
2
volumes. CO
2
EOR is qualifed as storage within a
clear legal and regulatory framework. Transportation issues are resolved and
a pipeline infrastructure develops; CO
2
price to oil producers is afordable.
EOR is seen as one piece of a near-term bridge to large-scale capture and
storage throughout the United States.
Economics & Policy
y Impacts to proftability
y Ability of smaller operators or
smaller felds to implement EOR/
infll
Oil prices remain strong relative to gas prices, driving operators to focus on oil
opportunities. Power, steam, and CO
2
prices remain reasonable due to lower
underlying natural gas prices.
Tax policy to encourage higher risk/cost activities is implemented to maintain
activity through price cycles. These include a revamp of the EOR tax credit
and allowances for marginal or low rate wells. Regulators in Alberta remain
cognizant of royalty rate and adjust as needed to maintain activity. Flexible
plugging regulations become widespread to avoid premature abandonment
and loss of wellbore access for improved oil projects. Solid economics drive
operators to implement projects that require more engineering work.
The Interstate Oil and Gas Compact Commission recommendations on CO
2
transportation, storage, and other regulatory items are widely adopted,
providing operators more certainty. Institutions that provide support and
knowledge to all operators continue their growth, enabling application to a
wide variety of felds and reservoirs throughout the United States.
CHAPTER 1 - RESOURCES AND SUPPLY 109
lower-48 and Canada. Te high potential case
would suggest an annual growth rate of slightly
greater than 1% over the next 25 years. Te growth
would be gradual, typical of a steady stream of
production from a diverse resource base.
Te limited potential case indicates a steady decline
in the range of 4% annually over the next 25 years. Not
dissimilar to the decline realized for much of the past
25 years, this suggests an environment of relatively
low prices and signifcant costs relative to those prices.
Table 1-12. Factors Considered for the Limited Potential Case
Technology or Issue Description
Technology (1)
y Reservoir Characterization, Stimula-
tion, and Management
y Sweep Efciency Gains
y Downhole monitoring and horizon-
tal well diagnosis
y Technology transfer enabled
y Impacts both primary/secondary and
enhanced oil recovery
There is limited use of existing reservoir management applications
combined with few new tools, meaning investment opportunities are
slow to be developed. Sweep efciency continues at status quo, so
unit costs go up, causing additional wells to be shut in. Little progress
in downhole monitoring means data analysis remains spotty; lack
of understanding of fow characteristics in horizontal wells causes
abandonment prior to full extraction of initially established reserves.
Existing public data remains in paper or legacy formats, causing long
cycle times and loss of projects. There is limited technology transfer
activity; it takes longer for new techniques to permeate industry
operations. Limited new personnel enter the industry with fewer growth
opportunities.
Technology (2)
Advanced Well Operations
Regulations around hydraulic fracturing that are restrictive rather than
progressive increase costs and delays, decreasing use. Technology
development slows with less activity and only the most prolifc
opportunities can aford the technology.
Low Oil Saturation Zones There is limited recognition or development of the potential of low oil
saturation zones and information on them is spotty and tightly held.
No alternatives to CO
2
fooding are pursued and carbon storage in these
reservoirs is not considered by policymakers.
Carbon Dioxide
Includes greenhouse gas, capture
costs, and legal framework
Worldwide and U.S. policies are implemented which discourage oil
(and coal) production and use of CO
2
injectant; existing incentives
are removed and regulations around operations (production, plant
processing and pipeline) are increased signifcantly; fees and taxes are
also increased substantially. Canadian CCS plans are shelved. This results
in new investment drying up; existing operations move to a decline
mode.
Economics & Policy
y Impacts to proftability
y Ability of smaller operators or smaller
felds to implement enhanced oil
recovery/infll
Oil prices are weak relative to gas prices, driving focus away from oil
production.
Existing tax incentives are phased out and no new incentives are added.
Additional or punitive taxes are enacted; higher risk and cost activities are
avoided by operators. Regulations requiring accelerated abandonment
come into play so numerous felds are abandoned and future advanced
recovery projects in these locations are limited.
Operators and resource owners have little incentive to pursue projects
involving higher amounts of engineering, instead funding a smaller
number of opportunities that are drilling based.
110 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Te midpoint within the range is close to cur-
rent production, suggesting potential exists for this
resource to continue as an important portion of
North American oil supply.
Kcy Convcntional Onshorc Tcchnologics
Oil feld development and production are com-
plex operations that involve application of hundreds
of technologies across many disciplines. Several of
these technologies are most likely to infuence the
supply picture through 2030, again due to their
potential impact on production from known oil accu-
mulations. Tey are contained within some broad
processes required to manage oil development and
producing operations:
y Design – Involves planning for locations, numbers,
and types of wells needed to produce and manage
the reservoir. It also involves sizing and design of
surface facilities to handle produced or injected
fuids, plus transportation and disposal of some
products. Besides project specifcations, produc-
tion expectations are developed which support
investment decisions. Within this area, rcscrvoir
charactcrization and pcrformancc simulation are
critical to establishing the initial project feasibil-
ity and subsequent management of the producing
formations.
y Implementation – Involves the installation and
feld operation of wells and equipment, includ-
ing drilling and well stimulation. Advanced well
operations (especially those involving horizontal
drilling and hydraulic fracturing) are considered
important. Technologies that reduce environ-
mental footprint and improve operational safety
are also critical to the petroleum industry’s “right-
to-operate” in sensitive locations.
y Operation and Monitoring – Te life of a produc-
ing oilfeld lasts a minimum of several years and
sometimes for a century, so efcient operating and
maintenance practices are important to maximiz-
ing recovery and economic beneft. Among myriad
activities, data from operations must be collected
and analyzed so that operational improvements
and incremental investments can be made to prof-
itably maximize production and reserves. Down-
holc monitoring, especially in complex recovery
processes or horizontal wells, is important to
success. In addition, advanced control systems that
reduce the human interface will provide increased
reliability and reduced costs.
y Recovery Process Improvement – Oilfeld develop-
ment relies on a given recovery process, be it pri-
mary production, water fooding, or an enhanced
process like carbon dioxide fooding. Technology
leading to improvcd swccp c?cicncy is critical to
maximizing production from existing operations
and in developing some of the multi-hundred bil-
lion barrel oil target remaining in existing felds or
in other low oil saturation targets.
y Application to New Resources – Because of the
natural decline of existing conventional oil produc-
tion, it is critical to fnd new resource targets to
maintain or grow production. Technologies target-
ing low oil saturation zoncs can impact supply.
More detail of these areas of technology can be
found in Topic Paper #1-5, “Onshore Conventional
Oil Including EOR,” available on the NPC website.
Because of the interest in increased use of carbon
dioxide in EOR operations, both to contribute to
incremental hydrocarbon recovery and as a sink for
storage of CO
2
, there follows a summary of the most
important aspects of this opportunity.
Carbon dioxide EOR is an established technology
used in the United States since the 1970s. A key
requirement for a carbon dioxide project is a depend-
able source of high purity and afordable CO
2
. For
this reason, most development to date has occurred
in west Texas and southeast New Mexico, where can-
didate oil felds and naturally occurring CO
2
source
felds are close enough to provide CO
2
at a reason-
able cost. In other locations, a few projects have been
implemented where a candidate oilfeld was close to
a relatively pure industrial source, where man-made
(anthropogenic) carbon dioxide is captured for EOR
use.
In the United States, most opportunities for using
naturally occurring CO
2
are already exploited, leaving
growth potential primarily to be met from anthropo-
genic CO
2
sources. Te most likely projects are those
where a relatively pure CO
2
source already exists,
since capture and transport are cost efective. Sepa-
ration of CO
2
from natural gas is a good example of
this. Certain industries, including cement, ammonia,
lime, iron, and steel also produce relatively pure CO
2
CHAPTER 1 - RESOURCES AND SUPPLY 111
streams as a byproduct. Over time, CO
2
from addi-
tional gas processing and certain other sources is
expected to be used in EOR applications.
Te category of CO
2
supply with the most volume
potential is the most challenging. Tese are projects
where carbon dioxide is captured from dilute streams,
typically large point source fue gas emissions at
power plants. Since this category will require a
substantial amount of fscal and regulatory support,
use will ultimately depend on U.S. and Canadian pol-
icy decisions. To be viable, the price of delivered CO
2
would have to be at a level where investments in EOR
projects ofer adequate returns. As CO
2
prices are
negotiated between sellers and purchasers in various
contractual arrangements, the price can vary widely
based on location, contract vintage, etc. However,
minimum prices discussed for CO
2
into EOR are usu-
ally less than $1 per Mcf ($10 to $15 per metric ton)
and maximum prices are typically in the range of
$2 to $3 per Mcf ($40 to $60 per metric ton). With
expected costs of capture and transport from dilute
sources well above this level, policies that provide
fnancial support to reduce delivered CO
2
pricing
would be required for a viable supply to use in EOR
applications.
Kcy Convcntional Onshorc Findings
and Implications
Finding 1: Industry reacts quickly to viable eco-
nomic returns on investment in conventional
onshore and EOR opportunities, and production
increases often follow. This ability to respond
requires consistent, stable regulation. Longer-term
investments requiring large capital infrastructure
are especially sensitive to stable policy. Sustained,
incremental improvements in technology, regula-
tions, and EOR injectant supply would stem the
historical decline and contribute large volumes over
time as gains compound annually.
y In the mid-2000s, higher activity resulted in
approximately 1.0 million barrels of oil per day
of increased conventional oil production in the
onshore U.S. It was triggered by strong prices,
incremental technology advances, and regulatory
certainty. Tis production resulted largely from
projects targeting developed felds and known
resources.
y Tis represents the activity of thousands of
operators over several hundred thousand pro-
ducing wells, operating in areas with existing
infrastructure. Activity increases or decreases with
proftability measures and is enabled by a high level
of regulatory predictability and certainty.
Te timing of production impact varies depending
upon the type of activity. Development drilling or
well enhancement can add volumes within a few
months; development of an EOR project may not
add volumes until several years after project ini-
tiation. In uncertain policy or price environments,
short-term resource investments are favored over
long-term EOR projects.
Rccommcndation 1: Some recommended areas
for consideration are as follows:
y Direct Financial Support or Investment
? Implement tax credit program for low volume
wells to improve ultimate recovery and retain
felds and infrastructure for potential future EOR
projects.
? Review/enhance the federal EOR tax credit
to make it more relevant in the current price
environment; consider simplifcation of calcula-
tions.
y Support, Technology, or Institutional Programs
? Support of organizations that disseminate
best practices or technology applications (e.g.,
Research Partnership to Secure Energy for
America and the Petroleum Technology Transfer
Council).
Finding 2: Production from enhanced oil recov-
ery projects, specifcally those relying on carbon
dioxide (CO
2
) injection, is a critical source of long-
term future production from lower-48 onshore con-
ventional resources. State and federal policies will
determine whether this supply stream declines,
has healthy incremental growth or reaches new
plateaus.
Te production wedge from CO
2
EOR is one of the
largest variables in conventional oil production pro-
jections, with estimates ranging from 0.3 to over
2.0 million barrels of oil per day by 2030.
y Because new feld discoveries are now smaller and
generally decline faster, EOR projects provide very
stable, long-term sources of oil reserves.
112 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Te resource target for all EOR is estimated at sev-
eral hundred billion barrels, though this number is
very dependent on oil price, CO
2
price and availabil-
ity, and specifc feld and wellbore conditions.
y EOR projects often have high fxed and variable
costs, making EOR production the “marginal bar-
rel” in many markets, often just below prevailing oil
price expectations.
y A reliable, afordable, and growing supply of carbon
dioxide will be a key determinant of future EOR
production.
y Skills needed to design and operate EOR projects
are not always readily available and many operators
do not have experience in EOR.
y For some felds, there is a limited window of
opportunity to implement EOR projects due to
aging infrastructure and rapidly declining pro-
duction volumes over which to spread fxed costs.
Delays in development could mean loss of poten-
tial reserves, with ultimate impacts dependent on
the regulatory environment, available technology
and economics.
y Tere are a number of areas where additional regu-
lations and policy actions would negatively afect
EOR production. Following are some examples of
areas where progressive regulations may infuence
future oil supply.
Rccommcndation 2: Some recommended areas for
consideration are as follows:
y Proactive Regulation
? Ensure fexible well plugging rules exist to avoid
premature abandonment of candidate oil felds.
? Provide regulatory certainty for well design/
construction standards, re-abandonment of
existing wells, CO
2
capture/storage credits,
generation and use of greenhouse gas ofsets
and CO
2
pipeline permitting. Maintain class II
well design where it is initially injected for EOR
purposes.
? Develop a clear regulatory framework for con-
verting an initial EOR project into a CCS project
that can claim fnancial or emission allowance in-
centives.
? Codify long-term liability rules for CO
2
stored in
reservoir after EOR.
y Current Practices Afrmed
? New regulations around the handling and use of
carbon dioxide are limited. Example: new rules
from the Environmental Protection Agency
regarding CO
2
as “hazardous.”
? Te regulatory framework in states with existing
CO
2
operations are exported to new areas.
Example: CO
2
pipelines – no need to reinvent the
wheel.
? Projects that incidentally store CO
2
should not
be harmed by new regulations targeting storage
projects pursued for fnancial purposes.
y Direct Financial Support or Investment
? Support conversion of public oil and gas data
from paper/flm legacy systems to digital format
to improve project development capability and
efciencies.
? Tax policy to incentivize new computer hardware/
software, because EOR projects are complex and
require a great deal of additional engineering and
geologic characterization and often require an
upgrade to a company’s information technology
hardware to evaluate the subsurface potential.
? Rapid amortization for site characterization or
other front end costs.
? Review/enhance the federal EOR tax credit to
make it more relevant in the current price envi-
ronment; consider simplifcation of calculations.
y Support, Technology, or Institutional Programs
? Support of research in the areas of reservoir
characterization, reservoir modeling and sweep
efciency improvement. Consider public/
private partnerships (e.g., Research Partnership
to Secure Energy for America) to provide
appropriate prioritization of topics.
Finding S: A large increase in CO
2
supply from
dilute anthropogenic sources will be required over
the next 10 to 15 years to extend EOR production
levels. The complex factors affecting this supply
include carbon capture and sequestration (CCS)
deployment, involving substantial government fscal
and policy action.
y Estimates of oil supply resulting from projects
using dilute CO
2
sources range up to more than two
million barrels of oil per day.
CHAPTER 1 - RESOURCES AND SUPPLY 113
y Te cost of CO
2
from dilute sources is dominated by
high capture costs; support will be required to build
demonstration projects for supply and as test sites
for technology evolution.
y Lack of signifcant progress in CCS projects appears
to be a function of low economic returns available to
those who would deploy the technology. Costs need
to decrease substantially to create market interest,
which may require step-changes in technology.
y EOR is compatible with CCS should it move for-
ward; EOR projects are seen as a win-win for those
advocating early adoption of CCS.
y Permanent carbon sequestration during EOR will
be part of the justifcation for these projects; the
legal framework to delineate post-closure liability
must be put in place. Additional considerations
include pore space ownership, new well design
standards, and potential re-abandonment of exist-
ing wells. Tese issues are already well discussed
among various government agencies and industry
groups. State support is important even if fnan-
cial incentives are small; it helps to provide greater
regulatory certainty and remove barriers that arise
in any new project development.
y Canada may be ahead of the United States in this
area with a combination of policy and funding.
Rccommcndation S: Some recommended areas for
consideration are as follows:
y Proactive Regulation
? A program is implemented which incentivizes
emission reductions while recognizing CO
2
EOR
as a CCS option.
? Framework and regulations are developed that
allow operators to understand and manage
post-closure liability from the outset of project
conceptualization.
? States without clear processes regarding CO
2
EOR
use Interstate Oil and Gas Compact Commission
guidance or another source to develop needed
regulations; don’t reinvent the wheel.
? Comprehensive Environmental Response,
Compensation, and Liability Act/Resource
Conservation and Recovery Act exemptions for
storage in qualifed sites.
? Price premium for low-carbon power, akin to
“renewable” pricing, or “credit” for CO
2
storage via
EOR. Ability to generate ofsets for CO
2
captured
from sources outside regulatory jurisdiction.
y Current Practices Afrmed
? New rules do not hinder projects that are
operating or in permitting phase.
? CO
2
transportation regulations, currently under
discussion for CCS are not onerous for EOR users.
? Maintain a fexible approach that allows both
common-carrier and private CO
2
pipeline models.
? Avoid considering CO
2
a pollutant; reinforce with
regulators that CO
2
is not hazardous, and is not
corrosive in the absence of free water and with
proper metallurgy.
y Direct Financial Support or Investment
? Direct investment or funding of carbon capture
and EOR+Storage projects for demonstration
purposes.
Express backstop of long-term liabilities arising
from storage may be necessary, including trust fund
models.
Enhanced tax credits for CO
2
EOR+Storage proj-
ects with exemptions from liability under Alternative
Minimum Tax provisions.
y Support, Technology, or Institutional Programs
? Increased funding for National Energy Tech-
nology Laboratory Carbon Sequestration Part-
nerships.
Finding 4: Substantial petroleum resources occur
naturally or remain after primary and secondary
recovery in low oil saturation zones. Increased under-
standing of these zones is necessary for extensive
development, whether by carbon dioxide fooding or
another technology.
y A sizable portion of the 300+ billion barrels
expected to remain unrecovered in existing oilfelds
are in zones of low oil saturation.
y Tere are additional low oil saturation zones (often
referred to as residual oil zones or ROZ) that occur
naturally. Tese are not well characterized, but are
estimated to hold at least 80 billion barrels. Tese
zones provide a new set of targets in addition to
already produced or developed felds.
114 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Carbon dioxide fooding is the only applicable pro-
cess currently deployed on a commercial scale to
recover these resources. As such, the new target
zones ofer additional storage potential should CCS
advance.
y Technology development and demonstration in
these zones will be focused in areas with existing
infrastructure and CO
2
supply options.
y At this point, no non-CO
2
alternative EOR process
has been developed capable of supporting substan-
tial commercial ROZ development. Water foods
that include chemical additives seem to have the
greatest application and promise.
Rccommcndation 4: Some recommended areas for
consideration are as follows:
y Proactive Regulation
? Ensure fexible well plugging rules exist to avoid
premature abandonment of candidate oil felds.
y Direct Financial Support or Investment
Consider separate tax credit to incent ROZ devel-
opment.
y Support, Technology, or Institutional Programs
? Support work to describe the ROZ resources
at various levels, including state agencies,
universities, U.S. Department of Energy, Research
Partnership to Secure Energy for America, and
the U.S. Geological Survey.
? Support open access research in alternative re-
covery processes, focusing on chemical fooding.
Need both basic and applied research.
Finding 5: Horizontal drilling and advanced
hydraulic fracturing technologies are important to
developing opportunities in the conventional oil
area much as they are in unconventional oil and
onshore gas development. Techniques to monitor and
understand horizontal well performance will improve
as these wells proliferate.
y Tese technologies ofer new tools to proftably
develop conventional oil and EOR reservoirs. Tey
also allow new hydrocarbon targets to be devel-
oped, that were previously thought unproducible or
uneconomic.
y Horizontal wells accounted for more than 50% of
wells drilled in the United States during 2010.
y Given the increasing reliance on horizontal wells
for reserve development, it will be critical to
understand fuid fow in a given well to optimize
production and maximize reserves and recovery
efciencies.
y Horizontal drilling and hydraulic fracturing tech-
nologies depend on materials that may be in short
supply or are used extensively in other industries.
Rccommcndation 5: Some recommended areas for
consideration are as follows:
y Current Practices Afrmed
? New regulation on hydraulic fracturing should
endeavor to maintain current regulatory efec-
tiveness to avoid loss of opportunities.
? Maintain ability to comingle multiple formations
where conservation principles are not compro-
mised.
y Support, Technology, or Institutional Programs
? Support research in the areas of downhole moni-
toring of wells, especially horizontals and those
used in EOR.
? Working group of industry and government to
identify potential material shortages and actions
to mitigate impact.
Unconvcntional Oil
Dcvclopmcnt and Production History
and Contcxt
In this study, unconventional oil includes Canadian
oil sands, Canadian heavy oil, and U.S. and Canadian
tight oil, all currently producing signifcant quantities
of oil, and potential future unconventional resources
in U.S. oil shale and U.S. oil sands, not yet currently
contributing production. Tese resources are located
in the onshore arenas of U.S. and Canada, but are dis-
tinguished from the conventional oil discussed in the
previous section by diferent hydrocarbon characteris-
tics, geologic occurrences, and production techniques.
Te extra heavy oils (also referred to as bitumen)
are extremely viscous – sometimes nearly solid. Tey
often contain high concentrations of sulfur and metals
such as nickel and vanadium. Tese properties make
them difcult to produce and process. Massive accu-
mulations exist in the Canadian oil sands of Alberta
and in smaller accumulations in the United States.
CHAPTER 1 - RESOURCES AND SUPPLY 115
However, not all unconventional oils are heavy. A
growing source of unconventional supply is tight oil
– produced from low-permeability siltstones, sand-
stones, and carbonates. Te produced oil has similar
properties (e.g., density, sulfur content) as conven-
tional oil. Historically, the oil was locked in the for-
mations and could not fow through the tight forma-
tion rock. However, recent advances in horizontal
drilling and well fracturing technologies now enable
production of tight oil. Notable plays include the Bak-
ken (spanning Saskatchewan, Manitoba, Montana,
and North Dakota), the Eagle Ford play in Texas, the
Cardium play in Alberta, and the Miocene Monterey
play in California. For the largest tight oil play, the
Bakken, the produced oil is sweet and light, and only
the geology and oil extraction techniques are uncon-
ventional.
Unconventional oil is also contained in U.S. oil shale
deposits. Te petroleum component of the oil shale
(kerogen) is less mature, not yet fully transformed
into oil or natural gas. Terefore, unlike conventional
oil and gas operations, kerogen in oil shale cannot be
pumped directly from the ground or refned with tra-
ditional techniques. Rather, oil shale must be heated
to high temperatures to transform the kerogen into
an upgraded hydrocarbon.
In these categories, oil in place is estimated at more
than 3.5 trillion barrels. However, the reserves, or
the amount of oil that can be economically produced,
make up approximately 5% of this total (Table 1-13).
Even though the recoverable oil is a small part of total
oil, it is still signifcant.
In terms of production, unconventional oil supply
in North America has been growing – reaching 2 mil-
lion barrels per day in 2009 or equivalent to about
10% of crude oil processed in U.S. refneries.
Te following sections discuss each of the main
components of current and future unconventional oil
supply in North America.
Canadian Oil Sands
History and Context
Canada’s oil sands are one of the world’s largest
hydrocarbon accumulations (see map, Figure 1-35).
Located in the Province of Alberta, they are semi-
liquid hydrocarbons with gravity of 10
o
API or less.
In 2009, the Alberta Energy Resources Conserva-
tion Board (ERCB) estimated the initial volume of oil
in place of crude bitumen in Alberta’s oil sands as
1,804 billion barrels. Te ERCB reported that 7% of the
oil in place, 131 billion barrels, is contained in shallow
deposits, generally less than 215 feet to the top of the
oil sands zone. All of the shallow oil sands (amenable
to surface mining) are located in the Athabasca oil
sands area. Surface mining and bitumen extraction
technologies are used to recover crude bitumen from
these shallow deposits. Te remaining 93% of the oil
in place, 1,673 billion barrels, is contained in deeper
deposits. In situ recovery techniques are used to
recover crude bitumen from the deeper deposits.
Te ERCB estimated approximately 10% of the oil in
place is recoverable with about 22% of the recover-
able volume located in shallow deposits that will be
Table 1-13. Size of North American Unconventional Oil Resources
(Billion Barrels)
Oil in Place
Resources
(Includes Reserves)
Ultimate Potential
U.S. Oil Shale
(Green River formation only)
1,500 0 800
Canadian Oil Sands 1,804 169.8 (Reserves) 308
Canadian Heavy Oil 35 1 N/A
U.S. Oil Sands 63 0 N/A
Tight Oil N/A 5.5 to 10 (Resources) N/A
Total Greater than 3,500 Greater than 177 Greater than 1,100
116 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
developed using surface mining and 78% located in
deeper deposits that will be developed using in situ
recovery.
To year-end 2009, about 4% of the initial estab-
lished reserves had been produced with about 65%
produced using surface mining and 35% produced
using in situ recovery.
Te ERCB estimates the ultimate potential of crude
bitumen recoverable by in situ recovery methods
from Cretaceous sediments to be about 210 billion
barrels and from Paleozoic carbonate sediments at
about 37 billion barrels. Nearly 70 billion barrels is
expected from within the surface-mineable bound-
ary. Te total ultimate potential of crude bitumen is,
therefore, about 315 billion barrels, of which 7 billion
barrels has been produced, leaving 308 billion barrels
remaining.
As of 2009, oil sands production has reached
1.49 million barrels per day of crude bitumen,
826 thousand barrels per day from surface mining,
and 664 thousand barrels per day from in situ proj-
ects. In 2009, the oil sands industry represented
approximately 50% of Canada’s total oil production.
Historical bitumen production over the last 15
years is illustrated in Figure 1-36.
To remove contaminants and improve the value
of oil sands crude, a large portion of Alberta’s bitu-
men production is upgraded to synthetic crude oil
(SCO) and other products before shipment to mar-
ket. After upgrading, supply of SCO (including other
products) and non-upgraded crude bitumen totaled
1.34 million barrels per day in 2009 (766 thousand
barrels per day of SCO and 570 thousand barrels per
day of non-upgraded crude bitumen). Te 2010 pro-
duction was 1.47 million (660 thousand barrels per
day of SCO and 810 barrels per day of non-upgraded
crude bitumen).
Key Development and Production
Technologies
Te hydrocarbon component of the oil sands, crude
bitumen, must be separated from sand, other mineral
materials, and formation water before it is delivered
to downstream upgraders or refneries. Shallow oil
sands deposits, generally less than about 215 feet to
the top of the oil sands zone, are usually exploited
Figure 1-35. Alberta’s Oil Sands Areas
UNITED STATES
A
LB
ER
TA
Source: IHS Cambridge Energy Research Associates, ©2009.
THE MINEABLE OIL SANDS REGION IS
SLIGHTLY SMALLER THAN THE STATE
OF RHODE ISLAND.
THE ENTIRE OIL SANDS
REGION PEACE RIVER, ATHABASCA,
AND COLD LAKE IS ROUGHLY THE
SIZE OF THE STATE OF NEW YORK.
THE PROVINCE OF ALBERTA IS
SIMILAR IN SIZE TO THE STATE OF TEXAS.
IN SITU
MAJOR OIL SANDS PROJECTS
MINEABLE REGION
MINING
PEACE
RIVER
FORT
MCMURRAY
COLD LAKE
OIL
SANDS
AREA
CANADA
Note: Comparisons to U.S. states are to the total areas
of the states, including land and water.
Figure 1-35. Alberta’s Oil Sands Areas
CHAPTER 1 - RESOURCES AND SUPPLY 117
using surface mining to recover ore-grade oil sands,
then delivered to an extraction plant for separation
of bitumen from the sand, other minerals, and water.
Deep oil sands, greater than about 215 feet to the top
of the oil sands zone, are exploited using in situ recov-
ery techniques, whereby the bitumen is separated
from the sand in situ and produced to the surface
through wells.
Established oil sands mining and extraction tech-
nologies are based on truck and shovel mining tech-
niques. Trucks capable of hauling up to 400 tons of
material are loaded by electric- and hydraulic-power
shovels with bucket capacities up to 58 cubic yards. Te
trucks transport oil sands ore to preparation facilities
where it is crushed and prepared for transport to an
extraction plant (where bitumen is separated from the
sand). Te ore is mixed with water to create slurry that
can be pumped to the extraction plant (this method is
known as “hydrotransport”). At the extraction plant,
bitumen is separated from the sand, water, and other
minerals using a hot water extraction process.
Developing oil sands mining and production pro-
cesses to improve recovery performance, reduce envi-
ronmental impact, and reduce costs include the fol-
lowing:
y Mine-face crushing and slurry preparation to elimi-
nate the use of heavy-hauler trucks
y Counter Current Drum Separator extraction pro-
cess (Bitmin process), developed to replace hot
water extraction and produce relatively dry tailings
sand
y Mine-face extraction, a process that uses cyclones
to separate bitumen from the sand at the mine face.
Established in situ bitumen recovery technologies
have been developed to deal with the heavy, viscous
nature of the bitumen, which means that it will not
fow under normal reservoir temperature conditions.
For recovery of bitumen from deep deposits, viscos-
ity must be reduced in situ to increase the mobility of
bitumen in the reservoir. Tis enables fow to well-
bores that bring bitumen to the surface. Bitumen
viscosity can be reduced in situ by injecting steam to
increase reservoir temperature, injecting solvents,
injecting air, or using electric heating. Steam-based
thermal recovery is the dominant recovery technique
Figure 1-36. Canadian Bitumen Production, 1998–2009
0
20
40
60
80
0
400
800
1,200
1,600
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
IN SITU PRODUCTION
SURFACE MINING PRODUCTION
PERCENTAGE MINED
T
H
O
U
S
A
N
D
B
A
R
R
E
L
S
P
E
R
D
A
Y
P
E
R
C
E
N
T
A
G
E
O
F
B
I
T
U
M
E
N
P
R
O
D
U
C
E
D
B
Y
M
I
N
I
N
G
YEAR
Source: Alberta Energy Resources Conservation Board (ERCB).
Figure 1-36. Canadian Bitumen Production, 1998–2009
118 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
used at Athabasca, Cold Lake, and Peace River. Te
industry also conducts feld tests of other in situ
recovery methods including solvent-based recov-
ery, co-injection of steam and solvents, co-injection
of steam and non-condensing hydrocarbons, in situ
combustion and electric heating. Compared to sur-
face mining, in situ bitumen production does not
produce tailings that require disposal, requires less
water due to higher recycle rates, and has a smaller
surface footprint.
Primary recovery or “cold production” occurs where
bitumen can fow under normal reservoir conditions
without additional stimulation. Tis approach has
been used successfully in the Wabasca area of Atha-
basca and in the Peace River Oil Sands Area. Second-
ary recovery, where production is stimulated by water
or polymer injection, has been used successfully in the
Wabasca area.
Most in situ bitumen production has been enabled
using steam-based thermal recovery techniques, such
as cyclic steam stimulation or steam-assisted gravity
drainage (SAGD). Tese techniques, developed since
the 1980s and 1990s, are now well established, and
play a signifcant role in overall expansion of oil sands
production.
In addition to improvements to these existing tech-
nologies, new in situ recovery processes are being
developed to reduce energy requirements, reduce
water use, lower costs, improve recovery factors, and
reduce environmental impacts. Tese include:
y Hybrid steam-solvent processes
y Solvent only processes
y In situ combustion
y Electric heating.
Production Potential
Development potential of productive capacity to
2035 and beyond has been reviewed by examining
industry’s historical success in growing production,
known plans for new development and expansion of
existing projects, and the expected contribution of
new areas and new technologies. We have developed a
most likely case, a constrained case, and a reasonably
unconstrained case. As stated earlier, the Canadian
oil sands industry is well established. Large-scale
commercial production began more than 40 years ago.
In 2009, production reached 1.34 million barrels per
day, and by 2015 productive capacity is projected to
approach about two million barrels per day. Several
new projects have recently come on stream, several
are under construction, and many more are proposed.
As of early 2011, industry had proposed projects rep-
resenting about 7.7 million barrels per day of new
bitumen productive capacity.
Based on our review of available resources, the sta-
tus of the industry, and the challenges it faces, it is
our view that the Canadian oil sands industry has the
high potential to provide up to 6 million barrels per
day of SCO and raw non-upgraded bitumen supply by
2035. Tis high case assumes a concerted efort by
Canada and the United States to address challenges
associated with unconventional oil development in
general and oil sands in particular (e.g., energy and
water intensity, tailings reduction and remediation,
export capacity, and other constraints).
Te most likely case we have examined would see oil
sands output grow to around 4.5 million barrels per
day by 2035. Tis assumes that:
y Supply continues to be driven by market demand
y Te current Canada/U.S. free-trade relationship
remains
y Oil prices remain sufcient to justify new project
investments
y Sufcient pipeline transportation capacity is built
to move products to market
y Public acceptance of oil sands development is main-
tained by continual environmental performance
improvements
y At this growth level, no undue restrictions are
expected on capital availability, availability of engi-
neering services, skilled labor supply, or material
and equipment supply.
A constrained case would see oil sands growing
only to about 3 million barrels per day by 2035.
Tis case assumes governments implement stron-
ger clean energy policies that create additional chal-
lenges for oil sands developments. Strong policies
to limit greenhouse gas (GHG) emissions encour-
age expansion of alternative forms of energy, while
regulatory oversight of oil sands tightens further,
particularly to address the impacts of oil sands
development on air and water quality and land use.
Te intersection of increasing costs and declining oil
demand and oil prices (lower oil demand stems from
CHAPTER 1 - RESOURCES AND SUPPLY 119
government clean energy policies) raises economic
hurdles and deters signifcant oil sands develop-
ments after 2020.
Canadian Hcavy Oil
History and Context
Most Canadian conventional heavy oil comes from
a region termed the “heavy oil belt.” Te heavy oil belt
straddles the border of Alberta and Saskatchewan, just
south of the oil sands Cold Lake region. Generally,
heavy oil projects north of township 53 in Alberta are
classifed as oil sands and projects south are classifed
as conventional heavy oil. In Saskatchewan, all heavy
oil production (including production north of the
Alberta cutof) is categorized as conventional heavy
oil. Because of the technological and geographic over-
lap between bitumen produced from in situ oil sands
and Canadian conventional heavy crude, Canadian
conventional heavy oil is included within the uncon-
ventional oil category of this study. Alberta defnes
heavy oil as all oil under 25.7
o
API south of township
53, while Saskatchewan production data use a cutof
of under 20
o
API for heavy oil.
In 2009, production of Canadian conventional
heavy oil was 382 thousand barrels per day with pro-
duction in decline (5% per year on average over the
past 5 years). Combined production from Alberta and
Saskatchewan peaked in 1997. Recent declines are
attributed to the maturity of “easy” oil and the shift
in industry focus towards oil sands (Figure 1-37).
Key Development and Production
Technologies
Today, heavy oil uses similar production technolo-
gies as in situ oil sands, such as:
y Cold heavy oil production with sand (CHOPS) –
Recovery factors range from 3% to as high as 12%.
y Horizontal well technologies – Typically applied
to areas of the heavy oil belt with lighter gravity
crudes, similar recoveries to CHOPS.
y Secondary recovery – Water and polymer fooding
are used in lower viscosity reservoirs.
y Termal (cyclic steam stimulation and steam drive)
– Oil recovery has reached 60%.
Figure 1-37. Canadian Heavy Oil Production, 1988–2009
0
100
200
300
1988 1991 1994 1997 2000 2003 2006 2009
ALBERTA HEAVY OIL
SASKATCHEWAN HEAVY OIL
YEAR
D
A
I
L
Y
F
L
O
W
T
H
O
U
S
A
N
D
B
A
R
R
E
L
S
P
E
R
D
A
Y
Note: Alberta production heavy oil includes all oil under 25.7 API, while Saskatchewan production data is all production
under 20
o
API cutof for heavy oil.
Sources: Alberta Energy Resources Conservation Board (ERCB) and Saskatchewan Ministry of Energy and Resources.
Figure 1-37. Canadian Heavy Oil Production, 1988–2009
120 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
commonly known as “oil shales,” which refers to oil or
kerogen rich shales that are either heated in situ and
produced or if surface accessible mined and retorted.
Te most notable tight oil plays in North America
include the Bakken play in the Williston Basin, the
Eagle Ford play in Texas, the Cardium play in Alberta,
and the Miocene Monterey play of California’s San
Joaquin Basin (see map, Figure 1-38). Starting in
the mid-2000s, advances in well drilling and stimula-
tion technologies combined with high oil prices have
turned tight oil resources into one of the most actively
explored and produced targets in North America.
In terms of oil resources the tight oil plays are signif-
icant. Total estimated resources of the tight oil plays
identifed by this report range from 6 to 34 billion
barrels, and are based on reports for both producing
and prospective tight oil plays. It is likely that this
estimate signifcantly underestimates the amount
of recoverable oil when new tight oil techniques are
applied to these deposits. Te NPC Resource and
Supply Data survey, analyzing a wide set of studies
and private industry outlooks, provided the high
side estimate of 34 billion barrels.
Among the producing tight oil plays, the Bakken
play is currently considered the largest, with esti-
mates of recoverable resources or resources ranging
from 3.65 billion barrels of oil to 4.3 billion barrels.
With respect to the prospective tight oil resources,
it has been calculated that the Tuscaloosa Marine
Shale play of central Louisiana and southern Missis-
sippi may hold resources of 7.0 billion barrels.
According to the North Dakota Department of
Mineral Resources–Oil and Gas Division, production
from the Bakken Formation in North Dakota has
increased from approximately 20 thousand barrels
per day in 2007 to more than 220 thousand barrels
per day in 2010. From the information available at
the time of this study, the Bakken accounts for most
of the current tight oil production, almost 350 thou-
sand barrels per day including U.S. and Canadian
production. However, recent development within
the Niobrara and Eagle Ford plays suggest that their
productivity may be comparable to that of the Bakken
within a few years.
Key Development and Production Technologies
Horizontal drilling technology, combined with
advances in well completion and hydraulic fracture
stimulation methods, has opened up domestic tight
Similar to in situ oil sands, new methods have been
developed and applied to improve recovery factors
and extend the life of these resources. Tese technol-
ogies include:
y Termal steam-assisted gravity drainage (SAGD)
y Hybrid steam/solvent and solvent only processes
y In situ combustion
y Enhanced cold fow recovery.
Production Potential
By 2035, we estimate Canadian heavy oil produc-
ing in a range of 135 thousand barrels per day (con-
strained case) up to 350 thousand barrels per day
(relatively unconstrained case).
Te most likely, or expected, case is for 2035 pro-
duction of 250 thousand barrels per day, assuming
an ongoing 4% decline per year to 2035 for cold fow
production. Te amount of production using steam
method increases from about 30 thousand barrels per
day currently to 130 thousand barrels per day. Fur-
ther steam injection projects are limited as few por-
tions of the resource are thick enough to apply steam
methods.
Te high, or reasonably unconstrained, case is for
2035 production of 350 thousand barrels per day,
with technological innovation enabling upside from
the expected case. Between 2025 and 2035 success-
ful and economic pilots of both combustion and heavy
EOR) with gas reinjection could be demonstrated in
the heavy oil belt. By 2035, these two innovations
would add another 100 thousand barrels per day to
production.
Te low, or constrained, case is for 2035 production
of 135 thousand barrels per day, assuming an ongo-
ing 4% decline per year to 2035 for cold fow produc-
tion. Te amount of production from thermal meth-
ods does not increase substantially, as new thermal
projects are limited to the more economic oil sands
deposits to the north.
Tight Oil
History and Context
Te term “tight oil” refers to crude oil or conden-
sate found in sedimentary rock formations character-
ized by very low permeability. Tis resource should
not be (but often is) confused with resources that are
CHAPTER 1 - RESOURCES AND SUPPLY 121
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122 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
development of more known plays, could result in a
50% increase in the 2035 estimate, to 3 million bar-
rels per day from this resource type.
In a constrained development case, production
and development could be limited by restrictions on
hydraulic fracturing by state and federal regulatory
agencies; limited availability of water for hydraulic
fracturing; or changes in the tax rules for oil explora-
tion and production activities that reduce the fnan-
cial incentive to produce tight oil resources. Tese
types of constraints could limit production from tight
oil in 2035 to around 600 thousand barrels per day.
U.S. Oil Shalc
History and Context
Oil shale consists of rock and a solid organic sedi-
ment called kerogen. Tis naturally occurring source
of hydrocarbon has not yet undergone the full trans-
formation to oil and gas by heat and pressure over
long periods of geologic time, creating a unique devel-
opment and production challenge.
Oil shale represents one of the world’s largest
unconventional hydrocarbon deposits with an esti-
mated 8 trillion barrels of oil in place. Approximately
6 trillion barrels of oil in place is located in the United
States, with the most concentrated deposits found
in the Green River Formation in Colorado, Utah, and
Wyoming. Tis formation contains about 1.5 trillion
barrels of oil in place. About 80% of this resource lies
under U.S. federal lands.
Tere is a limited history of oil shale production in
the United States, dating back to the 1970s and early
1980s, following the Arab oil embargoes. When oil
prices fell in the 1980s, oil shale production activi-
ties were halted although research into development
and production technologies continued. Tis includes
eforts by the U.S. federal government, which awarded
six research, development and demonstration (RD&D)
leases in Colorado and Utah in 2006 and ofered more
leases in 2009. In addition, companies, like Shell,
have undertaken oil shale development research proj-
ects on private land.
Because of the long time cycle and high capital
requirements of an oil shale project, broad and con-
sistent government support would be required to
develop a commercial oil shale industry. Support-
ive government policy and regulatory certainty are
oil production in North America. Te successful pro-
duction of tight oil relies on a detailed understanding
of potential pathways to unlock hydrocarbons from
low permeability and low porosity formations that
may contain natural fracture networks. Application
of specifc technologies and drilling strategies, espe-
cially with respect to well completion and stimulation
techniques, almost certainly difers from play to play,
and often even within a play.
Te Bakken play is an example of this. Te exploita-
tion approach for the Bakken evolved from early verti-
cal wells perforated across the entire thickness of the
formation to horizontal drilling of the upper shale,
then to the horizontal drilling of the middle Bakken
(which is not typically shale, but may be composed
of silts, sands, or carbonates) utilizing single stage
fracturing. Te current trend of horizontal drilling
involves multistage fracturing of the middle Bak-
ken. Te horizontal drilling approaches in the Bakken
have also included a host of multilateral well types
drilled in various orientations to optimize the infu-
ence of natural fracture networks and natural stress
and strain forces on productivity. Te current trend
in the Bakken is towards single well pad locations
with various horizontals (up to 12) drilled from one
location covering two 1,280-acre spacing units. Tis
signifcantly reduces surface disturbance and can save
capital associated with multiple rig mobilization and
demobilization.
Production Potential
By 2035, production from tight oil plays across
the United States and Canada could range between
600 thousand barrels per day up to as high as 3 mil-
lion barrels per day, with a most likely estimate of
around 2 million barrels per day.
Te most likely estimate involves the application
of knowledge gained during successful development
of the Bakken towards other tight oil plays over this
period. Bakken production is expected to be between
400 and 600 thousand barrels per day by 2035. If
levels of Bakken production from Saskatchewan and
Montana are each about half the North Dakota pro-
duction, and similar productivity is realized from
just three other large tight oil plays (for example the
Eagle Ford, Niobrara, and Cardium) then more than
2 million barrels per day of production from tight oil
formations in North America in 2035 is likely.
In the reasonably unconstrained case, continuing
improvement in recovery technologies, as well as
CHAPTER 1 - RESOURCES AND SUPPLY 123
If these barriers and challenges are not met, there is
a plausible low, or constrained, case in which there
could be zero oil shale production by 2035.
However, in the most likely case, we assume that
three to fve projects can emerge from the existing
lease program and develop commercial production
from the early 2020s, after conversion of RD&D
leases to commercial leases around the middle of the
current decade. Tis should lead to production rates
of around 250 thousand barrels per day by 2035, with
prospects for considerable growth in subsequent
decades.
In the high, or relatively unconstrained case, more
rapid technological progress and a supportive market
and regulatory environment could allow the industry
to develop larger projects earlier. Large projects in
the 100–200 thousand barrels per day output range
would take 3–5 years for development and 5–7 years
to reach sustainable production. In this scenario,
total production could reach as high as 1 million bar-
rels per day by 2035.
U.S. Oil Sands
History and Context
U.S. oil sands resources show some important dif-
ferences from the Canadian oil sands, discussed previ-
ously. Factors such as more varied land ownership,
more complex and challenging oil sand composition,
and geographical dispersion add to the challenges
faced by U.S. oil sands development.
Of the estimated 54–63 billion barrels of original
bitumen in place, the resource in the Utah is the larg-
est, at about 20 billion barrels, and the best under-
stood. Covering nearly 1 million acres, or 150 square
miles, 11 major deposits are designated as Special Tar
Sand Areas (STSA) within the state of Utah.
An important diference between Canadian and
U.S. oil sands (principally Utah) is that the U.S. sands
are “oil-wet” rather than “water-wet.” Oil-wet U.S.
sands lack the flm of water layered between the sand
grain and the bitumen in Canadian water-wet sands.
Te oil-wet nature of U.S. oil sands leaves the depos-
its more highly consolidated (typically 3-4 times the
compressive strength), making initial mining and ore
conditioning operations more energy intensive than
in Canada’s oil sands.
crucial for private industry to assess risks and to com-
mit the billions of dollars of required investment.
Commercial scale technologies with economically
attractive recovery efciency and acceptable environ-
mental impacts will be required. Because the road
to commercialization is measured in decades not
years – a long time horizon will allow development to
continue through “boom and bust” oil and gas price
cycles.
Key Development and Production Technologies
Oil shale production technologies fall into two broad
categories: in situ and ex situ. In an in situ develop-
ment, the resource is converted to oil and gas without
mining the oil shale ore. In ex situ development, the
ore is mined and transported to a surface retort where
it is heated and converted into oil and gas.
Te rich accumulations in Colorado may be best
developed by in situ technologies because of high
mining costs associated with thick overburden cover-
ing the resource. Te shallow accumulations in Utah
are generally not as thick as the Colorado deposits and
may be developed using ex situ mining and surface
retort technologies near the resource outcrop.
Several development approaches are underway,
mainly focusing on in situ techniques. Some of this
work is proceeding on federal RD&D leases. Te main
technologies are the following:
y Heating kerogen with electric heaters down the
wellbore to achieve pyrolysis of the kerogen and
conversion to oil and gas, which can then fow to
the surface
y Fracturing and chemical conversion of kerogen
y Mining and surface retorting to recover hydrocar-
bons.
Several decades of continuing sustained research
will be necessary to prove, demonstrate and deploy
efective technologies to achieve material production
of oil and natural gas from oil shale deposits. Such
a sustained efort will require long-term commit-
ment from companies and a supportive fscal, leasing,
access, and research regime from the U.S. government.
Production Potential
Many technical, environmental, and regulatory
challenges will need to be met before oil shales become
a signifcant contributor to North American oil supply.
124 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Experts working on this study estimated most
likely 2035 production of about 25 thousand bar-
rels per day. Tis assumes that one of the current
research and pilot projects achieves technology suc-
cesses allowing it to step up to commercial-scale
operations.
In the low, or constrained, case 2035 production
is estimated at 10 thousand barrels per day, again
assuming that one project can move to commercial
scale, but the pace of development would be con-
strained by environmental and fnancial barriers.
In the high, or reasonably unconstrained, case
it is assumed that enhanced policy, access, and fs-
cal support for resource development will encour-
age additional private capital to enter this play, and
that production could grow to 150 thousand barrels
per day by 2035, continuing on a slow growth curve
thereafter.
Ovcrall North Amcrican Unconvcntional
Oil Production Outlooks
Table 1-14 summarizes the potential production
pathways for the sources of unconventional oil pro-
duction analyzed in this section.
Most Iikcly Unconvcntional Oil Supply Projcc-
tion (7 million barrcls pcr day by 20S5). Te pro-
jection assumes steady growth from existing supply
At the time of this report, there is no commercial
bitumen production from the U.S. oil sands. Tere are
three small pilot scale operations in Utah, operating
on surface mineable deposits.
Key Development and Production Technologies
It is expected that variations of technologies used
in the Canadian oil sands region can be applied in the
United States; however, they will need to be adapted to
ft the oil-wet nature of U.S. resources and will require
smaller scale operations, given the greater resource
dispersion. Surface mining techniques would be used
for early development, with in situ technologies,
adapted to Utah conditions, deployed later. Oil-wet
and highly consolidated oil sands deposits, like those
in Utah, do not necessarily require radical technol-
ogy changes, but innovation and adaptation based on
known technologies from Alberta.
Production Potential
A U.S. Department of Energy Task Force on Stra-
tegic Unconventional Fuels, reporting in 2007, envi-
sioned the potential for U.S. oil sands production to
grow from zero to 350 thousand barrels per day by
2035 (with a more aggressive scenario of 500 thou-
sand barrels per day). Tis outlook appears optimis-
tic given the status of resource development, invest-
ment, and current policy and regulatory frameworks.
Table 1-14. Production Potential from North American Unconventional Oil*
(Barrels per Day)
2009 Actual 2035 Limited 2035 Likely 2035 High
U.S. Oil Shale 0 0 250,000 1,000,000
Canadian Oil Sands 1,350,000
†
3,000,000 4,500,000 6,000,000
Canadian Heavy Oil 382,000 135,000 250,000 350,000
U.S. Oil Sands 0 10,000 25,000 150,000
Tight Oil 265,000 600,000 2,000,000 3,000,000
Total 2,000,000 3,700,000 7,000,000 10,000,000
* The total unconventional production is weighted for the two sources of supply that are not currently commercial (oil shale and
U.S. oil sands). If one reaches its full potential, it is likely the other one would not. Therefore, both projections are weighted 50%
in the production capacity roll-up, all others are relatively independent of each other and have 100% weightings.
† The production of bitumen is 1.49 million barrels per day, but after upgrading part of the bitumen to synthetic crude oil,
some volume is lost, and overall supply is lower.
CHAPTER 1 - RESOURCES AND SUPPLY 125
years. If the goal is to increase domestic oil supply and
increase energy security, unconventional resources
will surely need to be tapped. Tese types of resources
necessitate supportive government policy.
Finding 1: Conficting information on environ-
mental impacts of unconventional supply, includ-
ing the relative GHG emission intensity of oil sands
development or water quality impacts from tight oil
production, could lead to misinformed or inefec-
tive policy. As unconventional supply has a larger
environmental footprint, the environmental efects
associated with production growth should be consid-
ered and planned for.
Rccommcndation 1: Provide access to inde-
pendent and accurate information to support the
formation of policy. Establish a Federal Advisory
Committee Act (FACA) team to provide an
independent forum to research and clarify aspects
of unconventional supply. Tis will identify areas
of uncertainty and illuminate facts – ensuring that
government initiatives are both informed and efec-
tive. Te FACA committee could also contribute to
the development of early, long-range planning that
considers the environmental efects associated with
future unconventional supply growth.
Finding 2: For unconventional sources with no
production, specifcally U.S. oil shale and U.S. oil
sands – several ingredients that have been critical
to the successful development of the Canadian oil
sands are currently not in place.
Limited Access – Corporations and individuals
are constrained in the ability to assemble contigu-
ous leases with large resources. Without certainty in
resource size, there is less incentive for companies to
risk capital.
Additional Fiscal Measures to Spur Growth – Cana-
dian and Alberta government participation in oil
sands included broad-based science and technology
research, pre-commercialization investments, favor-
able fscal terms, loan guarantees, and direct fnan-
cial investment over decades. Te U.S. government
provides vital funding for basic research, but these
ideas must move from the laboratory into the feld –
the next critical step in resource development; fund-
ing is often an issue for entrepreneurial frms, which
sometimes struggle to fnance high-risk feld pilots.
Unconventional royalties are another opportunity to
sources and successful development of new, gradually
implemented technologies. U.S. oil sands and U.S.
oil shale require the largest innovations, and com-
mercial methods for production must be deployed.
Other supply sources require ongoing improvements
to existing extraction methods. Unconventional oil
production is projected to reach 7 million barrels per
day by 2035.
Iimitcd Unconvcntional Oil Supply Projcction
(S.7 million barrcls pcr day by 20S5). Te low pro-
jection assumes production growth is slowed by a
number of factors. For sources of supply with no cur-
rent production (U.S. oil sands and U.S. oil shale), bar-
riers to development include limited access to acre-
age, and minimal fnancial incentives and investment
capital to pursue research and eventual commercial
development. For sources of supply with current pro-
duction, challenged economics (higher environmental
costs and environmental limits) ultimately constrain
growth.
High Unconvcntional Oil Supply Projcction
(10 million barrcls pcr day by 20S5). Te projection
assumes a set of circumstances that would accelerate
production growth. Major innovations in unconven-
tional extraction occur, solutions minimize environ-
mental efects, and strong government support in
the United States and Canada fosters development.
New technology is developed and rapidly deployed.
Physical constraints are the main limits to growth –
requirements to build pipeline capacity, time to build
infrastructure, reasonable time to learn and ramp up
capacity, water constraints, labor constraints, manu-
facturing equipment or drilling constraints. In this
projection – a true “stretch case” for unconventional
supply – production reaches 9 million barrels per day
by 2035.
Kcy Findings and Rccommcndations
For each source of unconventional oil supply, the
path to eventual production will be unique. In some
cases, the advance of broadly applicable oil and gas
technology could lead to surprisingly rapid produc-
tion growth – potentially the case for tight oil. How-
ever, development of tight oil technology is likely
to be the exception, not the norm. Unconventional
resources require new techniques to extract the oil.
Learning from the Canadian oil sands example, the
yardstick for measuring the successful development
and deployment of new technologies is decades – not
126 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
an economically viable, socially acceptable, and envi-
ronmentally responsible manner. Fiscal measures
could include loan guarantees, severance tax incen-
tives, lower royalties, accelerated capital deprecia-
tion, and job creation programs (including retraining
and fnancial support). Other ideas include up-front
investments to pursue technology deployment and
creative oil and gas royalty and fscal structures that
consider the higher operating and capital costs of
unconventional production.
incentivize development. Current U.S. royalties are
12.5% – the same level as lower risk, established con-
ventional oil production.
Rccommcndation 2: Create an environment that
fosters innovation and results in production growth;
access to acreage with sizable oil resources and long-
term stable fscal regime with federal measures to
support the industry. Ideally the fscal environment
stretches over multiple decades, in order to provide
the certainty to develop unconventional resources in
Te shale gas revolution could take production
of natural gas liquids (NGLs) supplies to unprec-
edented levels. If natural gas production rises to
more than 100 billion cubic feet per day by 2035
as predicted, an NGL supply increase of 60% or
greater above 2010 levels could occur. Tis sharp
rise in anticipated NGL production has broad
implications for demand, infrastructure, and
import/export opportunities.
NGLs are ethane, propane, normal butane, iso-
butene, and natural gasoline (pentanes+), pro-
duced when wellhead natural gas is processed
for delivery to market. NGLS, in gaseous form at
the wellhead, are extracted by chilling the natu-
ral gas to very low temperatures, a process that
liquefes the gases. In some cases, NGL extrac-
tion is required to produce a natural gas stream
that meets required pipeline or industrial speci-
fcations. In other cases, when the price of NGLs
is higher than that of natural gas, NGLs are
extracted for economic reasons.
Te diference between crude oil and natural
gas prices is a key driver in NGL prices. As the oil
to gas price ratio grows, the value of NGLs rela-
tive to gas also increases. Rising NGL prices have
been a factor in recently increased rig activity in
oil and liquids-rich natural gas plays such as in
the Permian, Williston, and Eagle Ford basins.
Each component of an NGL barrel has a unique
supply/demand profle. Ninety percent of eth-
ane comes from natural gas processing plants.
Demand for ethane is from petrochemical plants,
which transform ethane into ethylene, an essen-
tial component of plastic. Ethane is uneconomic
and difcult to export so demand is constrained
to North America.
Sixty percent of propane comes from natural
gas processing plants. A third goes to petrochemi-
cal demand and two-thirds goes to home heating
demand. Weather, ethylene prices, and export
economics drive the demand for propane.
Te motor fuels market drives demand for
the remaining NGLs: normal butane and isobu-
tane and natural gasoline. Natural gas process-
ing plants produce 45% of the n-butane and 60%
of the isobutane. Ninety percent or more of the
butanes are used in motor fuels. Natural gas pro-
cessing plants also make most of the natural gas-
oline. Petrochemical plants use a third of it and
refneries use two-thirds for fuels.
Current NGL infrastructure may not be large
enough or interconnected enough to handle
potential production growth. Te market will
likely respond with new investment, allow-
ing NGL markets and their customers to gain
signifcant advantages in domestic and global
markets. To date, there have been announce-
ments for an additional 7.8 billion cubic feet per
day of processing capacity in the United States,
an increase of 12%. Tese projects, built close
to shale development, are needed even though
processing plants along the Gulf Coast have
30–50% open capacity. Several projects are also
underway to expand fractionation capacity by
438 thousand barrels per day by 2014. Transpor-
tation and storage capacity is also expected to
increase. Two NGL pipelines have been proposed
to take NGLs from the Bakken to market.
Natural Gas Liquids
CHAPTER 1 - RESOURCES AND SUPPLY 127
2. United States Gulf Coast (part of PADD III)
3. Midwest (northern part of PADD II)
4. Rocky Mountain (the same as PADD IV)
5. Western Canada including Washington State
(Washington State is currently part of PADD V)
6. Eastern Canada
7. California (currently part of PADD V)
8. Alaska (currently part of PADD V)
Figure 1-39 shows the geographical extent of the
PADDs (Petroleum Administration for Defense Dis-
tricts) in the United States, often used to defne
regional petroleum logistics and market issues.
PADDs have been used to defne the oil pipeline
regions covered in this study.
As of 2009, the United States had approximately
55,000 miles of crude oil trunk lines (typically
8–24 inches in diameter) connecting North Ameri-
can supply and market regions. Tis number does
not include tens of thousands of miles of gathering
lines used to move crude oil from production felds to
trunk lines, refned products lines to move products
from refnery to market, and LPG/NGL lines used to
move other commodities such as propane and ethane.
Since the last NPC study on oil pipelines, conducted
in 1987–1989, the United States has seen signif-
cant shifts in supply and demand for crude oil. Total
imports of foreign crude into the United States have
nearly doubled from just over 4.7 million barrels per
day in 1987 to roughly 9 million barrels per day in
2009. Tis is a continuation of the trend of domestic
U.S. production falling over most of the period, while
oil demand increased.
One of the most signifcant changes in the dynam-
ics of U.S. crude oil transportation has occurred over
the past decade as the United States trended away
from its reliance on waterborne imports, towards
imports from Western Canada. Since the 1987 NPC
report, U.S. imports of Canadian crude oil have tripled
to nearly 2.5 million barrels per day, with nearly 40%
of that growth occurring since 2000.
Te most direct impact of this shift is highlighted
by changes in the Midwest and Rocky Mountain
regions. In the Midwest, many pipeline networks
were originally established to supply domestically
Finding S: For unconventional supply with pro-
duction, primarily Canadian oil sands, develop new
technologies that lower the environmental footprint
and ofer higher, more sustainable, oil production lev-
els. For instance, Canadian oil sands have about 5–15%
higher GHG emission per barrel than the average crude
oil consumed in the United States. Development of
new technologies to lower GHG emission intensities
would help to close this gap. In turn, these technolo-
gies could be implemented domestically to improve the
environmental footprint of new U.S. unconventional
resources (oil shale and U.S. oil sands). Investments
in low or possibly zero-carbon emitting energy such as
low-energy extraction methods or small-scale nuclear
generation to fuel extraction, or CCS – all hold poten-
tial for reducing GHG emissions.
Rccommcndation S: Continue to participate in
international and bilateral activities – such as the
Energy Partnership of the Americas’ Heavy Oil
Working Group. Identify technology areas of mutual
interest between the United States and Canada –
areas that target more environmentally sustainable
methods of production. New technologies could
result in economic opportunities for U.S. frms, while
increasing energy security. New technologies will
most likely advance the development, and reduce
the environmental impact, of U.S. oil shale and
U.S. oil sands supply and may ultimately prove use-
ful to other extractive industries.
Crudc Oil Pipclinc Infrastructurc
Ovcrvicw
Oil infrastructure is critical to the North Ameri-
can energy supply chain that has evolved over the
last century. For the purposes of this paper, oil
infrastructure is limited to pipeline transportation
infrastructure available for crude oil in North Amer-
ica. While marine, rail, and trucking operations can
be important infrastructure components, the vast
majority of North American oil supply is moved via
pipeline.
A detailed regional analysis of the crude oil pipeline
system is included in Topic Paper #1-7, “Crude Oil
Infrastructure,” which is available on the NPC web-
site. Te regions covered are as follows:
1. Mid-Continent (currently part of PADD II [Petro-
leum Administration for Defense Districts])
128 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Like the PADD I region, the West Coast Region,
consisting of PADD V excluding Alaska, remains a
largely separate market from the rest of the United
States and faces a unique set of issues. California
has no intraregional or interregional pipelines. An
interregional pipeline corridor operated when the
1987 NPC study was completed, but the system has
since been converted to natural gas service, a result
of declining production and dwindling throughput.
Regional crude oil production has fallen to less than
half of what it was in the 1980s and is now less than
1.3 million barrels per day. With little historical
need for waterborne import infrastructure, and the
age of some facilities approaching 50 years, the Cali-
fornia Energy Commission has forecasted a need for
signifcant expansion of waterborne import facilities
and tankage by 2030 to accommodate imports.
In spite of shifts in market dynamics since the
previous NPC study, the Mid-Continent region, spe-
cifcally Cushing, Oklahoma, remains the nexus of
North American crude oil supply and movements. As
of 2008, Cushing holds 5–10% of total U.S. crude oil
produced light crude oil from Texas and the U.S.
Gulf Coast region to large refning hubs in PADD
II. Northbound corridors from Cushing, Oklahoma
and St. James, Louisiana, once formed the backbone
of the crude oil pipeline infrastructure in the Mid-
Continent, U.S. Gulf Coast, and Midwest regions.
Now, they are increasingly secondary to the growing
demand for southbound capacity.
A similar situation is occurring in the Rocky Moun-
tain region, where a growing surplus of light Rocky
mountain crude oil supply, coupled with increasing
availability of Canadian supply and lower refnery
demand, has overwhelmed takeaway pipeline capac-
ity on the Rockies to Midwest Interregional Corridor.
Also, growth of crude oil supplies in the U.S. Mid-
Continent, coupled with growth in Canadian produc-
tion, is causing an imbalance in the traditional market
dynamics around the Gulf Coast region. Te expected
surge in future ofshore domestic production com-
bined with Canadian imports and the capacity of cur-
rent infrastructure will likely reduce the need for the
Gulf Coast to increase foreign crude import capability.
Figure 1-39. U.S. Petroleum Administration for Defense Districts (PADDs)
PADD I: EAST COAST PADD III: GULF COAST PADD II: MIDWEST PADD IV: ROCKIES PADD V: WEST COAST, AK, HI
Source: Energy Information Administration, Oil Market Basics, Appendix A, “Map of Petroleum Administration for Defense Districts.”
Figure 1-39. U.S. Petroleum Administration for Defense Districts (PADD)
CHAPTER 1 - RESOURCES AND SUPPLY 129
tions in corridor capacity between supply regions
and demand hubs and demonstrate how the com-
modities markets determine infrastructure needs.
Te last 25 years has been a period of punctuated
market development. Regions that had produced
a relatively stable supply of crude oil began to slow.
In the latter half of 2010 and the beginning of 2011,
West Texas Intermediate priced at Cushing, Okla-
homa, was for the frst prolonged period ever priced
at a signifcant discount to Brent and other worldwide
benchmark crudes. Tis shows how changes in bal-
ance between markets can impact crude oil pricing.
Where market inefciencies occur, industry continues
to act as an efective balancing mechanism by identi-
fying an economic opportunity and developing infra-
structure to rebalance the market.
Public policy should continue to support existing
market mechanisms and encourage the market to
respond to infrastructure needs emerging in the fore-
seeable future. Tis is the case for newly constructed
or expanded infrastructure, and also when under-
used pipelines need to be reversed, idled, or undergo
changes in type of service.
Energy Security
Energy security is protected when markets and the
industry are encouraged and able to respond swiftly to
economic drivers. Tere is no better example of this
than today’s changing North American supply and
demand landscape. Rapidly growing production from
Northern Alberta’s vast energy reserves is met with
ample pipeline export capacity to the United States,
allowing crude oil to fow to major refning districts
in the Midwest, Mid-Continent, and ultimately the
Gulf Coast. Te robust energy supply position for
North America will support energy security for the
United States, as long as the necessary pipeline cor-
ridors are in place to continue to link production and
markets.
While changes in supply patterns across North
America will favor expansion of certain corridors,
declining use may merit capacity in others. Market
forces will continue to support U.S. energy secu-
rity even where use determines some corridors may
become unnecessary. Tough changing supply pat-
terns are shifting towards a predominantly North-
South fow from Canada into the Midwest and Mid-
Continent, some degree of import capacity from the
inventory and it remains the price settlement point
for the benchmark West Texas Intermediate on the
NYMEX. Several major pipeline corridors service
the Cushing hub, including supply from the Western
Canadian Sedimentary Basin, making the Cushing
hub and surrounding region strategic importance to
North American market dynamics.
In addition to evolving market dynamics, pressing
issues for the network of crude oil pipelines across
North America include the age of existing infra-
structure, combined with encroachment from urban
development leading to concerns about public safety.
Together these issues will likely lead to an increas-
ingly stringent regulatory environment, and addi-
tional capital will be required to enhance the safety
and securing of oil infrastructure.
Te overarching trend in oil infrastructure is the
requirement to respond to shifting market dynam-
ics caused by changing sources of domestic supply
and evolving transfer corridor capacity requirements.
Emerging alternative crude oil sources in the West-
ern Canadian Sedimentary Basin and North Dakota’s
Bakken play are pushing Midwest and Mid-Continent
pipelines to realign existing infrastructure to back out
traditional imports from the Gulf Coast in favor of
growing supply from the north.
Kcy Findings
As a whole, the petroleum pipeline industry and
infrastructure network will face a number of common
challenges over the next 50 years. Industry, policy-
makers, and regulatory bodies must be mindful of
these challenges to ensure a balance of diligence and
efciency that will best serve the interests of petro-
leum producers and consumers.
Changing Market Dynamics and Public Policy
Since the 1987 NPC oil pipeline study, the petro-
leum transportation industry has responded to the
needs of a changing North American crude oil mar-
ket landscape. Declining crude oil production in
regions such as PADDs III and V has been ofset by
ofshore imports, or U.S. imports from western Can-
ada. Refnery rationalization and Canadian imports
in recent years have led to increased reliance on
PADD II refnery hubs in Chicago and Wood River.
Such shifts have been met with expansions or reduc-
130 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
If and when a decision is made to idle or abandon
a pipeline, determinations about the remediation of
the asset must be made. From an environmental and
social perspective it may or may not be in the public’s
interests to remove a pipeline and fully remediate a
right of way. Such decisions will be dependent on the
specifc region or environment and the local munici-
palities.
Aging Infrastructure
Much of the pipeline infrastructure in North Amer-
ica was laid well before the last NPC oil pipeline study
was conducted in 1987. In 2010, several existing
systems are already 50 years old with no plans to be
decommissioned based on asset age alone. On systems
where asset integrity remains high, and market
demand still necessitates infrastructure, there is no
reason to retire assets so long as adequate mainte-
nance and integrity programs can guarantee system
safety.
Asset integrity cannot be directly predicted by age
alone, but, as time passes, overall infrastructure and
integrity issues could become more common with age.
Among age-related challenges are:
y Internal and external pipeline coating issues
y External corrosion
y Tird-party damage
y Weld seam failures
y Specifc integrity issue around fash welded pipe.
Tese challenges are cause for concern not only
because of public safety risk, but because of heavy
reliance on pipeline infrastructure in the North
American economy. Te U.S. relies on a small number
of key pipeline transportation corridors. Mitigation
and integrity programs are in place, but these pro-
grams may result in increased operating and mainte-
nance costs. Downtime for planned maintenance will
increase and be accompanied by an increased risk of
apportionment on key pipelines.
Regulatory Challenges
Development of new or greenfeld pipeline projects
often faces procedural challenges because of a compli-
cated regulatory environment in the United States.
Te lack of overarching federal oversight in the oil
pipeline permitting process leaves potential projects
subject to a patchwork of required state level environ-
mental, regulatory, and commercial approvals.
U.S. Gulf Coast into those regions should remain
available. Economics and pricing dynamics dictate
that the throughput on those corridors will continue
to act as a balancing mechanism for pricing hubs. Tis
will ensure that imports from the Gulf Coast or the
Strategic Petroleum Reserve will be available to the
Mid-Continent and Midwest even if the majority of
supply originates in the Western Canadian Sedimen-
tary Basin or the Bakken play.
Existing Infrastructure Use
Changing market dynamics between regions
impacts existing infrastructure use. For most of the
past 50 years, pipeline infrastructure was oriented in
a south-north alignment. However, increasing sup-
ply from Canada coupled with falling supply from
traditional production regions is causing a reversal to
north-south orientation.
Tis shift, along with other changes in market
dynamics resulting from shifting crude oil supplies,
has resulted in a number of reversals, conversions,
and idling of existing systems. For some pipelines,
this means using existing infrastructure with com-
modities for which they were not originally designed.
While this is not a signifcant issue, it is important
for the industry to be responsive to how a pipeline’s
original design parameters combine with its current
operation.
In other regions, supply and demand shifts have
resulted in signifcantly underused lines. Situa-
tions have emerged where one or two shippers will
continue to rely on a pipeline, but capacity demand
remains consistently below the pipeline’s economic
threshold. In cases where demand on an existing
pipeline falls below optimal fow rates, the question
begs whether the asset ought to remain in service at
a sub-optimal fow rate with potentially prohibitive
operating economics, or whether the asset ought to
be idled entirely.
In these instances the pipeline service provider is
left in a challenging predicament. Economics around
a particular asset may no longer be favorable to con-
tinued operation, but the provider is left open to ship-
per and regulatory scrutiny for the adverse impact the
asset’s idling or abandonment may have on another
business. Such cases need to be carefully examined in
Canada and the United States and the beneft to one
party must be weighed carefully against the harm to
another.
CHAPTER 1 - RESOURCES AND SUPPLY 131
environmental approvals should not be provided. In
these cases, federal mandate is required to show that
the project serves the public’s interests, albeit at a
national rather than state level.
State permitting processes multiply the number
of separate and unique approvals required for each
individual project. Tis increases the costs and time
required for the development of new projects and
introduces signifcant commercial risk that one state
In some cases, the public beneft of a project is clear
on the national level, but less so at the state level.
For example, an oil pipeline connecting supply in
one region to demand in another may easily travel
through one or more states without any intermedi-
ate receipts or deliveries. However, states between
the origin and destination may see no immediate eco-
nomic beneft to residents or businesses. At the state
level it may be determined that with no immediate
and primary beneft to local residents, regulatory and
Mexico has been, and continues to be, an impor-
tant trading partner with the United States for
energy. In particular, of most relevance to this
study, there is long-standing trade in crude oil and
natural gas to the beneft of both countries.
In 2010, Mexico exported 1.15 million barrels
per day of crude oil to the United States. As such,
the country was the second largest crude oil sup-
plier to the United States, after Canada (and ahead
of Saudi Arabia, Nigeria, and Venezuela). Tis
underlines Mexico’s importance as a North Ameri-
can crude oil producer and supplier. Mexico’s crude
oil production in 2010 was 2.96 million barrels per
day. Tis has declined in recent years (from its high-
est level of 3.82 million barrels per day in 2004) as
large felds, particularly the ofshore Cantarell feld
in the Bay of Campeche, have begun to decline, and
output from newer felds has not grown sufciently
to ofset this decline. Even so, newer develop-
ments, such as the nearby Ku-Maloob-Zaap felds,
now produce more than Cantarell. Onshore devel-
opments, such as the Chicontepec felds, have been
considered as a future source of production growth
potential, but have not yet become large contribu-
tors to Mexico’s crude oil production.
Prospects for continuing availability to the
United States of signifcant crude oil supplies from
Mexico will depend on Mexico’s ability to reverse
the recent decline in overall crude oil production,
at a rate which also exceeds Mexico’s own internal
market needs.
With regard to natural gas, Mexico is a net
importer, mainly by pipeline from the United
States, although, in recent years, Mexico has added
capacity to import LNG from international mar-
kets, with terminals both on its east coast and west
coast. In 2010, Mexico’s net natural gas imports
from the United States were 0.83 billion cubic feet
per day, representing almost 12.5% of Mexico’s gas
demand. Mexico has signifcant, and growing, nat-
ural gas production, which in 2010 totaled 5.3 bil-
lion cubic feet per day. However, Mexico’s natural
gas demand is growing at a faster rate than its pro-
duction, leading to an increased need for imports,
of which the United States supplies the most sig-
nifcant share. Tere is a well-established set of
natural gas pipeline interconnections between the
United States and Mexico, allowing this trade to
continue and expand.
However, recent trends in Mexican oil and natu-
ral gas production and consumption indicate that
the relationship between the United States and
Mexico will be quite diferent in the future. Sig-
nifcant recent declines in Mexican oil produc-
tion alongside rising domestic demand will likely
restrict Mexico’s ability to export oil to the United
States in the medium and long term. Increasing
internal Mexican demand for natural gas, mostly
as a result of rising electricity demands, will raise
Mexican demand for imported natural gas from
the United States and for liquefed natural gas
from other countries. Tese market dynamics will
take place in a context where the Mexican govern-
ment will be assessing its long-standing frame-
work for hydrocarbons production that restricts
private investment in the sector. However, even
important energy sector liberalization in Mexico
is unlikely to lead to quick change in Mexican oil
and natural gas production trends, as the lag time
between investment and production can be quite
long.
Mexico Oil and Gas
132 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
ral gas supply, and includes an overview of the con-
text and production history, where applicable, the
key technologies required for development, potential
production pathways to 2035 and beyond, and an out-
line of the key fndings. Te section concludes with
an overview of the natural gas infrastructure system
required to deliver this supply to market. Each of
these topics is described in more detail in topic papers
that are available on the NPC website.
Unlike oil, natural gas from the United States
and Canada has supplied the vast majority of mar-
ket needs in the region over the past 50 years. Both
nations are large natural gas producers, but produc-
tion and development activities have been almost
exclusively directed towards serving the North
American market. With one exception (Alaska LNG,
operational since 1969), only recently have serious
proposals been put forward regarding the potential
to export North American gas into global markets.
Indeed, this was preceded by several years in which
facilities to import LNG were developed on a large
scale, in anticipation of domestic supply falling short
of meeting market growth in the United States and
Canada.
Onshore natural gas, from both conventional and
unconventional reservoirs, forms the vast majority
of current and future supply potential. Supply pros-
pects have been transformed in recent years as natu-
ral gas companies have applied technology to develop
gas supplies that could not previously be produced
in economic quantities, particularly from shale gas
basins. In addition, large actual and potential produc-
ing natural gas supplies from ofshore and the Arctic
are discussed below.
O?shorc
Dcvclopmcnt and Production History
and Contcxt
U.S. Lower-48 O?shore
Te ofshore has been an active and important
contributor to North American natural gas and oil
supply, as described in a previous section. Natural
gas activity has been almost exclusively located in
the central and western zones of the Gulf of Mexico,
although signifcant resources and production poten-
tial are known to exist in other ofshore areas.
may approve a project while another frmly disap-
proves it.
As infrastructure demands from continental
regions such as the oil sands grow and aging infra-
structure requires replacement, a streamlined federal
level permitting process will be of greater value.
Public Perceptions
With continued urban growth, a growing percent-
age of pipeline right-of-way is in close proximity to
residential and commercial development. As this
trend continues it will be crucial to ensure public
awareness of the facilities and to manage public per-
ceptions around leak detection.
Challenges in the oil transportation industry have
highlighted vulnerabilities in leak detection technol-
ogy and reminded home and business owners of the
facilities in their area. As the average age of North
America’s pipeline network rises, it is important
to work with municipalities to ensure emergency
response plans are up to date and to educate indi-
viduals and businesses near pipeline facilities of the
importance of “Call Before You Dig” programs and
who to notify if they suspect a leak.
Security and Protection of Pipeline Assets
In 2009, there were approximately 55,000 miles of
crude oil trunk lines (typically 8–24 inches in diam-
eter) and tens of thousands of miles of additional
feeder lines, gas lines, and natural gas liquids pipe-
lines in the United States. Te challenges around
pipeline surveillance and the volume and volatility
of the liquids transported through pipelines place
them at a high risk for severe social and environmen-
tal fallout should pipeline integrity be compromised
accidentally or intentionally. Beyond the immediate
physical consequences of a severe pipeline disruption,
the economic ramifcations of taking a major pipeline
corridor ofine even temporarily could be far reaching
and result in crude oil shortages, refnery shutdowns,
and market disruptions.
PROSPECTS FOR NORTH
AMERICAN GAS DEVELOPMENT
Ovcrvicw
Each major heading in this section describes one
segment of this portfolio of current and future natu-
CHAPTER 1 - RESOURCES AND SUPPLY 133
As with oil, a shift in development focus from the
shallow water Continental Shelf of the Gulf of Mexico
to the deepwater frontier zones (with water depths
greater than 1,000 feet) began in the mid-1990s, and
accelerated after 2000. Tis trend is expected to con-
tinue as more discoveries and drilling activities occur
in the deepwater and ultra-deepwater areas of the
Gulf of Mexico. Beginning around 2000, the Gulf of
Mexico’s shallow water gas production has markedly
declined while deepwater production has increased.
Deepwater natural gas production rose from 382 Bcf,
or 7.5%, of total Gulf of Mexico production in 1997 to
around 1.4 Tcf in 2004, or 35%, of total Gulf of Mex-
ico natural gas production.
Apart from the central and western zones of
the Gulf of Mexico, other ofshore areas in the U.S.
lower-48 were subject to congressional moratoria
from 1982 to 2008. After these moratoria expired,
Natural gas production from the federal ofshore
grew from about 0.06 Tcf in 1954 to a maximum of
around 5.2 Tcf in 1997, accounting for just over 25%
of total U.S. natural gas production at that time. Since
then, federal ofshore natural gas production has
declined to around 2.4 Tcf in 2009, or 11% of total
U.S. gas production. Figure 1-40 shows gas produc-
tion as a percentage of total U.S. production from
1960 to 2009.
Currently, U.S. lower-48 ofshore oil and gas pro-
duction is restricted to the Gulf of Mexico and the
Pacifc OCS shelf regions. Much of the eastern Gulf
of Mexico is expected to be restricted to drilling until
2022, and the Pacifc and Atlantic OCS areas were
restricted from leasing consideration up until 2008.
For the purposes of this study, oil and gas develop-
ment on the Alaska OCS is included in analysis of the
Arctic region, rather than the U.S. ofshore region.
Figure 1-40. Ofshore Gas Production as a Percentage of Total U.S. Production, 1960–2009
0
10
20
30
0
2
4
6
1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
P
E
R
C
E
N
T
A
G
E
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
1980 – First fve-year leasing program initiated
1981 – OCS moratoria begins
1
2
1982 – Onset of area-wide leasing 3
1995 – Passage of deepwater Royalty Relief Act 4
2008 – Expiration of OCS leasing moratoria 5
1 2 3 4 5
FEDERAL OUTER CONTINENTAL SHELF OCS
FEDERAL OCS PERCENTAGE OF TOTAL U.S. PRODUCTION
Sources: Total U.S. production data obtained from the Energy Information Administration’s Monthly Energy Review and federal
ofshore data obtained from the Ofce of Natural Resources Revenue; Bureau of Ocean Energy Management,
Ofshore Stats and Facts.
Figure 1-40. Ofshore Gas Production as a Percentage of Total U.S. Production, 1960–2009
134 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Canada O?shore
In Canada, ofshore hydrocarbon production comes
exclusively from its Atlantic margin; natural gas and
oil are produced in Nova Scotia (Figure 1-42) and
Newfoundland ofshore, respectively. Commercial
ofshore natural gas production has been centered on
the Sable Island sub-basin of the Scotian shelf. Natu-
ral gas is also produced ofshore Newfoundland, in
the White Rose and Jeanne d’Arc basins, but here it
is reinjected into the felds. Gas production from the
Sable Ofshore Energy Project comes from fve shal-
low marine felds (25 to 75 meters) that commenced
production between 1999 and 2004. In 2009,
459 MMcf/d was produced at the Sable Ofshore
Energy Project. In April 2010, cumulative gas pro-
duction reached 1.6 Tcf. Gas is piped onshore where
it is distributed to market through the Maritimes &
Northeast Pipeline.
Also in Nova Scotia, the Deep Panuke gas feld
in the Scotian Shelf should commence production
in 2011. Te feld is estimated to contain up to
900 Bcf of gas with a planned daily production of
300 MMcf/d.
the administration proposed leasing strategies that
would include selected new areas, such as an expanded
eastern Gulf of Mexico zone and areas of the mid
and south Atlantic coastline. However, these plans
were reconsidered in the aftermath of the Macondo
oil spill in the deepwater Gulf of Mexico. Tere are
currently no plans for new leasing outside the central
and western Gulf of Mexico. Estimates of undiscov-
ered technically recoverable natural gas resources
in the U.S. ofshore moratoria areas vary from 77 to
231 Tcf. Tis is a signifcant proportion of the
Bureau of Ocean Energy Management Regulation and
Enforcement mean estimates of total U.S. lower-48
ofshore undiscovered technically recoverable natural
gas of 288 Tcf.
12
A signifcant resource base remains
available for future ofshore natural gas production.
Figure 1-41 shows oil and gas resource estimates in
areas formerly under moratoria or considered of-
limits to OCS oil and gas production.
12 Minerals Management Service, “Assessment of Undiscovered
Technically Recoverable Oil and Gas Resources of the Nation’s
Outer Continental Shelf, 2006,” February 2006. MMS Fact
Sheet RED-2006-01b.
Figure 1-41. Estimates of Oil and Gas Resources in U.S. Ofshore Areas Formerly under Moratoria
0
50
100
150
200
250
0
10
20
30
40
50
60
70
MEAN ARI HIGH ARI MIDDLE API ALTERNATIVE
API
MEAN UTRR
MMS
MEAN UTRR
NARUC
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
O
F
G
A
S
B
I
L
L
I
O
N
B
A
R
R
E
L
S
O
F
O
I
L
GAS
OIL
Notes: ARI = Advanced Resources International; API = American Petroleum Institute; MMS = Minerals Management Service;
UTRR = undiscovered, technically recoverable resources; NARUC = National Association of Regulatory Utility Commissioners.
Sources: American Petroleum Institute, 2005; National Association of Regulatory Utility Commissioners, 2010.
Figure 1-41. Estimates of Oil and Gas Resources In U.S. Ofshore Areas Formerly Under Moratoria
CHAPTER 1 - RESOURCES AND SUPPLY 135
and a reasonably constrained production outlook, or
limited potential case, have been examined. Tese
refect the enablers and challenges to ofshore devel-
opment identifed by the NPC expert subgroup and by
respondents to the data survey.
Te high potential pathway is characterized by a
favorable economic environment, with increased
access to ofshore lands, accelerated technological
progress, and favorable government policies towards
ofshore development. Conversely, the limited poten-
tial pathway assumes more limited access to ofshore
zones, slower technological improvement, and a more
stringent policy and regulatory environment.
As with ofshore oil supply outlooks, alternate
cases published in the EIA’s Annual Energy Out-
look have examined environments of expanded of-
shore access, accelerated technology deployment,
and high prices that would afect prospects for nat-
ural gas (see Figures 1-43, 1-44, and 1-45). Tese
characterize the high potential ofshore natural gas
production pathway. Production of natural gas in
U.S. lower-48 ofshore trends from a minimum of
2.4 Tcf in 2010, in the reference case, to a maximum of
As in the U.S. lower-48, other ofshore areas in
Canada are subject to moratoria and other similar
restrictions on exploration and development activity.
Tese are discussed in the oil ofshore section above.
Kcy Dcvclopmcnt and Production
Tcchnologics
Ofshore oil and natural gas resource develop-
ment has been characterized by continuous technol-
ogy development and innovation, appropriate for
moving into greater water-depths, high-pressure,
high-temperature subsurface environments, and
complex geological settings. Because most of these
technologies are developed and deployed for both
oil and natural gas production, discussion of them is
included in the ofshore oil potential section of this
chapter.
Production Potcntial Pathways
U.S. Lower-48 O?shore
For the U.S. lower-48 ofshore, a reasonably uncon-
strained production pathway, or high potential case,
Figure 1-42. Monthly Ofshore Gas Production – Nova Scotia
0
4
8
12
16
20
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
B
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
M
O
N
T
H
SOUTH VENTURE ALMA NORTH TRIUMPH VENTURE THEBAUD
This fgure replaces the version found in 8/24 draft per Thierno Sow;
could not recreate original art, source could not be found by author
Source: Canada-Nova Scotia Ofshore Petroleum Board – Sable Ofshore Energy Project.
Figure 1-42. Monthly Ofshore Gas Production – Nova Scotia
136 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-44. Projection of U.S. Lower-48 Ofshore Gas Production – High Natural Gas Production Pathway
0
1
2
3
4
5
2010 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011 AEO2011 HIGH OCS RESOURCE CASE 2011
AEO2011 HIGH PRICE CASE 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-43. Projection of U.S. Lower-48 Ofshore Gas Production – Impact of Reduced Access
0
1
2
3
4
5
2010 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011
AEO2011 REDUCED OCS ACCESS 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-44. Projection of U.S. Lower-48 Ofshore Gas Production – High Natural Gas Production Pathway
Figure 1-43. Projection of U.S. Lower-48 Ofshore Gas Production – Impact of Reduced Access
CHAPTER 1 - RESOURCES AND SUPPLY 137
Gulf of Mexico providing the technical challenges are
overcome.
With respect to the limited potential production
outlook, the EIA’s low price case is an indicator of the
impact of the multiple factors that could afect pro-
duction. Natural gas production forecasts vary from
2.6 Tcf in 2010, in the low oil price Case, to 4.3 Tcf in
2035, in the AEO2010 reference case. Results of the
AEO2011 show gas production ranging from 2.4 Tcf
in 2010 to 2.1 Tcf in 2035, in the low oil price case.
Tat trend translates into a growth rate range of neg-
ative 1.1% per year in the Gulf of Mexico and nega-
tive 0.6% per year in the Pacifc region. Te reference
case of the AEO2011 shows natural gas production
increase from 2.4 Tcf in 2010 to 3.1 Tcf in 2035. Tat
trend represents an annual growth rate of 0.4% in the
Gulf of Mexico and 3.5% in the Pacifc region. Over-
all, the range of annualized growth rate of natural gas
production in the constrained case path is negative
1.1% to positive 0.4%.
As in the case of oil, if widespread long-term of-
shore development moratoria are reinstated, leading
to no development ofshore outside of the central
3.8 Tcf in 2035 in the high price case, according to the
AEO2011. Tat translates into an annual growth rate
range of 0.4 to 0.7%.
Similar to oil, much of the expected increase in
U.S. ofshore natural gas production is likely to come
from new discoveries in the Gulf of Mexico, such as
the Lower Tertiary trend. Te extent of the efects of
the Lower Tertiary trend on expansion of ofshore gas
resources is exemplifed by the McMoRan discovery of
the Davy Jones feld, located in 20 feet of water at a
total reservoir depth of nearly 30,000 feet. Although
shallower, conventional horizons of the Gulf of Mex-
ico Shelf have been heavily produced, only a small
percentage of wells have been drilled to more than
15,000 feet below the mud line. McMoRan’s Davy
Jones prospect is believed to hold at least 1 Tcf of
gas. Tis discovery demonstrates that hydrocarbon-
saturated Lower Tertiary formations exist not only in
remote, deepwater locations, but also closer to shore,
where development requires less time and money,
and infrastructure is in place. A number of other
Lower Tertiary play prospects, scheduled to come
online between 2010 and 2020, hold the promise of
a signifcant increase in natural gas production in the
Figure 1-45. Projection of U.S. Lower-48 Ofshore Gas Production – Low Natural Gas Production Pathway
0
1
2
3
4
5
2010 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011 AEO2011 HIGH OCS COST CASE 2011
AEO2011 LOW PRICE CASE 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-45. Projection of U.S. Lower-48 Ofshore Gas Production –
Limited Natural Gas Production Pathway
138 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
ultra-deepwater environments that lack basic
infrastructure needed to produce and to transport
the hydrocarbons to shore.
y Canadian ofshore production of natural gas is low
in comparison to the U.S. lower-48, and is confned
to the eastern shore in Newfoundland and Nova
Scotia. Removal of the formal and de facto mora-
toria will provide opportunities to increase natu-
ral gas development and production in ofshore
Canada.
Arctic
History and Contcxt
Te section on Arctic oil, earlier in this chapter,
describes the geographical scope of the Arctic as used
for this study and includes a map of the region stud-
ied. Tis section of the work looked at the regions of
Alaska, Canada, and Greenland subject to ice condi-
tions that impact hydrocarbon exploration and devel-
opment activities.
As with oil, this Arctic region contains very substan-
tial natural gas recoverable resources that can justif-
ably be termed as a world-scale natural gas resource
region. Te discovered undeveloped and technically
recoverable undiscovered volumes from Alaska, Arc-
tic Canada, and Greenland are currently estimated at
about 670 Tcf, on a mean, risked basis. Tis estimate is
roughly equal to the oil resource on an energy equiva-
lent basis. Figure 1-46 shows how this resource is dis-
tributed across the major basins of the region. And
Figure 1-47 shows how this resource is proportionately
split between Alaska, Arctic Canada, and Greenland,
including those areas under drilling moratoria or oth-
erwise unavailable for leasing.
Te long history of onshore and ofshore oil and
gas leasing, licensing, and exploration drilling in
the Arctic region has resulted in the discovery of
signifcant oil and gas reserves. Some reserves
have been developed and produced, most notably
the giant oil and gas feld at Prudhoe Bay on the
Alaska North Slope and the large oil and gas felds
(onshore and ofshore in Cook Inlet, Alaska). Tere
are also numerous stranded discoveries (no develop-
ment/production facilities and/or pipelines) such as
the Burger discovery in the U.S. Chukchi Sea. Tis
region also is believed to contain signifcant undis-
covered volumes, based on numerous government
agency estimates and supported by industry interest
and western zones of the Gulf of Mexico, overall
natural gas production could be 20% lower than this
outlook.
Kcy Findings
Comprehensive review of North American ofshore
oil and gas facts and prospects has led us to the fol-
lowing fndings:
y Natural gas development and production in the
U.S. lower-48 is signifcant, and may deliver posi-
tive production growth to 2050. Annual growth
rate of ofshore natural gas production is expected
to range from negative 1.1% to positive 0.7%
through 2035.
y According to the AEO2011, natural gas production
in the U.S. lower-48 ofshore is expected to decline
from 2.4 Tcf in 2010 to 2.1 Tcf in 2035 in the low
price case. Overall, U.S. lower-48 ofshore natural
gas production is also expected to rise from 2.4 Tcf
in 2010 to 3.8 Tcf in 2035 in the high oil price case.
y Beginning around 2020 and extending to 2050, we
expect the bulk of natural gas production in the
lower-48 ofshore to originate from the deepwater
Gulf of Mexico, the Gulf of Mexico Lower Tertiary
formations, and the Pacifc and the Atlantic of-
shore regions.
y Government policies favorable to accessing addi-
tional U.S. lower-48 ofshore lands are needed to
reach natural gas development and production
growth rates stated above.
y We expect a slow down and a postponement of of-
shore natural gas development and production if
unduly constraining operation safety requirement
and stringent environmental policies are imple-
mented in the OCS following the Macondo oil
spill in the deepwater Gulf of Mexico.
y Technological progress and innovation are the
key factors that would enable development and
production of natural gas in new frontier regions
located in deep water and in deeper reservoirs.
y Seismic innovative technologies that allow clearer
imaging of the subsalt horizons in the Gulf of
Mexico are pivotal to the expansion of hydrocar-
bon resources via additional newer discoveries.
y Subsea technology and an extended architecture
system will boost production of ofshore natu-
ral gas in remote and challenging deepwater and
CHAPTER 1 - RESOURCES AND SUPPLY 139
Figure 1-47. Split of Arctic Natural Gas Resource Potential
Note: Discovered undeveloped plus undiscovered (mean risked, technically recoverable) resources.
GREENLAND
AVAILABLE 21%
CANADA
AVAILABLE
28%
ALASKA
AVAILABLE
38%
ALASKA MORATORIA
AREA 5%
ALASKA POTENTIALLY
AVAILABLE FOR LEASE 2%
CANADA
UNAVAILABLE 5%
GREENLAND
UNAVAILABLE 1%
ALASKA'S TOTAL SHARE 45%
CANADA'S TOTAL SHARE 33%
GREENLAND'S
TOTAL SHARE
22%
Figure 1-47. Split of Arctic Natural Gas Resource Potential
Note: Discovered undeveloped plus mean risked, technically recoverable, undiscovered resources.
ARCTIC CIRCLE
TRILLION CUBIC FEET OF GAS
INTERNATIONAL BOUNDARY
DISPUTED ZONE
2
19.6
8.2
25
8.5
90.8
112.1
33.5
76.1
40
10.2
86.2
33.7
41.2
66
Figure 1-46. Arctic Gas Potential by Basin
Figure 1-46. Arctic Gas Potential by Basin
140 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
in 2010 following the Macondo oil spill in the deep-
water Gulf of Mexico. Te combined BOEMRE and
USGS total mean estimate of risked, undiscovered,
technically recoverable natural gas resources for the
Beaufort Sea is 33.5 Tcf gas. Te Chukchi Sea is also
signifcantly underexplored but is estimated to hold
76.8 Tcf of risked, undiscovered, technically recov-
erable resources of natural gas. Previous ofshore
exploration wells have demonstrated the occurrence
of natural gas, as described by BOEMRE, in both of
these basins (Burger, Kuvlum, Hammerhead, Sand-
piper, Seal, and Tern).
Central Alaska Onshore
Tis region contains several basins of possible
interest (Yukon Flats and Nenana Basin) but lacks
signifcant subsurface data. Various assessments
suggest that this region could contain natural gas
(5–11 Tcf).
South Alaska Onshore and Cook Inlet
Te Cook Inlet Basin covers some 15,000 square
miles; almost half are ofshore. Te Cook Inlet
onshore and state waters area has more than
300 exploration wells and numerous mature felds,
both onshore and ofshore, that have produced oil
and gas since the early 1900s. New exploration in this
basin waned after the 1968 giant Prudhoe Bay Field
discovery in north Alaska. Te basin is generally con-
sidered a mature province. Te mean, risked, undis-
covered, technically recoverable resources for the
Cook Inlet area are 25 Tcf of natural gas. Te other
basins in this region (Aleutian Peninsular [onshore
Bristol Bay and State Waters], Gulf of Alaska [onshore
and State waters], and Copper River) are believed to
have undiscovered reserve potential but lack a mod-
ern resource assessment. Exploration wells have been
drilled in these basins (Aleutian Peninsular, 36 wells;
Copper River, 11 wells; and Gulf of Alaska onshore
and state waters, 55 wells) but have not so far yielded
a commercial discovery.
South Alaska O?shore
Te Bering Shelf, North Aleutian Basin and Pacifc
Margin have been assessed as very prospective for
natural gas resources. Te Bering Shelf has 19.6 Tcf of
technically recoverable natural gas resources includ-
ing 8.6 Tcf on the Aleutian shelf, while the Pacifc
Margin has a further 8.2 Tcf. Te Aleutian Shelf plan-
ning area was considered for leasing within the 2007–
(leasing/licensing, historical 2D seismic and mod-
ern but limited 3D seismic, and renewed attempts
to secure regulatory permission to drill particularly
in the ofshore). Most of the signifcant yet-to-be-
found volumes are believed to be contained in the
ofshore, beneath the continental shelf. Unlike oil,
there has not been major natural gas production in
the Arctic, except within the Cook Inlet region of
Alaska, mainly as the large proved reserves under the
Prudhoe Bay and Point Tomson felds on the Alaska
North Slope and the felds on the Mackenzie Delta
have been unable to access the market as a result of
lack of pipeline infrastructure.
Following is a brief summary of the development
and production history for the most signifcant of the
main Arctic areas under consideration.
North Alaska Onshore
Exploration drilling in this region began in 1945
and discovered only non-commercial hydrocarbons
until the discovery of the giant Prudhoe Bay feld in
1968. Tis feld contained recoverable reserves of
15 billion barrels of oil and 27 Tcf of natural gas. Oil
has been produced from this feld since 1977, but the
produced associated natural gas has not been com-
mercialized due to the lack of a gas pipeline, and the
bulk of the produced gas has been and still is reinjected
back into the producing reservoir to enhance ongoing
oil recovery. Signifcant stranded gas (~8 Tcf) has also
been discovered at Pt. Tomson Field along the coastal
plain near the ANWR 1002 area. Many of the more
than 400 exploration wells drilled on or around the
North Slope coastal plain have shown non-associated
gas, particularly in the southern part of the region. In
addition, prospective areas outside of the North Slope
Coastal Plain (NPR-A, North Slope Foothills and the
ANWR 1002 area) are signifcantly underexplored.
Further, it is expected that the NPR-A and North Slope
Foothills region may have a higher endowment of gas
than oil.
North Alaska O?shore
Tere are 186 active leases in the Beaufort Sea,
most of which were issued following U.S. federal
lease sales held in 2005 and 2007. In the Chukchi
Sea, 487 leases were issued following a U.S. federal
lease sale in 2008. However, these leases had not
yet been drilled as of mid 2011, as a result of issues
outside the control of lessees, up to and including
the suspension of authorizations for Arctic drilling
CHAPTER 1 - RESOURCES AND SUPPLY 141
ventional oil and gas potential resides in immediately
ofshore basins with little potential in the adjacent
onshore areas. No quantitative assessments have
been conducted for the south and southeastern
ofshore margin of Greenland. Te ofshore acreage in
Greenland is administered by the Greenland Bureau
of Minerals and Petroleum.
Tcchnology
From the perspective of hydrocarbon exploration,
development, and production, natural gas activities
in the Arctic are subject to similar considerations as
those for oil, described in the Arctic oil section of this
chapter. Natural gas development in the Arctic faces
the additional challenge of required long-distance
pipelines to access markets in Canada and the United
States. Natural gas is not currently exported of the
North Slope, Mackenzie Delta/Canadian Beaufort,
Arctic Islands/Sverdrup Basin, or Labrador Shelf
because there is no gas pipeline infrastructure to
transport the gas to markets. Alternatives such as
tankering gas in the form of LNG or building a gas-
to-liquids plant which could convert the natural gas to
a higher density liquid product for transport through
the TAPS system have reportedly been studied,
but until recently have not been deemed economi-
cally competitive. Recent activity has been directed
toward developing the concept of a natural gas pipe-
line to move natural gas to market, as witnessed by
the Denali, TransCanada and Mackenzie Valley gas
pipeline proposals of recent years. Until export capa-
bilities are developed for the Alaska North Slope, the
majority of the gas will continue to be reinjected into
the producing reservoirs to enhance oil production,
and used locally for energy and heating. Meanwhile,
Mackenzie Delta and Canadian Beaufort gas remains
unproduced.
Potcntial Production Pathways
Given that no overall North American Arctic sup-
ply outlooks could be found in the public domain
(although there are a few basin-specifc analyses for
portions of Alaska and the Canadian Arctic), the Arc-
tic Subgroup developed three consensus cases: Lim-
ited Potential (reasonably constrained), Most Likely,
and High Potential (reasonably unconstrained).
Te adjective “reasonably” is used with care; it does
not imply that all constraints are either present or
removed. It represents the Subgroup’s informed view
of what may happen to Arctic development through
2012 5-Year Leasing Program. However, OCS Sale
214, scheduled for 2011, was removed from the sale
schedule by the Secretary of the Interior in the spring
of 2010 and the area is now under a Presidential with-
drawal from lease sales till June 2017.
Canadian North
Te Canadian North region contains onshore
basins in British Columbia, Yukon, Northwest Ter-
ritories, and Mackenzie Delta region, as well as the
ofshore Canadian Beaufort Sea area, Arctic Islands/
Sverdrup Basin area. Te National Energy Board of
Canada estimates the mean, risked, undiscovered,
technically recoverable resources for the Canadian
North Onshore basins as containing 1 Tcf gas. Te
NEB estimates the mean, risked, undiscovered,
technically recoverable resources for the Mackenzie
Delta/Canadian Beaufort Basin area as containing
52 Tcf gas. Te NEB estimates mean, risked, undis-
covered, technically recoverable resources for the
Arctic Islands/Sverdrup Basin as containing 28 Tcf
gas. In addition, the USGS has assessed the Canadian
Beaufort Outer Continental Slope region (outboard
of the Canadian Beaufort and Arctic Islands/Sver-
drup Basin areas) and estimates mean, risked, undis-
covered, technically recoverable resources of 15.1 Tcf.
Canadian East
Te Canadian East region is divided into the Cana-
dian Bafn Bay area (adjacent to the West Greenland)
and the Labrador/Newfoundland Shelf. Te southern
limit of the study area excludes the Scotian Shelf and
associated developments at Sable Island, where natu-
ral gas has been produced over the last decade. Te
Canadian Bafn Bay area is estimated to have a mean,
risked, undiscovered, technically recoverable natural
gas resource of 33.7 Tcf, based on ascribing 45% of
the USGS analysis of the West Greenland-East Canada
“Bafn basin” to the Canadian portion of this region,
while the Labrador-Newfoundland shelf is estimated
to hold 57 Tcf of natural gas.
Greenland
Te natural gas resources on the Continental mar-
gin ofshore Greenland are estimated as follows; West
Greenland 41.2 Tcf, North Greenland 10.2 Tcf, and
the East Greenland Rift Basins 86.2 Tcf, based on
ascribing 55% of the USGS analysis of the West Green-
land-East Canada “Bafn Basin” to the Greenland por-
tion of this region. Te USGS believes most of the con-
142 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
It should be noted that the Arctic Subgroup’s gas
production cases for Alaska may be conservative, as
compared to a published analysis by Northern Eco-
nomics suggesting that the U.S. Beaufort and Chuk-
chi OCS regions are capable of signifcant natural
gas production if the reported undiscovered hydro-
carbon resource assessment by the BOEMRE is vali-
dated by future exploration and appraisal drilling.
Te Northern Economics gas production forecast is
contained in Table 1-7 and Figures 1-29 and 1-30
(pages 99-100).
Kcy Findings
Te key fndings and recommendations relative
to Arctic development are included in the Arctic oil
section earlier in this chapter. Tere are no further
specifc fndings and recommendations relating only
to Arctic natural gas.
Onshorc Gas
Production History and Contcxt
Te onshore natural gas component of North
American supply includes both conventional and
unconventional gas as developed and produced in
onshore basins in the United States and Canada, with
the exception of onshore Arctic basins.
Currently, onshore gas from Canada and the United
States supplies over 95% of the natural gas con-
sumed in both these nations. Overall U.S. produc-
tion has increased signifcantly since 2005, with U.S.
2050, given economic, regulatory, and environmental
constraints that are less, or more, favorable to such
development.
Te three cases each outline a diferent production
scenario for major current or future developments.
Large, remote severely stranded resources (e.g., Cana-
dian Arctic Islands, NE Greenland Rift Basin) are not
included. Table 1-15 summarizes the assumptions
specifc to natural gas in these three scenarios.
Te most likely case is expected to lead to Arc-
tic production of 2 Tcf/yr (5.5 Bcf/d), based on
pipelines being developed in both Alaska and the
Mackenzie Delta/Canadian Beaufort to take gas to
market by around the middle of the 2020s. On the
Alaska side, this would amount to 1.6 Tcf/yr, with a
further 0.4 Tcf from the Mackenzie Delta and Cana-
dian Beaufort Sea.
In the Limited Potential case, these sources of gas
would remain stranded, assuming that the required
infrastructure development would not occur with
continuing economic and regulatory challenges act-
ing as a disincentive to the project proponents.
In the High Potential case, it is assumed that a
higher pace of resource development activity in
Alaska, including new ofshore areas and the Mack-
enzie Delta/Canadian Beaufort, would justify expan-
sions of the two pipeline systems by 2025, allowing
increases in production to a total of 2.9 Tcf/yr (almost
8 Bcf/d), of which about 2.2 Tcf would be from Alaska
and the remainder from the Canadian north.
Table 1-15. Three Potential Arctic Gas Production Pathways
Limited Potential Case Most Likely Case HIgh Potential Case
No Alaska gas pipeline Alaska gas pipeline;
4.5 Bcf/d, 2025
Alaska gas pipeline expansion;
5.9 Bcf/d, 2035
No Mackenzie gas pipeline Mackenzie gas pipeline;
1.2 Bcf/d, 2025
Mackenzie gas pipeline; expansion;
1.8 Bcf/d, 2035
No North Alaska, Chukchi or
Beaufort OCS, or Canadian Beaufort
production
North Alaska, Chukchi & Beaufort
OCS, and Canadian Beaufort
production; 15% resource
developed by 2050
North Alaska, Chukchi, and
Beaufort OCS, and Canadian
Beaufort production; 25% resource
developed by 2050
No Arctic Islands/Sverdrup Basin,
Labrador, or Grand Banks gas
No Arctic Islands/Sverdrup Basin,
Labrador, or Grand Banks gas
Labrador and Grand Banks gas;
10% resource developed by 2050
CHAPTER 1 - RESOURCES AND SUPPLY 143
begun in Canada, most notably in the Montney (silt-
stone) and the Horn River basin, but has not as yet
arrested the decline in overall production there.
U.S. (Bcf/d dry) and Canadian (Marketable)
Production Mix – Conventional and
Unconventional Sources 2000–2010
Unconventional production has increased from
approximately one-third of the total U.S. supply
mix in 2000, to nearly two-thirds in 2010, or from
33 to 63% of the total (Figure 1-48). Te increase
in U.S. production since 2005 is almost entirely due
to shale gas. Growth from this source alone exceeds
total U.S. production growth over this period. Shale
gas and coalbed methane represent a growing
percentage, currently approximately 11%, of overall
production in Canada. U.S. lower-48 and non-Arctic
Canada onshore gas production in 2009 is estimated
at 24.1 Tcf/yr.
Te focus on unconventional resource plays –
tight gas, coalbed methane, and shale gas – has also
arrested a previous decline in average well productiv-
ity, increased reserves per well drilled, and lifted the
dry natural gas production reaching an average of
57.8 Bcf/d in 2010. Tis dry production level repre-
sents an increase of 16% from the recent historic low
of 49.7 Bcf/d in 2005, and is the highest overall U.S.
production rate since 1973.
Production of natural gas from shale as a category
is largely responsible for the overall production
increase in the United States, having grown the most
in both absolute and percentage terms since 2000.
In 2000, shale gas production was approximately
1.0 Bcf/d, or about 2% of the U.S. supply mix. Shale
production had grown to approximately 11.6 Bcf/d
by 2010, representing approximately 20% of the
57.8 Bcf/d of estimated dry U.S. production
(Figure 1-48). Production from tight formations
has also increased in both absolute and percent-
age terms, increasing from 12.0 Bcf/d in 2000 to
19.9 Bcf/d in 2010, or from 23% to 34% of the total
over the period. When adding U.S. coalbed meth-
ane production, also considered “unconventional,”
production from unconventional sources has more
than doubled in the United States since 2000 –
increasing by 19.2 Bcf/d, from 17.2 Bcf/d in 2000,
to 36.4 Bcf/d in 2010. Shale gas production has also
Figure 1-48. U.S. and Canadian Production Mix, 2000–2010
0
20
40
60
80
2000 2002 2004 2006 2008 2010
B
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C
U
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P
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D
A
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YEAR
U.S. CONVENTIONAL
U.S. SHALE
U.S. TIGHT
U.S. CBM CANADIAN CONVENTIONAL
AND TIGHT CANADIAN SHALE
CANADIAN CBM
Note: CBM = coalbed methane.
Sources: Energy Information Administration; National Energy Board of Canada; and Wood Mackenzie.
Figure 1-48. U.S. and Canadian Production Mix, 2000–2010
144 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
and reserve trends should be expected, as tight gas
and shale gas production profles exhibit substan-
tially higher initial production rates and recoverable
reserves than conventional wells. Although uncon-
ventional wells are fewer in number, their prolifc
production and reserve additions have reversed a
declining trend.
Te frst widespread deployment of new drill-
ing and completion technologies focused on shale
gas was concentrated in the Barnett Shale play, in
northeast Texas. Te play, in active development
since the early 1990s, grew in importance from the
mid-2000s. Breakthroughs in technology trans-
formed the play into a prolifc producing area start-
ing in 2005. Peak month production in the Barnett
shale play increased by at least 60%, or by more than
500 Mcf/d per well, in the 2005–2009 period, com-
pared to 1990–2000.
While the Barnett Shale was an early success in
shale gas development, other plays are still being dis-
covered, with the Eagle Ford, Montney (siltstone),
Horn River, and the Marcellus Shale still in early,
but rapid development (Figure 1-50). Additional
reserve life index. Shale gas plays are dominating the
unconventional spectrum, although both tight gas
and coalbed methane continue to contribute to this
trend of increased productivity.
As shown on an annual basis in Figure 1-49, total
North American gas production reached a new high
of 27.3 Tcf in 2009 following a period of approxi-
mately fat production over the previous nine years,
despite a 57% increase in the well count. Te upturn
in production since 2005 coincides with the rapid
development of unconventional gas within North
America, particularly shale gas. Figure 1-49 includes
production and well counts from the Gulf of Mexico,
as the ofshore component was not identifed sepa-
rately within this particular 20-year data set. Te
Gulf of Mexico accounts for about 10% of produced
volumes.
Production and reserves from newly drilled wells
have increased since 2006, suggesting that not only
do these newly drilled wells replace natural declines
in rates and reserves in historical wells but they add
considerably more incremental rate and reserves per
well. Such a reversal of historical gas production
Figure 1-49. North American Gas Production and Operating Gas Wells
0
10
20
30
0
200
400
600
800
1,000
1989 1995 2000 2005 2010
T
R
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L
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N
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F
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T
W
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L
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N
T
T
H
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S
A
N
D
S
YEAR
NORTH AMERICAN GAS WELLS
NORTH AMERICAN ANNUAL GAS PRODUCTION
Note: Gulf of Mexico gas production and well count is included in North American data.
Sources: Wood Mackenzie; U.S. Energy Information Administration.
Figure 1-49. North American Gas Production and Operating Gas Wells
CHAPTER 1 - RESOURCES AND SUPPLY 145
Key Technology – Commercialization of Shale
as a Resource
Shale gas production can be traced back to the
mid-1800s, but until recently was a rather insignif-
cant source of energy. Once considered only a mar-
ginal producer, a source rock for hydrocarbons, or
as an impermeable barrier or seal for conventional
reservoirs, it is now a primary target for commercial
drilling. Tese ultralow-permeability reservoirs are
routinely exploited. Tis is made possible through
a combination of technologies, directional drilling,
seismic, lateral wellbores (horizontal wells), and
hydraulic fracturing. Without these technologies,
most shale reservoirs would not be commercial today.
Hydraulic fracturing is the most critical advance for
natural gas supply for North America.
Key Technology – Hydraulic Fracturing
First implemented for natural gas production in
1947 in the Hugoton gas feld, fracturing increases the
contacted surface area within a reservoir. Reservoir
rock is fractured by pumping high-pressure water with
a sand slurry that props the fractures open. Because
shale resource plays, including the Duvernay, Utica,
Collingwood, and others, wait in the wings, providing
a large future resource base for North American natu-
ral gas supplies.
Kcy Dcvclopmcnt and Production
Tcchnologics
Development of natural gas has recently been
dominated by the application of new technology,
especially the development of cost-efective fracture
stimulation in horizontal wellbores. Both horizontal
drilling and fracture stimulation have been in use for
decades. Fracture stimulation was frst implemented
in a gas feld in 1947 in the Hugoton gas feld and gas
from shale has been produced for more than a cen-
tury. Experimentation with horizontal drilling goes
back as far as the 1920s, although the frst commer-
cial application didn’t take place until the mid-1980s
in the Austin Chalk formation.
Following are some key milestones in develop-
ment and application of technologies to unlock North
America’s natural gas resources follow.
Figure 1-50. Production by Shale Play: Growing Beyond the Barnett
0
4
8
12
2000 2001 2002 2003 2004 2005
YEAR
2006 2007 2008 2009 2010
B
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C
U
B
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T
P
E
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D
A
Y
BARNETT FAYETTEVILLE WOODFORD HAYNESVILLE
MARCELLUS EAGLE FORD HORN RIVER MONTNEY AND DUVERNEY
Source: Wood Mackenzie.
Figure 1-50. Production by Shale Play: Growing Beyond the Barnett
146 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
It was not until the 1980s that notable commercial
horizontal wells were drilled in North America in the
Austin Chalk, Bakken, and Niobrara formations.
17
As technology improved, horizontal drilling enabled
previously, non-commercial formations to become
economic.
18
By the 1990s, more than 1,000 horizon-
tal wells had been drilled throughout the world.
19
After initial commercialization of the technique,
efciencies continued to improve, yielding longer
lateral lengths per well and ultimately continuing to
decrease surface disturbance. In 1987, the frst hori-
zontal wells in the Bakken Shale were of relatively
modest lengths of approximately 1,000 feet. By
the 1990s, as technology improved, lateral lengths
of 3,000 to 4,000 feet were possible, and today
wells are routinely drilled with lateral lengths of
10,000 feet.
Key Technology – Modern (3D) Seismic
Technology
Te increase in activity during the 1980s was also
spurred by the advent of 3D seismic technology. Te
exploration success rate increased, resulting in pre-
viously uneconomic plays becoming tenable. Today,
seismic data is processed using computer algorithms
that assist in identifying anomalies in the data. Tese
anomalies may be identifed as hydrocarbon depos-
its. From 1990 through 2001, the overall costs of
3D seismic imaging decreased by a factor of fve. Sur-
veys conducted by Te American Oil and Gas Reporter
as well as the Petroleum Technology Transfer Council
indicate that seismic technology has been highly ben-
efcial to the industry.
20
Modern seismic imaging techniques allow for
improved recognition of formation types and char-
acteristics. Te use of modern seismic technol-
ogy has allowed wells to be drilled while avoiding
17 Flores, C. P., “Technology and Economics Afecting Unconven-
tional Reservoir Development,” Master’s Tesis, Texas A&M
University, December 2008.
18 Joshi, S. D., “Cost/Benefts of Horizontal Wells,” SPE paper
83621 for SPE Western Regional/AAPG Pacifc Section Joint
Meeting, Long Beach, California, 2003.
19 Energy Information Administration, “Drilling Sideways – A
Review of Horizontal Well Technology and Its Domestic Appli-
cation,” Contract No. DOE/EIA-TR-0565, U.S. DOE, Washing-
ton, DC, April 1993.
20 Ammer, James, “Tight Gas Technologies for the Rocky Moun-
tains,” GasTIPS, Spring 2002, pages 18–23.
the frst fracturing treatment included no propping
agent to maintain conductivity within the induced
fractures, it proved unsuccessful. By 1949, hydrau-
lic fracturing was successfully implemented in the
Woodbine sands in East Texas and became commer-
cially viable.
13
Since then, many improvements have
been made to reliability and safety. By hydraulically
fracturing a gas reservoir, the efective permeability,
or capacity to fow, can be signifcantly increased. In
fact, with no stimulation treatment, many currently
producing reservoirs would be considered imperme-
able. Successful stimulation treatments can increase
permeability by fve to six orders of magnitude.
14
By
1955, more than 3,000 fracturing treatments were
pumped each month. Troughout the 1960s and
1970s, fracturing became better understood and
could be optimized for a particular formation.
15
Oper-
ational efciency improvements resulted in cost sav-
ings, making more plays economic. Today, coil tub-
ing fracturing technology has resulted in shorter time
requirements per fracture induced, and multiple zone
fractures can be completed in a short time. According
to the Independent Petroleum Association of Amer-
ica, approximately 90% of new gas well production
relies on hydraulic fracturing.
Key Technology – Horizontal Drilling
In horizontal well drilling, a well is drilled par-
allel to the formation, exposing more reservoir
rock than would be possible using a conventional
vertical completion technique.
16
By increasing
the length of the horizontal portion of the well,
multiple vertical well locations were replaced
with a single horizontal well for a fraction of the
cost, minimizing surface disturbance. As early
as 1927, the concept of drilling horizontally
through the producing formation was tested in
North America; however, many of the technique’s
early advances were made in Bashkiria, Russia.
13 Economides, M. J. and K. G. Nolte, Reservoir Stimulation, third
edition. (West Sussex: Wiley, 2000), page 367.
14 Economides et al., Petroleum Production Systems (New Jersey:
Prentice Hall, 1994), page 600.
15 Holditch, S. A., and N. R. Tschirhart, Optimal Stimulation
Treatments in Tight Gas Sands, SPE Paper 96104 for SPE Annual
Technical Conference and Exhibition, Dallas, Texas, 2005.
16 Sheikholeslami et al., “Drilling and Production Aspects of
Horizontal Wells in the Austin Chalk,” SPE Journal of Petroleum
Technology, July 1991, pages 773–779.
CHAPTER 1 - RESOURCES AND SUPPLY 147
tools to exact specifcations. Because of advances
in computer numerical control milling technology,
production times have been signifcantly reduced.
Downhole equipment is also more robust. Robotic
controllers are now used, especially in high-pressure
high-temperature environments. Prior to these
advances in electronic technology, many hydrocarbon
reservoirs were efectively inaccessible.
Advancing Technologies
Te following areas of ongoing research associated
with natural gas production will result in improved
recoveries and operational efciencies in the near
term:
y Fracturing technology
y Surface disturbance minimization
y Super-pad drilling
y Slim-hole completions
y Fit-for-purpose Coiled Tubing Drilling
y Multilateral wells.
potential water zones and areas of high faulting.
Although much work is still needed in this area, this
technology has increased the likelihood of drilling
locations of high productivity while decreasing the
chances of drilling low productivity wells.
Key Technology – Te Personal Computer
Technological improvements in computer process-
ing power have also resulted in tremendous efciency
gains. Prior to the widespread use of personal com-
puters, simulations and other rigorous mathematical
modeling required mainframe computer time. Tis
proved both cost and time prohibitive. Personal com-
puters have become ubiquitous in the industry, allow-
ing engineers and geologists to routinely execute
complex mathematical models to simulate reservoirs
and basins. Tis has been refected in metrics that
track worker productivity, as shown in Figure 1-51.
Te personal computer led to increases in worker
efciency and has enabled a host of other products.
Computer-aided design (CAD) software packages
are used in conjunction with computer numeri-
cal control machining to produce sophisticated
Figure 1-51. U.S. Total Well Count per Employee
0
2
4
6
8
0
100
200
300
400
1970 1980 1990 2000 2010
P
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X
1
,
0
0
0
YEAR
EMPLOYMENT IN EXPLORATION AND PRODUCTION
OIL AND GAS WELLS DRILLED/EMPLOYEE X 1,000
PRODUCING WELLS PER EMPLOYEE
Source: Bureau of Labor Statistics, 2010.
Figure 1-51. U.S. Total Well Count per Employee
148 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
For the production pathways analyzed here, the
NPC team used the resource data supporting the
Massachusetts Institute of Technology energy initia-
tives (MITei) report. Te data provide a reasonable
range of estimates in a format useful for scenario
building. MITei uses the North American supply
model developed by ICF, which provides for a high-
medium-low look using “current” technology and
the same for an “advanced” technology case, result-
ing in six diferent model outputs for consideration.
It should be noted that “current” refers to technol-
ogy applied in 2007 or earlier. Given recent break-
throughs, today’s application of technology renders
the “Advanced Technology” cases more relevant
today. For the purposes of this study, it was decided
to focus upon three onshore, non-Arctic resource
size cases:
y Case One – MITei/ICF Mean Resource Base, Cur-
rent (2007) Technology, Remaining Recoverable
Resource 1,901 Tcf, Estimated Ultimate Recover-
able Resource 2,996 Tcf. Te consensus view of the
NPC team is that this case is conservative and it is
highly probable that it will be surpassed.
y Case Two – MITei/ICF Mean Resource Base,
Advanced Technology, Remaining Recoverable
Resource 2,890 Tcf, Estimated Ultimate Recover-
able Resource 3,985 Tcf. Te consensus view of the
NPC team is that this case is also rather conservative
and it is probable that it will be surpassed.
y Case Tree – MITei/ICF High Resource Base,
Advanced Technology, Remaining Recoverable
Resource 3,561 Tcf, Estimated Ultimate Recover-
able Resource 4,656 Tcf. Te consensus view of the
NPC team is that this case is reasonable today and
could readily be surpassed.
Figure 1-52 illustrates the supply cost stack for
these three cases. Tis fgure shows gas resource
volumes on the horizontal axis plotted against cost
of supply ($/MMBtu) on the vertical axis. Te scale
is truncated at $30/MMBtu. Historical cumulative
gas production rose above 1,000 Tcf in 2006. The
estimated ultimate recoverable gas resources for the
three cases are plotted in Figure 1-52.
Te additional resources that might be recover-
able at costs above $20/MMBtu appear to be rela-
tively small, so comparisons among the cases can be
made at this level. Ultimate recoverable resources,
including cumulative production to date, range
Future Technology
Of natural gas production in the United States
in 2008, approximately 40% of the wells required
hydraulic fracturing stimulation to produce at
economic rates.
21
According to the Independent
Petroleum Association of America, approximately
90% of new gas wells rely on hydraulic fracturing to
produce.
22
Without both hydraulic fracturing and hor-
izontal drilling, future production growth in onshore
natural gas cannot be achieved and any reservoir
termed “unconventional” would be uneconomic. Te
EIA has modeled natural gas supply for a scenario
with no additional tight gas production. In this sce-
nario, natural gas production from onshore North
America falls by 39%. From these estimates it can be
seen that the future of natural gas supply in North
America will rely upon future availability and contin-
uous improvement in fracturing tight gas and shale
gas formations.
Production Potcntial
Potential for future production of onshore gas has
been transformed by development and application of
the technologies described in the previous section. A
number of studies have quantifed the resource base
and these assessments are included in Table 1-16.
Te most important realization from these stud-
ies is that in less than a decade, estimates of the
North America resource base have grown by more
than 150%. Te most recent study sponsored by
America’s Natural Gas Alliance includes a compre-
hensive geological and engineering based model of
32 unconventional plays, including shale gas, tight
gas sands, and coalbed methane formations. Tese
unconventional plays alone were projected to have
recoverable reserves over 2,600 Tcf. Tis recent
study, in combination with the consistent trend of
resource growth, provides a compelling argument
that the resource base is large. With sufcient con-
fdence in the underlying resource base, the focus
can shift to questions regarding supply and rates of
development.
21 Energy Information Administration, (2010a) Annual Energy
Outlook 2010 With Projections to 2035, (2010b) Natural Gas
U.S. Data. Retrieved fromhttp://www.eia.doe.gov/oil_gas/
natural_gas/info_glance/natural_gas.html.
22 Tiemann, Mary, Congressional Research Service, June 2, 2010.
Safe Drinking Water Act (SDWA): Selected Regulatory and
Legislative Issues, page 22.
CHAPTER 1 - RESOURCES AND SUPPLY 149
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150 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
(Should market needs be greater over this time
period, other supply sources, such as ofshore gas,
Arctic gas, or imported LNG would also be called
upon to complete the supply mix.)
y Restricted Supply Scenarios – Here assumptions
are analyzed to estimate the efects of various pos-
sible restrictions or constraints (such as limitations
on fracturing and resource access) on industry’s
ability to supply onshore gas. Two of these sce-
narios are illustrated in the following fgures: from
extreme limitations to supply (Figure 1-55) to mod-
erate limitations to supply (Figure 1-56). Clearly,
these assumptions would have a drastic efect on
the ability to supply North America gas domesti-
cally. Te remaining resource would be reduced by
over 70% compared to the unrestricted Flat Supply
scenarios, and potential plateau supply would be
eliminated entirely under the most extreme restric-
tions, such as disallowing hydraulic fracturing.
Plateau (fat) supply would be reduced from the
approximate 80–90 years, to approximately 40–50
years by assuming 33% restrictions on unconven-
tional supply.
from ~3,000 Tcf in Case One up to ~4,700 Tcf with
advanced technology in Case Tree.
With this understanding of the potential resource
base, we analyzed implications for supply potential
for the onshore non-Arctic segment of North Ameri-
can gas under several scenarios.
y Flat Supply Scenario – at a constant 24 Tcf/yr,
equal to current production rates, until beginning
of decline, the variation in remaining resource esti-
mates has a signifcant efect on the duration of pla-
teau supply length. As illustrated in Figure 1-53,
approximately fve to nine decades at this produc-
tion level are possible, followed by signifcant post-
plateau supply.
y Supply Growth Scenario – An increased rate of
supply scenario, whereby supply is assumed to
increase approximately 50% from 24.1 Tcf/yr to
36.5 Tcf/yr. Te increase takes place to achieve this
higher supply plateau in approximately one decade.
Tis plateau could be maintained for between two
and four decades after 2020, based on the resource
estimates used, as illustrated in Figure 1-54.
$0
$10
$20
$30
0 1,000 2,000 3,000 4,000 5,000 6,000
ULTIMATE RECOVERABLE RESOURCE (TRILLIONS OF CUBIC FEET)
Figure 1-52. Onshore Natural Gas Recoverable Resource Cases versus Cost of Supply at the Wellhead
WAS Figure ES-2
2,996
W
E
L
L
H
E
A
D
S
U
P
P
L
Y
C
O
S
T
(
D
O
L
L
A
R
S
P
E
R
M
I
L
L
I
O
N
B
T
U
)
3,985 4,656
100 YEARS OF
CONSUMPTION
AT CURRENT RATES
CUMULATIVE
PRODUCTION
THROUGH 2010
Note: See page 107 for case defnitions.
Sources: Energy Information Administration and MIT Energy Initiative (MITei)/ICF International.
CASE ONE
CASE TWO
CASE THREE
Figure 1-52. Onshore Natural Gas Recoverable Resource Cases versus Cost of Supply at the Wellhead
CHAPTER 1 - RESOURCES AND SUPPLY 151
Figure 1-54. Supply Growth Scenario
YEARS FLAT CONSUMPTION
2,100 TCF
TERMINAL
DECLINE
VOLUME
4,656 TCF
ULTIMATE
RESOURCE
1,500 TCF
TERMINAL
DECLINE
VOLUME
900 TCF
TERMINAL
DECLINE
VOLUME
3,985 TCF
ULTIMATE
RESOURCE
2,996 TCF
ULTIMATE
RESOURCE
20 0 31 33
1.4 TCF/YR GROWTH
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
HISTORY
Note: Supply Growth Scenario – 5% growth per year to 100 billion cubic feet per day.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
HISTORY
CASE ONE
CASE TWO
CASE THREE
Figure 1-54. Supply Growth Scenario
Figure 1-53. Flat Supply Scenario
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
YEARS FLAT CONSUMPTION
1,400 TCF
TERMINAL
DECLINE
VOLUME
4,656 TCF
ULTIMATE
RESOURCE
1,000 TCF
TERMINAL
DECLINE
VOLUME
600 TCF
TERMINAL
DECLINE
VOLUME
3,985 TCF
ULTIMATE
RESOURCE
2,996 TCF
ULTIMATE
RESOURCE
54 0 78 90
HISTORY
HISTORY
CASE ONE
CASE TWO
CASE THREE
Figure 1-53. Flat Supply Scenario
152 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-55. Extremely Restricted Supply Scenario – Extreme
YEARS FLAT CONSUMPTION
1,013
2,108
824
600
1,919
1,787
4 0
TCF ULTIMATE RESOURCE
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
HISTORY
CASE ONE
CASE TWO
CASE THREE
TCF TERMINAL
DECLINE VOLUME
Notes: Extremely restricted supply scenario – fracturing impact, no shale technology enabled.
Year-end 2009 cumulative = 1,095 TCF.
Cases Two and Three have immediate terminal decline.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
Figure 1-56. Moderately Restricted Supply Scenario
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
HISTORY
Notes: Moderately restricted supply scenario – fracturing impact, 67% tight/coalbed methane/shale technology enabled.
Year-end 2009 cumulative = 1,095 TCF.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
YEARS FLAT CONSUMPTION
1,400
3,789
1,000
600
3,283
2,587
0 37 49 54
HISTORY
CASE ONE
CASE TWO
CASE THREE
TCF ULTIMATE RESOURCE
TCF TERMINAL
DECLINE VOLUME
Figure 1-55. Extremely Restricted Supply Scenario
Figure 1-56. Moderately Restricted Supply Scenario
CHAPTER 1 - RESOURCES AND SUPPLY 153
draw on any particular resource type, the potential
amount of natural gas that would be produced over
the lifetime of the wells drilled between 2010 and
2050 was checked against public estimates of recov-
erable resources by type.
Te estimated production by resource type and
pace of onshore natural gas drilling to maintain com-
bined U.S. and Canadian production at current levels
of roughly 66 Bcf/d for the Flat Supply Scenario is
indicated in Figures 1-58 and 1-59.
Increasing output of shale gas rises to about 60%
of the total and is able to ofset declines in conven-
tional and coalbed methane production to maintain
production. As shale gas wells produce at higher
rates than many of the conventional, coalbed meth-
ane, and tight gas wells relied on previously, the
absolute number of new onshore gas wells required
to maintain current production remains less than
60% of the peak 2006 level.
To achieve signifcant increases in combined
U.S. and Canadian production to roughly 100 Bcf/d
by 2020, and maintain that level thereafter, would
Figure 1-57 provides a summary of Flat Supply,
Supply Growth, and Extremely Restricted Scenarios
using the mid-range estimate of recoverable resources
(Case Two), and as such provides a guide to the poten-
tial for reasonably unconstrained, most likely, and
constrained production pathways.
To further test the reasonableness of these poten-
tial production pathways, the study team ana-
lyzed the magnitude of input requirements needed.
Details of the methodology and results are described
in Topic Paper #1-8, “Onshore Natural Gas,” available
on the NPC website. Here we summarize the indica-
tive requirements of rigs, industry personnel, tubular
(steel) tonnage, proppant, and fracture stimulation
water usage required to support both the Flat Supply
and Supply Growth scenarios.
Based on expectations of relative economics of
the major natural gas types, it was assumed that
increases in drilling would primarily target shale
gas, and to a lesser extent tight gas. Conventional
gas and coalbed methane drilling were assumed to
remain essentially fat at around current levels over
the period to 2050. To avoid a disproportionate
Figure 1-57. Comparison of Three Supply Scenarios:
Mean Resource Base, Advanced Technology, and 2007 Cost Index
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
YEAR
Note: Year-end 2009 cumulative = 1,095 TCF.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
HISTORY
FLAT SUPPLY
SUPPLY GROWTH
EXTREMELY RESTRICTED SUPPLY
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
Figure 1-57. Comparison of Three Supply Scenarios: Mean Resource Base,
Advanced Technology, and 2007 Cost Index
154 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-58. Onshore North American Gas Production in Flat Supply Scenario
0
20
40
60
80
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
B
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
D
A
Y
YEAR
SHALE TIGHT COALBED METHANE CONVENTIONAL
Figure 1-59. Projected Wells Required in Flat Supply Scenario
0
20
40
60
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
W
E
L
L
S
T
H
O
U
S
A
N
D
S
YEAR
SHALE TIGHT COALBED METHANE CONVENTIONAL
Figure 1-58. Onshore North American Gas Production in Flat Supply Scenario
Figure 1-59. Projected Required Wells Required in Flat Supply Scenario
CHAPTER 1 - RESOURCES AND SUPPLY 155
activity is generally consistent with historical levels.
Employment would increase. High horsepower rigs
(1,500 horsepower or more) are estimated at approxi-
mately 25 to 33% of the total gas rig count.
Figure 1-63 illustrates the fracture stimulation
activity-related input requirements for U.S. lower-48
and non-Arctic Canada onshore gas supply, including
fracture stimulation stages, fracture proppant, and
initial water (without diferentiation between pri-
mary and re-used water) required for fracture stimu-
lation. Te Flat Supply scenario is expected to require
historically similar overall numbers of fracture stimu-
lation stages and proppant compared to recent levels.
Te Supply Growth scenario would require approxi-
mately 50% greater fracture stimulations overall by
2050 than recent history. Water (primary and re-use)
for fracture stimulations would increase, depending
upon scenario, by approximately 50–125% overall
by 2050 compared to recent levels. Local increases
in water use could be greater. Nonetheless, even
in the Supply Growth scenario in 2050, estimated
total annual water used for fracture stimulations at
2.5 billion barrels is still less than 0.2% of the U.S.
daily consumption in 2000 (excluding hydroelectric
involve higher levels of drilling. As indicated in
Figures 1-60 and 1-61, shale gas again is projected to
account for about 60% of the production from 2020
onward. By 2050, the requirement for new onshore
natural gas wells would be projected to reach over
80% of the 2006 peak.
While the absolute number of new onshore natural
gas wells remains below previous peaks, the numbers
may not be strictly comparable since shale gas wells
tend to require greater amounts of labor, equipment,
and materials to drill and complete than earlier gen-
erations of onshore natural gas wells. To test the level
of inputs required for drilling under the scenarios
examined, the study team looked at such items as
fracture stages, water use for fracturing, proppant,
steel, and manpower. Te following charts illustrate
the requirements derived from the level of activity
analyzed.
Te frst fgure set (Figure 1-62) illustrates the
activity-related input requirements for U.S. lower-48
and non-Arctic Canada onshore gas supply; namely
rigs (total and high horsepower), direct employment,
well capital, and steel for well tubulars. Tis level of
Figure 1-60. Onshore North American Gas Production in Supply Growth Scenario
0
40
80
120
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
B
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
D
A
Y
YEAR
SHALE TIGHT COALBED METHANE CONVENTIONAL
Figure 1-60. Onshore North American Gas Production in Supply Growth Scenario
156 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
on critical inputs (particularly fracture stimulation,
water disposal, and land access) on a national level
will cause natural gas supply rate to decline.
Kcy Findings
y Recent technology advances have enabled develop-
ment of large-scale tight gas and shale gas resources
in North America.
y Estimates of remaining resources, particularly of
shale gas, have increased signifcantly in recent
years and in all resource studies.
? Horizontal drilling coupled with multi-stage
fracture stimulation plays a key part in this
increase, enabling greatly increased production
of shale gas and tight gas.
y Te remaining recoverable gas resource (as of Jan-
uary 2010) is estimated to be between 1,900 and
3,600 Tcf.
? Further advances in technology and play delin-
eation beyond the current level are expected to
further increase this quantity.
utilization) of 213 billion gallons per day (1.85 tril-
lion barrels per year).
23
Advances by the industry to
reuse stimulation water and use non-potable water
will likely substantially reduce actual water use below
this estimate.
Natural gas can continue to be a signifcant con-
tributor to the continent’s energy supply and secu-
rity. Ample natural gas is available in North America
to supply current consumption levels for decades
and to support signifcant growth into other sectors
as well. New techniques, including cost-efective
multiple-stage fracture stimulation in horizontal
wellbores, have enabled vast resources never before
considered economic at any reasonable price. Input
resource requirements (e.g., rigs, people, fracture
stimulation proppant, and water) are signifcant yet
manageable, and achieving these levels of supply is
within industry capabilities. Extreme restrictions
23 Susan S. Hutson et al., “Estimated Use of Water in the United
States in 2000,” U.S. Geological Survey Circular 1268, 15 fg-
ures, 14 tables. (2004, revised April 2004, May 2004, and Feb-
ruary 2005).
Figure 1-61. Projected Wells Required in Supply Growth Scenario
SHALE TIGHT COALBED METHANE CONVENTIONAL
20
40
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
YEAR
0
60
W
E
L
L
S
T
H
O
U
S
A
N
D
S
Figure 1-61. Projected Wells Required in Supply Growth Scenario
CHAPTER 1 - RESOURCES AND SUPPLY 157
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158 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
0
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2008 2010 2030 2050
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Figure 1-63. Indicative Estimates of Well Stimulation–Related Inputs
YEAR
YEAR
YEAR
Figure 1-63. Indicative Estimates of Well Stimulation–Related Inputs
CHAPTER 1 - RESOURCES AND SUPPLY 159
mated to be available at 50% greater supply levels
than today, even accounting for a decade ramp up
and decline volumes.
y Supply costs should remain moderate as long as
development and production is not overly restricted
or unduly burdened.
y Requirements to support this resource develop-
ment are achievable based upon high level scoping:
? Directly employed personnel could increase
10–25% over 40 years.
? Legislative and regulatory constraints (particu-
larly on fracture stimulation) on development
activity could drastically reduce the available re-
coverable resource.
y Between fve and nine decades of fat supply at
2009 levels is estimated to exist, even accounting
for substantial (600–1,400 Tcf) resource being pro-
duced on a decline following the plateau.
y Onshore gas supplies can support increased use of
this resource. Up to three decades of supply is esti-
Liquefed Natural Gas (LNG) is a small but grow-
ing part of the global gas market. LNG consump-
tion in 2009 was 23.5 Bcf/d or 8.2% of total world
demand for natural gas, according to the BP Review
of World Energy. LNG demand has grown 6–7% per
year for the last two decades, far faster than the
overall 2–4% growth in the total global natural gas
market.
Liquefed natural gas is created by cooling natu-
ral gas to -161
o
C. At that temperature, natural gas
becomes a liquid and volume drops by a factor of
approximately 600. Tat decrease in volume allows
natural gas to be economically transported by spe-
cialized ships to distant markets.
Te United States began importing LNG in 1971
to a regasifcation terminal in Massachusetts but
importation had a ftful start. By 1982, four other
import terminals had opened and three of them
had closed. Reliance on imports picked up in the
1980s when proved U.S. gas reserves declined as
domestic demand continued to rise. Te inopera-
tive terminals reopened and eventually expanded.
By 2003, a report on LNG by the Energy Infor-
mation Administration (EIA) cited 11 diferent
domestic regas projects and listed seven more
in the Bahamas, Canada and Mexico that were
designed to supply natural gas to U.S. markets.
Te projects enabled import growth to 2.11 Bcf/d
in 2007, 3.3% of total U.S. consumption.
However, the diference between U.S. LNG pric-
ing and global LNG pricing complicates import
eforts. Te price of LNG globally is linked to the
primary alternative fuel, oil. In the United States,
LNG is linked to the domestic price of gas. When
oil prices are high and U.S. natural gas prices are
low, LNG providers prefer to ship supply to Asia or
Europe.
Te expected need for LNG imports continued
to drive U.S. expansion activities. In 2007, the
United States had 5 operating terminals and 24
projects approved for construction: 19 onshore
and 5 ofshore. In addition, 14 more projects had
been formally proposed.
About that time, however, it became apparent
that U.S. proved reserves of natural gas were rap-
idly growing due to development of tight gas sands
and coalbed methane reserves. Promising results
from the Barnett play were just becoming public.
By 2008, the assumption that the United States
had to import large quantities of LNG to meet ris-
ing demand was called into question. Expectations
for LNG imports plummeted by the end of the
decade and a number of projects were suspended or
cancelled. Today, the 18.3 Bcf/d of terminal regas
capacity is expected to operate at low load factors
for the foreseeable future.
Tree factors – abundant domestic supply, low
prices and anticipated fat natural gas demand
through 2035 – have turned the focus to exports.
Apache and EOG are developing the Kitimat
LNG project in British Columbia – once intended
for imports – with plans to supply the planned
700 MMcf/d from the Horn River play. Cheniere is
developing a liquefaction facility in Louisiana that
could produce up to 2.6 Bcf/d from four trains. Free-
port LNG and Macquarie Energy have announced
plans to construct 1.4 Bcf/d of liquefaction from
four trains at the existing 1.65 Bcf/d Freeport LNG
terminal in Freeport, Texas. All three projects have
applied for export permits.
Liquefed Natural Gas Overview
160 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Natural gas transmission pipelines transport
natural gas from production areas to market areas.
Transmission pipelines receive gas from gathering or
processing facilities and deliver it to end users, local
distribution companies, or other transmission pipe-
lines for further transportation to market. FERC is
charged with approving construction and operation
of interstate natural gas pipeline facilities. Currently,
there are approximately 220,000 miles of interstate
pipeline in service in the United States. In addition,
the EIA estimates that there are over 76,000 miles of
intrastate pipeline in operation. Construction and
operation of intrastate pipelines is regulated by the
states in which the pipelines are located.
In addition to FERC’s responsibility to review and
authorize interstate natural gas and storage facilities
in the United States, multiple other federal statutes
afect the construction of interstate natural gas pipe-
lines and storage facilities. Tese include the Clean
Air Act, the Clean Water Act, the Endangered Species
Act, the Coastal Zone Management Act, the Fish and
Wildlife Coordination Act, the Historic Preservation
Act, the Rivers and Harbors Act, the Mineral Leas-
ing Act, the Federal Land Policy Management Act,
and the Wild and Scenic Rivers Act. Additional state
and local agencies provide approvals for gathering
and processing facilities, and may present additional
requirements for pipeline and storage projects.
Natural gas storage facilities help meet gas demand
peaks when demand exceeds production and long-
haul pipeline throughput levels. When cold weather
or other market conditions create more demand for
gas than domestic production or imports can satisfy,
gas in storage makes up the diference. When sup-
plies of natural gas exceed demand (e.g., between
seasonal peak demand periods), storage allows gas
producers to continue production without interrup-
tions. Tis lowers the need to cut back on production
or to shut in wells, which could damage their integ-
rity. In North America, gas is typically injected dur-
ing the summer (April to October) and withdrawn in
the winter (November to March). Storage can also
be used for seasonal system supply or for peak intra-
day demands, in particular where high deliverability
storage is needed to supply gas-fred power genera-
tion activated for peak electric power loads.
FERC has jurisdiction over underground storage
sites owned and operated by interstate pipelines,
as well as independently operated storage sites that
ofer services in interstate commerce. EIA reports
? Te rig count required is manageable and within
historical levels, although a higher level of high
horsepower rigs is anticipated.
? Well capital and steel needed for pipelines,
tubing and casing is similarly manageable and
comparable to recent historical levels.
? Proppant needed for fracture stimulation may
double or treble versus 2010 estimates (fat to
double versus 2008) over 40 years.
? Water (including primary and re-use) needed
for fracture stimulation could increase 50–150%
to approximately 2.5 billion barrels of water
annually, less than 0.1% of U.S. water withdrawal
in 2000 (less than 0.2% of U.S. water withdrawal
in 2000 excluding hydroelectric use).
Natural Gas Infrastructurc
History and Contcxt
Te U.S. natural gas infrastructure system com-
prises a network of buried transmission, gathering
and local distribution pipelines, natural gas process-
ing, LNG, and storage facilities. Natural gas gather-
ing and processing facilities are necessarily located
close to sources of production. Tey gather gas from
producing wells and remove water, volatile compo-
nents and contaminants before the gas is fed into
transmission pipelines, which transport natural gas
from producing regions to consuming regions. Stor-
age facilities are located in both production areas
and near market areas, subject to geological limi-
tations and market forces. North American natu-
ral gas infrastructure has developed over the past
30 years to link regions of supply with regions of
demand. Major production basins in the Gulf of
Mexico, Appalachia, Western Canada, and the Rocky
Mountains connect to population centers in the
Northeast, Upper Midwest, West Coast, and South-
east markets.
Natural gas gathering and processing infrastruc-
ture collects natural gas from producers, processes
it to meet the specifcations of pipeline quality gas,
and delivers it into the pipeline grid. Tere are cur-
rently 38,000 miles of gas gathering infrastructure
in the United States and approximately 85 Bcf/day
of gas processing capacity. Gathering and processing
facilities are generally subject to oversight by state
regulators.
CHAPTER 1 - RESOURCES AND SUPPLY 161
Existing infrastructure will come under pressure in
some regions, particularly regions with higher sup-
ply costs that are unable to maintain or grow pro-
duction in competition with lower cost shale gas.
Shifting gas supply will result in the closing of some
processing facilities and may drive business clo-
sures and consolidations in some regions. In other
regions, new infrastructure will be required, includ-
ing gathering pipelines and processing plants in pro-
ducing regions, and possibly new pipelines to trans-
port ethane and other natural gas liquids.
there are 401 active underground natural gas
storage felds with a total working gas capacity of
approximately 4.2 Tcf. Of that amount, 2.6 Tcf
serves interstate commerce.
Infrastructurc Dcvclopmcnt Issucs
Gathering and Processing
Te rapid growth of shale gas production and its
transformative efect on North American gas supply
is changing the gathering and processing industry.
Gas hydrate is a solid naturally occurring sub-
stance consisting predominantly of methane gas
and water that occurs throughout Arctic regions
and beneath the outer continental shelves through-
out the world. In hydrates, water molecules form
an open, solid lattice that encloses methane. Many
scientists believe gas hydrates are one of the larg-
est storehouses for carbon on the planet. Te U.S.
Geological Survey frst assessed technologically
recoverable gas volumes in 2008 and estimated 85
Tcf of gas could be recovered from Alaska’s North
Slope. A 2009 Minerals Management Service
(MMS) assessment reported more than 21,000
Tcf of gas in place in hydrate form in the Gulf of
Mexico with a mean, statistical estimate of more
than 6,700 Tcf.
It’s still unclear whether gas can be commercially
developed from hydrates, though feld tests in
Korea, India and China have been promising. Field
production test experiments in the United States
are still pending with the frst planned for the Alaska
North Slope. Looking forward through 2050, sce-
narios suggest production from gas hydrates in
the United States could range from 10 Bcf/yr to
10 Tcf/yr. Tere are several technological chal-
lenges to producing gas hydrates. Hydrates are
found only in deep waters or the arctic. Te dis-
association of the hydrates once removed from its
temperature/pressure regime requires develop-
ment of specialized equipment to recover and pre-
serve the gas. Domestically, research into hydrates
as a resource is primarily conducted by federal
agencies and academia. Global R&D eforts sug-
gest that gas hydrates found in sand reservoirs are
the best target for early production due to higher
methane saturation levels and the suitability of
sand to well development. After the MMS report
on hydrates in the Gulf of Mexico, the gas hydrates
Joint Industry Project conducted logging-while-
drilling operations at seven wells at three sites
with the intent of discovering sand reservoirs with
gas hydrates. Six of the seven wells confrmed pre-
dictions of sand with gas hydrates, most of them at
high saturation levels.
Research on production technologies in the
United States and Japan is focused on production
via well bores. Researchers have ruled out surface
dredging or shallow-subsea mining. Te environ-
mental harm is too great and the energy in such
deposits is likely too small to be of value. Of the
various well-based approaches proposed, reservoir
depressurization and chemical exchange are the
most promising. Depressurization breaks the gas
hydrate into gas and water components. Both are
driven to the well bore and produced to the sur-
face. Chemical exchange – CO
2
for CH
4
– ofers the
potential to sequester CO
2
while releasing the gas.
Te challenge is that CO
2
immediately forms into
a hydrate when it reaches water in the formation,
creating the potential for only limited injection of
CO
2
and production of methane. To further evalu-
ate the potential for exchange, DOE is collaborat-
ing with Conoco Phillips to conduct a short feld
trial in Alaska this year. Gas hydrates have strong
climate implications. Te fndings to date suggest
gas hydrates can play a signifcant role in large,
acute and global climate events such as those that
occurred in the Earth’s ancient past.
Methane Hydrates
162 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
state pipeline to transport Marcellus shale basin gas
are under construction, 449 miles are pending, and
almost 1,000 miles of potential projects have been
announced. An interesting characteristic of the Mar-
cellus Basin area pipelines is that while the total capac-
ity proposed will be large, the mileage will be seem-
ingly small when compared to long haul pipelines in
the west. Tis is due to the proximity of this supply to
highly populated east coast markets.
Another important potential source of gas supply
for the lower-48 states is the North Slope of Alaska,
with approximately 35 Tcf of gas reserves. Beginning
with the passage of the Alaska Natural Gas Transpor-
tation Act in 1976, projects have been considered to
transport Alaskan gas. In 2004, Congress passed the
Alaska Natural Gas Pipeline Act with the objective
to facilitate the timely development of an Alaskan
natural gas transportation project to transport natu-
ral gas from the North Slope of Alaska to the lower-
48 states. Te Act also confrmed the Commission’s
authority to authorize a pipeline to transport Alaskan
natural gas to the lower-48 states and designated the
Commission to be the lead agency for processing the
National Environmental Policy Act documentation.
Te TransCanada Alaska Pipeline project is a joint
venture of TransCanada Alaska Company LLC and
ExxonMobil. Tis project is designed to transport up
to 4.5 Bcf/d of Alaskan North Slope gas to the Alaska-
Canada border, approximately 750 miles. Te project
has a Canadian afliate proposing to construct facili-
ties from the Alaska-Canada border to existing facili-
ties in Alberta. From Alberta, the gas would be trans-
ported through existing facilities to delivery points in
the United States. However, based on the apparent
economics of Alaskan gas versus shale gas, it seems
unlikely that Alaskan gas will be delivered to the
lower-48 states in the foreseeable future.
Te United States used an average of 66.1 Bcf/d of
natural gas in 2010. Tis is far lower than the inter-
state capacity of 183 Bcf/d. Nearly half the capacity
we have today has been built since 1972. Because
pipeline systems must be sized and designed for
peak capacity rather than average capacity, much of
apparent overcapacity is refected in these numbers.
Although this redundancy creates a robust and reli-
able transmission system, it is not evenly distributed
across North America. Pockets of constraints and
areas of overcapacity still exist because of local supply
and demand factors.
Shale gas production will be an increasingly impor-
tant source of new production. Te growth in shale
gas development also has increased the recognized
reserves of NGLs in the United States. However, the
growth in liquids from all gas shale plays is not uni-
formly distributed across the country. Te NGL-rich
gas plays are the Barnett in Texas, the western por-
tion of the Marcellus in Pennsylvania, the Woodford
in Oklahoma, the Eagle Ford play in southern Texas,
and the Niobrara play in Colorado, Nebraska, and
Kansas. Te Fayetteville in Arkansas, the Haynesville
in Louisiana, and the Horn River in Western Canada
are dry by comparison.
Shale gas basins in new regions, such as the Mar-
cellus in the Northeast and mid-Atlantic, will require
an entirely new set of NGL pipelines to connect to
markets. Te public in some areas of this region is
not accustomed to, and may be actively opposed to,
production and processing facilities. Efective public
outreach and consultation will be necessary for suc-
cessful development.
Transmission Pipelines
Since 2000, FERC has approved over 16,000 miles
of interstate pipeline and nearly fve million horse-
power of compression. Tese projects can be catego-
rized either as greenfeld pipelines (new pipelines in
new rights-of-way) or as enhancements (i.e., looping
of an existing pipeline, addition of compression, or
extensions or laterals of an existing system). About
14,000 miles of interstate pipeline and 4.6 million
horsepower of compression have also been placed into
service.
Recent development of shale gas basins in the
southeast U.S. has spawned a boom in transmis-
sion pipeline construction in that part of the coun-
try. Shale gas supplies have been connected, via new
pipelines, to the traditional long-line pipelines that
transport natural gas from the Gulf of Mexico to the
mid-Atlantic and northeast U.S. Over 2,400 miles of
interstate pipeline has been approved to move south-
east U.S. shale gas.
Looking to the future, pipeline construction will
continue in the southeast U.S. to access shale gas
deposits. However, a major build-out of interstate
pipeline capacity in the mid-Atlantic and northeast
U.S. will be needed to transport gas from the Mar-
cellus basin to markets. In fact, 201 miles of inter-
CHAPTER 1 - RESOURCES AND SUPPLY 163
umes of new gas supply to the existing pipeline grid.
Te requirement for new gas processing infrastruc-
ture will be driven by the large volumes of new gas
production that are expected to be connected over the
forecast period, and by the expectation that relatively
strong oil prices will encourage investment in the
extraction of natural gas liquids.
Te June 2011 INGAA Foundation study on
North American natural gas infrastructure needs
through 2035 projects a cumulative need for almost
414,000 miles of gathering pipelines, including indi-
vidual well connections, for a cumulative investment
requirement (in nominal dollars) of about $50 bil-
lion. Te same study projects a need for 32 Bcf/d of
gas processing capacity additions through 2035 for
a total investment of $22 billion (in nominal dol-
lars). Tis may need to be supplemented by new NGL
pipelines, in particular from the Marcellus region to
markets in the Midwest or Gulf Coast.
New Transmission Pipeline Requirements
Future pipeline infrastructure expansion will be
driven by a shift in production from mature basins
to areas of unconventional (i.e., shale) natural gas
production. Regions with unconventional production
growth, such as the Marcellus basin in the Appala-
chian region of the northeast U.S., will experience the
greatest infrastructure investment.
A demand-side factor that will infuence construc-
tion of more transmission pipeline is the expected
increase in gas-fred electric generation as coal-fred
generation is afected by expected environmental and
carbon regulation. Gas-fred generation, given the
amount of domestic shale gas, is likely to be relatively
cheaper than in previous years and has approximately
half the emissions of coal-fred generation.
Te INGAA Foundation 2011 study estimates that
by 2035 the expanded market will require about
36,000 miles of transmission pipelines and a fur-
ther 14,000 miles of shorter lateral pipelines needed
to connect new gas-fred power generation capac-
ity, gas storage, and processing plants. Tis would
require cumulative investments of nearly $130 billion
(in nominal dollars) by 2035.
New Storage Requirements
Very few states have suitable depleted reservoirs,
aquifers, and salt formations available for storage
Storage
FERC has authorized almost 970 Bcf of new under-
ground storage capacity – either as expansions of
existing storage felds or as new storage sites – since
2000. Since 2002, 416 Bcf of new capacity has actu-
ally gone into service. Similar to historical pipeline
expansion, storage development has mainly occurred
in the south central U.S. to frst accommodate the
expected increase in imported liquefed natural gas,
and, more recently, to store the gas produced from
shale basins. Tis trend in the location of storage
facilities is expected to continue.
Storage feld development is limited by the chal-
lenges of fnding sites with the appropriate combina-
tion of geological features, pipeline proximity, and
the ability to obtain land, rights, and permitting.
Large portions of the United States, including much
of the Northeast, do not have geological structures
conducive to underground gas storage.
Strong growth in gas demand for power gen-
eration has increased demand for fexible, high-
deliverability storage that can be cycled several
times annually. Most of the value that these facili-
ties create comes from short-term price volatility
rather than the summer/winter price spreads that
have underpinned traditional storage development.
Futurc Natural Gas Infrastructurc
Rcquircmcnts
Estimating levels of needed infrastructure growth
requires consideration of future supply and demand for
natural gas. Fluctuating levels of supply and demand
within an integrated market produces price signals
that elicit an infrastructure investment response. For
example, if supply develops in a region without suf-
fcient pipeline capacity, a price diference develops
between the supply area and downstream demand
centers. If this diference is high enough, it signals a
need for new pipeline capacity to allow more gas to
fow. When seasonal price spreads develop, a signal
is sent to the market to store gas in lower priced peri-
ods and extract it when prices are higher. In addition,
price volatility signals value for more storage capacity
to provide a physical tool for shorter term balancing.
New Gathering and Processing Requirements
Te requirement for new gas gathering infrastruc-
ture will be driven by the need to connect large vol-
164 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
NORTH AMERICAN OIL AND GAS
PRODUCTION PROSPECTS
TO 2050
Preceding sections of this chapter describe the most
signifcant current and potential sources of North
American oil and natural gas production available
over the next several decades. Tere are many plau-
sible permutations of the mix and timing of develop-
ment of these resources and their translation into
productive capacity. Factors that enable or constrain
supply capacity development, be they geologic, tech-
nical, or the result of public policy choice, can play
out in many diferent ways, so this report does not
present a defnitive vision of North American oil and
gas production in either 2035 or 2050. Te ranges
of production pathways shown earlier in this report
suppose either a reasonably smooth path of develop-
ment, surmounting the barriers which may exist, or a
more limited outlook, in which barriers signifcantly
constrain production capacity. Such enablers and
challenges will, of course, exist beyond 2035, out to
2050 and beyond. However, if North America fnds
itself on the constrained pathway as 2035 approaches,
it would be unwise to assume that it is possible to
change course and expect to recover productive capac-
ity by 2050, given the long lead times and develop-
ment challenges involved in activating resources
which have not already been the focus of attention.
With this perspective, it is reasonable to assume
continuity in the trends to 2035 under either devel-
opment case. In a development-constrained world,
some supply sources would have declined to zero or
a low number as existing reservoirs continue their
natural decline and are not replenished by new drill-
ing activity. Tis would be the case with the Arctic, for
example, relying on a single pipeline to enable crude
oil production to occur and be transported to mar-
ket. Without further exploration, the pipeline will
be shut down when fows fall below operational mini-
mum rates, which would probably occur at some time
during the 2040s. Ofshore oil and gas output would
also have declined to low production rates by 2050 if
development is confned to the Gulf of Mexico. Just
as existing production would be subject to decline,
new sources would likely not be developed in the con-
strained world. New Arctic exploration would not
be deemed viable, other ofshore areas would prob-
ably remain restricted to development, and onshore
conventional and unconventional oil supplies would
development. Areas without much storage potential
include Nevada, Idaho and Arizona, the Central Plains
states, Missouri and almost the entire East Coast
(except for portions of western New York, western
Pennsylvania, and West Virginia). Any target storage
formation must frst be reasonably close to a major
pipeline before storage development can be consid-
ered.
Salt cavern storage is expected to dominate new
storage development, essentially doubling over the
forecast period. Te 2011 INGAA Foundation study
estimates approximately 590 Bcf of new storage
capacity is required by 2035 to meet market growth
for a cumulative investment of about $5 billion (in
nominal dollars).
Kcy Findings
y Growing shale gas supply will create a signifcant
requirement for new gathering, processing, and
pipeline infrastructure.
y New storage requirements for the growing natural
gas market are relatively modest.
y Strong oil prices relative to gas prices are driving
development to liquids-rich areas and creating a
need for new processing infrastructure.
y New pipelines may be required to move natural gas
liquids from producing areas to established markets.
y Development of shale supply from new basins will
put pressure on existing infrastructure in high cost
supply regions.
y Existing infrastructure should be used, when prac-
tical, to reduce capital requirements and environ-
mental impacts.
y Development of a pipeline from Alaska’s North
Slope to the integrated North American market
would require signifcant investment.
y Te growing gas infrastructure grid can support
signifcant switching from coal to gas in electric
generation and underpin the use of natural gas as
a transport fuel.
y Te development of shale gas supply further
increases the reliability of the natural gas infra-
structure by increasing production from regions
not prone to hurricanes, and by geographically
diversifying natural gas supply.
y Governments should ensure that efcient siting and
other regulatory processes are in place to underpin
necessary infrastructure investment.
CHAPTER 1 - RESOURCES AND SUPPLY 165
can support supplies for decades to come and by 2050,
given sustained technology development, it is likely
that currently assessed resources will be augmented
by methane hydrates from the Arctic and the Gulf
of Mexico. Te size of this potential resource could
reasonably be expected to supply the North American
natural gas market into the next century, and provide
opportunities for deployment of those technologies
in other regions of the world where methane hydrate
resources are identifed. On the oil side, vast Canadian
oil sands resources could enable continued growth in
production through 2050, allowing Canada to remain
one of the largest oil producing countries, with
considerable benefts for the North American econ-
omy and energy security. Oil shale from the Colorado
and Utah kerogen deposits could become a very signif-
icant supply of oil – again, if technology development
and access is sustained in the interim period.
be faced with increasingly stringent challenges.
Methane hydrates and oil shale development would
also be seriously at risk from prolonged access and
development constraints. In the case of natural gas,
conventional resources that do not depend on hydrau-
lic fracturing would be mostly played out well before
2050 leaving the North American gas market to be
largely supplied by imports. Te additional demand
for global natural gas supplies would probably amplify
the supply/demand stresses in the global market with
potentially serious consequences for the economy and
for energy security.
In contrast, if prudent development, in all its
senses, is enabled over the long-term, through 2050
and beyond, a large contribution to North America’s
oil and natural gas market requirements can be met
from domestic production. Te natural gas resource
doc_337202731.pdf
Prudent development of North American crude oil and natural gas resources should begin with a reliable understanding of the resource base, particularly as that understanding has changed significantly in recent years. It had been widely assumed for decades that natural gas and oil production potential in North America was in terminal decline.
CHAPTER 1 - RESOURCES AND SUPPLY 43
Abstract
Prudent development of North American crude
oil and natural gas resources should begin with
a reliable understanding of the resource base,
particularly as that understanding has changed
signifcantly in recent years. It had been widely
assumed for decades that natural gas and oil pro-
duction potential in North America was in termi-
nal decline. Tis belief was shared by governments,
the public, and even the oil and gas industry, and it
was one of the main flters through which energy
supply and security issues were examined. To
support this view, many observers referred to the
Hubbert curve* delineating resource depletion, a
theory that was frst demonstrated by analyzing
conventional oil production in the United States.
On the natural gas side, the perception of immi-
nent declining supply led to expectations that
North America would soon be importing lique-
fed natural gas (LNG) to meet domestic demand,
and thus to the construction of several new LNG
regasifcation and import terminals in the United
States and Canada.
However, the widespread deployment of recent
advances in drilling and completion technologies,
in particular horizontal drilling and multi-stage
hydraulic fracturing, have dramatically changed
the outlook and prospects for North American
natural gas and oil supply potential. Tis chapter
describes the revised potential for North Ameri-
can gas and oil supply, identifes the technology
innovations responsible for expanding resource
potential, and examines the implications for
resource development. It sets out recent ranges
of assessments of the natural gas and oil recov-
erable resource base in the United States and
Canada, and looks at how these resources may be
prudently developed, leading to productive capac-
ity potential, depending on choices made in three
areas: (1) access and regulatory regimes; (2) sus-
tained technology development; and (3) success in
managing environmental impact and risk, within
the context of whether the size of oil and natural
gas resources is near the high or low end of cur-
rent understanding.
Te outline of the Resource and Supply chapter
is as follows:
y Summary and Key Findings
y North American Oil and Natural Gas Resources
y Analysis of North American Oil and Natural Gas
Resource and Production Outlooks
y Prospects for North American Oil Development
y Prospects for North American Gas Develop-
ment
y North American Oil and Natural Gas Resource
Development Prospects to 2050.
Chapter One
Cuuoe Ott nNo Nniuunt Gns
Resouuces nNo Suvvtv
* Te Hubbert curve was frst proposed by geologist M. King
Hubbert in a 1956 paper for the American Petroleum Insti-
tute. It hypothesizes that fossil fuel production follows
a symmetrical bell-shaped curve, with peak production
occurring when about 50% of the estimated ultimate recov-
erable resource has been produced. Tis approach correctly
predicted the peak of U.S. conventional oil production
around 1970 but has proved less reliable in other geogra-
phies and for other hydrocarbon resource types.
44 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
INTRODUCTION AND SUMMARY
Summarics and Kcy Findings
Supply Summary
Te North American crude oil and natural gas
resource and supply system is a complex network that
includes several major components: (1) the natural
endowments or physical store of oil and/or natural
gas in the subsurface; (2) the commercial quantities
of crude oil and natural gas that can be produced from
the overall subsurface source rock using known or
expected technologies; (3) access to oil and natural
gas resources through drilling wells or surface mining;
and (4) the physical network of crude oil and natural
gas pipelines to transport crude oil and natural gas
to refneries and natural gas processing centers and
to end-use consumers. Included in this chapter is an
evaluation of the principal types of crude oil and natu-
ral gas supply within the United States and Canada, as
well as those new areas of oil and natural gas resource
types that could become available for development
and production by the middle of this century. Tese
include:
y Arctic oil and natural gas (United States, Canada,
and Greenland)
y Ofshore United States and Canadian oil and natu-
ral gas (non-Arctic)
y Onshore natural gas (including conventional and
unconventional sources)
y Onshore conventional oil (including enhanced oil
recovery [EOR] operations and opportunities)
y Unconventional oil (including Canadian and U.S. oil
sands, oil shale, and tight oil)
y Methane hydrates.
(Tis study does not include a detailed review of
oil and gas resource and development potential in
Mexico, although hydrocarbon prospects in that
country are described in a topic paper that is avail-
able on the National Petroleum Council (NPC) web-
site [www.npc.org] and briefy summarized later in
this chapter. Mexico is geographically part of North
America and is recognized as an important crude
oil supplier to the United States as well as a current
importer from the United States of approximately
1 billion cubic feet per day [Bcf/d] of natural gas.)
Te principal focus of this analysis is the United
States and Canada. Both countries are major oil and
natural gas producers with very signifcant future oil
and gas supply potential. Tis chapter describes and
analyzes the infrastructure systems that make these
resources available to markets. It covers the cur-
rent situation as well as a framework for developing
infrastructure needs over the next several decades.
For natural gas, the infrastructure system includes
feld gathering systems, gas processing facilities, gas
storage felds, and long distance high-capacity trans-
mission pipelines. Natural gas liquids infrastruc-
ture is also discussed, given the potential for growth
in liquids, such as ethane, propane, and butane,
extracted from produced natural gas. Tis study
does not report on local utility distribution pipeline
systems that deliver natural gas to residential, com-
mercial, and industrial customers. In the case of oil,
infrastructure to transport produced crude oil from
production areas to refneries is also assessed. Te
parallel NPC study on Future Transportation Fuels,
referred to in the Preface, will assess refnery capac-
ity, upgrading, and downstream infrastructure for
refned products, which are not within the scope of
this study.
Environmental questions related to oil and natu-
ral gas production and transportation are discussed
in detail in Chapter Two, Operations and Environ-
ment, although their critical importance to enabling
the development of supply potential in most areas is
described here.
Data Sourccs
Multiple data and analysis sources inform this
chapter. It relies frst on existing, publicly available
studies to compare and contrast resource estimates
and production views to 2050. In addition, the
Resource & Supply Task Group conducted a confden-
tial survey of proprietary outlooks, primarily from oil
and gas companies and specialized energy consulting
groups, to add additional breadth and depth to the
source material. Details include:
y Public Data. Approximately 50 publicly available
energy outlooks from government, industry, and
consultant sources were examined. Te U.S. and
Canadian governments provided integrated energy
outlooks – e.g., the Energy Information Adminis-
tration (EIA), the National Energy Board of Canada
(NEB), the International Energy Agency (IEA), the
CHAPTER 1 - RESOURCES AND SUPPLY 45
Figure 1-1. North American Natural Gas Resources Can Meet Decades of Demand
United States Geologic Survey (USGS), and the
Bureau of Ocean Energy Management, Regulation
and Enforcement (BOEMRE).
y Proprictary Data. More than 80 energy and con-
sultant companies received a request to complete
a comprehensive resource, production, and supply
chain survey. More than 25 industry and consul-
tant templates were returned. Te public account-
ing frm Argy, Wiltse & Robinson, P.C. received,
aggregated, and protected the proprietary data
responses. Te aggregation resulted in 12 unique
outlook cases.
Rcsourcc Summary
Natural gas resource assessments have recently
increased as a result of technologies that can produce
gas economically from source rock (such as tight gas,
shale gas, and coalbed methane) in ways previously
not feasible (the so-called “shale gas revolution”).
Although these sources of natural gas have been
known for many years, the application of certain
technologies, including drilling horizontal wells and
hydraulic fracturing, has enabled resource assess-
ments to include much higher volumes of gas in
the technically recoverable categories. Tis change,
above all, has transformed the outlook for natural
gas supply in North America from one of declining
domestic supply and increasing imports, to one of
abundant supply from within the region for decades
to come, most likely at moderate cost.
A 2011 Massachusetts Institute of Technology
(MIT) study on North American natural gas analyzes
the range and cost of natural gas resources. Te MIT
study lays out a number of diferent cases based on
various assumptions, from which this study has
chosen three to illustrate the sustainability of the
resource at current or greatly expanded market size.
Tese cases are summarized in Figure 1-1, where the
horizontal axis shows total ultimately recoverable
natural gas resources, under the three cases, and the
vertical axis shows wellhead cost of supply (not to
be confused with the market price of natural gas, in
which many other factors come into play). Te three
cases featured here are the mean resource estimate
with current technology (in green), the mean resource
estimate with advanced technology (in blue), and the
high resource estimate with advanced technology
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Figure 1-1. North American Natural Gas Resources Can Meet Decades of Demand
ALSO used as Fig. ES-3
RANGE OF
CUMULATIVE
DEMAND
2010–2035
TRILLION CUBIC FEET
LOW
DEMAND
HIGH
DEMAND
Notes: The vertical axis represents estimated wellhead cost of supply. The cost of supply can vary over time and place, in light of
diferent regulatory conditions, diferent technological developments and deployments, and other diferent technical
conditions. In none of these cases is “cost of supply” to be interpreted as an indicator of market prices or trends in market
prices, since many factors determine prices to consumers in competitive markets.
MIT = Massachusetts Institute of Technology.
Source of MIT information: The Future of Natural Gas: An Interdisciplinary MIT Study, 2011.
MIT MEAN RESOURCE CASE
MIT ADVANCED TECHNOLOGY CASE
MIT HIGH RESOURCE TECHNOLOGY CASE
46 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
(in red). Because these technologies were viewed as
advanced when the MIT study was developed but are
now considered standard by the industry, they do not
take into account future technology improvements.
Figure 1-2 highlights a number of natural gas
resource assessments from more than a decade and
clearly shows the diference between estimates before
and after unconventional gas began to be understood
in the mid-2000s. Over an even longer period, it has
been generally observed that oil and natural gas recov-
erable resource estimates tend to increase.
Te range of future technically recoverable natu-
ral gas resources used here is between 1,900 and
3,600 trillion cubic feet (Tcf), representing about 25%
of global natural gas resources. Tis does not include
potentially vast resources of methane hydrates pres-
ent in the Gulf of Mexico and in the North American
Arctic, some of which could become economically
producible in the 2035–2050 time frame if develop-
ment of technologies for production and environmen-
tal impact management is successful.
North America is home to world-class crude oil
resources in several diferent basins and plays.
Te mean undiscovered technically recoverable oil
resources potential in the U.S. lower-48 ofshore is
estimated at nearly 60 billion barrels, of which pro-
duction has only begun in one area, the central and
western zones of the Gulf of Mexico, with scope for
signifcant further development in other ofshore
zones. Te Arctic, another world-class resource area,
contains an estimated 100 billion barrels of recov-
erable oil (and an additional equivalent amount in
recoverable natural gas). Te Alberta oil sands have a
recoverable oil potential of more than 300 billion bar-
rels. Tese resources are relatively concentrated, but
onshore conventional oil also has signifcant recover-
able oil resources, estimated at close to 80 billion bar-
rels, not including the potential for tens of billions
of barrels present in low saturation and residual oil
zones. Recent growth in unconventional “tight oil”
production has highlighted a short to medium term
resource that could be as high as 34 billion barrels.
In the long term, oil shale plays, such as those in the
Green River formation in Colorado, Utah, and Wyo-
ming, are known to have an enormous amount of
kerogen-rich oil shale deposits. Developing new com-
mercially viable technology that heats the kerogen oil
shale to produce recoverable oil could yield producible
resources estimated at 800 billion barrels.
Production Potcntial
Te United States and Canada are signifcant pro-
ducers of both natural gas and crude oil, among the
top world producing countries. Te United States
now surpasses Russia as the top natural gas producer
in the world, as can be seen in Figure 1-3. Canada and
the United States together now produce over 40%
more gas than Russia and provide 25% of global gas
supply. (Since the North American market represents
about 25% of global gas demand, the region can now
be considered self-sufcient in natural gas, unlike
other major gas-consuming economies around the
world, such as Western Europe, Japan, and China).
Te United States and Canada also produce
crude oil at a globally signifcant scale. As shown in
Figure 1-4, the United States is the third largest pro-
ducer, behind Russia and Saudi Arabia. Te U.S. and
Canada together now produce 10.5 million barrels
per day, or about 4% more oil than Russia. Figure 1-4
shows the positions of the United States and Canada
among the top producers. Mexico also features promi-
nently in this list, although this study does not detail
Mexican oil production prospects. “Oil” as represented
in this chart includes crude oil, condensate, and natu-
ral gas liquids.
Success in achieving production levels of this mag-
nitude has been built over many years of developing
technologies, exploring new plays and improving
operating practices, and has created a strong platform
for enhanced production potential during the next
several decades. However, the oil and natural gas
industry must adhere to sound risk mitigation and
prudent environmental management practices and
the marketplace must be allowed to function within a
framework of appropriate access and regulation.
Making Rcscrvc Dcvclopmcnt Choiccs
Tis study has examined the potential for resource
development and production potential from all the
identifed major current and future sources of natu-
ral gas and oil production in North America. Te
objective was to identify the level of production that
could be achieved by 2035, in a high potential envi-
ronment in which: (1) reasonable resource access
will be available; (2) appropriate regulation will be
applied; (3) industry will continue improvements
in production and environmental operating prac-
tices; and (4) there will be sustained research and
CHAPTER 1 - RESOURCES AND SUPPLY 47
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48 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-4. United States and Canada Are Among Leading Oil Producers
M
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Figure 1-4. United States and Canada Are among Leading Oil Producers
WAS Figure ES-4
Source: BP Statistical Review of World Energy.
RUSSIA SAUDI
ARABIA
USA IRAN CHINA CANADA MEXICO UNITED
ARAB
EMIRATES
IRAQ VENEZUELA
Figure 1-3. United States and Canada Are Among Leading Natural Gas Producers
Figure ES-1. United States and Canada Are Among Leading Natural Gas Producers
0
20
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USA RUSSIA CANADA IRAN NORWAY QATAR CHINA ALGERIA SAUDI
ARABIA
INDONESIA
Source: BP Statistical Review of World Energy.
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CHAPTER 1 - RESOURCES AND SUPPLY 49
development of new technologies and techniques to
support development of additional resources that
will become available over the long term (such as
oil shale and methane hydrates).
Tis high potential is then contrasted with a lim-
ited production potential over the same time frame,
should resource development be subject to con-
straints, including lack of access, increased regula-
tory barriers, lower resource potential, or lack of
technology-related research and development. Nei-
ther of these extremes represents the most likely out-
come, which is likely to be a point between the two.
Te limited and high potential cases show the impact
of resource development choices made in investment
and public policy.
Te range of oil supply potential in the United
States and Canada for each signifcant supply source
is shown in Figure 1-5, compared with that source’s
production in 2010.
For both crude oil and natural gas, the end points
for the range of potential for each resource type are
not intended to be additive, since both market needs
and investment focus will determine the actual mix
of resource development. Te ranges indicate which
supply sources can have the most impact over the
time frame covered by this study, and which could be
most afected by the choices made in either the con-
strained or unconstrained cases.
North American oil production growth potential can
come from a number of sources, including Canadian
oil sands, the U.S. ofshore (including the Gulf of Mex-
ico), tight oil, EOR, Arctic exploration and oil shale (in
that order of scope and development lead time). Te
point – and the opportunity – is that further develop-
ment of these sources could lead to lower overall future
declines in total U.S. and Canadian oil production.
Potential for growth of these sources is summa-
rized as follows:
y Arctic oil has the scope to grow from a level of about
0.6 million barrels per day to a range of 0.3–0.9 mil-
lion barrels per day by 2035 and considerable scope
for further expansion post-2035.
y Ofshore, non-Arctic U.S. and Canadian oil pro-
duces about 1.8 million barrels per day and could
produce between 1.8 and 2.3 million barrels per day
Figure 1-5. More Resource Access and Technology Innovation
Could Substantially Increase North American Oil Production
2010 2035 LIMITED 2035 HIGH POTENTIAL
ONSHORE CONVENTIONAL
OFFSHORE
ARCTIC
NATURAL GAS LIQUIDS OIL SANDS
TIGHT OIL
OIL SHALE
UNCONVENTIONAL OIL
{
}
0
10
20
M
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P
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D
A
Y
Figure 1-5. More Resource Access and Technology Innovation Could Substantially Increase
North American Oil Production
ALSO used as Figure ES-6
Note: The oil supply bars for 2035 represent the range of potential supply from each of the individual supply sources and types
considered in this study. The specifc factors that may constrain or enable development and production can be diferent for
each supply type, but include such factors as whether access is enabled, infrastructure is developed, appropriate
technology research and development is sustained, an appropriate regulatory framework is in place, and environmental
performance is maintained.
Source: Historical data from Energy Information Administration and National Energy Board of Canada.
50 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
by 2035, depending on choices made to expand
access and lease availability to new ofshore zones
and on the pace of technology development.
y Onshore, non-Arctic conventional oil in the United
States and Canada contributes about 3.4 million
barrels per day. Access, technology and availabil-
ity of CO
2
for EOR are key factors that could lead
to a decline to around 1.5 million barrels per day
by 2035 or an expansion to over 4 million barrels
per day by 2035, with these factors also playing
into longer term potential.
y Unconventional oil has several categories; each is
at a diferent stage of development.
? Te largest unconventional oil production
comes from the Canadian oil sands in Alberta.
Tese produce about 1.5 million barrels per
day and by 2035 could reach between 3 and 6
million barrels per day, depending on the pace
of development as infuenced by access, the
regulatory environment, and technology and
supply chain issues.
? Heavy oil in Canada is a mature resource that
produces about 0.4 million barrels per day, and
by 2035 this could decline to about 0.15 million
barrels per day or stabilize to maintain current
output levels.
? Tight oil, such as that produced in the North
Dakota/Montana Bakken play, is an emerging
resource type, which has ramped up to about
0.4 million barrels per day within the past three
or four years. Tis type of production is likely to
grow to between 2 and 3 million barrels per day,
depending on access to new plays and continued
technology development, and the pace at which
new drilling can ofset decline rates of existing
production.
? U.S. oil shale, predominantly represented
by the huge deposits identifed in the Green
River Formation in Colorado, is a longer-term
development prospect. While there have been
historical attempts at production and some
research projects have been underway in recent
years, there is no commercial production today.
It is uncertain whether this can be developed
by 2035, so its potential ranges from zero to an
upside of 1 million barrels per day within this
time frame. In a success case, this resource would
continue to grow production over a much longer
period post 2035. Development of economic
production technologies is the key requirement
for this play, with access and appropriate environ-
mental risk management also playing a key role.
? Oil sands resources also exist in the United
States, primarily in Utah, but these are not yet
developed. Tey represent somewhat diferent
challenges than the Alberta oil sands and are
signifcantly smaller, but represent another
longer-term potential prospect. By 2035, the
range of output is estimated at between zero and
0.15 million barrels per day, again with longer-
term growth prospects if initial activities are
successful.
For natural gas, the main components of supply,
current and potential, are illustrated in Figure 1-6.
Recent technology advances have enabled the
development of widespread and large-scale tight gas
and shale gas resources across North America.
Te study group estimated that between fve and
nine decades of production at moderate cost at today’s
market size is available from the resource base, as
currently understood, if production development can
continue to use critical horizontal drilling and hydrau-
lic fracturing technologies. Natural gas supply poten-
tial can be augmented and extended with improve-
ments in technologies to increase recovery factors or
new technology development to tap into new resource
types, such as methane hydrates.
Te dominant source of U.S. and Canadian natural
gas production in the near, medium, and long terms
is likely to be onshore unconventional gas, such as
tight gas, shale gas, and coalbed methane, as is cur-
rently the case. In addition, other sources can play an
important role:
y Onshore, non-Arctic gas in the United States and
Canada currently produces 24 Tcf per year. By
2035, this could grow to around 36 Tcf as required
by the market, if onshore gas development is facili-
tated by an appropriate business environment and
regulatory framework, but could decline to around
18 Tcf if development is constrained by regulatory,
access, or technology restrictions.
y Arctic gas, currently stranded because of lack of
pipelines to market, does not contribute to current
supply apart from a small quantity for local market
consumption in Alaska. Depending on whether one
or more natural gas pipelines are developed from
CHAPTER 1 - RESOURCES AND SUPPLY 51
the Alaska North Slope and the Mackenzie Delta,
the 2035 Arctic production could range from 0 to
2.7 Tcf.
y Ofshore, non-Arctic natural gas currently contrib-
utes about 1.7 Tcf, almost exclusively from the U.S.
Gulf of Mexico. Tis has declined in recent years as
the resources available from the shallow water con-
tinental shelf have matured. Looking out to 2035,
the range of potential ofshore supply is estimated
at between 2.2 and 4.8 Tcf on the high side, depend-
ing mainly on the success of new Gulf of Mexico play
types and the pace and scope of opening of access to
new ofshore zones, particularly the eastern Gulf of
Mexico and ofshore Atlantic and Pacifc zones.
Substantial methane hydrate resources have also
been identifed, particularly in the Gulf of Mexico
and portions of the Arctic. Tese could be available
for development in the long term, beginning in the
2030–2050 period, leading to production of 1–10 Tcf
per year by 2050, and with the potential for sustained
growth over the remainder of the century.
Tis domestic supply potential has completely trans-
formed the outlook for imported LNG to North Amer-
ica. LNG regasifcation capacity of about 18.5 Bcf/d
was developed at multiple locations in the United
States and Canada over the past decade with capac-
ity to supply almost one-third of current mar-
ket demand, anticipating expanded need for gas
imports. Although this capacity may not be used to
the extent foreseen, it will play a valuable role in pro-
viding fexibility of supply sources and supporting
energy security. With expanded U.S. and Canadian
supply potential, LNG export options are now being
considered.
Infrastructurc
Te 2007 NPC Hard Truths study described infra-
structure as a key link in the chain, connecting sup-
ply to markets, and found that knowledge of existing
infrastructure and planning for new infrastructure
capacity could fall short of meeting market needs.
Sufcient natural gas midstream infrastructure,
including gathering systems, processing plants, trans-
mission pipelines, storage felds, and LNG termi-
nals, is crucial for efcient delivery and functioning
markets. Insufcient infrastructure, can contribute
to price volatility, delivery bottlenecks, stranded gas
supplies, and reduced economic activity.
Figure 1-6. North American Natural Gas Production Potential
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
TIME
TECHNICAL COMPLEXITY
010
2030
3040+
1020
ONSHORE CONVENTIONAL + UNCONVENTIONAL
2010 20352050
LOW HIGH
HYDRATES
ARCTIC
OFFSHORE GULF OF MEXICO + ATLANTIC/PACIFIC
Note: North American oil and gas resource types have varying capabilities to infuence future supply requirements. This chart
demonstrates the growth potential and technical complexity required to develop each resource. Relative bubble sizes and
vertical scale indicate supply potential for each resource type in current and future views. The bubble color provides an
indication of the technical complexity required to develop each resource. While many of the resource types have growth
potential under the right regulatory and market conditions, those most likely to underpin future demand are what today are
considered “unconventional” oil and gas.
Figure 1-6. North American Natural Gas Production Potential
52 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Tis study has examined infrastructure for both
natural gas and crude oil in North America and con-
cluded that expansion and regional change in supply
sources will require new infrastructure development
over the next several decades, including more than
30,000 miles of long-distance natural gas pipelines
and up to 600 Bcf of natural gas storage capacity, a
scale of expansion that is consistent with historical
rates of system growth.
Market signals and existing regulatory structures
have been efective in bringing about appropriate
infrastructure expansions. In particular, regulatory
frameworks implemented by the Federal Energy
Regulatory Commission (FERC) in the United States
and the National Energy Board in Canada have sup-
ported expansion of natural gas storage and pipeline
systems in recent years, and should facilitate pru-
dent development of new infrastructure expansions
in the future. As these agencies do not oversee oil
pipeline permitting, developers must navigate mul-
tiple jurisdictions to construct new crude oil pipe-
lines. Permitting has usually been completed with-
out undue delay, but large-scale pipelines needed to
supply markets from new or growing supply sources
such as in Alaska or Alberta will require a more inte-
grated approach.
New infrastructure will be required to move natu-
ral gas from regions where production is expected to
grow to areas where demand is expected to increase.
Not all areas will require new gas pipeline infra-
structure, but many (even those that have a large
amount of existing pipeline capacity) may require
new investment to connect new supplies to markets.
In recent years, natural gas producers and marketers
have been the principal shippers on these new “sup-
ply push” pipelines. Tese “anchor shippers” have
been willing to commit to long-term, frm contracts
for natural gas transportation service that provide
the fnancial basis for moving forward with these
projects. Looking ahead, producers should continue
to be motivated to ensure outlets for their gas sup-
plies via pipelines. Abundant and geographically
diverse shale gas contributes to a competitive natu-
ral gas market if connected to adequate storage and
delivery systems.
A recent Interstate Natural Gas Association of
America (INGAA) Foundation study on North
American Midstream Infrastructure through 2035
found that the United States and Canada will require
annual average midstream natural gas investment of
$8.2 billion per year, or $205.2 billion (in real 2010
dollars) total, over the nearly 25-year period from
2011 to 2035 to accommodate new gas supplies, par-
ticularly from the prolifc shale gas plays, and growing
demand for gas in the power-generation sector. Tis
capital investment requirement includes mainlines,
laterals, processing, storage, compression, and gath-
ering lines.
Kcy Findings
y Tere is signifcant potential for sustained produc-
tion at current or higher levels for natural gas and
oil in the United States and Canada resulting from
recent developments in technologies and increased
understanding of the resource base. Declines in
production, expected until fairly recently, would
come as a result of policy choice, not as a conse-
quence of resource limitations. Growth is now a
real opportunity, particularly in natural gas produc-
tion. Prospects for mitigating overall oil declines
are improving and, if access for development and
delivery improves, new sources of North American
oil supply could be developed.
y Te public and policymakers need to be better
informed on the scale of resources available and
the implications to security, competitiveness, and
commercial opportunity, to help reverse the long-
standing perception that North American oil and
natural gas is in decline or unavailable for develop-
ment.
y Natural gas and oil producing plays and new supply
resource opportunities provide a rich and diverse
portfolio of options to support North American
oil and gas markets for decades to come. A port-
folio approach to resource development requires
sustaining current and near-term sources of
production, while creating the conditions for lon-
ger-term options to be exercised with technology
advances, and when environmental practices and
market conditions are right. It would be a mistake
to neglect segments of the portfolio because near-
term production from a current source is strong.
y Much higher assessments of recoverable natural
gas resources in the United States and Canada, now
totaling around 3,000 Tcf or more, have given this
region the opportunity to be largely self-sufcient
in natural gas for many years. A portfolio of options
exists, including: sustaining current large-scale
CHAPTER 1 - RESOURCES AND SUPPLY 53
gas production from the Gulf of Mexico and from
onshore conventional and unconventional gas,
while also opening access; crafting appropriate reg-
ulatory frameworks; and developing technologies
and production techniques to enable new sources of
supply, including from Arctic exploration, new of-
shore areas, and methane hydrates. Importantly,
the newly identifed large natural gas resources
appear to have a moderate cost of supply, underpin-
ning the competitiveness of natural gas with other
energy sources.
y U.S. and Canadian oil production, despite its
high levels, currently falls well short of satisfying
demand in the region. Te North American oil
supply potential discussed here does not indicate
U.S. and Canadian oil production could grow suf-
fciently to bridge this gap, unless there are also
signifcant declines in demand for oil. Energy
security considerations must, therefore, be met by
openness to trade and investment with a diversity
of crude oil producers around the world. However,
a strong portfolio of U.S. and Canadian oil develop-
ment options exists to cover current and near-term
production and long-term development prospects.
If these options are exploited, there are grounds
for optimism that North America can continue to
be a major crude oil producer to 2050 and beyond,
meeting a signifcant proportion of its market
needs. In a reasonably unconstrained case, the
United States and Canada could produce up to
15–18 million barrels per day by 2035, potentially
a much higher proportion of regional demand than
today. However, if future development were con-
strained it is likely that production would fall even
further below market needs, requiring greater
dependence on imports. Near and medium term
production potential comes from the ofshore
Gulf of Mexico, U.S. and Canadian conventional
onshore oil production, the Alberta oil sands and
the emerging production from tight oil plays. In
the medium to long term, signifcant development
options have been identifed in new ofshore areas,
the Arctic, and possibly U.S. oil shale and oil sands.
y Higher end supply potential ranges described in
this study must meet four prerequisites:
? Sound and prudent development practices that
balance responsible environmental impact risk
management and mitigation with the economic
and energy security benefts of hydrocarbon
production.
? Access to the resource, where the industry
can demonstrate that sound and prudent
development practices will be deployed in all
cases. Tis includes creating and sustaining a
framework for access in itself as well as the terms
and conditions of access such as length of leases
and other lease stipulations.
? Predictable regulatory regimes that can evolve
with advancing technology and best practices
to allow long-term investment decisions within
a predictable framework. Onshore, the federal
government should defer to robust state
regulations, recognizing that state regulators are
often more familiar with regional geology and
environmental conditions. Ofshore, the federal
government should seek input from the natural
gas and oil industry in development of any new
regulations, since industry expertise can inform
the regulatory process and avoid unintended
consequences such as delays in bringing needed
supply online.
? Sustained technology development and deploy-
ment, appropriate for each resource type and
geographic and geologic setting, covering
development and production techniques and
environmental risk management. Oil and natural
gas companies are able to develop appropriate
technologies for accessible, prospectively
commercial areas, while longer term resource
opportunities may require partnership with
government agencies and academic institutes to
ensure sustained technology development eforts
occur.
Summary of Scopc and Objcctivcs
To summarize the scope and objectives of this
chapter as they have been discussed earlier, the funda-
mental question here is how the oil and gas resources
in the United States and Canada can be developed to
meet long-term market needs, using a development
model that ensures energy security and prudent envi-
ronmental risk management, while bringing the ben-
efts of continued and expanded development of sig-
nifcant resources within the region.
Tis chapter focuses on the hydrocarbon develop-
ment potential in the United States and Canada.
Demand issues and operational management and
environmental questions are addressed in separate
chapters of the report.
54 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Tis work examines the principal oil and gas pro-
ducing areas within the United States and Canada and
new areas or types of oil and gas resource that could
become available for development and production by
the middle of the century. Tese include:
y Te Arctic (U.S., Canadian, and Greenland Arctic
regions)
y Ofshore U.S. and Canada (non-Arctic)
y Onshore natural gas
y Onshore conventional oil (including EOR opera-
tions and opportunities)
y Unconventional oil (including Canadian and U.S. oil
sands, oil shale, and tight oil)
y Methane hydrates.
Te scope of this work includes studies of current
and future infrastructure needs for both oil and nat-
ural gas, as hydrocarbon development can only pro-
ceed if there is a way to transport produced volumes
to market. Terefore, we have examined the cur-
rent pipeline system for crude oil between the major
U.S. and Canadian producing regions and the major
refning centers, analyzed future pipeline needs, and
described the regulatory and investment framework
necessary for future pipeline development. Tis cov-
ers the major crude oil pipeline systems that deliver
to refneries, but does not cover refned product
pipeline systems downstream of the refning facili-
ties. For natural gas, the analysis covers major inter-
state transmission pipeline infrastructure, as well
as gas storage and processing facilities, but does not
address lower-pressure local utility natural gas pipe-
line distribution systems. Natural gas liquids infra-
structure needs are also included within the scope of
this analysis.
Although LNG is discussed in one of this study’s
topic papers, it is not a major focus of this work.
However, LNG is referenced within this chapter,
both as a source of imported natural gas as well as a
potential future option for developing export capac-
ity.
Te objectives of this chapter are to:
y Describe the current best level of understanding of
the technically recoverable resource base for U.S.
and Canadian oil and natural gas available for devel-
opment in the frst half of this century.
y Describe the range of production potential until
2035 for each of the identifed oil and gas resource
types and regions. Tis range sets out to encompass
a reasonably unconstrained production pathway, in
which technological and development choices facil-
itate development and today’s regulations are not
signifcantly tightened, down to a reasonably con-
strained production pathway in which regulatory
choices, access limitations, or a slower pace of tech-
nological development create barriers to develop-
ment. Expected development pathways lie between
these two limits.
y Describe the key current and future advances in
technologies that will allow development and pro-
duction of this region’s oil and gas resources, and
comment on the role of innovation led by the U.S.
oil and gas sector and public research initiatives in
expanding global oil and gas resource potential.
y Assess current and future major infrastructure
requirements to support oil and gas development
and describe the key factors that could either enable
or delay new infrastructure or modifcation of exist-
ing pipeline delivery systems and natural gas stor-
age facilities.
y Describe how oil and gas production potential could
develop to 2050 and beyond, through technological
improvement and/or access to new resource types.
y Frame the implications of the oil and gas resource
development potential identifed for investors and
policymakers.
Te contents of this chapter are supplemented
and completed by a set of detailed topic papers on
each of the major study areas, available on the NPC
website.
Summary of Mcthodology
Te NPC constituted a task group within the
broader scope of this study to specifcally focus on
oil and gas resources and productive potential within
North America. Te Resource & Supply Task Group
divided the work among nine specialized subgroups,
each focusing on a specifc portion of the study. Te
subgroups are as follows:
y Oil and gas resources and resource assessments
y Analysis of data and studies collected for the pur-
pose of this study
y Arctic oil and gas (onshore and ofshore)
CHAPTER 1 - RESOURCES AND SUPPLY 55
y Ofshore (non-Arctic) oil and gas
y Onshore gas
y Conventional onshore oil, including EOR
y Unconventional oil
y Oil infrastructure
y Natural gas infrastructure.
In addition, smaller groups or individuals were tasked
with researching and writing focused white papers on
particular subjects that were not included within the
framework of the main subgroups. Tese white papers
cover the following topics:
y LNG
y Methane hydrates
y Mexican oil and gas supply
y Natural gas liquids (NGLs).
In order to develop a sound assessment of the
range of possible outcomes for North American oil
and gas resources and production, together with the
key challenges and enablers to this development, two
approaches were taken in parallel – analysis of existing
public studies and a confdential survey of private, pro-
prietary studies.
Tere are numerous public, government, and indus-
try organizations that have made macroeconomic and
energy demand, supply, and infrastructure outlooks
assessments. While some have made available to the
public, many companies develop their own internal
analysis as a support for their long-term investment
strategies.
Te Resource & Supply Task Group established a data
and studies subgroup to collect and analyze as much
accessible existing resource data as possible. Teir
objective and evaluation methodology was designed
to capture the wide spectrum and range of outlooks,
including the underlying assumptions and supply
challenges identifed by various organizations. Tis
subgroup also designed and conducted a confdential
survey of private organizations, primarily oil and gas
companies and consulting groups, using an auditable
procedure to capture respondents’ and industries’
views and insights. Te auditable process protected
the proprietary data of survey respondents and survey
results were aggregated to ensure confdentiality (indi-
vidual responses couldn’t be directly attributed to any
particular source). Te survey results added important
data and insights to the public studies record. Govern-
ment organizations such as the Energy Information
Administration, the U.S. Geological Survey, the Bureau
of Ocean Energy Management, the National Energy
Board of Canada, and the International Energy Agency
also contributed data and time to this work.
Te resources and resource assessment team estab-
lished appropriate resource defnitions to be used in
the study, described the sources for resource assess-
ments, and commented on the diferences between
resource assessments coming from diferent organi-
zations. Tis team studied a range of resource assess-
ments from government, academic, and private sector
sources. Understanding the nature of resource assess-
ments and the range of resource potential is considered
a crucial component for the development of long-term
national energy policy, and this subgroup set out to
document and explain the best current understanding
of this area.
Oil and gas development potential and driving
forces can vary signifcantly between regions and
resource types. For this reason, the NPC study estab-
lished specialized subgroups for each of the major
resource types (Arctic, ofshore, onshore gas, conven-
tional oil, and unconventional oil). Each subgroup
was stafed by expert contributors, specialized in that
particular resource area, from the oil and gas industry,
academia, government, and consultancies. Te sub-
groups developed a set of complete and credible esti-
mates of current production and future production
potential of each area based on specifc technologies,
resource size estimates, hydrocarbon development
practices and regulatory frameworks as applicable
in each resource type and area. Tus the individual
teams developed a consistent and credible view of
supply potential that could in most cases go into
more depth and detail than the information provided
through the data and studies analysis.
Finally, two subgroups were established to discuss
current and future oil and natural gas infrastructure
development. Te oil infrastructure subgroup ana-
lyzed the crude oil pipeline system, from major North
American producing basins to major refning centers.
Te natural gas infrastructure subgroup analyzed
major interstate pipeline systems, natural gas storage
capacity, and gas processing plants, and discussed nat-
ural gas liquids infrastructure to the extent that this
may infuence natural gas development. Both infra-
structure groups were tasked with describing current
infrastructure networks as well as the ability of the
56 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
system to evolve to meet future needs, either because
of expansion of supply or because of regional shifts in
supply patterns across North America.
Each subgroup was asked to structure its work to
respond to a set of framing questions defned early in
the study (see “Framing Questions” in Text Box). Sub-
groups met regularly at focused meetings or workshops
with wider participation to advance their research and
analysis and to formulate conclusions and implications.
Subgroup leaders and/or their representatives par-
ticipated in Task Group meetings to share and review
progress and to comment on broader aspects of the
study. Each subgroup prepared a topic paper specifc to
its area, which explores issues in greater detail than can
be included in this summary chapter. Te topic papers
are available on the NPC website.
Te remaining sections of this chapter explore the
analysis and evidence that has led to these fndings,
and give more detail on the specifc enablers and chal-
lenges relevant to each component of North American
oil and gas supply and its supporting infrastructure.
NORTH AMERICAN OIL AND
NATURAL GAS RESOURCE
ENDOWMENT
Te objective of this section is to provide detailed
background about resource assessments, described
in the section above; defne the hydrocarbon related
terms prevalent in the assessments; summarize the
fnding of the key public assessments; and set down
key fndings from the material.
Hydrocarbon Rcsourcc Asscssmcnt
Uscs and Dc?nitions
Usc of Rcsourcc Asscssmcnts
Oil and natural gas resource assessments serve a
variety of fundamental needs of consumers, policy-
makers, land and resource managers, investors, regu-
lators, industry planners, and others. Governments
utilize resource assessments to exercise responsible
Framing Questions
Te Resource & Supply Task Group (as with
the work of the study as a whole) was designed
to answer a set of framing questions. Te ques-
tions were formulated early in the study process,
tested and refned with input from the study lead-
ership, and then became the basis to guide the
specifc work processes and outputs from each of
the specialized subgroups. Te framing questions
were also used over the course of the study as a
test to determine whether newly identifed issues
were within the overall scope and objectives of
the work.
Te following framing questions were used to
guide the research and analysis of the Resource &
Supply Task Group.
y What is the scope of technically recoverable
conventional and unconventional oil and gas
resources available in the United States and
Canada, according to most recent estimates?
y How much of these oil and gas resources can
be translated into productive capacity by 2050
under reasonable technical and economic
assumptions?
y What are the main drivers or assumptions
behind existing North American oil and gas sup-
ply projections?
y What factors could signifcantly increase or
decrease the productive potential of these
resources (e.g., geology, geography, access, tech-
nology, non-environmental regulation, etc.)?
y What could be the particular contribution of
each of the major types of oil and gas resource
considered in this study and what specifc devel-
opment challenges may they face?
y How will sufcient infrastructure (gathering sys-
tems, gas processing plants, crude oil, gas pipe-
lines, and gas storage) be developed to link these
resources to the market?
Te framing questions have allowed this sup-
ply analysis to focus on the key areas of resource
scope, hydrocarbon development pathways, pro-
duction potential, technology and innovation, and
the diverse set of enablers and challenges that can
help achieve the potential of the domestic oil and
natural gas resources available or constrain their
development below their potential contribution.
CHAPTER 1 - RESOURCES AND SUPPLY 57
stewardship on public lands, to estimate future rev-
enues to the government, and to establish energy,
fscal, and national security policies. Te petroleum
industry and the fnancial community use resource
estimates to establish corporate strategies and make
investment decisions. Regulatory organizations such
as government energy ministries, corporation com-
missions, and the Bureau of Land Management and
Bureau of Ocean Energy Management of the U.S.
Department of the Interior utilize resource estimates
in designating acreage for leasing and drilling.
Hydrocarbon Dc?nitions
Pctrolcum is a collective term for hydrocarbons in
the gaseous, liquid, or solid phase; in other words –
natural gas, crude oil, NGLs, and bitumen. Te hydro-
carbon resource endowment includes crude oil, natu-
ral gas, and NGLs. Following are defnitions for the
diferent forms of petroleum:
1
y Crudc Oil is defned as a mixture of hydrocarbons
that exists in a liquid phase in natural underground
reservoirs and remains liquid at atmospheric
pressure after passing through surface separation
facilities.
y Natural Gas is a mixture of hydrocarbon compounds
existing in the gaseous phase or in solution with oil
in natural underground reservoirs at reservoir tem-
perature and pressure conditions and produced as a
gas under standard temperature and pressure condi-
tions. Natural gas is principally methane, but may
contain ethane, propane, butanes, and pentanes, as
well as certain non-hydrocarbon gases, such as car-
bon dioxide, hydrogen sulfde, nitrogen, and helium.
y Natural Gas Iiquids are those portions of the
hydrocarbon resource that exist in the gaseous
phase when in natural underground reservoir con-
ditions, but are liquid at surface conditions (that
is, standard temperature and pressure conditions:
60º F/15º C and 1 atmosphere) or at higher pressure
and/or lower temperature conditions. Te NGLs
are separated from the produced gas and liquefed
at the surface in lease separators, feld facilities, or
gas processing plants.
Oil and gas accumulations are usually treated sepa-
rately in the assessment process. Gas-to-oil ratios
(GOR) are calculated for each accumulation to identify
1 American Petroleum Institute, “Standard Defnitions for
Petroleum Statistics,” 1995.
the proportions of the two major commodities (oil or
gas). An oil accumulation is commonly defned as hav-
ing a GOR of less than 20,000 cubic feet of gas per bar-
rel of oil at standard temperature and pressure; a gas
accumulation is defned as having a GOR equal to or
greater than 20,000 cubic feet of gas per barrel of oil.
Rcscrvcs are those quantities of petroleum antici-
pated to be commercially recoverable by application of
development projects to known accumulations from a
given date forward under defned conditions (such as
prevailing economic conditions, operating practices,
and government regulations). Reserves must sat-
isfy four criteria: they must be discovered, recoverable,
commercial, and remaining based on the development
project(s) applied. Reserves are further subdivided as
Proved, Probable, or Possible, also commonly referred
to as P1, P2, or P3, respectively, in accordance with
the level of certainty associated with the estimates
and their development and production status.
Rcsourccs are those quantities of petroleum esti-
mated, as of a given date, to be potentially (or tech-
nically) recoverable from known or undiscovered
accumulations, exclusive of Reserves. Such resources
are classifed by some as Contingent or Prospective
Resources depending on whether the accumulation is
known or undiscovered, respectively.
In-Placc and Tcchnically Rccovcrablc Rcsourccs
– oil and gas reserves and resources in known or yet
to be discovered accumulations represent at a given
time only the technically recoverable portion of the
in-place oil or gas endowment. Failure to clearly char-
acterize an announced resource estimate as in-place,
technically recoverable, or economically recoverable is
a common occurrence of which users of resource esti-
mates must always be wary. Developments in tech-
nology as well as geologic understanding of a reser-
voir or commodity can make previously uneconomic
resources economic and commercially viable. Exam-
ples of such progress include the development of coal-
bed gas, tight gas and shale gas reservoirs, shale oil
reservoirs, deeper conventional targets, and ofshore
deepwater development. In addition, improvement of
recovery factors can take place over time, thus grow-
ing the resource estimate for a given reservoir.
Undiscovcrcd Rcsourccs are postulated to exist
outside of known accumulations on the basis of geo-
logic knowledge and theory. Examination of size char-
acteristics of known accumulations, together with an
analysis of how many have already been discovered, is
58 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
used to project numbers and sizes of those which may
remain to be discovered. Tis is the general manner in
which conventional, undiscovered resources are esti-
mated or assessed. Often, when there are few or no
data for the basin or region under study, analogs to
known petroleum regions, including their character-
istics and properties, are used to estimate resources.
Te predicted volumes to be found in the undrilled
population of potential accumulations refect esti-
mated undiscovered resources. Tese estimates must
take into account the average prospecting success
rate, number of undrilled remaining prospects, and
the predicted size characteristics for the future dis-
coveries. Te results of such analyses carry a much
greater uncertainty (wider range of volumetric out-
comes) than the uncertainty associated with remain-
ing reserves in existing felds because there are fewer
data on which to base the estimate.
It must always be kept in mind that resource esti-
mates are snapshots in time. Since the earth has a
fnite endowment of liquid hydrocarbons, from which
we produce more and more each year, the logical con-
clusion would be that the estimates for what remains
to be found should be going down, but this is not the
case. Usually, resource estimates conducted by an
individual organization tend to increase over time
owing to some combination of the availability of more
and better data, new acreage that was previously inac-
cessible or incorrectly considered non-prospective, or
new play types (such as shale gas or subsalt oil) made
feasible by technological progress.
Convcntional and Unconvcntional Hydrocar-
bon rcsourccs. In most contemporary defnitions,
a primary diference between “conventional” and
“unconventional” liquids is viscosity, that is, a fuid’s
resistance to fow. Enormous deposits of potentially
productive liquid hydrocarbons exist in nature that
cannot fow under either reservoir or surface condi-
tions – an unconventional resource. Tis category
includes huge deposits of low viscosity oil and bitu-
men deposits (oil sands) in western Canada. Te volu-
metric potential of these deposits may dwarf that of
conventional accumulations.
Te following defnitions refect these viscosity-
based diferences, and other relevant diferences:
y Convcntional Oil: Petroleum found in liquid form
fowing naturally or capable of being pumped with-
out further processing or dilution.
y Unconvcntional Oil: Heavy oil, very heavy oil, oil
shale, and oil sands are all currently considered
unconventional oil resources. Most have a high
viscosity and fow very slowly (if at all) and require
processing or dilution to be produced through a
wellbore. However, not all unconventional oil is
heavy. Te defnition of unconventional oil can also
include such resources as tight oil, which has low
viscosity, but which is not produced using conven-
tional techniques. Some unconventional oils may
also require special transportation and refning
technology.
y Hcavy Oil: Heavy crude oils are understood to
include only those liquid or semiliquid hydrocar-
bons with a gravity of 20
o
API or less. Tese include
fuel oils remaining after the lighter oils have been
distilled of during the refning process.
y Vcry Hcavy Oil: Very heavy oil is defned as having
a gravity of less than 10
o
to 12
o
API.
y Oil Shalc: A fne-grained sedimentary rock contain-
ing kerogen, a solid organic material. Te kerogen in
oil shale can be converted to oil through the chemi-
cal process of pyrolysis. (“Oil shale” is unrelated to
liquid petroleum produced from wells drilled into
more thermally mature shales, that is sometimes
called “shale oil.”)
y Oil Sands: Also referred to as bituminous sands, oil
sands are a combination of sand, water, and bitu-
men. Bitumen is a semisolid, degraded form of oil
that will not fow unless heated or diluted with
lighter hydrocarbons.
y Continuous Typc Rcsourccs (c.g., shalc gas,
tight gas, coalbcd mcthanc): Some organizations,
such as the USGS, use the term continuous accu-
mulation to defne those unconventional oil and
gas resources that are economically produced but
are not found in conventional reservoirs such as
coalbed gas, tight gas sands, shale gas, and many
of the tight oil plays. Continuous accumulations
are petroleum accumulations (oil or gas) that have
large spatial dimensions and indistinctly defned
boundaries, and which exist more or less indepen-
dently of the subsurface water column. Another
key diference between conventional and uncon-
ventional accumulations is that some of these
(shales and coals) are both source rock and reser-
voir rock.
CHAPTER 1 - RESOURCES AND SUPPLY 59
North Amcrican Hydrocarbon Rcsourcc
Classi?cation Systcms
Several diferent classifcation systems have been
developed to systematically describe and label mea-
sured and estimated hydrocarbon resource volumes
according to two or three of the principal uncertain-
ties (primarily geologic and economic uncertainty,
and sometimes commercial status). Tough these
systems have many similarities as well as overlaps,
each was developed with its own intended estimation
focus. Each also has its own terms that do not always
have exact equivalents in the other system’s lexicons.
Te principal systems in use are the following, and
each is described in detail in Topic Paper #1-1, “Oil
and Gas Geologic Endowment,” which is available on
the NPC website.
y Te Potential Gas Committee classifcation system,
introduced in 1964
y Te McKelvey system, dating from 1972
y Te United Nations system, adopted by the United
Nations in 2004
y Te Petroleum Resources Management System,
developed by several collaborating organizations
and approved by the Society of Petroleum Engi-
neers in 2007.
Unccrtainty
Signifcant uncertainties are an inherent part of
resource estimation. Te best-constructed methodol-
ogies have two key elements: (1) they directly address
the resulting estimates’ principal uncertainties; and
(2) they are transparent regarding the assessment
methodology. Tese factors are critical for users to
understand exactly what the assessments represent.
What constitutes a resource has changed over time.
Twenty years ago, coalbed methane was not a viable
part of the U.S. energy mix. It now accounts for about
8% of domestic natural gas production. Technological
developments and developments in geologic and engi-
neering understandings continually move the edge of
what makes a resource a reserve.
Te history of the petroleum industry is replete
with instances of overly pessimistic predictions and
“good” resource-related surprises. Salient U.S. exam-
ples include:
y “Experts” predicted at the beginning of the last cen-
tury that the modern domestic oil era, initiated in
Pennsylvania during the mid-1800s, would soon
end owing to lack of sufcient resources. Instead,
major fnds in other places soon proved them wrong,
such as the 1901 discovery of Spindletop Field in
the Texas Gulf Coast region, and the 1890–1920s
discoveries of several large felds in California’s Los
Angeles and San Joaquin basins.
y Many believed in the early 1940s that oil and gas
either did not exist in, or could not be produced
from, the open ocean – until 1947 that is, when
Kerr-McGee used a platform-plus-barge combina-
tion to drill the frst successful well out of sight of
land in the Gulf of Mexico.
y Similarly pessimistic views that production from
the large California oil felds would dwindle to a
trickle due to resource exhaustion have been repeat-
edly negated by technological advancements. Such
advances include the introduction of waterfood-
ing prior to the 1960s and, more importantly, the
application of thermal recovery methods to heavy
oil reservoirs since the 1960s.
y Few “experts” held out hope that oil and gas could
exist in deep water (over 5,000 feet) at great sub-
seabed depths (on the order of 30,000 feet total
vertical depth) until Shell’s 1986 Mensa prospect
discovery proved they did.
y Te late 1980s advent of large-scale coalbed meth-
ane production was virtually unheralded, and there-
fore unanticipated.
y Te late 1990s advent of large-scale natural gas
and NGLs production from massively hydrauli-
cally fractured organic-rich shales, initiated in the
Barnett Shale of Texas’ Fort Worth Basin, was also
unanticipated.
y Although small-scale hydraulic fracturing of oil-
bearing “shale” formations such as California’s
Monterrey Formation began in the 1980s, the
adaptation of combined horizontal drilling and
massive hydraulic fracturing as originally developed
for gas in the Barnett Shale, to productive develop-
ment of the oil-bearing Bakken Formation of Mon-
tana, North Dakota, Saskatchewan, and Manitoba,
was also unheralded and unanticipated until its
rapid adoption and expansion began in 2001.
Tis long and continuing history of unanticipated
“good” resource-related surprises begs the ques-
tion as to what currently ignored and discounted
60 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
oil and gas resources might have the potential to
provide similar surprises in the future. Given his-
tory’s lessons about scientifc and technological
progress, perhaps consideration ought be given
to establishment of a small but highly compe-
tent efort dedicated and resourced specifcally
to (1) identify and characterize those oil and gas
resources not yet being quantitatively estimated
(using both open-source and disclosure-protected
proprietary data and information), and (2) iden-
tify, analyze, summarize, and status-assess ongoing
and/or needed R&D activities, basic or applied, that
may hold promise for rendering these resources
technically and then economically producible at
some time well into the future. Possibilities include
enhanced recovery of residual oil (both bypassed
and difuse) from old felds, oil shale conversion, and
methane hydrate production, all of which are already
being researched to varying degrees. Tis study
includes a formal recommendation along these lines
(see Executive Summary, Core Strategies).
Ovcrvicw of Rcccnt and Currcnt
North Amcrican Oil and Gas
Rcsourcc Asscssmcnts
Resource assessments are conducted by govern-
ment agencies, the private sector, and academic and
professional organizations in the United States and
Canada. Only publicly available (i.e., nonpropri-
etary) assessments were examined by the Resources
Subgroup. Most assessments were robust, transpar-
ent, and well documented. Each had a slightly dif-
ferent purpose or focus, and therefore provided a
unique perspective on North American resources.
Resource estimates for North America span the
spectrum of resources and reserves. Te principal
resource assessments evaluated for this study were
the following:
y Minerals Management Service (now Bureau of
Ocean Energy Management, Regulation and
Enforcement)
y IHS Energy
y Potential Gas Committee
y U.S. Geological Survey
y USGS Circum-Arctic Resource Appraisal
y Geological Survey of Canada
y Canada-Nova Scotia Ofshore Petroleum Board
y Canada-Newfoundland and Labrador Ofshore
Petroleum Board
y Canadian Association of Petroleum Producers
y Alberta Energy and Utilities Board
y Alberta Energy Resources Conservation Board
y National Association of Regulated Utility Commis-
sioners
y Advanced Resources International
y ICF International (input to MIT study on the Future
of Natural Gas).
Kcy Findings and
Obscrvations
Resource estimates for North America vary widely
across a broad spectrum of resources and reserves.
Tere are good reasons for the diferences, includ-
ing studies with diferent purposes, and also include
factors such as use of diferent methodologies, inclu-
sion or exclusion of reserves growth, inclusion of
only selected basins or reservoirs, inclusion of dif-
ferent types of hydrocarbons (e.g., crude oil only vs.
all liquids), variations in assumptions about tech-
nology and economics (e.g., including current tech-
nology vs. assuming future advances in exploration
and completion technology), and difering minimum
feld sizes.
Resource assessments are conducted by govern-
ment agencies, the private sector, and academic and
professional organizations in the United States and
Canada. Only the government agencies provide a
comprehensive set of assessments, covering oil and
gas, onshore and ofshore, conventional and uncon-
ventional, and so on.
Signifcant uncertainties are inherent in resource
estimation. Te best-constructed methodologies
directly address the resulting estimates’ princi-
pal uncertainties, and transparency regarding the
assessment methodology and assumptions underly-
ing the estimates is critical for users to understand
exactly what they represent.
A better understanding of reserves growth is
required for all types of oil and gas resources, espe-
cially those that are emerging.
Small changes in recovery efciency (percentage of
oil in place that will ultimately be produced), indi-
vidually and cumulatively, will continue to have a
CHAPTER 1 - RESOURCES AND SUPPLY 61
signifcant impact on the size of technically and eco-
nomically recoverable resources. Present and future
R&D could also result in additional production from
older felds. In addition, support of feld trials of
new and advanced technologies is critical to advanc-
ing new methods needed to grow North American oil
and gas supply.
Mature onshore areas in the United States and
Canada have some, but limited, conventional
opportunities. CO
2
EOR, assuming anthropo-
genic sources are available, has the potential for
substantial additional oil production. Offshore
North America conventional resources still have
significant potential, especially the Gulf of Mexico.
There is potential, as well, in the offshore Atlantic
and Pacific. The Arctic holds very large potential,
undiscovered resources.
Te role of unconventional resources in the North
American energy endowment will continue to have a
growing and profound impact on the future energy
supply outlook. Onshore unconventional resources,
in particular, will be very important. Shale gas,
Canadian oil sands, tight gas, tight oil, gas hydrates,
and possibly oil shale are expected to provide further
scope for additions to reserves.
Tere are many unknowns regarding unconven-
tional, ofshore, and Arctic sources. Additional data
and information are required to make informed pol-
icy and commercial decisions about these potential
resources.
ANALYSIS OF RESOURCE AND
PRODUCTION OUTLOOKS AND
STUDIES
Ovcrvicw
As was clear in the previous sections, an important
element of the work done for this study was to col-
lect and analyze data and outlooks published by gov-
ernmental agencies, independent forecasting groups,
industry associations, or others, as well as data sup-
plied on a confdential basis by individual companies.
Tis section presents a detailed view of the ranges of
outlooks for future North American oil and gas sup-
ply that were analyzed in this process and the insights
gained.
Te objective of the Data and Study Analysis Team
was to understand and interpret the:
y Uncertainty surrounding the size of North Ameri-
ca’s conventional and unconventional oil and natu-
ral gas resource base, as refected in published anal-
yses and proprietary data and forecasts
y Challenges and enablers to convert this resource
endowment into production and supply volumes
that can help meet the future energy needs of
North America.
Te Data and Study Analysis Team comprised
diverse skill sets, experiences, and expertise from
participants from large integrated energy compa-
nies (e.g., Chevron, ExxonMobil, Shell); major inde-
pendent oil and gas producers with representatives
of the American Natural Gas Alliance (e.g., Encana,
Questar); large industry service companies (e.g., Hal-
liburton); consultant companies (e.g., ICF Interna-
tional, Nehring Associates, Wood Mackenzie); and
U.S. and Canadian government agencies.
In conducting a “study of studies,” the Team evalu-
ated a broad, diverse range of energy outlooks. Te
study scope was limited to North America with focus
on the 2010–2050 time frame. Data were collected
from public, government, industry, and consultant
sources. Approximately 50 publicly available energy
outlooks were examined. Te U.S. and Canadian gov-
ernments provided integrated energy outlooks – e.g.,
the Energy Information Administration, the National
Energy Board of Canada, the International Energy
Agency, the United States Geologic Survey, and the
Bureau of Ocean Energy Management, Regulation
and Enforcement.
More than 80 energy and consultant compa-
nies received a request to complete a comprehen-
sive resource, production, and supply chain survey/
template. More than 25 industry and consultant
templates were returned, and then aggregated to
maintain the confdentiality of the individual com-
pany’s proprietary data. Te aggregation resulted in
12 unique outlook cases compiled for this study.
Te current North America oil resource and sup-
ply situation is relatively straightforward. Canada
and Mexico are currently exporting oil into the U.S.
markets and the only question is whether their
resource base/supply capacity can continue to be
meet internal demand while also enabling exports.
U.S. production, plus Canadian exports to the United
62 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
States, have not been sufcient to meet the more than
20 million barrels a day that are consumed today.
Terefore, the analysis focused on whether the
resource base and future production capacity could
reach internal demand levels, and/or how large the
domestic/import supply gap could grow to in the
future. Te results suggest that North American
production capacity will likely not grow fast or large
enough to meet the growing needs for oil in the
region.
Te North American gas resource and supply situa-
tion has changed in recent years. Te industry’s rela-
tively recent application of horizontal drilling com-
bined with hydraulic fracturing has led to a greater
understanding of the potential magnitude of the U.S.
and Canadian recoverable resource base, now believed
to have grown considerably (perhaps two and a half
times or more over estimates from as recently as
2003). In the last decade, there was a perception that
domestic supplies could not meet internal demand
requirements and signifcant volumes of LNG imports
would be required to satisfy demand. Tus, our goal
was to assess if there are sufcient, afordable domes-
tic gas resources that can be utilized to meet all poten-
tial demand scenarios. Te spread in demand out-
looks for the gas (20 to 40+ Tcf/yr) refect:
y Low side cases – low economic growth and/or cur-
tailing energy use to minimize carbon emission and
other environmental impacts
y “Mid” cases that refect a historical percentage
share in the overall fuel mix and moderate economic
growth consistent with historical rates
y High side cases that contemplate increased pen-
etration in the power and even transportation sec-
tors. Tis also would likely improve the resultant
environmental impact for these demand growth
scenarios and/or reduce the liquid import gap that
has both economic and energy security advantages
for the United States.
Te supply outlooks studied here seem to fall into
three general types of future scenarios: (1) Tere are
constrained supply cases corresponding to a more
stringently regulated industry environment, and/or
curtailment of access/development of new opportuni-
ties; (2) Te vast majority of the outlooks (spectrum of
“mid” cases) refect iterations of industry, public, and
government “business as usual” cases, where economic
growth and product prices will be the primary determi-
nants of market needs and investment in new supply;
(3) Te high production cases will require considerable
alignment among industry, government, and public
stakeholders towards a common, shared, long term
vision for the future direction of the energy sector.
Te oil cases require signifcant long-term commit-
ments to diversifying the portfolio of North Ameri-
can supply areas; early and increased data collection
to understand the new play areas (some currently in
moratoria areas); research and technology to assess
the commercial viability and development of large
Rockies unconventional oil resources; and a new
long-distance pipeline network (targeting U.S. Gulf
Coast refners or for crude oil export to Asia Pacifc
via a Western Canadian facility/port) to support the
growth potential of Canadian oil sand production.
Te low and mid gas supply cases are likely to be
driven by similar conditions to the oil outlooks
described above; however, the high gas production
scenarios are associated with natural gas serving an
increasing gas share of the overall energy mix in the
United States and Canada including in the power and
transportation sectors. We have assessed the indus-
try requirements and fundamentals to achieve this
possible paradigm shift for gas, and while we believe it
is feasible from a resource base and industry capabil-
ity standpoint, considerable alignment and coopera-
tion between industry, government, and public stake-
holders will be required to ramp up production rapidly
and sustain 30 to 40 or more Tcf/yr production levels
for future decades.
A Rangc of Asscssmcnts
Given the wide range of assessments from diverse
groups, made over a number of years and covering var-
ious geographic areas, developing a view of potential
resources and development potential is a critical and
complex process. Confdence is gained by compar-
ing resource estimates to better understand the data
available and the input assumptions. Tose that
assessed onshore oil may use diferent assumptions
from those assessing ofshore gas; those that made
an assessment fve years ago may have diferent data
than an assessment done a year ago. Furthermore,
some assessments may include conventional and
unconventional hydrocarbons while others may not.
Te estimates and assumptions can be further veri-
fed by comparison with industry activity and perfor-
mance. A promising resource that attracts little inter-
est or activity may be either optimistically assessed or
CHAPTER 1 - RESOURCES AND SUPPLY 63
activity is restricted because of policy or operational
constraints. Greater confdence in resource estimates
leads to greater confdence in future energy supply’s
potential from the diferent sources studied.
Estimating a future resource is challenged by the
fact that most of the resource is hidden deep in the
subsurface, often in deep water or even beneath Arc-
tic ice. Some areas have moratoria on drilling or the
collection of seismic data such that even rudimentary
estimates are difcult to achieve. Tat said, much of
the world’s thick sequences of sediments do contain
oil and gas, and therefore, by analogue with producing
areas, we can project at least the existence of oil and
gas, if not their quantities even in unexplored areas.
Where known commercial accumulations occur we
can identify additional, on-trend, undrilled features
that are likely to be productive, but even here the full
extent of the hydrocarbon province and accumula-
tion sizes are far from precisely known. In existing
felds where the volumes of in-place oil or gas is bet-
ter understood, there are complicating factors such as
variations in permeability, communication with the
borehole and reservoir energy issues that make the
amount that is recoverable uncertain. Industry activ-
ity and performance is another leading indicator of
the underlying assumptions and fundamentals associ-
ated with the existing resource estimates. In addition
to these “below ground” uncertainties there are many
“above ground” factors such as demand, cost, infra-
structure, policy, environmental factors and the rate
of technology development that may limit or enable
the benefcial extraction of the resource.
For these reasons, resource outlooks and forecasts
vary on the nature and amount of available resources.
Te tables and charts included in this section capture
this uncertainty by stating ranges as observed in the
data collection from academic, industry, and govern-
mental sources. Te ranges attempt to capture 80%
of the values presented; therefore, there are outliers
that extend beyond what is shown here. Tese ranges
represent irreducible uncertainty due to the inherent
variability of the assumptions rather than variations
in fundamental data.
Tese resource estimates are further qualifed by
observations of what the industry can do and is doing
now. Tese “resource–industry activity” comparisons
have three categories:
1. Robust resource estimate and demonstrated
commerciality (for example: shale gas, Gulf of
Mexico oil, oil sands and possibly tight oil).
Interrupting development of these resources
means going to less robust, more technically
challenging and more expensive resource types.
2. Less robust resource estimate with limited or
no industry access (e.g., Arctic, Pacifc, Atlantic,
and Eastern Gulf of Mexico). Tese areas need
sufcient study and data collection to understand
their potential. Seismic surveys and drilling will
enable more accurate resource estimates, which
may be much smaller or greater than currently
known. Industry frst needs to fully demonstrate
its readiness and capability to explore and develop
that resource in ways that protect workers,
safeguard the environment, and provide a positive
return on capital. Only when industry has won
the confdence of government and public is this
possible and, even then, may depend on other
considerations of political process.
3. Least robust resource estimate, wherein industry
has access but little activity (e.g., kerogen oil
shale to oil, EOR using anthropogenic CO
2
, deep
ofshore gas). Tese are more uncertain. Tey
may be the next big resource opportunity or they
may always be just one step away from being a
commercial reality. Government and industry
need to develop policies and technologies that
increase the probabilities of these potential
resources contributing to future production.
From this analysis, it is likely that some resources
will dominate early because of their abundance,
access, availability, and relative cost, while others
will play a supporting role and be available for later
development. Usually lower cost natural gas and oil
resources are developed before moving to higher cost
resources as lower cost sources are depleted, within
the constraints of access and the availability of appro-
priate and cost-efective technology.
Natural Gas
With abundant supplies in the United States and
Canada, North America is amply supplied with
natural gas to meet domestic demand over the next
several decades even at growing production levels.
Tis is largely driven by recent advances in horizon-
tal drilling and hydraulic fracturing that have allowed
gas to be extracted from shale and low permeability
formations. As a result of these advances, estimated
future resources are large and growing. Currently
64 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
the range is 1,500 to 4,000 Tcf for the United States
and 500 to 1,250 Tcf for Canada. Tese numbers
have grown rapidly in recent years (from 100s of Tcf)
and may grow further as more of these new plays
are tested. Tis potential is being realized as seen in
recent production increases.
Tere may be opportunities to augment these sup-
plies with Arctic natural gas if infrastructure is devel-
oped. Another possible upside to gas supply may
come from ofshore exploration in the little explored
moratorium areas and in the long term, methane
hydrates. Overall natural gas supply is driven by
unconventional shale gas and tight gas (without
these, natural gas production would still be in decline).
But other important resources will be important
contributors in the longer term.
Crude Oil
Oil production has been in long-term decline, but
Canadian oil sands, deepwater Gulf of Mexico oil, and,
with less certainty, tight oil could help slow or even
arrest the decline as seen over the last year or two.
Onshore U.S. conventional discoveries peaked in 1938
and the industry has adapted by moving to the Arctic,
ofshore, oil sands and now tight oil. Oil sands have
the largest upside, as only 70 of the 170 billion barrels
of oil potential are currently under development.
Additional oil resources may come from enhanced
oil recovery. For example, the 35 to 80 billion barrels
of oil onshore U.S. is largely due to new advances in
EOR. A larger and longer-term upside resource may
come from heating kerogen shale deposits (some-
times called oil shale). Tis requires heating the rock
to accelerate maturation of organic material and con-
verting it to oil and gas.
Crudc Oil
Rcsourcc Estimatcs
Te United States’ oil resource base has increased
over time due to technology enhancements and a
greater understanding of new “frontiers.” Te U.S. oil
in place endowment (the broadest possible defnition
of the resource) for conventional reservoirs is about
11% of the world’s total, while the country’s uncon-
ventional reservoirs are 23%. Adding in Canada’s
unconventional bitumen endowment, thought to be
in excess of two trillion barrels, would increase this
percentage.
While U.S. crude oil production peaked in the early
1970s at around 9.6 million barrels per day, except for
the start-up of Prudhoe Bay and periods of high oil
prices, it has been on a downward slope (44% from
the peak) since 1985 (Figure 1-7). In total, the United
States imports about half its petroleum liquids con-
sumption of nearly 20 million barrels per day – equiv-
alent to about a quarter of the world’s liquid demand.
Current and recent data and studies indicate that
the remaining North American resource base is likely
to be in excess of 500 billion barrels.
In the U.S. resource base table (Table 1-1), we have
included three industry cases that represent the range
of remaining resource estimates received from indus-
try, plus the most recent EIA-released data, as of the
time of this study. Te industry’s assessment of the
United States’ remaining resource base ranged from
106 to 270 barrels, which is almost entirely contained
in conventional reservoirs at this point. Te United
States’ remaining technically recoverable conven-
tional resources are only 6% of the world’s total. Te
United States has produced about 200 billion barrels
of its original oil in place. To date, that is about 17%
of all oil produced in the world. Tere are still remain-
ing North American resources that can provide signif-
icant recoverable totals if technical and environmen-
tal issues can be addressed (Table 1-2).
Te largest remaining North American oil resource
potential is the unconventional Canadian oil sands
(150–300+ billion barrels of recoverable resources)
and U.S. Rockies shale kerogen plays (over 1 trillion
barrels in place). Te U.S. unconventional Rockies oil
plays, while having signifcant in place volumes, need
considerable research, experimentation, technology
advancements, and the resolution of above ground
environmental challenges before technically recover-
able resources can be realized. Moreover, these issues
all need to be addressed to assess the commercial via-
bility before proceeding with large-scale production
projects that could materially impact the oil supply
situation. Tis is not expected until after 2030.
In 2010, Canadian oil sands were already contribut-
ing around 1.5 million barrels per day and could grow
to over 5 million barrels per day out beyond 2030,
which could represent approximately 40–50% of all
U.S. and Canadian crude oil production. Infrastruc-
ture expansion to transport this heavy crude to suit-
able upgrading facilities and refneries will be neces-
sary to achieve these large growth aspirations.
CHAPTER 1 - RESOURCES AND SUPPLY 65
Te Gulf of Mexico is a world-class petroleum sys-
tem with approximately 50 billion barrels of remain-
ing potential. A considerable amount of this potential
is located in the lower permeability, Paleogene play
(with commercial viability/attractiveness still uncer-
tain) and in a number of new play types that have less
overall total potential than the current Miocene deep-
water play. Te Miocene play producing felds are the
largest contributors to the current 1.5 million barrels
per day production level in the Gulf of Mexico. Future
supply outlooks from the Gulf of Mexico range from
1 to 3 million barrels per day and largely refect the
uncertainty regarding industry drilling activity lev-
els and acreage availability in future lease sales that
has arisen since the tragic Macondo oil spill in the
deepwater Gulf of Mexico. While there is signifcant
Figure 1-7. U.S. Crude Oil* Production’s Downward Trend
0
4
8
12
16
1970 1975 1980 1985 1990 1995 2000 2005 2010
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
* Crude oil and condensate.
Sources: Energy Information Administration’s AEO2010 Reference Case and International Energy Outlook 2009.
OIL IMPORTS FROM ELSEWHERE
OIL IMPORTS FROM MEXICO
OIL IMPORTS FROM CANADA
U.S. OIL PRODUCTION
Figure 1-7. U.S. Crude Oil* Production’s Downward Trend
Table 1-1. Oil Resource Base (Billion Barrels)
EIA NPC Study
AEO2011 Low Scenario Mid Scenario High Scenario
Lower-48 Ofshore Conventional 57 40 65 100
Alaska (onshore and ofshore) 48 25 40 55
Lower-48 Onshore Conventional 80 35 50 85
Unconventional (“tight oil”) 34 5 10 15
Shale Kerogen … 0 0 10
Oil Sands … 1 2 5
U.S. Total Remaining 219 106 167 270
Sources: Energy Information Administration’s Annual Energy Outlook 2011 (AEO2011); and NPC Industry Survey, Aggregated Data.
66 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
near- to mid-term potential in other lower-48 of-
shore areas (e.g., world class petroleum system – of-
shore California) and the U.S. and Canadian Arctic
(80–100 billion barrels overall), new regulatory and
permitting requirements plus acreage access will drive
activity levels in these areas.
Finally, the liquid-rich areas in the shale plays and
the Bakken/Tree Forks and Monterey tight oil res-
ervoirs have been actively pursued by industry over
the last fve years. Production has grown to around
400 thousand barrels a day from these plays. Te
current resource assessment of the tight oil plays is
6–34 billion barrels. Production levels could grow
signifcantly, to 2–3 million barrels per day in the
future. Additionally, it is still unclear how much
crude oil and condensate versus natural gas liquids
will ultimately be recovered from the shale gas plays.
Te individual crude oil and condensate production
rates for new wells are relatively low after the steep
initial decline in the frst year of production; however,
they are proftable and contributing to growth in the
lower-48 onshore sector. As the U.S. onshore conven-
tional oil feld production levels continue to decline,
the increased “tight oil” activity may partially ofset
this decline in the next 10 to 20 years.
Te only other area that could contribute material
volumes to ofset natural feld declines in the mature
U.S. lower-48 onshore, which is producing around
3 million barrels a day, is from enhanced oil recovery
resulting from injecting carbon dioxide (CO
2
) into the
reservoir. Te industry has been successful in recov-
ering additional oil from older felds by applying this
technology and utilizing natural sources of CO
2
. Tere
is considerable debate as to how much additional oil
can be recovered from the felds that haven’t been
fooded with CO
2
as some of these are not suitable,
while others are currently not “connected” to a natural
source of CO
2
, requiring infrastructure development
in these felds. While anthropogenic (man-made
CO
2
) capture, transportation, injection and storage
for enhanced oil recovery is another potential source
of CO
2
, there is signifcant uncertainty regarding
the cost of supply, regulatory requirements, and con-
struction of new onshore CO
2
pipelines necessary for
commercial project viability.
More detail on the regional and play-type oil
resource profles can be found in oil-related topic
papers, including Topic Paper #1-2, “Data and Studies
Evaluation,” available on the NPC website.
Production Outlooks
In addition to published outlooks, the Data and
Study Analysis Team obtained a wide range of indus-
try and consultant views on oil resources and pro-
duction supply capacity to develop its outlook on
Table 1-2. High Potential North American Oil Resources
Resource Type Resource Potential Resource Development Enablers
Canadian Oil Sands Recoverable Resource Potential =
150–310 billion barrels; future
production levels possibly in excess of
5+ million barrels per day
Long-distance pipeline and infrastructure
project to U.S. Gulf Coast or Canadian
West Coast?
U.S. Gulf of Mexico Oil Recoverable Resource Potential =
40–60 billion barrels; future near- and
mid-term production levels of 1.5–3.0
million barrels per day?
Resumption of pre-Macondo deepwater
drilling activity levels; Paleogene reservoir
performance and commerciality
U.S. and Canadian Tight
“Shale” Liquid Plays
Recoverable Resource Potential =
10–20 billion barrels; future North
American production levels possibly in
excess of 1+ million barrels per day
Hydraulic Fracturing; resource intensive –
people, equipment, materials; How much is
crude oil/condensate (refned transportation
products) vs. natural gas liquids
New U.S. Lower-48
Ofshore & U.S. and
Canadian Arctic Areas
Recoverable Resource Potential =
80–100 billion barrels; mid-term
(e.g., U.S. West Coast) and longer-term
(e.g., Arctic) production levels in excess
of several million barrels per day
Opening of moratoria areas and data
collection; timely exploration/development
program approvals
CHAPTER 1 - RESOURCES AND SUPPLY 67
production. In this section, we examine both govern-
ment and industry outlooks and assumptions to pro-
vide perspective on the future.
Te total U.S. production volumes in the EIA refer-
ence case and the industry mid case were relatively
similar by 2035, as seen in Figure 1-8. Te industry/
consultant mid case oil total production forecasts
were lower by 1 million barrels per day than the EIA’s
Annual Energy Outlook (AEO) 2011 forecast in 2035.
Consequently, the industry’s oil production com-
pound average growth rate (CAGR) from 2009 until
2035 was 0.1% versus 0.3% in the AEO2011 Refer-
ence Case. Generally, the industry’s median case
showed lower growth for the onshore sector than the
EIA’s reference case.
Te industry was more bullish for the ofshore;
however, there is uncertainty regarding assumptions
for future activity levels in the ofshore (lower-48 and
Arctic) following the Macondo oil spill in the deepwa-
ter Gulf of Mexico in April 2010. Te 2011 EIA ref-
erence case and industry views were relatively simi-
lar for growing production in the Arctic. Tis likely
represents general alignment on the relatively high
supply costs anticipated for future exploration and
development projects in the Arctic and the perceived
challenges associated with ofshore drilling.
Te industry’s high case U.S. production levels were
signifcantly greater than the EIA’s AEO2011 refer-
ence case, with a 2.3% CAGR. In this case, industry
cited big production gains in Alaska and ofshore,
no doubt based on the assumption of increased
acreage access in areas that are currently under
moratoria. Consultant studies on the behalf of
various U.S. government agencies suggested there
are between 30 and 50 billion barrels that are inac-
cessible to industry. Finally, we also compared the
range of industry cases with the IEA World Energy
Outlook Current Policies case. Te IEA production
output levels generally coincided with the low indus-
try case.
NGL production may be an increasingly important
source of liquids produced in the United States and
Canada, particularly as shale gas focused companies
shift activity towards some of the more liquids-rich
gas plays. Te Data Study Analysis Team obtained
some industry/consultant U.S. NGL outlooks. Te
Figure 1-8. U.S. Oil Production by Type: Industry High/Med/Low Survey Responses versus AEO2011 Reference Case
0
4
8
2009 2025
AEO2011
LOW
2025 INDUSTRY 2035 INDUSTRY
MED HIGH
2035
AEO2011
LOW MED HIGH
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
KEROGEN
CONVENTIONAL OFFSHORE
CONVENTIONAL ONSHORE
ARCTIC
Sources: Energy Information Administration’s AEO2010 Reference Case and International Energy Outlook 2009.
Figure 1-8. U.S. Oil Production by Type: Industry High/Med/Low Survey Responses
versus AEO2011 Reference Case
68 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
industry’s mid (2.3 million barrels per day) and high
(2.9 million barrels per day) forecasts in 2030 span
either side of the AEO2011 forecast of 2.7 million
barrels per day, while the industry’s low (2.0 million
barrels per day) forecast is relatively fat through
2030.
Te study team received a wide range of industry/
consultant views regarding future Canadian oil pro-
duction. Te industry mid case oil total production
forecasts were lower than EIA’s forecast, and also
below IEA’s forecast total in all years. At 1.9%, indus-
try’s median Canadian oil production CAGR from 2009
until 2030 was just slightly less than IEA at 2.0%, but
well below the EIA’s Reference Case Canadian oil pro-
duction CAGR at 2.9%. Te industry/consultant high
scenario provided a 2.8% CAGR, just below EIA’s ref-
erence case CAGR estimate. In all the cases, conven-
tional oil production from the onshore and ofshore
was projected to decline due to the high feld decline
rates and relatively small remaining potential in both
Western Canada and the ofshore (Atlantic). More-
over, no signifcant production was anticipated in the
Canadian Arctic, probably a result of the high supply
cost of these large, remaining resources, along with
the absence of infrastructure or cost-efective trans-
portation mechanisms to get these remote resources
into the marketplace.
Te major diferences between the cases in
Figure 1-9 are predominantly due to the range of pro-
duction levels for the Canadian oil sands. Te indus-
try’s median case is only 3.6 million barrels per day – a
signifcant 600 thousand barrels per day below the
agency forecasts of commercially available resource
plays in North America. Even the industry’s high
case at about four million barrels per day is below
both the EIA and IEA cases at 4.2 million barrels per
day. Clearly, industry is more conservative about
overcoming the above ground challenges to rapidly
increase production, especially in light of the addi-
tional pipeline infrastructure that will be required
to either bring additional volumes down the refners
on the U.S. Gulf Coast (e.g., the currently proposed
Keystone XL project) or consider exporting crude oil
to Asia Pacifc, which would require a new infrastruc-
ture network from Alberta to the Canadian west
coast, and export facilities.
Figure 1-9. Industry Forecast of Canadian Oil Production by Type versus EIA and IEA Totals
Sources: Energy Information Administration (EIA) Annual Energy Outlook 2010 (AEO2010) and International Energy Outlook
2010 (IEO 2010); International Energy Agency (IEA) World Energy Outlook 2010 (WEO 2010).
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID
HIGH
2.0 2.2 2.4 2.6 1.4 2.1 2.8 3.2 3.6 2.1 2.8 3.4 4.0
0
2
4
6
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
INDUSTRY OIL SANDS
INDUSTRY CONVENTIONAL OFFSHORE
INDUSTRY CONVENTIONAL ONSHORE
INDUSTRY ARCTIC
EIA TOTAL OIL IEO 2010
IEA TOTAL OIL WEO 2010*
ACTUAL
* New Policies Case.
Figure 1-9. Industry Forecast of Canadian Oil Production by Type versus EIA and IEA Totals
CHAPTER 1 - RESOURCES AND SUPPLY 69
In summary, the future of North American future
oil supplies in the near to medium term is heavily
dependent on the U.S. ofshore (40–100 billion bar-
rels “economically” recoverable resources) and Cana-
dian oil sands (150–310 billion barrels of “economi-
cally” recoverable resources). Existing oil production
from Alaska also delivers a signifcant near-term
contribution amounting to over 10% of U.S. crude
oil production, and maintaining this production has
an important role in the time until Arctic exploration
can deliver new oil supply. Production from EOR,
tight oil, shale oil, and liquids from coal or natural gas
will contribute some growth volumes. More impor-
tantly, if U.S. federal government regulation prevents
access to the U.S. ofshore resources, or constrains
transport of Canadian oil sands production, then
North American oil production could decline.
Te U.S. and Canadian combined total conven-
tional oil production (Figures 1-10 and 1-11) has
undulated from 8.4 million barrels per day in 1995,
to 7.5 million barrels per day in 2005, to 8.1 mil-
lion barrels per day in 2010. Te EIA is forecasting
that conventional oil sectors will slowly trend down
to 7.3 million barrels per day in 2035. However,
EIA shows Canadian oil sands production grow-
ing signifcantly and driving total North American
oil production to over 11 million barrels per day
by 2035. When comparing EIA’s U.S. and Canada
oil production forecast with IEA’s and the indus-
try’s, the EIA case is the most optimistic, with the
exception of the industry’s high case. Te IEA is
forecasting 2030 U.S. and Canadian production
1.5 million barrels per day lower than EIA. Te
industry’s median case ends up being about the same
in 2030 as IEA’s, whereas its low case forecasts only
7.3 million barrels per day, a full 3.6 million barrels
per day lower than EIA’s forecast.
Natural Gas
Rcsourcc Estimatcs
Historically, North American gas production
has generally kept pace with growing consumption
requirements. Canadian production has continued
to exceed demand, while just in the past decade
the United States and Mexico have received LNG
imports in addition to the pipeline gas from within
North America to supplement their domestic supply
base. As a result of drilling technology advances and
the emergence of the recent “game changing” shale
gas plays, the gap between U.S. demand and produc-
tion is closing rapidly and likely to reduce greatly the
future need for LNG imports (see Figures 1-12 and
1-13).
North America contains both conventional and
unconventional oil and gas resources. Until the last
decade, most oil and gas resource estimates largely
included conventional in place and recoverable vol-
umes. Te vast majority of historical production
from North America has been from conventional res-
ervoirs and our understanding of both the in-place
and ultimate recoverable volumes is more mature
than for unconventional accumulations.
While the size of the North American conventional
resource base is relatively well understood, our knowl-
edge of the unconventional gas endowment is growing
rapidly given increased industry activity and focus on
shale and tight gas. Te gas assessments of the ulti-
mate, technically, commercially, remaining recover-
able resource base for both Canada and United States
vary considerably (Table 1-3). Tis is largely a func-
tion of the vintage of the assessments and whether
they included the most recent data and insights from
the unconventional gas sector, especially shale gas.
Te ultimate remaining recoverable resources for the
United States ranged from 1,000 to 4,500 Tcf of gas,
while Canada ranged from 500 to 1,250 Tcf of gas.
Te United States has produced around 1,140 Tcf,
which suggests it has consumed around 20 to 40%
of the total domestic gas endowment based on the
range of collected data. Canada has produced around
175 Tcf, which is around 10% to a quarter of its
total gas resource base. If Canada used its domestic
supplies for only internal demand requirements at
current consumption rates, this would be equivalent
to 140 to 360 years of domestic supply.
Te U.S. conventional, remaining recoverable
resource base is approximately 25 to 40% of the total
remaining natural gas volumes in the United States
and ranges from 515 to 1,160 Tcf of gas. Te cur-
rent EIA (2011 reference case) assessment of over
1,000 Tcf of gas is at the upper end of the indus-
try estimates and may suggest a diference of views
regarding the technical and commercial viability of
some of the remaining conventional resource base.
Te EIA and industry have a relatively similar view
of the conventional onshore, with the low and mid
cases for industry ranging from 215 to 290 Tcf and
70 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-11. U.S. and Canadian Oil Production Cases
* Includes condensate, natural gas liquids, and refnery gain.
0
2
4
6
8
10
12
14
2010 2015 2020 2025 2030
IEA* U.S. + CANADA OIL PRODUCTION
INDUSTRY HIGH OIL PRODUCTION
INDUSTRY MEDIAN OIL PRODUCTION
INDUSTRY LOW OIL PRODUCTION
EIA U.S. + CANADA* OIL PRODUCTION
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
Sources: International Energy Agency (IEA) World Energy Outlook 2010; Energy Information Administration (EIA)
Annual Energy Outlook 2010.
Figure 1-11. U.S. and Canadian Oil Production Cases
Figure 1-10. U.S. and Canadian Oil Production Forecast
0
4
8
12
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
1980 1990 2000 2010 2020 2030 2040
* Includes condensate, natural gas liquids, and refnery gain.
Source: Energy Information Administration’s International Energy Outlook 2010.
CANADIAN UNCONVENTIONAL PRODUCTION
CANADIAN CONVENTIONAL PRODUCTION*
U.S. CONVENTIONAL PRODUCTION
U.S. + CANADA CONVENTIONAL
Figure 1-10. U.S. and Canadian Oil Production Forecast
CHAPTER 1 - RESOURCES AND SUPPLY 71
FIgure 1-12. U.S. Natural Gas Production and Consumption
0
10
20
1981 1986 1991 1996 2001 2006 2011
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
DRY GAS PRODUCTION
CONSUMPTION
Source: Energy Information Administration’s AEO2011 Reference Case.
Figure 1-13. Canadian Natural Gas Production and Consumption
0
2
4
6
1980 1985 1990 1995 2000 2005 2010
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
DRY GAS PRODUCTION
CONSUMPTION
Source: Energy Information Administration’s AEO2011 Reference Case.
Figure 1-12. U.S. Natural Gas Production and Consumption
Figure 1-13. Canadian Natural Gas Production and Consumption
72 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
the EIA (2011 reference case) was 290 Tcf. Tis is
probably the most mature exploration and produc-
tion area in North America. Te industry remaining
recoverable resource range for the ofshore region
was 160–375 Tcf and the EIA (2011 reference case)
was at the upper end at 320 Tcf. Te vast majority of
the remaining resources are located in the Gulf of
Mexico with estimates ranging from 200 to 300+
Tcf, with the Pacifc and the Atlantic Coast each
around 20 to 30+ Tcf. Te 2011 EIA reference case
had the highest estimate of the Arctic remain-
ing recoverable gas of 418 Tcf, which exceeded the
industry’s range of 130–345 Tcf and the Potential
Gas Committee (2008) assessment of 194 Tcf. Te
largest remaining recoverable resources in the Arc-
tic are located in the Alaska North Slope and include
the approximately 35+ Tcf already discovered, plus
additional exploration and growth potential bring-
ing the total potential to over 100 Tcf. Te Chukchi
Outer Continental Shelf (OCS) (~90 Tcf), Beaufort
(~30 Tcf), and Bering Shelf (~20 Tcf) also may con-
tain material gas resources. Finally, various consul-
tants (ICF International 2008, Science Applications
International Corporation/Gas Technology Institute
Table 1-3. Natural Gas Resource Base
(Trillions of
Cubic Feet)
PGC 2008
(2010)
EIA
AEO2011
Low Scenario* Mid Scenario*
High
Scenario*
Produced 1,140
U.S. Total Remaining 2,074 (2,170) 2,543 1,500 2,300 4,000
Arctic 194 290 130 210 345
Lower-48 Ofshore
Conventional
869 446 160 260 375
Lower-48 Onshore
Conventional
352 215 290 440
Tight Gas 455 200 350 550
Shale 616 (687) 862 700 1,000 1,800
(Lower-48) Coalbed
Methane
99 (159) 138 90 120 150
NEB 2010 Low Scenario* Mid Scenario*
High
Scenario*
Produced 175
Canada Total* Remaining 1,027 500 900 1,250
Ofshore Conventional 100 85 100 105
Arctic 116 45 75 125
Onshore Conventional 115 100 145 185
Tight Gas 104 40 70 100
Shale Gas
(NEB doesn’t include
Montey)
82 (+>200–
400+)
200 400 600
Coalbed Methane 34 30 80 140
* Low-High range based on spread of all data.
Sources: Potential Gas Committee (PGC) 2008 and 2010; Energy Information Administration’s Annual Energy Outlook 2011
(AEO2011); National Energy Board of Canada (NEB) 2010; and NPC Industry Survey, Aggregated Data.
CHAPTER 1 - RESOURCES AND SUPPLY 73
[SAIC/GTI] 2010), at the request of the U.S. govern-
ment agencies, have estimated between 100 and
300 Tcf of the remaining recoverable gas in the United
States is located in moratoria areas, with 100+ Tcf
in the lower-48 ofshore and onshore (largely Rock-
ies) and up to 20+ Tcf in the Arctic. Te ofshore
and Arctic gas resources that have so far been esti-
mated in the moratoria areas are all in conventional
reservoirs.
Te United States’ unconventional, remaining
recoverable resource base is around 60 to 75% of the
total remaining gas volumes in the United States and
ranges from 990 to 2,305 Tcf of gas. Te most recent
EIA estimate for remaining unconventional recover-
able gas is over 1,000 Tcf with industry’s mid sce-
nario around 1,400 Tcf.
Te U.S. lower-48 is estimated to have in-place
coalbed methane resources of 700 Tcf, of which the
remaining, economically resource base ranges from
70 to 150 Tcf with an expected value/most likely esti-
mates of 100–120 Tcf. Coalbed methane is a relatively
small component of the total unconventional gas
resource base. Te vast majority of the coalbed meth-
ane recoverable resources are located in the Rockies
(50–90 Tcf) in the San Juan and Powder River basins;
with the East Coast, Gulf Coast, and Mid-Continent
regions ranging from 5 to 10+ Tcf each.
Te tight gas remaining recoverable resources in
the EIA 2011 reference and mid industry scenarios
are around 350 Tcf, with a range of 200 to 520 Tcf.
Approximately 120 Tcf of tight gas has been pro-
duced, which leaves anywhere from 65 to 85+% of
the resource base that is yet to be developed and can
contribute signifcant annual supply volumes towards
future North America gas demand. Te largest
remaining resources are in the Rockies (with expected
value/most likely estimates around 200+ Tcf), largely
in the Greater Green River, Uinta, Piceance, and
San Juan basins. Tere is also material (in excess of
50+ Tcf) resource potential in the Gulf Coast
(e.g., Mesozoic plays in East Texas and South Texas
Tertiary plays), East Coast (e.g., Appalachia), and
Mid-Continent (e.g., Granite Wash) regions.
U.S. shale gas is a potential game changer, with
most recent industry resource estimates ranging from
700 to 1,800 Tcf (Table 1-4), with the EIA reference
and industry mid case at about 1,000 Tcf (Table 1-3).
Shale gas has been the predominant driver in renewed
optimism about the U.S. gas resources and supplies
for the future.
Te Canada conventional, remaining recoverable
resource base is approximately a third of the total
remaining gas volumes in Canada and ranges from
230 to 415 Tcf of gas (see Table 1-3). Te industry
mid scenario and the NEB (reference) cases were
very similar (approximately 325 Tcf). Te range for
the ofshore region is relatively narrow at 85–105
Tcf and almost all of the resources are located in
the Atlantic. Te range for the onshore region for
the industry scenarios was 100–185 Tcf, with rela-
tively close agreement between the industry low
and mid cases with the NEB reference case of 115
Tcf. Te remaining onshore gas volumes are located
almost entirely in Western Canada. Te greatest
uncertainty for the conventional sector lies in the
Arctic region. Te NEB estimate of 116 Tcf was at
the high end of the industry range of 45–125 Tcf.
Te Arctic areas identifed with the largest remain-
ing potential include the Mackenzie Delta/Canadian
Table 1-4. U.S. Shale Gas Most Likely
(Mean, Average, etc.) Recoverable Resources
Regions & Plays
Range for Navigant
2008, PGC 2008,
EIA AEO2011,
ANGA 2010 Estimates
East Coast 70–613
Gulf Coast 90–350
Mid-Continent 110–205
Rockies 45–75
Marcellus 177–546
Haynesville 34–251
Eagle Ford 20–68
Barnett (Fort Worth Basin) 26–168
Fayetteville (Ark. & Okla.) 21–52
Woodford (Ark. & Okla.) 12–28
Mancos (Uinta) 11–21
Sources: America’s Natural Gas Alliance (ANGA) 2010 Studies;
Energy Information Administration (EIA) AEO2011; Navigant
Consulting for the American Clean Skies Foundation: “North
American Natural Gas Supply Assessment,” July 2008; and
Potential Gas Committee (PGC) 2008.
74 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Beaufort (~60 Tcf) and the Arctic Islands/ Sverdrup
Basin (~35 Tcf).
Te Canada unconventional, remaining recover-
able resource base is approximately two-thirds of the
total remaining gas volumes in Canada and ranges
from 270 to 840 Tcf of gas. Te NEB and industry
believe there is around 150 Tcf of remaining recov-
erable resources in coalbed methane and tight gas
reservoirs in the mid/reference cases. Additionally,
the incremental upside for coalbed methane plus
tight gas in the industry high scenario was less than
100 Tcf. Tese plays types are located almost entirely
in Western Canada close to the existing infrastructure
network.
Canadian shale gas is another potential game
changer. Te industry estimate of remaining recover-
able resource potential estimates of 200–600 Tcf could
be almost half of the remaining gas resource potential
for Canada. Tese plays are in the early development
phase and thus we can expect the “mean” or most
likely values and the range to be better delineated as
we get additional well and production performance
data over the next decade. Whereas in conventional
reservoirs where as much as 95% of the natural gas
can be recovered, the ultimate recoverable volume
from shale reservoirs may reach up to 20–30% of
the in-place resource, with recovery from some less
rich reservoirs down below 10%. Cretaceous, Juras-
sic, Triassic, Mississippian, and Devonian shales are
potential targets with the largest resource potential
located in Western Canada.
In summary, the outlook for North America natu-
ral gas production has changed dramatically in just
the past few years. Te gas resource base in both the
United States and Canada is believed to have increased
signifcantly and will have profound impacts on the
North American energy market from an economic,
energy security and environmental standpoint. Te
gas resource base does not appear to be a limiting fac-
tor on bringing new North American supplies to mar-
ket. Estimates of technically recoverable shale gas are
highly likely to change over time as new information
is gained through drilling, production, and technolog-
ical and managerial development.
Production Outlooks
Only in the most optimistic, high-side cases were
the outlooks for U.S. conventional production lev-
els forecast to increase above the current 10 Tcf/yr
(Figure 1-14). Te amount of new conventional gas
wells required to simply maintain production levels
continues to increase over time and industry has been
focusing its capital in lower cost and/or higher pro-
ductivity wells in other sectors (e.g., unconventional
and ofshore supply regions). Recent exploration
discovery sizes have been small, wildcat success rates
have been low, and much of the remaining resource
potential is in small feld fractions in the U.S. lower-48
onshore conventional sector.
Tere is a wide range in the future productive capac-
ity of the lower-48 ofshore, with current production
levels of around 2.5 Tcf/yr falling to 1.5 Tcf/yr in 2035
in the low-side cases and rising as high as 3.2 Tcf in
the high-side cases. While initial fow rates from of-
shore wells can exceed 50 million cubic feet per day
(MMcf/d), these wells have steep decline rates and
thus active drilling programs to replenish supplies are
needed to maintain and grow production. We inter-
pret the outlooks for decline in U.S. lower-48 ofshore
production levels in the cases we collected from indus-
try to refect concerns about the resumption of his-
torical drilling activity levels in the Gulf of Mexico and
the timing of access to new areas in the Gulf, Pacifc,
and Atlantic.
Te Arctic (Alaska) region currently is producing
less than 0.3 Tcf/yr; however, there are consider-
able discovered (in excess of 35+ Tcf) and additional
undiscovered resources that could supply in excess of
2+ Tcf/yr if the necessary infrastructure was in place
to move gas into the U.S. lower-48 markets. As with
the Mackenzie project in the Canadian Arctic, the tim-
ing of the Alaska pipeline project continues to slip and
most outlooks now question whether these supplies
will be entering the market before 2035, a major devi-
ation from past studies that foresaw Arctic gas online
as early as this decade.
By the 2020s, more than 60% of the total U.S. gas
supplies are likely to come from domestic, unconven-
tional resources. Te studies indicate that the small-
est unconventional resource contributor will be coal-
bed methane, with current production levels around
2 Tcf/yr, and future production capacity ranging from
1.5 to 2.5 Tcf/yr by 2035. Tree quarters of the cur-
rent production is from the Rocky Mountains, with
the lion’s share from the San Juan and Powder River
basins. Te majority of regional data for the coal-
bed methane sector suggested the approximately
0.5 Tcf/yr of production from the Gulf Coast, East
CHAPTER 1 - RESOURCES AND SUPPLY 75
Coast, and Mid-Continent regions will likely be dif-
fcult to sustain till 2035. Te vast majority of the
remaining resource potential is situated in the Rock-
ies. Te San Juan and Powder River basins have
been producing for more than 25 years and most of
the readily accessible resources have been developed.
Coalbed methane developments are not without
above ground challenges, including the disposal of
water removed from the producing wells, the surface
footprint/impact on landowners and local communi-
ties and unintended loss of methane into the atmo-
sphere (e.g., underground mining). Fortunately, these
issues can be monitored and have been managed to
minimize their impact. Industry and the government
agencies continue to evaluate new technologies and
approaches to protect the environment and maximize
operational best practices.
Tight gas reservoirs are currently producing more
than 6 Tcf/yr and almost all the outlooks indicated
that supplies could grow from this sector. Although
the lowest cost, tight gas “sweet spots” have been
developed, there are still considerable feld in-fll
and additional exploratory opportunities that can
be pursued and relatively easily tied into the exist-
ing regional infrastructure. In 2008, the Rockies and
Gulf Coast each produced around 2 Tcf/yr, while the
Mid-Continent contributed around 1 Tcf/yr.
Most outlooks anticipate Gulf Coast tight gas
production will decline in the future, with the larg-
est possible increases by 2035 from the Rock-
ies. Operators have been actively developing tight
gas felds for over 10–15 years and working with
the government (state and federal) agencies and
local communities to address issues that arise. Te
primary focus area is continued environmental
protection, with water use and management being the
most pressing issue from industry, public, and gov-
ernment perspectives.
U.S. and Canadian tight and shale gas are likely
to make up more than 60% of the remaining total
resource base and will be the driver for gas production
growth and energy self sufciency/security objectives
in the future. U.S. shale gas production has grown
from about 1 Tcf/yr in 2006 to currently in excess of
4 Tcf/yr. Continued shale gas exploration and devel-
opment over the next 5–10 years will help further
Figure 1-14. Representative U.S. Conventional Gas Production Cases
0
4
8
12
T
R
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L
L
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N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
2009
LOW
2015
MID
HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID HIGH ACTUAL LOW
2035
MID HIGH
CONVENTIONAL OFFSHORE
CONVENTIONAL ONSHORE
ARCTIC
Source: NPC Industry Survey, Aggregated Data.
Figure 1-14. Representative U.S. Conventional Gas Production Cases
76 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
reduce the current uncertainty over the long term for
the U.S. and Canadian resource base. While conven-
tional, coalbed methane and tight gas developments
are becoming increasingly costly and/or complex,
“lower” cost shale developments provide potential
to grow U.S. and Canadian production. If the higher-
end recoverable resource estimates are afrmed, a
robust production plateau can be maintained for
many decades. In the mid and high industry cases in
Figure 1-15, shale gas production is anticipated to
grow to more than 10 Tcf/yr by 2035. Te main chal-
lenges associated with large-scale shale gas develop-
ments are potential concerns about water use/man-
agement associated with the hydraulic fracturing
applications required to produce commercial quanti-
ties of gas from shale reservoirs, and other surface
impacts.
In all cases studied, the Canadian onshore conven-
tional sector production output is expected to decline
over the next 20 years (see Figure 1-16) and con-
tinue the trend of declining production (in excess of
1 Tcf/yr) over the last 10 years. Tese supplies are
almost entirely in Western Canada, and we anticipate
industry will continue to maximize ultimate recovery
from these plays; however, most new additions will be
small pool sizes around existing felds or infll drill-
ing projects. Te rate of decline in the existing res-
ervoirs/felds in Western Canada is greater than 10%
per annum. Without large, new discoveries, it will be
impossible to reverse this trend. Deep, high pressure,
and/or sour gas remaining resources/opportunities
are likely to be higher cost developments and may not
attract investment in light of lower cost unconven-
tional plays in the area.
Future gas production capacity from the Canadian
ofshore (Atlantic) is believed to be relatively small
(less than 0.2 Tcf/yr). Unless large new discoveries
are made in the Atlantic (e.g., Orphan basin), this area
is unlikely to have a material impact on Canada’s con-
ventional production capacity.
Te only area that can provide substantive new
conventional gas volumes is the Canadian Arctic;
however, there is considerable diversity of views as
to when this generally “higher” cost gas will enter
the market. Te anticipated Mackenzie gas project
Figure 1-15. Representative U.S. Unconventional Gas Production Cases
T
R
I
L
L
I
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N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID
HIGH ACTUAL LOW
2035
MID HIGH
0
10
20
30
SHALE GAS
COALBED METHANE
TIGHT GAS
Source: NPC Industry Survey, Aggregated Data.
Figure 1-15. Representative U.S. Unconventional Gas Production Cases
CHAPTER 1 - RESOURCES AND SUPPLY 77
timing has slipped considerably since the frst NPC
North America gas study in 1999, largely a result of
the challenges associated with building a large export
pipeline from the discovered felds (with signifcant
follow-up potential in the Arctic) to existing Western
Canada infrastructure.
Unconventional gas production is expected to of-
set the overall decline for the conventional sources in
Canada (Figure 1-17). Shale gas is the potential game
changer and is anticipated to grow from the 0.1 to
1.5 Tcf/yr (low) to 2.4 Tcf/yr (high) by 2030. Coal-
bed methane production is anticipated to be between
0.3 Tcf/yr and 0.6 Tcf/yr in the above scenarios by
2030. While it is difcult to distinguish the transi-
tion from conventional to tight and shale gas reser-
voirs in Western Canada, the perception is that there
is more remaining resource potential to exploit tight
and shale gas in the study time frame than conven-
tional sources.
All the outlooks collected indicated that Canadian
gas production will exceed even the largest inter-
nal demand requirement scenarios (up from 2.8 to
4 Tcf/yr), and, therefore, the main driver for Cana-
dian output will be “pull” from the United States and
other export markets. Most outlooks suggested that
without shale gas and in some instances Arctic gas
production, Canadian gas production is likely to
continue its decline from historical levels. Both the
industry “mid” and reference cases indicate that
Canadian conventional, tight gas, and coalbed meth-
ane supplies would likely decline to around 4 Tcf/yr
by 2025. Te industry view was more optimistic
about the contributions likely from shale gas plays,
whereas the NEB saw the Arctic gas and pipeline com-
ing into play earlier than industry.
Te combined outlooks from all sources for U.S. and
Canadian production potential over the next two and
a half decades (as seen in Figure 1-18) indicate rea-
sonable scope for continued growth in production to
the high 30s Tcf level. Clearly, actual growth rates will
depend just as much on market factors as on supply
potential, but the outlooks show there would be scope
for supply to support quite signifcant market expan-
sion, which would bring economic and energy security
as well as greenhouse gas benefts.
Figure 1-16. Representative Canadian Conventional Gas Production Cases
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID HIGH
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
ACTUAL
0
1
2
3
4
Source: NPC Industry Survey, Aggregated Data.
CONVENTIONAL OFFSHORE
CONVENTIONAL ONSHORE
ARCTIC
Figure 1-16. Representative Canadian Conventional Gas Production Cases
78 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-17. Representative Canadian Unconventional Gas Production Cases
2009
LOW
2015
MID HIGH LOW
2020
MID
HIGH LOW
2025
MID HIGH LOW
2030
MID HIGH
YEAR
ACTUAL
0
1
2
3
4
5
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
SHALE GAS
COALBED METHANE
TIGHT GAS
Source: NPC Industry Survey, Aggregated Data.
Figure 1-18. Industry Estimates of Potential Natural Gas Production from North American Supply Sources
0
10
20
30
40
2000 2005 2009 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
Sources: Energy Information Administration’s AEO2010 Reference Case; and International Energy Agency’s WEO 2010.
CANADA SHALE HIGH
CANADA SHALE MID
U.S. ARCTIC MID
U.S. SHALE HIGH
U.S. LOWER48 SHALE MID
U.S. LOWER48 CONVENTIONAL + TIGHT + CBM MID
2010 AEO LG DEMAND
2010 WEO FP DEMAND
Notes: CBM = coalbed methane; LG = low growth; FP = future policies; WEO = World Energy Outlook.
Figure 1-17. Representative Canadian Unconventional Gas Production Cases
Figure 1-18. Industry Estimates of Potential Natural Gas Production
from North American Supply Sources
CHAPTER 1 - RESOURCES AND SUPPLY 79
Dcvclopmcnt Challcngcs and Enablcrs
While the gas base resource is large, there are chal-
lenges to delivering U.S. and Canadian gas production
growth. A long-term approach is necessary to address
the energy trade-ofs that will provide the optimal
solution for North America’s energy future. Follow-
ing is a brief discussion of these challenges at various
stages along the value chain. All were identifed by
respondents to the confdential data survey as issues
of concern. A typical development path is outlined in
Figure 1-19.
Resource Access is essential to sustaining and grow-
ing production. Since most unconventional gas plays
are on private rather than government held acreage,
several issues pertain: many conventional ofshore
opportunities in the lower-48 states and Alaska are
currently not available to industry; recent proposed
lease sales in the Gulf of Mexico have been delayed
and cancelled in the Alaska OCS; and the lease “expiry”
clock is winding down on currently held acreage. Con-
sultant studies done on the behalf of the various U.S.
government agencies have estimated that between
100 and 300 Tcf are currently in moratoria areas inac-
cessible to industry.
Opportunity Identifcation/Research & Technology
Development is the enabler to unlock future oppor-
tunities. Industry will typically focus its resources
(people, funding) in the areas it believes will have
the most commercial impact. For example, although
the Atlantic, Pacifc, and some Arctic ofshore is cur-
rently inaccessible, modern methods of seismic data
collection and interpretation would help improve
our understanding of their resource potential and
the commercial viability of these areas, which can
only help shorten the time between opening them
up and the production of oil and gas.
In the E&P Project Planning and Execution area, per-
mitting and compliance with all regulatory require-
ments is becoming increasingly difcult and time con-
suming. In the ofshore sector, industry is actively
seeking to begin operating again in the Gulf of Mex-
ico deepwater and pursue exploratory activities on
leases in the Arctic. However, signifcant delays are
Figure 1-19. A Typical Production Pathway
IDENTIFICATION OF TECHNICALLY VIABLE ENERGY RESOURCES
ASSESSMENT OF RESOURCE BASE SIZE AND COMMERCIAL VIABILITY/DOABILITY
RESOURCE OPPORTUNITY, ACREAGE, ETC. ACCESS
EXPLORATION VALIDATE; QUANTIFY; DECISION POINT TO TRIGGER LARGE DEVELOPMENT INVESTMENTS
PROJECT DEVELOPMENT INDUSTRY CAPACITY PEOPLE, MATERIALS, EQUIPMENT, ETC.; CAPITAL AVAILABILITY;
PROJECT MANAGEMENT PRACTICES; PERMITTING
INFRASTRUCTURE/TRANSPORTATION TO END USERS AVAILABILITY;
TIMING OF NEW TRANSPORTATION ROUTES/NETWORKS
PRODUCTION OPERATIONS BEST PRACTICES
Figure 1-19. A Typical Production Pathway
80 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
being encountered, likely delaying future production
volumes. A timely solution is needed and coopera-
tion between government ofcials, industry, and the
public that can accelerate resolution to this challenge
would be welcomed.
Since an increasing share of future production will
be from shale and tight oil and gas opportunities that
require hydraulic fracturing, all permitting/opera-
tional/regulatory concerns regarding unconventional
gas and tight oil must be addressed in a timely manner
to continue allowing volumes to grow from these large
resources. Water cycle management is one of the most
important focus areas that will enable exploratory
and development activities. In addition to provid-
ing a clear, timely process to drill and complete wells,
industry and other stakeholders should continue
to explore innovative ways to reduce water use and
improve recycling and disposal technology/practices.
Additional surface, air, and other areas are being stud-
ied by industry and government agencies. However,
there is a need to apply the most cost-efective solu-
tions that help reach an optimal balance for economic,
environment, and energy security considerations.
Industry Capacity needs to be evaluated on a total
energy system basis, since increased activity in
any one sector or area may only result in a shift in
resources, rather than a material increase in the oil
and gas industry’s ability to grow total supplies.
As originally noted in the 2007 NPC Hard Truths
report, the oil and gas industry is facing a consider-
able human resource challenge. Nearly 50% of the
workforce will be eligible for retirement in the next
10 years and fewer university graduates have entered
the workforce over the past generation. Industry and
government have roles to play in helping to rebuild
the science and engineering capabilities and commu-
nicating the benefts of employment with oil and gas
companies. An increased focus on training younger
employees is essential, especially if activity levels con-
tinue to increase, with an emphasis on operational
best practices, safety and environmental protection
in order to address the retirements of many highly
experienced industry personnel.
While growth in the gas sector can be partially ofset
by shifting resources from other parts of the industry,
the system could become stretched or incapable of
meeting a high growth scenario in the unconventional
gas and tight oil areas, Canadian oil sands, expansion
of E&P in the ofshore and Arctic, and fnally resource
intensive plays like oil shale in the Rockies. Growth
in all these areas would put a large strain on people,
materials, and equipment.
Industry/Government/Public Cooperation can be the
linchpin to work through obstacles and/or challenges
to our energy future. Te most rapid and efective
way to resolve issues is to work together to under-
stand the fundamentals; quantify the benefts and
concerns; openly discuss the trade-ofs with all con-
cerned stakeholders; and then jointly support and
proceed with a “solution” to accelerate energy “gains”
(that should include increased efciency/reduction in
energy use, increased supply, increased environmen-
tal protection, and increased energy security).
One way to improve the data sharing and knowledge
of the fundamentals would be to work through exist-
ing organizations to develop a more systematic pro-
cess for governments, industry, and public to collect,
discuss and share data that would be kept in a well-
managed repository. Improving full-cycle, energy
value chain modeling (tools, data, interpretation, and
workshops) could expand a more rounded discussion
of alternative energy visions, strategic directions, and
overall energy policy options. Periodic studies by the
industry, government committees, and public institu-
tions are both helpful and useful.
PROSPECTS FOR NORTH
AMERICAN OIL DEVELOPMENT
Ovcrvicw
Both the United States and Canada are major oil
resource-holding and -producing countries on a global
scale and have been for many years. However, since
the United States is also a large oil importer, the
focus of attention has been on reducing imports and
improving energy security by demand-side measures,
such as efciency standards for vehicles, rather than
supply-side measures, such as enabling domestic oil
supply development in new areas. Tis section of the
report sets out the opportunities for continued North
American oil development and production activities
at scale. Major producing areas now contributing sig-
nifcant volumes of crude oil to North American sup-
ply are profled, such as the ofshore Gulf of Mexico,
the Alberta oil sands, and the multiple producing
basins focusing on conventional oil distributed across
the United States and Canada. Opportunities for sus-
taining and growing these sources are examined and
CHAPTER 1 - RESOURCES AND SUPPLY 81
assessed. In addition, emerging and new sources of
crude oil in the region are examined. Tese include new
exploration in the Arctic regions of the United States
and Canada, the emerging tight oil plays, the poten-
tial from ofshore zones where access has been under
development restrictions, and the potential emergence
of new unconventional oil sources such as U.S. oil shale.
Each major heading in this section describes one seg-
ment of this portfolio of current and future oil supply,
and includes an overview of the context and produc-
tion history, where applicable. Also included are the
key technologies required for development, the poten-
tial production pathways to 2035 and beyond, and an
outline of the key fndings. Te section concludes with
an overview of the crude oil pipeline network required
to deliver this supply to market. Each of these topics
is described in more detail in the topic papers to this
report, available on the NPC website.
O?shorc
Dcvclopmcnt and Production History
and Contcxt
U.S. Lower-48 O?shore
Ofshore oil and gas development and produc-
tion have been on the rise in North America over an
extended period. In the U.S. lower-48, federal OCS oil
production has increased its contribution to total U.S.
production from less than 1% in 1954 to more than
30% in 2009. Te expansion of ofshore development
and production is ascribed overall to technological
progress keeping pace with more challenging ofshore
environments leading to larger feld discoveries in
ever-increasing water depths.
Currently, U.S. lower-48 ofshore oil and gas produc-
tion is restricted to the Gulf of Mexico, with a minor
contribution from the Pacifc OCS region (about 4%
of U.S. ofshore production). Much of the Eastern
Gulf of Mexico is expected to be restricted to drilling
until the year 2022, and the Pacifc and Atlantic OCS
areas were restricted from leasing consideration up
until 2008. For the purposes of this study, oil and gas
development on the Alaska OCS is included as part
of the Arctic region, rather than in the U.S. ofshore
region.
From its beginning in late 1940s, the U.S. federal
ofshore oil and gas industry has grown tremen-
dously. In 1954, federal ofshore crude oil and con-
densate production was around 2.5 million barrels or
nearly 7,000 barrels per day. Tat fgure peaked at
around 600 million barrels in 2002 or 1.64 million
barrels per day, accounting for 29% of total U.S. crude
oil and condensate production. A surge in Gulf of
Mexico deepwater oil production led to an increase of
OCS crude oil production to around 591 million bar-
rels in 2009 or 1.62 million barrels per day; account-
ing for 30% of total U.S. oil production. Figure 1-20
shows ofshore oil production as a percentage of total
U.S. production from 1960 to 2009.
Te move to deep water was made possible by con-
tinuous advancements in technologies that permit-
ted drilling and development in these environments.
Examples of these advancing deepwater technology
“frsts” in the Gulf of Mexico include the frst fxed
platform, “Cognac” installed in 1979 at water depth of
1,023 feet, while the tallest steel jacket “Bullwinkle,”
considered the economic limit for this fxed plat-
form type, was installed in 1989 at water depth of
1,353 feet. Te frst tension leg platform, “Joliet” was
installed in 1989 at water depth of 1,760 feet, fol-
lowed by “Neptune,” the frst Spar/Subsea platform
installed in 1997 in a water depth of 1,930 feet. On
the ultra-deepwater front, Herschel/Na Kika/Fourier
was the frst Floating Production System installed in
water depth of 6,950 feet in 2003. Te frst Floating
Production Storage and Ofoading system in the Gulf
of Mexico is scheduled for frst production in 2011 at
the Cascade and Chinook prospects in 8,800 feet of
water. According to the Minerals Management Ser-
vice (MMS) report on deepwater Gulf of Mexico, in
February 1997, there were 17 producing deepwater
projects, up from only 6 at the end of 1992. Since
then, industry has been rapidly advancing into ultra-
deepwater, and many of these anticipated felds have
commenced production. At the end of 2008, there
were 141 producing projects in the deepwater Gulf of
Mexico, up from 130 at the end of 2007.
2
In March of 2010, Shell started production at the
Perdido Spar complex in the Western Gulf of Mexico,
and overtook the Independence Hub by setting the
record for production in the deepest water. Moored
170 miles ofshore in 7,817 feet of water, with sub-
sea wells in up to 9,627 feet of water, peak production
should achieve 130 thousand barrels of oil equivalent
per day.
2 Richardson et al., Deepwater Gulf of Mexico 2008: America’s Of-
shore Energy Future, U.S. Department of the Interior, Minerals
Management Service, 2008, OCS Report MMS 2008-013.
82 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Development of the deepwater frontier (water
depth greater than 1,000 feet) is responsible for
increasing overall OCS crude oil and natural gas pro-
duction since 2000. In fact, the year 2000 marks
a transition from predominantly shallow water
oil production to deepwater production. In 2000,
annual deepwater crude oil production amounted to
271 million barrels, while shallow water production
was 252 million barrels. By 2007, annual crude oil
production from the shallow water had dropped to
140 million barrels while in deepwater regions of the
Gulf of Mexico production rose to 328 million bar-
rels. Since 2005, the deepwater Gulf of Mexico has
contributed about 70% of the total Gulf of Mexico
OCS crude oil production. Tis trend is expected to
continue as more discoveries and drilling activities
occur in the deepwater and ultra-deepwater areas of
the Gulf of Mexico.
Given this history, the deepwater area of the Gulf
of Mexico represents an important part of U.S. oil
supply, and it is viewed as one of the most important
world oil and gas provinces. All this has been made
possible by means of technological breakthroughs
that have allowed oil and gas companies to operate
out in these harsh and challenging environments.
Te advent of drill ships capable of drilling in water
depth up to 10,000 feet and deeper reservoirs, along
with the subsea completion technology and the Hub
system have greatly contributed to the expansion of
ofshore oil and gas development and production.
Subsea tieback technology coupled with innovative
subsea technology also increase the ability of the
industry to develop and produce more oil and gas
in felds that would not otherwise be economical.
Accounting for approximately 290 productive wells
in deep water, subsea systems continue to be a key
Figure 1-20. Federal Outer Continental Shelf (OCS) Oil as a Percentage of Total U.S. Production, 1960–2009
0
0.4
0.8
1.2
1.6
O
I
L
P
R
O
D
U
C
T
I
O
N
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
0
10
20
30
P
E
R
C
E
N
T
FEDERAL OCS FEDERAL OCS PERCENTAGE OF TOTAL U.S. PRODUCTION
1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
YEAR
1961 – First subsea well completed
1988 – Deepest fxed platform installation – Bullwinkle
1996 – First SPAR completed – Neptune
2006 – Installation of Independence hub in Gulf of Mexico
2002 – Deepest pipeline constructed at 7,209 feet
2010 – Completion of construction of frst foating production
storage and ofoading in Gulf of Mexico
1
2
6
1989 – First U.S. tension leg platform – Jolliet at 1,760 feet
– 3D seismic processing begins
– Subsalt drilling begins
2003 – Discoverer Deep Seas drillship hits frst well deeper
than 10,000 feet
3
4
1997 – Longest tieback constructed – Mensa 5
7
8
9
1 2 3 4 5 6 7 8 9
Figure 1-20. Federal Outer Continental Shelf (OCS) Oil
as a Percentage of Total U.S. Production, 1960–2009
CHAPTER 1 - RESOURCES AND SUPPLY 83
component in the success of the industry in deepwa-
ter regions of the Gulf of Mexico.
Additional development potential exists in areas
that have largely been under exploration and develop-
ment moratoria for most of the past two decades, in
particular the Eastern Gulf of Mexico and the Atlantic
and Pacifc OCS. Estimates of the undiscovered tech-
nically recoverable resources of crude oil in U.S. of-
shore moratoria areas vary from 18.2 to 63.0 billion
barrels. In contrast, the BOEMRE mean estimates
of total U.S. lower-48 ofshore undiscovered techni-
cally recoverable oil are 59.3 billion barrels.
3
Although
these estimates include a wide range of assumptions,
their sheer magnitude demonstrates that a signifcant
resource base remains available for future ofshore oil
production.
Canada O?shore
In Canada, ofshore hydrocarbon production
comes exclusively from its Atlantic margin, with nat-
3 Minerals Management Service, “Assessment of Undiscovered
Technically Recoverable Oil and Gas Resources of the Nation’s
Outer Continental Shelf, 2006,” February 2006.
ural gas and oil being produced in Nova Scotia and
Newfoundland ofshore.
In ofshore Newfoundland, production in the
Jeanne d’Arc Basin of the Grand Banks started in
1997 with the Hibernia feld followed by the Terra
Nova and White Rose felds in 2002 and 2005, respec-
tively. From an initial annual production of 1.3 mil-
lion barrels in 1997, production reached 97.7 million
barrels in 2009, with a peak production of 134.5 mil-
lion barrels in 2007. In 2009, average daily produc-
tion was 340 thousand barrels per day. Cumulative
oil production reached 1,125 million barrels in April
2010 (Figure 1-21).
While Canadian ofshore production and develop-
ment plans are confned to the Newfoundland and
Nova Scotia sectors of the Atlantic margin, explora-
tion activities (seismic and drilling) are planned in
both areas and their less explored domains (Lauren-
tian, Sydney, Orphan, and Flemish Pass sub-basins)
that are under the Canada-Nova Scotia Ofshore
Petroleum Board (CNSOPB) or Canada-Newfound-
land and Labrador Ofshore Petroleum Board
(CNLOPB) rules.
Figure 1-21. Total Monthly Oil Production – Ofshore Newfoundland and Labrador
0
2
4
6
8
10
12
14
1997 1999 2001 2003 2005 2007 2009 2011
M
I
L
L
I
O
N
B
A
R
R
E
L
S
NORTH AMETHYST
WHITE ROSE
TERRA NOVA
HIBERNIA
Source: Canada-Newfoundland and Labrador Ofshore Petroleum Board.
Figure 1-21. Total Monthly Oil Production – Ofshore Newfoundland and Labrador
84 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Te Gulf of St. Lawrence has been recently evalu-
ated to host an in-place best estimate (P50) of
41 Tcf of gas and 2,500 million barrels of oil, largely in
Carboniferous reservoirs. A signifcant gas discovery
(77 Bcf) was made in this basin in 1970. Except for
restricted zones under the jurisdictions of CNSOPB
or CNLOPB, most of the Gulf area is under a de facto
moratorium. Te non-regulated area is currently the
subject of jurisdiction discussions between the federal
and provincial governments. Areas under the juris-
diction of the CNSOPB and CNLOPB are, however,
open for exploration. Seismic acquisition is planned
in the CNLOPB area in 2011.
Te Georges Bank area (ofshore Nova Scotia) is
evaluated to host 3,500 million barrels of in-place
oil resources. Te area is currently under an explora-
tion moratorium, which has been recently extended
to 2015.
Te Pacifc margin of western Canada is under a
de facto moratorium, though no ofcial legislation
has been put in place. Tere have been no discoveries
in this area, and the best estimate (P50) indicates the
presence of in-place resources of 43.4 Tcf of gas and
9,800 million barrels of oil.
Of all the areas under legislated or de facto mora-
toria, the Gulf of St. Lawrence is the one most likely
to be opened for exploration in the next 5 to 10 years.
Production Pathways
Potential production from the ofshore areas can be
infuenced by a variety of factors including technology
progress, access to ofshore leases, the economic envi-
ronment, infrastructure development, environmental
risk management capabilities, and geology. Here we
set out a reasonably unconstrained production poten-
tial and contrast it with a more constrained view,
thus defning the range for U.S. lower-48 ofshore oil
production.
Te unconstrained case is characterized by a
favorable economic environment with buoyant oil
demand, increased access to ofshore lands, and
accelerated technological progress. Conversely, the
constrained case assumes lower oil demand, limited
access to ofshore zones, and slower technological
improvement.
In particular, alternate cases published in the
Energy Information Administration’s Annual
Energy Outlook are based on scenarios and sensi-
tivities with expanded ofshore access, accelerated
technology deployment and high oil price environ-
ments. Production of oil in U.S. lower-48 ofshore
increases from 1.7 million barrels per day in 2010 to
2.3 million barrels per day in 2035, in the high oil
price case, according to the fnal results of AEO2011
(Figure 1-22).
Te bulk of the expected increase in U.S. ofshore
oil production is likely to come from new discover-
ies in deepwater and ultra-deepwater regions of the
Gulf of Mexico, such as the Lower Tertiary trend.
Te Lower Tertiary is recognized as a huge resource
with the potential for long-life projects of up to 30 to
40 years and the opportunity to enhance recoveries
through advancing technology.
Te AEO2011 Low Oil Price case provides insight
into the lower or more constrained development
pathway. Production of oil decreases from 1.8 mil-
lion barrels per day in 2010 to 1.4 million barrels of
oil per day in 2035. Tat level could be even lower
if more restrictive operational safety requirements
and legislative policies were passed and imple-
mented, following the 2010 Macondo oil spill in the
deepwater Gulf of Mexico. Tis occurrence would
afect the rate of development and production of
deepwater and ultra-deepwater oil and gas prospects
in general, and the lower tertiary trend in particu-
lar. Te overall efect would be to increase drill times
along with exploration and development costs, and
thus slow signifcantly expected production over the
next 10 years and dampen long-term output from the
U.S. ofshore. Production could be 20% lower by 2035
if long-term moratoria were reinstated as a result of
the Macondo oil spill in the deepwater Gulf of Mexico
and no development takes place outside the central
and western Gulf of Mexico.
Kcy O?shorc Tcchnologics
Over the past 100 years, the petroleum industry
has demonstrated an ability to develop breakthrough
technologies that made a signifcant impact on fnd-
ing and producing oil and gas. Drilling rigs, wireline
logging, logging while drilling, geophysical surveys,
subsea systems, and enhanced oil recovery, to name
a few, have fueled an incredible century of progress.
Tey provide diverse examples of efective existing,
emerging, and future technologies that will expand
CHAPTER 1 - RESOURCES AND SUPPLY 85
the frontiers of exploration and production. Cer-
tainly each of them continues to play a critical role
in increasing production growth in North America.
But industry is now faced with continuing and even
growing challenges in the ofshore, trying to grow
production in deep water, often with poor subsurface
images, in remote areas with limited infrastructure,
in deeper, often hostile, high pressure high temper-
ature environments, and fnally doing all of this in
a basin that is becoming more mature. Te Gulf of
Mexico is one of the most important regions in the
United States for energy resources and infrastructure,
accounting for just under 30% of total U.S. oil pro-
duction and 13% of total natural gas production.
Figure 1-23 illustrates that over 70% of that of-
shore oil production in the Gulf comes from deep
water, accounting for almost a quarter of U.S. oil
production – and the amount is rising.
Future, successful exploration and development
in both maturing open and currently restricted
OCS areas will be critical to maintain North Ameri-
can oil and gas production. Operations must be con-
ducted with improved safety measures while con-
trolling costs. Tackling these challenges will involve
continued use of existing technologies. To improve
success and increase production and recovery, espe-
cially in the Gulf of Mexico Lower Tertiary, develop-
ment of new technologies will be necessary to ensure
challenges are overcome.
Topic Paper #1-3, “Ofshore Oil and Gas Supply,”
associated with this report, builds of the excel-
lent commentary made in the two technology topic
papers that accompanied the 2007 NPC study Hard
Truths: Facing the Hard Truths about Energy. Te frst
of these papers, “Exploration Technology,” identi-
fed fve technology areas in which future develop-
ments have the potential to signifcantly impact
exploration results over the next 25 years. Te sec-
ond, entitled “Deepwater,” identifed four top pri-
ority deepwater-specifc technological challenges
most important to future deepwater development.
Te following is a summary of the key technologies
from the papers.
Figure 1-22. Projection U.S. Lower-48 Ofshore Oil Production
0
1
2
2.5
2010 2015 2020 2025 2030 2035
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011 AEO2011 REDUCED OCS ACCESS 2011)
AEO2011 HIGH OCS 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-22. Projection U.S. Lower-48 Ofshore Oil Production
86 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
“Exploration Tcchnology” Topic Papcr
4
y Core Technology Areas:
? Seismic
? Controlled Source Electromagnetics (CSEM)
? Interpretation Technology
? Earth Systems Modeling
? Subsurface Measurements.
y Auxiliary Technologies – Future developments or
applications that have the potential to signifcantly
impact exploration results by 2030:
? Drilling Technology
? Nanotechnology
? Computational Technology.
4 Cassiani et al., “Exploration Technology,” Topic Paper, National
Petroleum Council Study, Hard Truths: Facing the Hard Truths
about Energy, 2007.
“Dccpwatcr Tcchnology” Topic Papcr
5
y Top Priority Deepwater-Specifc Challenges:
? Reservoir Characterization
? Extended System Architecture
? High-Pressure and High-Temperature (HPHT)
Completions Systems
? Metocean Forecasting and Systems Analysis.
y Related topics discussed in other reports:
? Subsalt imaging
? Gas to Liquids
? Arctic.
y Other Important Deepwater Technologies Consid-
ered:
? Infrastructure life extension
5 Conser et al., “Deepwater,” Topic Paper, National Petroleum
Council Study, Hard Truths: Facing the Hard Truths about
Energy, 2007.
Figure 1- 23. Annual Oil Production Trend from Ofshore Shallow and Deepwater Ofshore Outer Continental Shelf
0
100
200
300
400
500
1978 1980 1985 1990 1995 2000 2005 2010
V
O
L
U
M
E
M
I
L
L
I
O
N
S
O
F
B
A
R
R
E
L
S
YEAR
DEEPWATER GULF OF MEXICO OIL PRODUCTION
SHALLOW WATER GULF OF MEXICO PRODUCTION
Source: Bureau of Ocean Energy Management, Deepwater Gulf of Mexico 2009: Interim Report of 2008 Highlights,
OCS Report MMS 2009-016.
Figure 1-23. Annual Oil Production Trend from Ofshore Shallow and Deepwater Outer Continental Shelf
CHAPTER 1 - RESOURCES AND SUPPLY 87
? Virtual prototyping
? Unconventional options.
Tese papers also provided suggestions and options
for accelerating development and use of technol-
ogy and identifed two issues critical to successful
development of oil and gas resources in ever-harsher
environments. Tese are: (1) future marine technol-
ogy leadership and (2) valuing technology to enable
access.
Te “Ofshore Oil and Gas Supply” topic paper
accompanying this report (available on the NPC web-
site) evaluates technologies that will enable growth
of ofshore production for the next 40 years, based
on discussion among the Ofshore Subgroup mem-
bers, colleagues within our respective companies
and organizations, as well as extensive literature
search, including the 2007 NPC study Hard Truths
Technology Topic Papers. To prioritize technologies,
two surveys were submitted to professionals in the
various key disciplines of geology, geophysics, petro-
physics, reservoir engineering, drilling engineering,
completion, and production engineering for feed-
back. Te frst survey asked the participants to rate
oil and gas production capacity growth challenges
and enablers that are included in the 2010 NPC
Petroleum Resource Template. Te second survey
was based on the 2007 NPC Hard Truths topic papers
and asked participants for feedback on the previ-
ously identifed core technologies listed above and
any additional ones that would signifcantly impact
growth in production, concluding with a ranking
of the technologies. Not surprisingly, the surveys
showed that many of the priorities have not changed
from the previous topic papers and the diferences of
note are due primarily to the focus on ofshore deep
water.
Key changes from the 2007 report include mov-
ing Drilling and Computational Technology from the
auxiliary level to the core level and the addition of
Improved and Enhanced Oil Recovery, where a large
target of recoverable remaining oil in place exists.
Extended Architecture is central to any discussion
on the growth of oil and gas production and is dis-
cussed together with including Completions and Digi-
tal Fields. High-Pressure High-Temperature (HPHT)
Completions Systems certainly remains a key tech-
nology category, but in this report will be tackled as
HPHT environment in the various core technologies
that it impacts. Te only technology no longer on the
core list is CSEM. Although that tool can reduce the
exploration risk in CSEM-suitable settings, it was not
ranked at the level of the other core technologies and
would now be included at the auxiliary level. Of fnal
note, a brief update on the status of industry plans for
containment is included under the Drilling Technol-
ogy section of the “Ofshore” topic paper. As such, the
updated list of core technologies that will be critical to
oil and gas capacity growth ofshore are:
y Scismic – Utilization of man-made acoustic waves
to image the subsurface geology has been a game
changer, allowing industry to unlock the explora-
tion potential of the deepwater Gulf of Mexico and
optimize the development of discoveries. Tech-
nical advances in imaging algorithms, processing
fows and acquisition geometries are underway
that could make improvements in imaging neces-
sary to expand existing and emerging hydrocarbon
bearing trends as well as identify new ones.
y Computational Tcchnology – A key enabling
technology. While not invented by the oil and gas
industry, studies have concluded that this indus-
try has propagated digital technologies, altered its
management and organization, and changed the
way people connect to the data far more than any
other industry. Te value delivered from the accom-
panying technologies in this list would not be pos-
sible without it.
y Intcrprctation Tcchnology – Has played a sig-
nifcant role in the impact of 3D seismic on success
rates. With the adaptation of tools used in other
industries, such as medical imaging, interpreters are
now able to visualize and interpret data much faster.
Tey are not limited to thinking in 3D, but literally
can visualize in 3D, or “climb into” the data set.
y Earth-Systcms Modcling – Encompasses geology,
hydrology, climatology, and other applied sciences
involved in studying the earth as an integrated
system. Earth systems modeling joins basin and
petroleum system modeling together to quantita-
tively model a sedimentary basin’s deposition, ero-
sion, and heat fow history together with essential
elements of the Petroleum System (source, overbur-
den, reservoir, seal) and critical processes (trap for-
mation, generation and migration, accumulation,
preservation) during the evolution of a sedimen-
tary basin.
6
6 L. B. Magoon and W. G. Dow, Te petroleum system—From
source to trap, American Association of Petroleum Geologists
Memoir 60, Tulsa, Oklahoma, 1994.
88 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Drilling – Industry has come a long way from the
days of dropping a heavy bit down the hole to chisel
away the soft rock formations. In 1909, the two-
cone rotary bit unlocked the full potential of the
rotary drilling system, allowing for the efcient
drilling of wells in much deeper, harder rock envi-
ronments. Further advances followed with direc-
tional and horizontal drilling, top drives, and rotary
steerable assemblies. Te trend for conventional oil
and gas discovery has been to drill in environments
that were previously inaccessible. Traditionally this
means drilling deeper into hotter and higher-pressure
zones and to do so in ever more extreme environ-
ments such as ultra-deepwater. Historically the
only way to access these zones is to get bigger rigs,
stronger steel, and more durable tools and there is
little reason to believe this trend will not continue.
New rigs coming out are capable of drilling in up to
12,000 feet of water and 40,000 feet total depth.
y Subsurfacc Mcasurcmcnts – At the turn of the
20th century, oil industry pioneers began to
search for ways to obtain information about what
the drill bit was encountering. Tis led to devel-
opment of core sampling and mud-analysis of
the wellbore cuttings (mud logging) that came to
the surface. Beginning in 1978, one of the most
infuential technologies for drilling and subsur-
face measurement occurred when Teleco intro-
duced the frst commercial measurement while
drilling (MWD) tool, enabling operators to know
the location of their well while drilling. Within a
decade, Schlumberger introduced the other criti-
cal technology, logging while drilling, or LWD,
which allowed geoscientists to get petrophysical
measurements, similar to openhole wireline logs,
immediately after the bit drilled the formation.
Tis information can then be viewed essentially in
real time on the rig and back onshore in the ofce,
allowing for more timely decisions.
y Rcscrvoir Charactcrization – Involves building
a high-resolution geologic model of the reservoir
that incorporates characteristics key to reservoir
storage and production of hydrocarbons. It con-
sists of a geometric description of the boundary
surfaces, faults, bedding geometries, and a 3D dis-
tribution of reservoir properties such as permeabil-
ity and porosity. Robust reservoir characterization
is critical to predicting and monitoring the produc-
tion behavior in increasingly complex reservoirs
with fewer more costly direct well penetrations.
y Extcndcd Systcm Architccturc – In shallower
water, options for developing the extremities of
felds not reachable by directional drilling from an
existing platform or where costs would not justify
the installation of one or more platforms, drove
the development of subsea well systems and their
accompanying tiebacks. In deep water, this led to
the development of Tension Leg Platforms (TLPs),
semi-submersible foaters and spars that act as
hubs to collect production from multiple subsea
well systems for processing and transportation via
pipeline to shore. Today the term extended system
architecture applies to the combination of these
facilities and includes fow assurance, well control,
power distribution, and data communications to
improve recovery and extend the reach of produc-
tion hubs to remote resources.
y Improvcd and Enhanccd Oil Rccovcry – Boosting
the recovery factor of world’s felds just 1% has the
potential to cover three years of worldwide produc-
tion. Tis increased productivity of hydrocarbons
is known as Enhanced Oil Recovery (EOR) and
Improved Oil Recovery (IOR). Technology for these
types of recovery processes is already in place at
many felds around the world, with EOR primarily
onshore. Techniques for IOR include: waterfood;
subsea processing and pumping such as sea foor
separation, gas lift, multiphase pumps, and electric
submersible pumps; horizontal and multilateral
drilling to expose more of the formation or multiple
formations to the open hole; improved perforation
and stimulation methods; advanced logging proce-
dures; and optimal placement of wells.
7
y Mctoccan Forccasting and Systcms Analysis –
Integrated models to predict both above and below
surface “weather” and engineering system response.
Te ability to characterize and predict the behavior
of the oceans is essential for safe conduct of explo-
ration and production operations ofshore. Te
ability to predict near term conditions for the seas
and currents is necessary to plan and conduct safe
drilling and production operations in the marine
environment and to respond to any hydrocarbon
spill incident.
Kcy Findings
y Oil development and production in the U.S.
lower-48 ofshore is signifcant, and the expecta-
tion is that a production growth trend will extend
7 S. A. Ali, “Mature Field Revitalization,” Technology Focus: Jour-
nal of Petroleum Technology, January 2009.
CHAPTER 1 - RESOURCES AND SUPPLY 89
to the year 2050. Te Ofshore Subgroup expects
ofshore oil production to increase to the year
2035 by an average annual growth rate range of
0.2% to 0.9%.
y According to the AEO2011, crude oil production in
the U.S. lower-48 ofshore is expected to rise up to
2.3 million barrels per day in 2035 in the high oil
price case.
y Beginning around 2020 and extending to the year
2050, the bulk of oil production in the U.S. lower-
48 ofshore is expected to originate from the deep-
water Gulf of Mexico, in the emerging Lower Ter-
tiary trend and the extension of existing and new
trends into areas that are currently poorly imaged.
Also, we expect additional impacts on production
from increased access to the Pacifc, and the Atlan-
tic ofshore regions.
y Government policies favorable to accessing more
U.S. lower-48 ofshore lands are needed to allow
for the occurrence of the oil and gas development
and production growth rates mentioned above.
y A slowdown and a postponement of ofshore oil
and gas development and production are expected
if more stringent operational safety requirements
and environmental policies are implemented in
the OCS following the Macondo oil spill in the
deepwater Gulf of Mexico.
y Technological progress and innovation are the key
factors that would enable development and produc-
tion of oil and gas in new frontier regions located in
deep water and in deeper reservoirs. Most notably,
technologies adapted to the high-pressure high-
temperature (HPHT) environment, delivery rates,
and reduction of drilling costs are the key drivers
for the huge oil and gas resources hosted in the
Gulf of Mexico Lower Tertiary formations. Tese
formations have potentially greater than 15 billion
barrels of recoverable oil reserves, some of which is
located in areas of at least 60 miles from the near-
est infrastructure. Te challenges of this environ-
ment cross multiple disciplines and advances in
technologies associated with seismic imaging,
completion and casing design, subsea production
equipment, subsea processing, and high integrity
pressure protection systems, while underway, need
to continue, if not accelerate. HPHT applications to
10 thousand pounds per square inch (ksi) and 250oF
are common in today’s market and the envelope has
pushed out to 15 ksi and 400oF, with some limited
gaps. However, now the envelope is being pushed
even further to 20–30 ksi and >400oF in the shal-
low water gas play of the Lower Tertiary trend.
y Seismic innovative technologies that allow for
better imaging of the subsalt horizons in the Gulf
of Mexico are pivotal to the expansion of hydro-
carbon resources via additional newer discover-
ies. Tese include imaging algorithms, acquisition
geometries, and inclusion of more azimuths in pro-
cessing and retention of high frequencies.
y An extrapolation of the top 500 supercomputer per-
formance lists predicts Exascale computing capabil-
ity with a 1,000-fold increase in processing capa-
bility within 10 years. With some seismic vendors
today approaching the level of computing capability
seen with the national computers on the top 500
list, it will be exciting to see what challenges can be
conquered with the Exascale computing level, such
as near real-time seismic imaging.
y Tere is a need to reduce drilling costs so that many
more exploration wells can be drilled, allowing com-
panies to test more concepts and perhaps encour-
age more improved and enhanced oil recovery
programs. Dual gradient drilling is one such con-
cept scheduled to be implemented in the deepwater
Gulf of Mexico this year.
y Subsea technology and extended architecture sys-
tems will boost production of ofshore oil in remote
and challenging environments of the deepwater
and ultra-deepwater areas, which lack the basic
infrastructure needed to produce and to transport
the hydrocarbons to shore.
y Te ofshore feld of the future, which we are not far
from today, will have multiple satellite felds pro-
duced via subsea completions and long tiebacks to
hub facilities. Te subsea manifolds will be equipped
with remote power and communication ability, so
remote surveillance and control functions are avail-
able at the hub as well as the onshore production
center. Smart equipment will be deployed on the
seafoor and downhole that will accept commands
from the ofshore hub or onshore center to improve
reservoir production efciency. Sophisticated mod-
els of the reservoir, well, and processing systems will
be kept up to date and running online, so surveil-
lance is a “manage by exception” process. Field opti-
mization will be regularly reviewed and based on
analysis so that asset managers can make decisions
when opportunities are encountered, instead of pro-
ducing to a plan that may be months to years old.
90 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Tere have been signifcant advances in subsurface
measurement over the last decade, but the demand
for increased resolution and data will require
improved real-time transmission methods. Te
need to improve downhole fuid characterization
and reservoir parameter data for in situ properties,
and to monitor wells down-hole for longer periods
will be critical to predicting feld performance in
more challenging environments.
y Improved and enhanced oil recovery techniques
could reach an additional 44 billion barrels of oil
equivalent left in discovered felds at abandonment.
Tis is based on data from more than 80 felds and
450 reservoirs developed in the Deepwater Gulf of
Mexico Research Partnership to Secure Energy for
America project 07121-1701, entitled “IOR of the
Deepwater Gulf of Mexico.”
y In the U.S. lower-48 ofshore, newer geologic plays
and trends such as the Lower Tertiary and deeper
reservoirs are expected to contribute to current and
near future production of crude oil and natural gas.
y Canadian ofshore production of oil is lower in com-
parison to the U.S. lower-48, and is confned to the
eastern shore in Newfoundland and Nova Scotia.
Removal of the imposed and the de facto moratoria
will provide better opportunities for increasing of-
shore oil development and production in ofshore
Canada.
Arctic
History and Contcxt
For the purposes of this study, the Arctic is defned
as those areas in Alaska, Canada, and Greenland sub-
ject to ice and permafrost conditions, rather than sim-
ply those areas north of the Arctic Circle. Greenland
is included, even though it is a territory of the king-
dom of Denmark, as any future oil production from
Greenland would very likely be supplied to the U.S.
and/or Canadian oil markets. Te map in Figure 1-24
shows the areas in Alaska, Canada, and Greenland
covered in this portion of the study, within the red
dotted line.
Te Arctic study area is estimated to contain over
7 billion barrels of discovered undeveloped and over
90 billion barrels of mean, risked, technically recov-
erable undiscovered volumes of oil and NGLs. Tese
LABRADOR
NEWFOUNDLAND
U.S.
CANADA
GREENLAND
STUDY AREA
ARCTIC CIRCLE
INTERNATIONAL
BOUNDARY
BEAUFORT
CHUKCHI
NORTH
ALASKA
BERING
SHELF
PACIFIC MARGIN
SOUTH ALASKA
CENTRAL
ALASKA
MACKENZIE
DELTA/
CENTRAL
BEAUFORT
CANADA NORTH
ONSHORE BASINS
ARCTIC ISLANDS/
SVERDRUP BASIN
EAST CANADA
WEST GREENLAND
EAST
GREENLAND
RIFT BASINS
NORTH GREENLAND SHEARED MARGIN
Figure 1-24. Arctic Subgroup Study Area
ARCTIC CIRCLE
Sources: Bureau of Ocean Energy Management, Regulation and Enforcement; Canada-Newfoundland Ofshore Petroleum Board; IHS
Inc.; National Energy Board of Canada; and United States Geological Survey.
Figure 1-24. Arctic Subgroup Study Area
CHAPTER 1 - RESOURCES AND SUPPLY 91
volumes are highlighted on the map in Figure 1-25,
which indicates their location by basin, and are
described in Finding 1 later in this section. Additional
information can be found in Topic Paper #1-4, “Arctic
Oil and Gas,” available on the NPC website.
Figure 1-26 shows how the crude oil resources
described above are distributed among Alaska, Can-
ada, and Greenland and highlights the amount of
undiscovered oil resources that lie in areas currently
under moratoria or otherwise unavailable for leas-
ing. Tese are world-scale resources, which will need
to be validated by exploration and development drill-
ing activity in order to enable production from the
2025–2050 time frame.
Te long history of onshore and ofshore oil and
gas leasing/licensing and exploration drilling in the
Arctic region has resulted in discovery of signifcant
oil and gas reserves, some of which have been devel-
oped and produced, most notably the giant oil and
gas feld at Prudhoe Bay on the Alaska North Slope
and the large oil and gas felds (onshore and ofshore)
in Cook Inlet, Alaska, as well as numerous stranded
discoveries (no development/production facilities or
pipelines). Experts expect the region to contain sig-
nifcant yet-to-be-found volumes, based on numer-
ous government agency estimates and supported
by industry interest (leasing/licensing, historical
2D seismic and modern but limited 3D seismic, and
renewed attempts to secure regulatory permission
to drill particularly in the ofshore). Most of these
volumes are expected to be ofshore, beneath the
continental shelf.
Following is a brief summary of the development
and production history for the most signifcant of the
main Arctic areas under consideration.
North Alaska Onshore
Exploration of this region began in 1909 with dis-
covery of active oil seeps in the Cape Simpson area
of what is now the Northwest National Petroleum
Reserve–Alaska (NPR-A). In 1945, the frst explora-
tion drilling resulted in non-commercial fnds until
the discovery of the giant Prudhoe Bay Field in 1968
(15 billion barrels oil and 27 Tcf gas recoverable).
Notes: Discovered undeveloped plus mean risked, technically recoverable, undiscovered volumes by basin. Prospective basins
highlighted in green for Alaska, in yellow for Canada, and in blue for Greenland.
BBO = billion barrels of oil; BBNGL = billion barrels of natural gas liquids.
A
RCTIC CIRCLE
1.3
0 0.2
0.1
1.7
0
0.7
0
16.7
0.8
15.4
0.7
9.9
0.1
9.2
0.2
0.6
0
4.7
0
1.4
0.2
8.9
8.1
5.9
0.9
4.8
0.7
2.7
0
BBO + BBNGL
BBO
BBNGL
INTERNATIONAL BOUNDARY
DISPUTED ZONE
Figure 1-25. Arctic Oil and Natural Gas Liquids Resources
Figure 1-25. Arctic Oil and Natural Gas Liquids Resources
92 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Prudhoe Bay helped drive the construction of the
Trans-Alaska Pipeline System (TAPS), completed in
1977, and ushered in a new era of exploration. Over
400 exploration wells have been drilled in this region,
mostly in the North Slope Coastal Plain, and have
resulted in the discovery of numerous felds, many
of which are currently producing. Te northern dis-
coveries are primarily oil and gas, while the south-
ern discoveries are largely non-associated gas with
some possibility of oil. Natural gas is not exported
due to the lack of a gas pipeline and most of the gas is
re-injected back into producing reservoirs to enhance
oil recovery. Prospective areas outside the North
Slope Coastal Plain (NPR-A, North Slope Foothills,
and the Arctic National Wildlife Refuge, 1002 Area
[ANWR 1002]) are signifcantly underexplored.
North Alaska O?shore
Exploration drilling in the federal portion of the
Beaufort Sea area began in earnest following the
1968 discovery of the Prudhoe Bay Field (onshore)
and the completion of TAPS in 1977. Te frst ofer-
ing occurred in a joint federal/state lease sale held
in 1979. Tis and subsequent OCS lease sales, the
most recent of which was held in 2007, have allowed
access to waters beyond the three-mile limit. Explor-
atory eforts since 1970 (~90,000 miles of 2D seis-
mic and 30 exploration wells) have yielded four
discoveries that have been deemed capable of pro-
duction and have been termed signifcant discov-
eries by BOEMRE and the Alaska Division of Oil &
Gas. Tree of these discoveries, Hammerhead (Sivul-
liq), Sandpiper, and Liberty, are completely in OCS
waters but have not yet been developed. Te fourth
discovery, Northstar, underlying both federal and
state waters, has been developed and producing oil
since 2001.
With respect to the Chukchi Sea, in the early 1980s,
BOEMRE (formerly MMS) determined that this area
had a large resource potential and that long-term
oil pricing would support exploration and develop-
ment. BOEMRE held the frst lease sale (Sale 109)
covering this prospective area in 1988, ofering more
than 25 million acres. Industry drilled fve explora-
tion wells from 1989 to 1991, and demonstrated a
working petroleum system with strong afnities to
Figure 1-26. Split of Arctic Oil Potential (not Including Natural Gas Liquids)
Note: Discovered undeveloped plus undiscovered (mean risked, technically recoverable).
GREENLAND
AVAILABLE 17%
CANADA
AVAILABLE
20%
ALASKA
AVAILABLE
37%
ALASKA
MORATORIA
AREA 13%
ALASKA POTENTIALLY
AVAILABLE FOR LEASE 4%
CANADA
UNAVAILABLE 6%
GREENLAND
UNAVAILABLE 2%
ALASKA'S TOTAL SHARE 55%
CANADA'S TOTAL SHARE 26%
GREENLAND'S
TOTAL SHARE
19%
Figure 1-26. Split of Arctic Oil Potential (not Including Natural Gas Liquids)
CHAPTER 1 - RESOURCES AND SUPPLY 93
the North Slope and Beaufort Sea regions. Four of
the fve wells contained reservoirs with oil and gas
“pay,” as defned by BOEMRE, and the ffth well-
demonstrated oil and gas shows. Tese wells were
drilled 60 miles or more of of the coast in water
depths ranging from 137 to 152 feet. Although none
of the prospects were deemed commercial at the
time, existence of a working petroleum system was
demonstrated.
Canadian North
In the Canadian North, oil and gas exploration
dates back to the recognition of oil seeps in the 1700s
and the 1920 discovery of the Norman Wells oil
feld (0.3 billion barrels oil recoverable). Te late
1940s and 1950s saw increased exploration in the
southern portion of the Northwest Territories.
Exploration then moved northward above the Arc-
tic Circle, frst into the Mackenzie Delta in 1960,
then the Arctic Islands and Sverdrup Basin in 1961
and the Canadian Beaufort Ofshore in 1972. Many
signifcant oil and gas felds (Parsons Lake, Taglu,
Niglintgak, Drake Point, Adlartok, Tarsiut, Issung-
nak, Amauligak, and Kopanoar accumulations) were
found. Tese discoveries were the result of an exten-
sive exploration efort that resulted in 213 wells
drilled in the onshore Mackenzie Delta, 174 wells
in the Arctic Islands/Sverdrup Basin, and 87 wells
in the ofshore Canadian Beaufort. Drilling activ-
ity in these areas subsided in the late 1980s, but
high global energy prices in 2004–2008 combined
with the proven occurrence of oil and gas renewed
industry’s interest in this region. Canadian Beau-
fort licensing rounds in 2007–2010 drew signifcant
industry interest. Six exploration licenses covering
three million acres were issued to ExxonMobil/Impe-
rial, BP, ConocoPhillips, and Chevron for working
commitment of 1.89 billion Canadian dollars. Explo-
ration activities commenced in 2008-2009 with the
acquisition of 3D seismic data and exploratory drill-
ing may commence as soon as 2014.
Canadian East
Te Labrador-Newfoundland Shelf region ofshore
is one of two promising areas within the Canadian
East. It contains the Saglek, Hopedale, Hawke,
Orphan, Jeanne d’Arc, and Flemish Pass ofshore
basins. Tese basins reside along the Continen-
tal margin in water depths ranging from less than
100 meters to greater than 3,000 meters. Explora-
tion in this ofshore region began in 1966. Wildcat
drilling started in 1971 and continued through 1984.
Discoveries along the Newfoundland portion of this
margin yielded signifcant oil and gas reserves in the
Jeanne d’Arc Basin including the giant Hiber-
nia (1979), Hebron/Ben Nevis (1981), Terra Nova
(1983), and White Rose (1984) felds. Development
of the Hibernia feld, as well as the Terra Nova and
White Rose felds, has resulted in the cumulative
production of 1 billion barrels of oil as of 2009 and
development of Hebron/Ben Nevis is planned. In
2004, a second wave of licensing and exploratory
drilling began in this region in the Flemish Pass and
Orphan Basin areas. Several wells have been drilled
with an announced discovery in the Flemish Pass
area. Another promising area, described below, is the
Canadian portion of the Bafn Bay region, an area
shared with Greenland.
Greenland
Te West Greenland-East Canada Province includes
the ofshore region of eastern Canada and western
Greenland from approximately latitude 63° north to
80° north. Oil seeps have been sampled and described
from Nuussuaq Peninsula, Disco Island, and Fossilik
outcrops on the west coast of Greenland and have
been reported at Scott Inlet on the Canadian side.
Tirteen exploration wells (three wells on the Cana-
dian and ten on the Greenland side) have been drilled
in this area and several have demonstrated the pres-
ence of hydrocarbons. Licensing of numerous tracts
has continued on the Greenland portion of the basin
with the most recent licenses being awarded in 2010.
Cairn Oil drilled three exploration wells on their
ofshore licenses in 2010 and announced that two
wells had encountered thermal gas and that one well
encountered oil. Cairn has returned to this region in
2011, and is currently drilling additional exploration
wells on their licenses.
Te East Greenland Rift Basin also looks very prom-
ising, based on a recent USGS assessment. Greenland
intends to hold the frst licensing round for this of-
shore region in 2012. Licenses in this region will fea-
ture a 16-year term.
Tcchnology
Hydrocarbon resources identifed in the Arctic
region are mainly conventional oil and gas for which
exploration, appraisal, and production technologies
94 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
are well understood and widely available for regions
residing in shallow water (less than 100 meters)
and those areas not impacted by signifcant icebergs
(such as the continental shelves of the Alaska OCS
and the Canadian Beaufort and Grand Banks region).
Technology has not been a limiting factor in the
development of the Alaska North Slope, (both onshore
and in State waters), in Cook Inlet in southern Alaska
(onshore and ofshore), ofshore on the Newfound-
land-Labrador shelf, and for exploration activity in
the Chukchi and Beaufort Seas and ofshore Green-
land. In the Arctic, however, as in other regions, the
deployment of technology particularly needs to take
into account the protection of sensitive ecosystems
from an environmental standpoint.
Awareness of environmental imperatives has led to
signifcant technological advances by the oil indus-
try, in order to achieve safe resource extraction with
minimal disturbance to the environment. To cite
two examples among many: the oil and gas indus-
try developed the Rolligon that allows heavy loads
to be carried across the Arctic tundra with minimal
ground pressure and disturbance; and horizontal-
and extended-reach drilling technology that makes it
possible to drill multiple wells from a single pad at
less cost and with a smaller environmental footprint
than the traditional multiple pad approach.
Te certainty that technology and related practices
to prevent and mitigate environmental risks associ-
ated with the Arctic will continue to be enhanced
led the Arctic Subgroup to conclude that technology
is not likely to limit onshore or ofshore exploration
and development, except in regions where water
depths exceed 100 meters or where signifcant iceberg
management is necessary. Near-term advances in
ofshore pipeline trenching will be important across
the Arctic, especially in deepwater conditions (over
100 meters of water depth) such as the Continental
Slope region of the Canadian Beaufort, Labrador, or
Greenland. Advances in iceberg management will also
be important for Greenland and portions of the Cana-
dian Atlantic ofshore. Te history of the region indi-
cates that innovation will continue as new challenges
are identifed. Tere are many Arctic producing felds
on land today, and safe development and production
of ofshore Arctic reserves has occurred since the late
1960s (Cook Inlet and Northstar Field, Alaska; Hiber-
nia, Canada; and Sakhalin, Russia) demonstrating
that resource extraction can occur in the midst of sen-
sitive ecosystems.
Since the Arctic region is primarily defned by harsh
ice conditions that afect drilling operations and envi-
ronmental risk management, the Arctic Subgroup
undertook an assessment of the severity and impact
of ice conditions across the various Arctic basins stud-
ied here. Te study draws on the experience of over
450 existing wells ofshore in the western Arctic, as
seen in Figure 1-27.
Ofshore basins where this activity has taken place
experience all three dominant types of ice conditions
(land-fast ice, pack ice, and icebergs). Table 1-5 sum-
marizes the key characteristics of each basin. Ice
conditions impact most aspects of exploration and
development activities and technology, including
seismic acquisition, drilling equipment, well design,
and support feet (including oil spill response capa-
bilities). Te study team used these parameters
to develop a comparison across all Arctic basins,
including those located north of Norway and Russia,
of the technology and development challenges asso-
ciated with ice-regime impacts. Tis comparison is
summarized in Figure 1-27.
Figure 1-28 illustrates the wide range of technical
and operational challenges that are present through-
out the major global Arctic basins. Tis assessment
shows that these challenges have been met at both
the exploration and development phase.
Arctic ofshore exploration is centered in North
America and the industry has demonstrated its
ability to function through the full range of Arctic
operating conditions with more than 450 existing of-
shore wells. Experience in the Arctic spans a period
from the 1960s to the present day, and so it comes as
no surprise – though for many in the general public
it may – that industry has accomplished a wealth of
successful operating experience in diverse Arctic of-
shore conditions. Te strength of experience gained
in challenging operating environments such as in
the Canadian Beaufort Sea and the Labrador Sea
(Canada) should build confdence that industry has
the tools, procedures, and know-how to operate safely
throughout the ofshore Arctic.
Arctic ofshore production history refects the same
level of success as demonstrated through the drilling
of over 450 exploration wells. While this screening
assessment only cites major production centers such
as the Grand Banks (Canada) and Sakhalin (Russia),
there are other examples such as the Cook Inlet region
(south Alaska) and the various near-shore production
CHAPTER 1 - RESOURCES AND SUPPLY 95
1
2
3
4
5
6
7
1
2
3
4
5
6
7
CHUKCHI SEA 5 WELLS
U.S. BEAUFORT SEA 58 WELLS
CANADIAN BEAUFORT SEA 89 WELLS
CANADIAN ARCTIC ISLANDS 160 WELLS
LABRADOR 29 WELLS
GRAND BANKS 129 WELLS
SOUTHWEST GREENLAND 6 WELLS
~450 ARCTIC OFFSHORE WELLS
Figure 1-27. Wells Drilled in the Ofshore Arctic
5
58
89
160
29
129
6
Figure 1-27. Wells Drilled in the Ofshore Arctic
Figure 1-28. Ice Regime Development Comparison
BARENTS
SEA
GRAND
BANKS
SW
GREENLAND
KARA
SEA
CHUKCHI
SEA
SAKHALIN LAPTEV
SEA
LABRADOR BEAUFORT
SEA
NW
GREENLAND
NE
GREENLAND
INCREASING DEGREE OF DIFFICULTY
Notes: Signifcant levels of oil and gas production are already being produced from Arctic basins such as the Grand Banks (Canada)
and Sakhalin (Russia) in both pack ice and pack ice/iceberg operating environments.
Signifcant operating experience has been successfully gained in several of the more challenging Arctic basins (i.e., U.S. Chukchi
and Beaufort, ~35 wells in open water to pack ice; Canadian Beaufort, ~90 ofshore wells in both open water and pack ice; and
Labrador, ~30 ofshore wells in pack ice and pack ice/iceberg operating environments.
A strong history of successful exploration and production operations across a wide range of Arctic operating conditions and
challenges has demonstrated that industry can explore and develop oil and gas safely in the Arctic.
Figure 1-28. Ice Regime Development Comparison
96 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
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CHAPTER 1 - RESOURCES AND SUPPLY 97
facilities along the U.S. Beaufort Sea coastline (North-
star). Tese projects have demonstrated the ability
for industry to design production facilities in keep-
ing with the regulatory and environmental challenges
that existed in these areas, and thus allow the safe and
efcient production of oil and gas reserves from the
Arctic ofshore.
Fifty years of oil and gas development history in the
ofshore Arctic marks a period of continuous improve-
ment and development that has guided safe, success-
ful Arctic operations in all the major Arctic ofshore
ice environments. Ofshore Arctic operating capabil-
ity is a North American success story that is poorly
understood and appreciated, despite the fact that it
has been ongoing for over half a century.
Potcntial Production Pathways
Given that no overall North American Arctic sup-
ply outlooks could be found in the public domain
(although there are a few basin-specifc analyses for
portions of Alaska and the Canadian Arctic), the Arc-
tic Subgroup developed three consensus cases: Rea-
sonably Constrained, Most Likely, and Reasonably
Unconstrained (Table 1-6). Te adjective “reason-
ably” is used with care; it does not imply that all con-
straints are either turned on or turned of at either
end of the scale. Tese cases represent the Subgroup’s
informed view of what may happen to Arctic develop-
ment through 2050, given economic, regulatory, and
environmental constraints that either are less or more
favorable to such development.
Te three cases each outline a diferent production
scenario for major current or future developments.
Large, remote severely stranded resources (e.g., Cana-
dian Arctic Islands, NE Greenland Rift Basin, etc.) are
not included.
Te most likely production outlook for the Arctic
indicates a 2035 production potential of 0.77 million
barrels per day (282.5 million barrels per year). Tis
includes a normal decline of current Alaska North
Slope production to 0.28 million barrels per day,
augmented by new discoveries on the North Slope, in
the Chukchi and Beaufort Seas, and in Alaska state
waters, totaling 0.3 million barrels per day. Arctic
Canada would provide a further 0.2 million barrels
per day, split between Grand Banks production and
new discoveries in the Canadian Beaufort and Mack-
enzie Delta areas.
Te constrained case outlook assumes that new
exploration activity would not occur because of a
variety of restrictions on access and permitting,
and the only remaining production would be from
currently producing felds that will be in decline
over this period. Total remaining production in
2035 would be just 0.33 million barrels per day
(120 million barrels per year), split between the
Alaska North Slope (if the TAPS pipeline is still in
operation) and the Grand Banks area of Canada. Fur-
ther declines post-2035 would ultimately lead to the
closure of the TAPS oil pipeline as available supply
falls below the assumed operational minimum vol-
umes of about 200 thousand barrels per day. It is
Table 1-6. Three Potential Arctic Oil Production Pathways
Reasonably
Constrained Case
Most Likely Case Reasonably
Unconstrained Case
No Chukchi, Beaufort OCS,
or Canadian Beaufort production
North Alaska onshore, Chukchi
and Beaufort OCS, and Canadian
Beaufort production; 15% resource
developed by 2050
North Alaska onshore, Chukchi and
Beaufort OCS, and Canadian Beaufort
production; 25% resource developed
by 2050
Trans-Alaska Pipeline System
(TAPS) ofine 2030+/-
TAPS ~300 thousand barrels per day TAPS ~500 thousand barrels per day
Grand Banks oil current decline
only Hebron developed
Grand Banks oil slow decline
few satellites developed
Grand Banks fat oil production
No East Canada “Bafn Bay” or
West Greenland oil
No East Canada “Bafn Bay” or West
Greenland oil
East Canada “Bafn Bay” and
West Greenland oil; 10% resource
developed by 2050
98 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
estimated that this could occur around 2045, making
any subsequent development reliant on new infra-
structure.
In the upside case, with a higher level of resource
development in the new ofshore areas of the Arctic,
particularly ofshore the Alaska North Slope, total
production by 2035 could be as high as 0.88 million
barrels per day (322 million barrels per year). Half a
million barrels per day of this could come from high
potential developments in the Beaufort and Chukchi
seas.
It should be noted that the Arctic Subgroup’s oil
production forecast for Alaska may be conservative,
as compared to a published analysis by Northern Eco-
nomics that suggests the U.S. Beaufort and Chukchi
OCS regions are capable of signifcant production,
collectively exceeding 1.0 million barrels per day
(~399 million barrels per year) in 2035 (Table 1-7 and
Figures 1-29 and 1-30), if the undiscovered hydro-
carbon resource assessment reported by BOEMRE is
validated by future exploration and appraisal drilling.
Kcy Findings and Rccommcndations
Tis section summarizes the main fndings and
recommendations of the Arctic Subgroup and applies
primarily to the U.S. Arctic.
Despite its remoteness and harsh operating condi-
tions, safe development of the Arctic region is pos-
sible and essential for meeting U.S. energy goals.
Finding 1 describes the huge portion of America’s
energy that resides in the Alaskan Arctic, but explo-
ration needs to occur now in order to arrest the pro-
duction decline that could threaten viability of the
existing Trans-Alaska Pipeline for crude oil. Findings
2 and 4 note that the limiting factor in recovery of
the Arctic’s vast energy resources is not necessar-
ily technology, but rather regulatory uncertainty
and risk of litigation from groups opposing drilling
and development activity (especially in the United
States). Finding 3 describes specifc U.S. challenges
associated with carrying out an efective and safe
exploration and appraisal program in the Arctic, given
the present 10-year lease terms, since only 70–105
days (ofshore) and 70–150 days (onshore) are realis-
tically available for such activities each calendar year.
Other fndings discuss the impact of the Jones Act,
lack of infrastructure, and how the United States is
falling behind other nations.
Tis study supports the idea that action by the
U.S. federal government is warranted, if these critical
resources are to be validated and safely developed in
a prudent manner for America’s beneft. Or, to put
it in more specifc terms, the main consequence com-
mon to the majority of the following fndings and
recommendations is that the huge resource base, as
described by the U.S. Geological Survey, Bureau of
Ocean Energy Management, Regulation and Enforce-
ment, National Energy Board of Canada, Geological
Survey of Canada, and the various State and Pro-
vincial government resource agencies for the North
American Arctic region, will not be available when
needed in the 2025–2050 time frame or afterwards if
the status quo is maintained.
Finding 1: Te North American Arctic (United
States, Canada, and Greenland) has a large (world
scale) discovered undeveloped hydrocarbon resource
base (6.4 billion barrels oil, 0.9 billion barrels natu-
ral gas liquids, and 73 Tcf gas)
8
and a very large
undiscovered resource base (80.1 billion barrels oil,
11.1 billion barrels natural gas liquids, and 595 Tcf
gas).
9
Development lead times are very long (histori-
cally, 10 to 20 years or longer from discovery to frst
production).
10
Rccommcndation 1: To ensure the future energy
security of the United States, near- and medium-term
exploration drilling by industry should be promoted
by the U.S. government to validate the resource esti-
mates and identify the most promising regions.
Finding 2: Exploration and development technol-
ogy, both onshore and ofshore, is not expected to be
a limiting factor in future development of conven-
tional U.S. Arctic resources, within the time frame
of this study. Areas for further innovation and tech-
nological advances will be required in areas where
water depths exceed 100 meters or regions that
require iceberg management capability (Greenland).
8 Mean, discovered, technically recoverable volume estimate.
Tese discovered volumes are remote to existing development
and production infrastructure. References for all quoted vol-
umes cited in Sections IV, V, VI, and VII of Topic Paper #1-4,
“Arctic Oil and Gas.”
9 Mean, risked, technically recoverable, undiscovered, yet-to-fnd
volumes. References for all quoted volumes cited in Sections
IV, V, VI, and VII of the “Arctic” topic paper.
10 Tomas et al., “Alaska North Slope Oil and Gas: A Promis-
ing Future or an Area in Decline? Addendum Report,” 267 p,
U.S. DOE/NETL/Arctic Energy Ofce, April 2009. Tables 2.5
and 2.6.
CHAPTER 1 - RESOURCES AND SUPPLY 99
Table 1-7. Summary of Alaska OCS Development Scenarios and
Oil and Gas Production Forecasts
Beaufort Chukchi
North
Aleutian
Total
Resource Size (Mean)
Oil and condensates (billion barrels) 5.97 8.38 0.71 15.06
Gas (trillion cubic feet) 15.94 34.43 7.65 58.02
Exploration
Exploration/Delineation Wells 47 43 10 100
Exploration Rig Seasons 31 27 8 66
Development
No. of Ofshore Production Platforms 7 4 2 13
Ofshore/Onshore Pipelines (miles) 235 680 300 1,215
Shore Bases/Facilities
Marine Terminal Yes Yes Yes
Liquefed Natural Gas (LNG) Facility No No Yes
Production Facility Yes Yes Yes
Support Base Yes Yes Yes
Production
Year 1st Oil Flows 2019 2022 2021
Year 1st Gas Flows 2029 2036 2022
No. of Producing Fields 7 4 2 13
Total Cumulative Volume Produced (through 2057)
Oil & Gas (billion barrels of oil equivalent) 6.34 6.16 1.29 13.69
Oil & Condensates (billion barrels) 5.10 4.79 0.39 10.18
Gas (trillion cubic feet) 6.96 7.78 5.08 19.82
Daily Peak Production
Oil & Condensates (barrels per day) 1,165,707 565,472 105,074
Gas (million cubic feet per day) 883 1,421 661
Note: Northern Economics’ resource size estimates are from the 2006 Minerals Management Service Resource Assessment.
The numbers shown in the table are the mean undiscovered economically recoverable resource estimates, assuming resource
commodity prices of $60 per barrel of oil and $9.07 per thousand cubic feet of natural gas.
Source: Northern Economics in association with the Institute of Social and Economic Research, University of Alaska, Economic
Analysis of Future Ofshore Oil and Gas Development: Beaufort Sea, Chukchi Sea, and North Aleutian Basin, prepared for Shell
Exploration and Production, March 2009.
100 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-29. U.S. Beaufort Sea Outer Continental Shelf Production Forecast
0
200
400
600
800
1,000
YEAR
B
A
R
R
E
L
S
O
F
O
I
L
A
N
D
C
O
N
D
E
N
S
A
T
E
P
E
R
D
A
Y
T
H
O
U
S
A
N
D
S
0
200
400
600
800
1,000
M
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
O
F
G
A
S
P
E
R
D
A
Y
OIL AND CONDENSATE GAS
Source: Northern Economics, Inc. estimates based in part on Minerals Management Service (MMS) scenarios in Beaufort Sea Planning
Area Oil and Gas Lease Sales 186, 195, and 202: Final Environmental Impact Statement. OCS EIS/EA MMS 2003-01, February 2003.
2017 2022 2026 2030 2034 2038 2042 2046 2050 2054 2058
Figure 1-30. U.S. Chukchi Sea Outer Continental Shelf Production Forecast
0
200
400
600
2017 2022 2026 2030 2034 2038 2042 2046 2050 2054 2058
YEAR
B
A
R
R
E
L
S
O
F
O
I
L
A
N
D
C
O
N
D
E
N
S
A
T
E
P
E
R
D
A
Y
T
H
O
U
S
A
N
D
S
0
400
800
1,200
1,600
M
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
O
F
G
A
S
P
E
R
D
A
Y
Source: Northern Economics, Inc. estimates based in part on Minerals Management Service (MMS) scenarios in
Chukchi Sea Planning Area, Oil and Gas Lease Sale 193 and Seismic Surveying Activities in the Chukchi Sea:
Final Environmental Impact Statement. Volume I: Executive Summary, Sections I through VI. OCS EIS/EA MMS 2007-026.
OIL
GAS
Figure 1-29. U.S. Beaufort Sea Outer Continental Shelf Production Forecast
Figure 1-30. U.S. Chukchi Sea Outer Continental Shelf Production Forecast
CHAPTER 1 - RESOURCES AND SUPPLY 101
Tere are numerous Arctic producing felds on land
and safe development and production of ofshore
Arctic reserves has occurred globally since the late
1960s, which collectively demonstrates that resource
extraction can occur in the midst of sensitive eco-
systems. Innovation will continue as new challenges
are identifed.
Rccommcndation 2: Industry has always risen to
the challenge, and if allowed, they will continue to
advance elements of Arctic exploration and develop-
ment technology to reduce the operational footprint
and safely produce oil and gas. We recommend a
reasonable set of policies and regulations that allow
industry to continue prudent exploration and devel-
opment in the Arctic and to proceed with technology
advances. Near-term advances in ofshore pipeline
trenching will be important across the Arctic espe-
cially in prospective regions with deepwater condi-
tions (>100 meters) such as the Continental Slope
region of the Canadian Beaufort or Greenland.
Advances in iceberg management will also be impor-
tant for Greenland and portions of the Canadian
Atlantic ofshore.
Finding S: Te existing 10-year lease terms are
not long enough to ensure sustained exploration
and appraisal of material Arctic oil and gas resources
in the U.S. Arctic basins. Infrequent lease sales,
lengthy, multifaceted permitting procedures, a high
incidence of litigation and a required sequential set
of data-gathering and permitting activities coupled
with short drilling windows (onshore winter and
ofshore summer) reduce the ability to identify,
appraise, and develop economic volumes in this
short time span.
Rccommcndation S: Adopt a licensing system for
Alaska that is similar to, but improves upon, Canada
or Greenland’s system in recognition of the limited
seasonal operating period, particularly for the U.S.
federal ofshore areas (70–105 days per year). Can-
ada ofers large tracts (versus 3-square mile blocks)
with a work commitment bid that covers 9 years if a
well is drilled within the frst 5 years (still problem-
atic and should be extended given the challenges of
the Arctic and the new regulatory requirements), and
is extended indefnitely if producible hydrocarbons
are discovered on the tract. Greenland ofers similar-
sized tracts and exploration terms and is extending
the initial license term to 16 years for its NE Green-
land ofshore round that will be held in 2012.
Finding 4: Tere is no clear, dependable, regulatory
path for gaining approval of submitted exploration
or development permit applications. Tis is due to
a multitude of U.S. government agencies/regula-
tory bodies that have overlapping authority, and
each have their own independent permit review and
approval schedule.
Rccommcndation 4: Streamline regulatory per-
mitting processes and promote collaboration and
coordination of the numerous federal agencies/
regulatory bodies, to avoid redundant analyses and
jurisdictional overreach. A coordinated approach
would provide predictable project scheduling and a
more efcient use of human resources within the fed-
eral government and industry.
Finding 5: Te Merchant Marine Act of 1920 (the
Jones Act, codifed in 2006) was established to regu-
late cabotage (the coastal shipping of cargo and pas-
sengers) within the United States. Te Act requires
cabotage in U.S.-fagged, constructed, owned and
operated vessels. Te Jones Act rules on tankers
and support vessels mandate largely unavailable and
uncompetitively priced ships, unduly increasing the
cost of operations in the U.S. Arctic. Few U.S.-fagged,
ice-classed vessels are available for U.S. Arctic of-
shore operations, so either exemptions are required
to allow the use of foreign-fagged vessels that are able
to meet U.S. Arctic shipping standards, or excessive
delays and costs (three times the capital and operat-
ing expense dollars to build and operate a U.S.-fagged
feet) will be incurred to comply with this statute.
Rccommcndation 5: Continue to provide exemp-
tions to the Jones Act for the non-U.S.-fagged,
ice-class vessels used in U.S. Arctic exploration
and appraisal operations. Tis will ensure that ice-
class vessels are available at competitive rates given
the long lead times required for Arctic ofshore
operations.
Finding 6: Alaska Coastal communities only
receive tax revenue from onshore facilities related
to oil and gas development in the onshore and State
waters areas of Alaska, which leads to local opposi-
tion of OCS exploration and development in the U.S.
Arctic.
Rccommcndation 6: Te U.S. should consider a
federal revenue sharing program for the Alaska state
and local coastal governments of potentially impacted
communities, perhaps initiating a program similar in
102 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
mechanism to the Gulf of Mexico Energy Security
Act in which 37.5% of the revenue from new Gulf
of Mexico leases after 2007 is distributed to local
coastal political subdivisions.
11
Finding 7: Oil tanker transport from the Arctic to
consumer markets is currently a viable export method.
Year-round tankering of crude oil from the Arctic to
market will likely be a viable cost-efective alternative
to pipeline transport in the future. Tankering ofers
greater fexibility of evacuating crude oil from mul-
tiple onshore or ofshore development facilities than
new pipelines. Lower transport costs increase the
economic viability of projects, and therefore, increase
the production potential.
Rccommcndation 7: Prepare for this transporta-
tion option in the future. Te United States needs
to catch up with, and then expand, technological
advances, which when combined with the possibility
of more open seas later within the time frame of this
study, will provide for America’s energy needs. In the
long term, America may lose the TAPS due to dimin-
ishing fow (2030 to 2045 time frame) unless immedi-
ate eforts are made to fnd and develop more oilfelds
to stem the decline in oil production and maintain
adequate fow in the pipeline. Failure to act will result
in the loss or serious deferment of any oil potential
until well beyond the 2050 horizon.
Onshorc Oil
Dcvclopmcnt and Production: History
and Contcxt
U.S. Lower-48 Onshore
In 2010, the U.S. lower-48 onshore produced
3.1 million barrels of crude oil and condensate per day,
or about 56% of total U.S. oil production. Between
1990 and 2005, production declined at about 4% per
year. Starting about 2004, higher oil prices incen-
tivized higher levels of investment activity and pro-
duction subsequently fattened and then increased
somewhat. In some regions, enhanced oil recovery
technologies (also known as tertiary recovery or
EOR), particularly steam-injection and gas-injection,
have maintained oil production rates in mature felds
11 Bureau of Ocean Energy Management, Regulation and
Enforcement, “Gulf of Mexico Eneregy Security Act,” http://
www.boemre.gov/ofshore/GOMESARevenueSharing.htm.
at levels higher than would have otherwise occurred.
Figure 1-31 illustrates the total production trend and
contribution of EOR projects.
Te outlook for future oil production in the lower-
48 onshore region is dependent upon both primary
and EOR resource development. Expanded oil pro-
duction from oil-bearing shale and low permeability
formations, especially those not yet under develop-
ment, is critical to mitigating the general decline in
onshore production. Te development and applica-
tion of advanced EOR technologies to mature felds
enables the extension of feld economic life with mini-
mal exploration risk, adding additional supply at the
margin.
Although the onshore segment accounts for only
36% of 2010 U.S. oil production, it accounts for
only 52% of the traditional U.S. oil resource base.
Te onshore lower-48 is estimated to hold only 14%
of total U.S. undiscovered oil resources, with the
remaining 86% located in Alaska, the U.S. ofshore,
and unconventional (tight oil) reservoirs. Tese esti-
mates, summarized by region in Table 1-8, illustrate
the exploration maturity of the conventional onshore
relative to other segments of supply.
About one quarter of the onshore lower-48 resource
base consists of undiscovered oil resources, indicat-
ing that the onshore lower-48 resource base has been
largely discovered and produced. Total U.S. oil pro-
duction peaked in 1970 at 9.6 million barrels per day,
which at that time came mostly from onshore lower-
48 oil felds. Tus, future oil production in the lower-
48 onshore region will depend heavily on the degree
to which oil can be recovered from existing and aban-
doned oil felds. Further recovery of oil from these
felds will largely depend upon the economic viability
of incremental development and enhanced oil recov-
ery, which are driven by oil price, technology, and
regulatory policy.
Table 1-8 estimates do not include potentially pro-
ducible oil resources that exist below the oil-water-
contact point where a formation holds mostly oil and
a little water to a deeper layer holding mostly water
and little oil. Tese deeper zones are called “oil-to-
water transition zones” and “residual oil zones.”
Residual oil zones (ROZ) have not had a long history
of production testing at a commercial scale (nine
are in ongoing feld tests), but have physical proper-
ties similar to oil-bearing zones that have been pro-
duced through primary and secondary techniques.
CHAPTER 1 - RESOURCES AND SUPPLY 103
Conservatively, these ROZs hold tens of billions of
barrels of oil in place and provide additional targets
for recovery using EOR technology.
EOR oil production has increased as primary and sec-
ondary production has declined (Figure 1-32). In 1986,
EOR production accounted for only 10% of onshore
lower-48 oil production. From 2000 through 2008,
EOR averaged about 20% of the total. Figure 1-32 and
Table 1-9 illustrate the contribution of specifc tech-
nologies to enhanced recovery production over time.
Termal EOR has historically been the most signifcant
due to the very successful application of steam injec-
tion to the large, heavy oil felds in Southern Califor-
nia. However, thermal production continues to decline
as these reservoirs deplete. Chemical EOR has not had
widespread application to date; the felds using “other
gases” are predominantly in the Arctic and ofshore
arenas. In contrast to these technologies, production
from CO
2
EOR has steadily increased as projects have
been implemented or expanded.
Te conventional oil felds in the onshore United
States started out with about 500 billion barrels of
oil in place. After primary and secondary produc-
tion, over 300 billion barrels still remain as targets
for EOR and incremental feld development projects.
Volumes in the ROZ provide additional targets. Te
CO
2
component appears most promising for signif-
cant expansion of production from this large target,
but will require new sources of pure and afordable
carbon dioxide. Most CO
2
currently used in EOR is
from natural sources with limited growth opportu-
nities. Major volumes from man-made or anthro-
pogenic CO
2
sources would be needed to realize the
potential of this resource in a large way.
Canada
Canada onshore conventional (light/medium) oil
production, including condensates and enhanced oil
recovery production, has steadily declined in recent
years, dropping from about 1.1 million barrels per
day in the 1990s to 0.7 million barrels in 2010. Tis
accounts for about 20% of total Canadian oil pro-
duction, which is increasingly dominated by oil sand
operations. Volumes include a small amount of “tight
oil” production from extension of the Bakken play
into Canada and application of that technology in
other areas of the country. Figure 1-33 provides the
Figure 1-31. U.S. Lower-48 Onshore Oil Production, 1986–2010
0
2
4
6
1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
ENHANCED OIL RECOVERY TERTIARY
PRIMARY AND SECONDARY OIL PRODUCTION
Sources: U.S. Energy Information Administration and the Oil & Gas Journal’s Biennial Enhanced Oil Recovery surveys.
Figure 1-31. U.S. Lower-48 Onshore Oil Production, 1986–2010
104 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
recent historical trend and a projection indicating few
changes are expected in the components of this sup-
ply area.
Light/medium crude oil resources remain concen-
trated in the traditional producing provinces in west-
ern Canada with potential reserves estimated in the
range of 7 to 8 billion barrels (Table 1-10).
Past Canadian EOR production has contributed
only modestly to onshore conventional oil production.
In 2010, EOR volumes totaled about 65,000 barrels
per day, accounting for 9% of conventional onshore
production. EOR’s share, however, could grow if EOR
production either remains constant or grows and
if non-EOR conventional production continues to
decline. Production from both carbon dioxide and
chemical fooding has increased in recent years with
the Weyburn CO
2
and Pelican Lake polymer projects
making signifcant contributions. Original oil in place
for onshore conventional light/medium was about
80 billion barrels. Of this, some 50 to 60 billion
barrels are expected to remain after primary and
secondary production and provide a target for EOR
development.
Table 1-8. U.S. Technically Recoverable Oil Resources
As of January 1, 2009
(Billion Barrels)
Region
Proved
Reserves
Inferred
Reserves
Undiscovered
Resources
Total
Percent
Undiscovered
Onshore
Conventional Oil
Northeast 0.2 0.2 0.7 1.1 64%
Gulf Coast 1.5 3.1 6.5 11.0 59%
Mid-Continent 1.2 7.1 5.4 13.6 40%
Southwest 4.8 23.4 2.6 30.7 8%
Rocky Mountains 2.5 6.7 2.1 11.3 18%
West Coast 2.6 7.3 2.3 12.1 19%
Subtotal 12.7 47.6 19.5 79.9 24%
Tight & Shale Oil NA 2.5 31.6 34.1 93%
Onshore Lower-48
Subtotal
12.7 50.1 51.1 113.9 45%
Alaska &
Ofshore Lower-48
7.8 12.4 84.7 105.0 81%
U.S. Total 20.6 62.5 135.8 218.9 62%
Conventional Onshore
Lower-48 as a Percentage
of Total U.S.
62% 76% 14% 36%
Notes: NA = Not Available; shale and tight oil proved reserves are included in the regional proved reserve volumes. Crude oil
resources include lease condensates but do not include natural gas plant liquids or kerogen. Undiscovered oil resources in areas
where drilling is ofcially prohibited are not included. For example, this table does not include the Arctic National Wildlife Refuge
undiscovered oil resources of 10.4 billion barrels. Undiscovered resources in this table are “technically recoverable,” which is the
estimated volume of oil that can be produced with current technology. “Proved reserves” are those reported to the Security and
Exchange Commission as fnancial assets. “Inferred reserves” are expected to be produced from existing felds over their lifetime,
but which have not been reported as proved reserves.
Source: U.S. Energy Information Administration, Annual Energy Outlook 2011 Projections.
CHAPTER 1 - RESOURCES AND SUPPLY 105
Figure 1-32. Total U.S. Enhanced Oil Recovery Production, 1986–2010
0
200
400
600
800
1,000
1986 1990 1994 1998 2002 2006 2010
T
H
O
U
S
A
N
D
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
OTHER GASES
CARBON DIOXIDE
CHEMICAL/POLYMER
THERMAL
Sources: Oil & Gas Journal’s Biennial Enhanced Oil Recovery surveys.
Figure 1-32. Total U.S. Enhanced Oil Recovery Production, 1986–2010
Figure 1-33. 2005–2025 Canada Onshore Light/Medium Oil Production by Province, Plus Pentanes and Condensates
0
0.50
1.00
2005 2010 2015 2020 2025
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
PENTANES AND CONDENSATES
OTHER ONSHORE
SASKATCHEWAN
ALBERTA
HISTORICAL PROJECTED
Source: Canadian Association of Petroleum Producers, Canadian Crude Oil Production Forecast 2011–2025, June 2011.
Figure 1-33. 2005–2025 Canada Onshore Light/Medium Oil Production by Province,
plus Pentanes/Condensates
106 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Table 1-9. U.S. Enhanced Oil Recovery Production, 2000–2010
By Technology Category (Thousand Barrels Per Day)
EOR Technology Category 2000 2002 2004 2006 2008 2010
Thermal Injection EOR
Steam 418 366 340 287 275 273
In Situ Combustion 3 2 2 13 17 17
Hot Water 3 3 4 2 2
Total Thermal EOR 421 371 345 304 294 292
Chemical Injection EOR
Polymer/Chemicals 2 0 0 0 0 negligible*
Other negligible negligible negligible 0 0 0
Total Chemical EOR 2 negligible negligible 0 0 negligible
Gas Injection EOR
Hydrocarbon Miscible
and Immiscible
125 95 97 96 81 81
CO
2
Miscible 189 187 206 235 240 272
CO
2
Immiscible negligible negligible negligible 3 9 9
Nitrogen 15 15 15 15 20 9
Total Gas EOR 329 297 318 349 350 371
Total U.S. EOR Production 752 668 663 653 644 663
Total Onshore Lower-48
EOR Production
†
626 574 566 557 563 582
Total Onshore Lower-48
Oil Production
3,078 2,758 2,628 2,660 2,769 3,087
Total Onshore Lower-48 Oil
Production, excluding EOR
2,452 2,184 2,062 2,103 2,206 2,505
EOR Percentage of
Total Onshore Lower-48
Oil Production
‡
20% 21% 22% 21% 20% 19%
* A table entry of “negligible” indicates that the production volume was less than 0.5 thousand barrels per day.
† All hydrocarbon miscible and immiscible enhanced oil recovery (EOR) production is located either in Alaska or the
ofshore Gulf of Mexico and was subtracted from U.S. total to calculate onshore lower-48 EOR oil production.
‡ Based on Total Onshore Lower-48 EOR Production, which excludes hydrocarbon EOR production.
Sources: Oil & Gas Journal’s Biennial Enhanced Oil Recovery Project Surveys; and U.S. Energy Information Administration.
CHAPTER 1 - RESOURCES AND SUPPLY 107
Production Pathways
To develop boundaries of a supply range for con-
ventional onshore oil and enhanced oil recovery, rel-
evant technologies and issues were grouped into cat-
egories. For each of these, scenarios for limited and
high potential cases were developed. A production
profle for each pathway was developed qualitatively to
get a directional view of that boundary over the next
25 years. For the United States, production catego-
ries of primary plus secondary, CO
2
EOR, and other
EOR were considered separately, and then summed.
For Canada, conventional light oil was considered as a
total production stream made up of existing (virtually
all primary + secondary) and new CO
2
EOR. Adjust-
ments were made to exclude tight oil production as
this is addressed in the unconventional supply section.
Te factors that were considered for the high poten-
tial pathway are shown in Table 1-11. And the fac-
tors driving the limited potential case are shown in
Table 1-12.
Figure 1-34 illustrates the estimated supply
fairway for onshore conventional oil for the U.S.
Table 1-10. Canada Potential Light/Medium
Conventional Oil Resources, as of 2006
Region
Light/Medium
Crude Oil
(Billion Barrels)
Percentage
of Total
Alberta 5.7 65%
British
Columbia
0.5 6%
Saskatchewan 1.1 13%
Subtotal –
Onshore
7.3 84%
Eastern
Ofshore
1.4 16%
Total Canada 8.7 100%
Source: Natural Resources Canada, “Canada’s Energy
Outlook: The Reference Case 2006,” Ottawa, Canada, 2006,
page 35. Table US1.
Figure 1-34. Supply Fairway for North American Onshore Conventional/Enhanced Oil Recovery
0
1
2
3
4
5
2005 2010 2015 2020 2025 2030 2035
M
I
L
L
I
O
N
B
A
R
R
E
L
S
P
E
R
D
A
Y
YEAR
Note: Reference Case based on Energy Information Administration and Canadian Association of Petroleum Producers data,
reduced for estimated unconventional production.
REFERENCE CASE ACTUAL HIGH POTENTIAL PATH LIMITED POTENTIAL PATH
GAP DUE TO
UNCONVENTIONAL
ADJUSTMENT
Figure 1-34. Supply Fairway for North American Onshore Conventional/Enhanced Oil Recovery
108 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Table 1-11. Factors Considered for the High Potential Case
Technology or Issue Description
Technology (1)
y Reservoir characterization,
stimulation, and management
y Sweep efciency gains
y Downhole monitoring and hori-
zontal well diagnosis
y Technology transfer enabled
y Impacts both primary/secondary
and enhanced oil recovery
Existing tools for reservoir characterization, simulation and overall
management practices continue to be implemented, increasing project
inventory in existing felds. There is continued improvement in sweep
efciency, translating to higher oil recovery and better use of injectants such
as carbon dioxide, steam and chemicals. Gains in downhole monitoring are
made, allowing data analysis that adds to recovery process improvement.
Importantly, diagnosis of horizontal well performance improves, allowing
those wells to produce to their ultimate potential.
Public/private partnerships grow, enabling technologies to develop and be
shared among operators and resource owners. Widespread movement to
digital formats for public data continues, improving cycle time for project
screening and development. Institutions at all levels encourage job market
entrants to consider technical roles in the industry.
Technology (2)
Advanced well operations
Advanced well operations of horizontal drilling and fracturing continue
their growth throughout the United States with appropriate regulatory
intervention and minimal local opposition. Incremental technology
improvements are developed which allow additional resource plays to be
exploited prudently and economically.
Low Oil Saturation Zones Low/residual oil zones are widely recognized by industry and government
as potential targets for both hydrocarbon production and carbon storage.
State and federal geological agencies undertake systematic assessments of
low oil saturation zones that have been drilled but largely overlooked in the
past. Results from projects currently underway in the Permian Basin become
models for other areas.
Focused eforts (either public or private) to develop new alternative
technologies to CO
2
fooding in these zones progress. Mechanisms to share
these throughout the industry are in place.
Carbon Dioxide
Includes greenhouse gas, capture
costs, and legal framework
An aggressive carbon capture and sequestration (CCS) efort develops, in
which worldwide and U.S. policies are implemented, which incent capture
and storage of large CO
2
volumes. CO
2
EOR is qualifed as storage within a
clear legal and regulatory framework. Transportation issues are resolved and
a pipeline infrastructure develops; CO
2
price to oil producers is afordable.
EOR is seen as one piece of a near-term bridge to large-scale capture and
storage throughout the United States.
Economics & Policy
y Impacts to proftability
y Ability of smaller operators or
smaller felds to implement EOR/
infll
Oil prices remain strong relative to gas prices, driving operators to focus on oil
opportunities. Power, steam, and CO
2
prices remain reasonable due to lower
underlying natural gas prices.
Tax policy to encourage higher risk/cost activities is implemented to maintain
activity through price cycles. These include a revamp of the EOR tax credit
and allowances for marginal or low rate wells. Regulators in Alberta remain
cognizant of royalty rate and adjust as needed to maintain activity. Flexible
plugging regulations become widespread to avoid premature abandonment
and loss of wellbore access for improved oil projects. Solid economics drive
operators to implement projects that require more engineering work.
The Interstate Oil and Gas Compact Commission recommendations on CO
2
transportation, storage, and other regulatory items are widely adopted,
providing operators more certainty. Institutions that provide support and
knowledge to all operators continue their growth, enabling application to a
wide variety of felds and reservoirs throughout the United States.
CHAPTER 1 - RESOURCES AND SUPPLY 109
lower-48 and Canada. Te high potential case
would suggest an annual growth rate of slightly
greater than 1% over the next 25 years. Te growth
would be gradual, typical of a steady stream of
production from a diverse resource base.
Te limited potential case indicates a steady decline
in the range of 4% annually over the next 25 years. Not
dissimilar to the decline realized for much of the past
25 years, this suggests an environment of relatively
low prices and signifcant costs relative to those prices.
Table 1-12. Factors Considered for the Limited Potential Case
Technology or Issue Description
Technology (1)
y Reservoir Characterization, Stimula-
tion, and Management
y Sweep Efciency Gains
y Downhole monitoring and horizon-
tal well diagnosis
y Technology transfer enabled
y Impacts both primary/secondary and
enhanced oil recovery
There is limited use of existing reservoir management applications
combined with few new tools, meaning investment opportunities are
slow to be developed. Sweep efciency continues at status quo, so
unit costs go up, causing additional wells to be shut in. Little progress
in downhole monitoring means data analysis remains spotty; lack
of understanding of fow characteristics in horizontal wells causes
abandonment prior to full extraction of initially established reserves.
Existing public data remains in paper or legacy formats, causing long
cycle times and loss of projects. There is limited technology transfer
activity; it takes longer for new techniques to permeate industry
operations. Limited new personnel enter the industry with fewer growth
opportunities.
Technology (2)
Advanced Well Operations
Regulations around hydraulic fracturing that are restrictive rather than
progressive increase costs and delays, decreasing use. Technology
development slows with less activity and only the most prolifc
opportunities can aford the technology.
Low Oil Saturation Zones There is limited recognition or development of the potential of low oil
saturation zones and information on them is spotty and tightly held.
No alternatives to CO
2
fooding are pursued and carbon storage in these
reservoirs is not considered by policymakers.
Carbon Dioxide
Includes greenhouse gas, capture
costs, and legal framework
Worldwide and U.S. policies are implemented which discourage oil
(and coal) production and use of CO
2
injectant; existing incentives
are removed and regulations around operations (production, plant
processing and pipeline) are increased signifcantly; fees and taxes are
also increased substantially. Canadian CCS plans are shelved. This results
in new investment drying up; existing operations move to a decline
mode.
Economics & Policy
y Impacts to proftability
y Ability of smaller operators or smaller
felds to implement enhanced oil
recovery/infll
Oil prices are weak relative to gas prices, driving focus away from oil
production.
Existing tax incentives are phased out and no new incentives are added.
Additional or punitive taxes are enacted; higher risk and cost activities are
avoided by operators. Regulations requiring accelerated abandonment
come into play so numerous felds are abandoned and future advanced
recovery projects in these locations are limited.
Operators and resource owners have little incentive to pursue projects
involving higher amounts of engineering, instead funding a smaller
number of opportunities that are drilling based.
110 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Te midpoint within the range is close to cur-
rent production, suggesting potential exists for this
resource to continue as an important portion of
North American oil supply.
Kcy Convcntional Onshorc Tcchnologics
Oil feld development and production are com-
plex operations that involve application of hundreds
of technologies across many disciplines. Several of
these technologies are most likely to infuence the
supply picture through 2030, again due to their
potential impact on production from known oil accu-
mulations. Tey are contained within some broad
processes required to manage oil development and
producing operations:
y Design – Involves planning for locations, numbers,
and types of wells needed to produce and manage
the reservoir. It also involves sizing and design of
surface facilities to handle produced or injected
fuids, plus transportation and disposal of some
products. Besides project specifcations, produc-
tion expectations are developed which support
investment decisions. Within this area, rcscrvoir
charactcrization and pcrformancc simulation are
critical to establishing the initial project feasibil-
ity and subsequent management of the producing
formations.
y Implementation – Involves the installation and
feld operation of wells and equipment, includ-
ing drilling and well stimulation. Advanced well
operations (especially those involving horizontal
drilling and hydraulic fracturing) are considered
important. Technologies that reduce environ-
mental footprint and improve operational safety
are also critical to the petroleum industry’s “right-
to-operate” in sensitive locations.
y Operation and Monitoring – Te life of a produc-
ing oilfeld lasts a minimum of several years and
sometimes for a century, so efcient operating and
maintenance practices are important to maximiz-
ing recovery and economic beneft. Among myriad
activities, data from operations must be collected
and analyzed so that operational improvements
and incremental investments can be made to prof-
itably maximize production and reserves. Down-
holc monitoring, especially in complex recovery
processes or horizontal wells, is important to
success. In addition, advanced control systems that
reduce the human interface will provide increased
reliability and reduced costs.
y Recovery Process Improvement – Oilfeld develop-
ment relies on a given recovery process, be it pri-
mary production, water fooding, or an enhanced
process like carbon dioxide fooding. Technology
leading to improvcd swccp c?cicncy is critical to
maximizing production from existing operations
and in developing some of the multi-hundred bil-
lion barrel oil target remaining in existing felds or
in other low oil saturation targets.
y Application to New Resources – Because of the
natural decline of existing conventional oil produc-
tion, it is critical to fnd new resource targets to
maintain or grow production. Technologies target-
ing low oil saturation zoncs can impact supply.
More detail of these areas of technology can be
found in Topic Paper #1-5, “Onshore Conventional
Oil Including EOR,” available on the NPC website.
Because of the interest in increased use of carbon
dioxide in EOR operations, both to contribute to
incremental hydrocarbon recovery and as a sink for
storage of CO
2
, there follows a summary of the most
important aspects of this opportunity.
Carbon dioxide EOR is an established technology
used in the United States since the 1970s. A key
requirement for a carbon dioxide project is a depend-
able source of high purity and afordable CO
2
. For
this reason, most development to date has occurred
in west Texas and southeast New Mexico, where can-
didate oil felds and naturally occurring CO
2
source
felds are close enough to provide CO
2
at a reason-
able cost. In other locations, a few projects have been
implemented where a candidate oilfeld was close to
a relatively pure industrial source, where man-made
(anthropogenic) carbon dioxide is captured for EOR
use.
In the United States, most opportunities for using
naturally occurring CO
2
are already exploited, leaving
growth potential primarily to be met from anthropo-
genic CO
2
sources. Te most likely projects are those
where a relatively pure CO
2
source already exists,
since capture and transport are cost efective. Sepa-
ration of CO
2
from natural gas is a good example of
this. Certain industries, including cement, ammonia,
lime, iron, and steel also produce relatively pure CO
2
CHAPTER 1 - RESOURCES AND SUPPLY 111
streams as a byproduct. Over time, CO
2
from addi-
tional gas processing and certain other sources is
expected to be used in EOR applications.
Te category of CO
2
supply with the most volume
potential is the most challenging. Tese are projects
where carbon dioxide is captured from dilute streams,
typically large point source fue gas emissions at
power plants. Since this category will require a
substantial amount of fscal and regulatory support,
use will ultimately depend on U.S. and Canadian pol-
icy decisions. To be viable, the price of delivered CO
2
would have to be at a level where investments in EOR
projects ofer adequate returns. As CO
2
prices are
negotiated between sellers and purchasers in various
contractual arrangements, the price can vary widely
based on location, contract vintage, etc. However,
minimum prices discussed for CO
2
into EOR are usu-
ally less than $1 per Mcf ($10 to $15 per metric ton)
and maximum prices are typically in the range of
$2 to $3 per Mcf ($40 to $60 per metric ton). With
expected costs of capture and transport from dilute
sources well above this level, policies that provide
fnancial support to reduce delivered CO
2
pricing
would be required for a viable supply to use in EOR
applications.
Kcy Convcntional Onshorc Findings
and Implications
Finding 1: Industry reacts quickly to viable eco-
nomic returns on investment in conventional
onshore and EOR opportunities, and production
increases often follow. This ability to respond
requires consistent, stable regulation. Longer-term
investments requiring large capital infrastructure
are especially sensitive to stable policy. Sustained,
incremental improvements in technology, regula-
tions, and EOR injectant supply would stem the
historical decline and contribute large volumes over
time as gains compound annually.
y In the mid-2000s, higher activity resulted in
approximately 1.0 million barrels of oil per day
of increased conventional oil production in the
onshore U.S. It was triggered by strong prices,
incremental technology advances, and regulatory
certainty. Tis production resulted largely from
projects targeting developed felds and known
resources.
y Tis represents the activity of thousands of
operators over several hundred thousand pro-
ducing wells, operating in areas with existing
infrastructure. Activity increases or decreases with
proftability measures and is enabled by a high level
of regulatory predictability and certainty.
Te timing of production impact varies depending
upon the type of activity. Development drilling or
well enhancement can add volumes within a few
months; development of an EOR project may not
add volumes until several years after project ini-
tiation. In uncertain policy or price environments,
short-term resource investments are favored over
long-term EOR projects.
Rccommcndation 1: Some recommended areas
for consideration are as follows:
y Direct Financial Support or Investment
? Implement tax credit program for low volume
wells to improve ultimate recovery and retain
felds and infrastructure for potential future EOR
projects.
? Review/enhance the federal EOR tax credit
to make it more relevant in the current price
environment; consider simplifcation of calcula-
tions.
y Support, Technology, or Institutional Programs
? Support of organizations that disseminate
best practices or technology applications (e.g.,
Research Partnership to Secure Energy for
America and the Petroleum Technology Transfer
Council).
Finding 2: Production from enhanced oil recov-
ery projects, specifcally those relying on carbon
dioxide (CO
2
) injection, is a critical source of long-
term future production from lower-48 onshore con-
ventional resources. State and federal policies will
determine whether this supply stream declines,
has healthy incremental growth or reaches new
plateaus.
Te production wedge from CO
2
EOR is one of the
largest variables in conventional oil production pro-
jections, with estimates ranging from 0.3 to over
2.0 million barrels of oil per day by 2030.
y Because new feld discoveries are now smaller and
generally decline faster, EOR projects provide very
stable, long-term sources of oil reserves.
112 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Te resource target for all EOR is estimated at sev-
eral hundred billion barrels, though this number is
very dependent on oil price, CO
2
price and availabil-
ity, and specifc feld and wellbore conditions.
y EOR projects often have high fxed and variable
costs, making EOR production the “marginal bar-
rel” in many markets, often just below prevailing oil
price expectations.
y A reliable, afordable, and growing supply of carbon
dioxide will be a key determinant of future EOR
production.
y Skills needed to design and operate EOR projects
are not always readily available and many operators
do not have experience in EOR.
y For some felds, there is a limited window of
opportunity to implement EOR projects due to
aging infrastructure and rapidly declining pro-
duction volumes over which to spread fxed costs.
Delays in development could mean loss of poten-
tial reserves, with ultimate impacts dependent on
the regulatory environment, available technology
and economics.
y Tere are a number of areas where additional regu-
lations and policy actions would negatively afect
EOR production. Following are some examples of
areas where progressive regulations may infuence
future oil supply.
Rccommcndation 2: Some recommended areas for
consideration are as follows:
y Proactive Regulation
? Ensure fexible well plugging rules exist to avoid
premature abandonment of candidate oil felds.
? Provide regulatory certainty for well design/
construction standards, re-abandonment of
existing wells, CO
2
capture/storage credits,
generation and use of greenhouse gas ofsets
and CO
2
pipeline permitting. Maintain class II
well design where it is initially injected for EOR
purposes.
? Develop a clear regulatory framework for con-
verting an initial EOR project into a CCS project
that can claim fnancial or emission allowance in-
centives.
? Codify long-term liability rules for CO
2
stored in
reservoir after EOR.
y Current Practices Afrmed
? New regulations around the handling and use of
carbon dioxide are limited. Example: new rules
from the Environmental Protection Agency
regarding CO
2
as “hazardous.”
? Te regulatory framework in states with existing
CO
2
operations are exported to new areas.
Example: CO
2
pipelines – no need to reinvent the
wheel.
? Projects that incidentally store CO
2
should not
be harmed by new regulations targeting storage
projects pursued for fnancial purposes.
y Direct Financial Support or Investment
? Support conversion of public oil and gas data
from paper/flm legacy systems to digital format
to improve project development capability and
efciencies.
? Tax policy to incentivize new computer hardware/
software, because EOR projects are complex and
require a great deal of additional engineering and
geologic characterization and often require an
upgrade to a company’s information technology
hardware to evaluate the subsurface potential.
? Rapid amortization for site characterization or
other front end costs.
? Review/enhance the federal EOR tax credit to
make it more relevant in the current price envi-
ronment; consider simplifcation of calculations.
y Support, Technology, or Institutional Programs
? Support of research in the areas of reservoir
characterization, reservoir modeling and sweep
efciency improvement. Consider public/
private partnerships (e.g., Research Partnership
to Secure Energy for America) to provide
appropriate prioritization of topics.
Finding S: A large increase in CO
2
supply from
dilute anthropogenic sources will be required over
the next 10 to 15 years to extend EOR production
levels. The complex factors affecting this supply
include carbon capture and sequestration (CCS)
deployment, involving substantial government fscal
and policy action.
y Estimates of oil supply resulting from projects
using dilute CO
2
sources range up to more than two
million barrels of oil per day.
CHAPTER 1 - RESOURCES AND SUPPLY 113
y Te cost of CO
2
from dilute sources is dominated by
high capture costs; support will be required to build
demonstration projects for supply and as test sites
for technology evolution.
y Lack of signifcant progress in CCS projects appears
to be a function of low economic returns available to
those who would deploy the technology. Costs need
to decrease substantially to create market interest,
which may require step-changes in technology.
y EOR is compatible with CCS should it move for-
ward; EOR projects are seen as a win-win for those
advocating early adoption of CCS.
y Permanent carbon sequestration during EOR will
be part of the justifcation for these projects; the
legal framework to delineate post-closure liability
must be put in place. Additional considerations
include pore space ownership, new well design
standards, and potential re-abandonment of exist-
ing wells. Tese issues are already well discussed
among various government agencies and industry
groups. State support is important even if fnan-
cial incentives are small; it helps to provide greater
regulatory certainty and remove barriers that arise
in any new project development.
y Canada may be ahead of the United States in this
area with a combination of policy and funding.
Rccommcndation S: Some recommended areas for
consideration are as follows:
y Proactive Regulation
? A program is implemented which incentivizes
emission reductions while recognizing CO
2
EOR
as a CCS option.
? Framework and regulations are developed that
allow operators to understand and manage
post-closure liability from the outset of project
conceptualization.
? States without clear processes regarding CO
2
EOR
use Interstate Oil and Gas Compact Commission
guidance or another source to develop needed
regulations; don’t reinvent the wheel.
? Comprehensive Environmental Response,
Compensation, and Liability Act/Resource
Conservation and Recovery Act exemptions for
storage in qualifed sites.
? Price premium for low-carbon power, akin to
“renewable” pricing, or “credit” for CO
2
storage via
EOR. Ability to generate ofsets for CO
2
captured
from sources outside regulatory jurisdiction.
y Current Practices Afrmed
? New rules do not hinder projects that are
operating or in permitting phase.
? CO
2
transportation regulations, currently under
discussion for CCS are not onerous for EOR users.
? Maintain a fexible approach that allows both
common-carrier and private CO
2
pipeline models.
? Avoid considering CO
2
a pollutant; reinforce with
regulators that CO
2
is not hazardous, and is not
corrosive in the absence of free water and with
proper metallurgy.
y Direct Financial Support or Investment
? Direct investment or funding of carbon capture
and EOR+Storage projects for demonstration
purposes.
Express backstop of long-term liabilities arising
from storage may be necessary, including trust fund
models.
Enhanced tax credits for CO
2
EOR+Storage proj-
ects with exemptions from liability under Alternative
Minimum Tax provisions.
y Support, Technology, or Institutional Programs
? Increased funding for National Energy Tech-
nology Laboratory Carbon Sequestration Part-
nerships.
Finding 4: Substantial petroleum resources occur
naturally or remain after primary and secondary
recovery in low oil saturation zones. Increased under-
standing of these zones is necessary for extensive
development, whether by carbon dioxide fooding or
another technology.
y A sizable portion of the 300+ billion barrels
expected to remain unrecovered in existing oilfelds
are in zones of low oil saturation.
y Tere are additional low oil saturation zones (often
referred to as residual oil zones or ROZ) that occur
naturally. Tese are not well characterized, but are
estimated to hold at least 80 billion barrels. Tese
zones provide a new set of targets in addition to
already produced or developed felds.
114 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
y Carbon dioxide fooding is the only applicable pro-
cess currently deployed on a commercial scale to
recover these resources. As such, the new target
zones ofer additional storage potential should CCS
advance.
y Technology development and demonstration in
these zones will be focused in areas with existing
infrastructure and CO
2
supply options.
y At this point, no non-CO
2
alternative EOR process
has been developed capable of supporting substan-
tial commercial ROZ development. Water foods
that include chemical additives seem to have the
greatest application and promise.
Rccommcndation 4: Some recommended areas for
consideration are as follows:
y Proactive Regulation
? Ensure fexible well plugging rules exist to avoid
premature abandonment of candidate oil felds.
y Direct Financial Support or Investment
Consider separate tax credit to incent ROZ devel-
opment.
y Support, Technology, or Institutional Programs
? Support work to describe the ROZ resources
at various levels, including state agencies,
universities, U.S. Department of Energy, Research
Partnership to Secure Energy for America, and
the U.S. Geological Survey.
? Support open access research in alternative re-
covery processes, focusing on chemical fooding.
Need both basic and applied research.
Finding 5: Horizontal drilling and advanced
hydraulic fracturing technologies are important to
developing opportunities in the conventional oil
area much as they are in unconventional oil and
onshore gas development. Techniques to monitor and
understand horizontal well performance will improve
as these wells proliferate.
y Tese technologies ofer new tools to proftably
develop conventional oil and EOR reservoirs. Tey
also allow new hydrocarbon targets to be devel-
oped, that were previously thought unproducible or
uneconomic.
y Horizontal wells accounted for more than 50% of
wells drilled in the United States during 2010.
y Given the increasing reliance on horizontal wells
for reserve development, it will be critical to
understand fuid fow in a given well to optimize
production and maximize reserves and recovery
efciencies.
y Horizontal drilling and hydraulic fracturing tech-
nologies depend on materials that may be in short
supply or are used extensively in other industries.
Rccommcndation 5: Some recommended areas for
consideration are as follows:
y Current Practices Afrmed
? New regulation on hydraulic fracturing should
endeavor to maintain current regulatory efec-
tiveness to avoid loss of opportunities.
? Maintain ability to comingle multiple formations
where conservation principles are not compro-
mised.
y Support, Technology, or Institutional Programs
? Support research in the areas of downhole moni-
toring of wells, especially horizontals and those
used in EOR.
? Working group of industry and government to
identify potential material shortages and actions
to mitigate impact.
Unconvcntional Oil
Dcvclopmcnt and Production History
and Contcxt
In this study, unconventional oil includes Canadian
oil sands, Canadian heavy oil, and U.S. and Canadian
tight oil, all currently producing signifcant quantities
of oil, and potential future unconventional resources
in U.S. oil shale and U.S. oil sands, not yet currently
contributing production. Tese resources are located
in the onshore arenas of U.S. and Canada, but are dis-
tinguished from the conventional oil discussed in the
previous section by diferent hydrocarbon characteris-
tics, geologic occurrences, and production techniques.
Te extra heavy oils (also referred to as bitumen)
are extremely viscous – sometimes nearly solid. Tey
often contain high concentrations of sulfur and metals
such as nickel and vanadium. Tese properties make
them difcult to produce and process. Massive accu-
mulations exist in the Canadian oil sands of Alberta
and in smaller accumulations in the United States.
CHAPTER 1 - RESOURCES AND SUPPLY 115
However, not all unconventional oils are heavy. A
growing source of unconventional supply is tight oil
– produced from low-permeability siltstones, sand-
stones, and carbonates. Te produced oil has similar
properties (e.g., density, sulfur content) as conven-
tional oil. Historically, the oil was locked in the for-
mations and could not fow through the tight forma-
tion rock. However, recent advances in horizontal
drilling and well fracturing technologies now enable
production of tight oil. Notable plays include the Bak-
ken (spanning Saskatchewan, Manitoba, Montana,
and North Dakota), the Eagle Ford play in Texas, the
Cardium play in Alberta, and the Miocene Monterey
play in California. For the largest tight oil play, the
Bakken, the produced oil is sweet and light, and only
the geology and oil extraction techniques are uncon-
ventional.
Unconventional oil is also contained in U.S. oil shale
deposits. Te petroleum component of the oil shale
(kerogen) is less mature, not yet fully transformed
into oil or natural gas. Terefore, unlike conventional
oil and gas operations, kerogen in oil shale cannot be
pumped directly from the ground or refned with tra-
ditional techniques. Rather, oil shale must be heated
to high temperatures to transform the kerogen into
an upgraded hydrocarbon.
In these categories, oil in place is estimated at more
than 3.5 trillion barrels. However, the reserves, or
the amount of oil that can be economically produced,
make up approximately 5% of this total (Table 1-13).
Even though the recoverable oil is a small part of total
oil, it is still signifcant.
In terms of production, unconventional oil supply
in North America has been growing – reaching 2 mil-
lion barrels per day in 2009 or equivalent to about
10% of crude oil processed in U.S. refneries.
Te following sections discuss each of the main
components of current and future unconventional oil
supply in North America.
Canadian Oil Sands
History and Context
Canada’s oil sands are one of the world’s largest
hydrocarbon accumulations (see map, Figure 1-35).
Located in the Province of Alberta, they are semi-
liquid hydrocarbons with gravity of 10
o
API or less.
In 2009, the Alberta Energy Resources Conserva-
tion Board (ERCB) estimated the initial volume of oil
in place of crude bitumen in Alberta’s oil sands as
1,804 billion barrels. Te ERCB reported that 7% of the
oil in place, 131 billion barrels, is contained in shallow
deposits, generally less than 215 feet to the top of the
oil sands zone. All of the shallow oil sands (amenable
to surface mining) are located in the Athabasca oil
sands area. Surface mining and bitumen extraction
technologies are used to recover crude bitumen from
these shallow deposits. Te remaining 93% of the oil
in place, 1,673 billion barrels, is contained in deeper
deposits. In situ recovery techniques are used to
recover crude bitumen from the deeper deposits.
Te ERCB estimated approximately 10% of the oil in
place is recoverable with about 22% of the recover-
able volume located in shallow deposits that will be
Table 1-13. Size of North American Unconventional Oil Resources
(Billion Barrels)
Oil in Place
Resources
(Includes Reserves)
Ultimate Potential
U.S. Oil Shale
(Green River formation only)
1,500 0 800
Canadian Oil Sands 1,804 169.8 (Reserves) 308
Canadian Heavy Oil 35 1 N/A
U.S. Oil Sands 63 0 N/A
Tight Oil N/A 5.5 to 10 (Resources) N/A
Total Greater than 3,500 Greater than 177 Greater than 1,100
116 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
developed using surface mining and 78% located in
deeper deposits that will be developed using in situ
recovery.
To year-end 2009, about 4% of the initial estab-
lished reserves had been produced with about 65%
produced using surface mining and 35% produced
using in situ recovery.
Te ERCB estimates the ultimate potential of crude
bitumen recoverable by in situ recovery methods
from Cretaceous sediments to be about 210 billion
barrels and from Paleozoic carbonate sediments at
about 37 billion barrels. Nearly 70 billion barrels is
expected from within the surface-mineable bound-
ary. Te total ultimate potential of crude bitumen is,
therefore, about 315 billion barrels, of which 7 billion
barrels has been produced, leaving 308 billion barrels
remaining.
As of 2009, oil sands production has reached
1.49 million barrels per day of crude bitumen,
826 thousand barrels per day from surface mining,
and 664 thousand barrels per day from in situ proj-
ects. In 2009, the oil sands industry represented
approximately 50% of Canada’s total oil production.
Historical bitumen production over the last 15
years is illustrated in Figure 1-36.
To remove contaminants and improve the value
of oil sands crude, a large portion of Alberta’s bitu-
men production is upgraded to synthetic crude oil
(SCO) and other products before shipment to mar-
ket. After upgrading, supply of SCO (including other
products) and non-upgraded crude bitumen totaled
1.34 million barrels per day in 2009 (766 thousand
barrels per day of SCO and 570 thousand barrels per
day of non-upgraded crude bitumen). Te 2010 pro-
duction was 1.47 million (660 thousand barrels per
day of SCO and 810 barrels per day of non-upgraded
crude bitumen).
Key Development and Production
Technologies
Te hydrocarbon component of the oil sands, crude
bitumen, must be separated from sand, other mineral
materials, and formation water before it is delivered
to downstream upgraders or refneries. Shallow oil
sands deposits, generally less than about 215 feet to
the top of the oil sands zone, are usually exploited
Figure 1-35. Alberta’s Oil Sands Areas
UNITED STATES
A
LB
ER
TA
Source: IHS Cambridge Energy Research Associates, ©2009.
THE MINEABLE OIL SANDS REGION IS
SLIGHTLY SMALLER THAN THE STATE
OF RHODE ISLAND.
THE ENTIRE OIL SANDS
REGION PEACE RIVER, ATHABASCA,
AND COLD LAKE IS ROUGHLY THE
SIZE OF THE STATE OF NEW YORK.
THE PROVINCE OF ALBERTA IS
SIMILAR IN SIZE TO THE STATE OF TEXAS.
IN SITU
MAJOR OIL SANDS PROJECTS
MINEABLE REGION
MINING
PEACE
RIVER
FORT
MCMURRAY
COLD LAKE
OIL
SANDS
AREA
CANADA
Note: Comparisons to U.S. states are to the total areas
of the states, including land and water.
Figure 1-35. Alberta’s Oil Sands Areas
CHAPTER 1 - RESOURCES AND SUPPLY 117
using surface mining to recover ore-grade oil sands,
then delivered to an extraction plant for separation
of bitumen from the sand, other minerals, and water.
Deep oil sands, greater than about 215 feet to the top
of the oil sands zone, are exploited using in situ recov-
ery techniques, whereby the bitumen is separated
from the sand in situ and produced to the surface
through wells.
Established oil sands mining and extraction tech-
nologies are based on truck and shovel mining tech-
niques. Trucks capable of hauling up to 400 tons of
material are loaded by electric- and hydraulic-power
shovels with bucket capacities up to 58 cubic yards. Te
trucks transport oil sands ore to preparation facilities
where it is crushed and prepared for transport to an
extraction plant (where bitumen is separated from the
sand). Te ore is mixed with water to create slurry that
can be pumped to the extraction plant (this method is
known as “hydrotransport”). At the extraction plant,
bitumen is separated from the sand, water, and other
minerals using a hot water extraction process.
Developing oil sands mining and production pro-
cesses to improve recovery performance, reduce envi-
ronmental impact, and reduce costs include the fol-
lowing:
y Mine-face crushing and slurry preparation to elimi-
nate the use of heavy-hauler trucks
y Counter Current Drum Separator extraction pro-
cess (Bitmin process), developed to replace hot
water extraction and produce relatively dry tailings
sand
y Mine-face extraction, a process that uses cyclones
to separate bitumen from the sand at the mine face.
Established in situ bitumen recovery technologies
have been developed to deal with the heavy, viscous
nature of the bitumen, which means that it will not
fow under normal reservoir temperature conditions.
For recovery of bitumen from deep deposits, viscos-
ity must be reduced in situ to increase the mobility of
bitumen in the reservoir. Tis enables fow to well-
bores that bring bitumen to the surface. Bitumen
viscosity can be reduced in situ by injecting steam to
increase reservoir temperature, injecting solvents,
injecting air, or using electric heating. Steam-based
thermal recovery is the dominant recovery technique
Figure 1-36. Canadian Bitumen Production, 1998–2009
0
20
40
60
80
0
400
800
1,200
1,600
1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009
IN SITU PRODUCTION
SURFACE MINING PRODUCTION
PERCENTAGE MINED
T
H
O
U
S
A
N
D
B
A
R
R
E
L
S
P
E
R
D
A
Y
P
E
R
C
E
N
T
A
G
E
O
F
B
I
T
U
M
E
N
P
R
O
D
U
C
E
D
B
Y
M
I
N
I
N
G
YEAR
Source: Alberta Energy Resources Conservation Board (ERCB).
Figure 1-36. Canadian Bitumen Production, 1998–2009
118 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
used at Athabasca, Cold Lake, and Peace River. Te
industry also conducts feld tests of other in situ
recovery methods including solvent-based recov-
ery, co-injection of steam and solvents, co-injection
of steam and non-condensing hydrocarbons, in situ
combustion and electric heating. Compared to sur-
face mining, in situ bitumen production does not
produce tailings that require disposal, requires less
water due to higher recycle rates, and has a smaller
surface footprint.
Primary recovery or “cold production” occurs where
bitumen can fow under normal reservoir conditions
without additional stimulation. Tis approach has
been used successfully in the Wabasca area of Atha-
basca and in the Peace River Oil Sands Area. Second-
ary recovery, where production is stimulated by water
or polymer injection, has been used successfully in the
Wabasca area.
Most in situ bitumen production has been enabled
using steam-based thermal recovery techniques, such
as cyclic steam stimulation or steam-assisted gravity
drainage (SAGD). Tese techniques, developed since
the 1980s and 1990s, are now well established, and
play a signifcant role in overall expansion of oil sands
production.
In addition to improvements to these existing tech-
nologies, new in situ recovery processes are being
developed to reduce energy requirements, reduce
water use, lower costs, improve recovery factors, and
reduce environmental impacts. Tese include:
y Hybrid steam-solvent processes
y Solvent only processes
y In situ combustion
y Electric heating.
Production Potential
Development potential of productive capacity to
2035 and beyond has been reviewed by examining
industry’s historical success in growing production,
known plans for new development and expansion of
existing projects, and the expected contribution of
new areas and new technologies. We have developed a
most likely case, a constrained case, and a reasonably
unconstrained case. As stated earlier, the Canadian
oil sands industry is well established. Large-scale
commercial production began more than 40 years ago.
In 2009, production reached 1.34 million barrels per
day, and by 2015 productive capacity is projected to
approach about two million barrels per day. Several
new projects have recently come on stream, several
are under construction, and many more are proposed.
As of early 2011, industry had proposed projects rep-
resenting about 7.7 million barrels per day of new
bitumen productive capacity.
Based on our review of available resources, the sta-
tus of the industry, and the challenges it faces, it is
our view that the Canadian oil sands industry has the
high potential to provide up to 6 million barrels per
day of SCO and raw non-upgraded bitumen supply by
2035. Tis high case assumes a concerted efort by
Canada and the United States to address challenges
associated with unconventional oil development in
general and oil sands in particular (e.g., energy and
water intensity, tailings reduction and remediation,
export capacity, and other constraints).
Te most likely case we have examined would see oil
sands output grow to around 4.5 million barrels per
day by 2035. Tis assumes that:
y Supply continues to be driven by market demand
y Te current Canada/U.S. free-trade relationship
remains
y Oil prices remain sufcient to justify new project
investments
y Sufcient pipeline transportation capacity is built
to move products to market
y Public acceptance of oil sands development is main-
tained by continual environmental performance
improvements
y At this growth level, no undue restrictions are
expected on capital availability, availability of engi-
neering services, skilled labor supply, or material
and equipment supply.
A constrained case would see oil sands growing
only to about 3 million barrels per day by 2035.
Tis case assumes governments implement stron-
ger clean energy policies that create additional chal-
lenges for oil sands developments. Strong policies
to limit greenhouse gas (GHG) emissions encour-
age expansion of alternative forms of energy, while
regulatory oversight of oil sands tightens further,
particularly to address the impacts of oil sands
development on air and water quality and land use.
Te intersection of increasing costs and declining oil
demand and oil prices (lower oil demand stems from
CHAPTER 1 - RESOURCES AND SUPPLY 119
government clean energy policies) raises economic
hurdles and deters signifcant oil sands develop-
ments after 2020.
Canadian Hcavy Oil
History and Context
Most Canadian conventional heavy oil comes from
a region termed the “heavy oil belt.” Te heavy oil belt
straddles the border of Alberta and Saskatchewan, just
south of the oil sands Cold Lake region. Generally,
heavy oil projects north of township 53 in Alberta are
classifed as oil sands and projects south are classifed
as conventional heavy oil. In Saskatchewan, all heavy
oil production (including production north of the
Alberta cutof) is categorized as conventional heavy
oil. Because of the technological and geographic over-
lap between bitumen produced from in situ oil sands
and Canadian conventional heavy crude, Canadian
conventional heavy oil is included within the uncon-
ventional oil category of this study. Alberta defnes
heavy oil as all oil under 25.7
o
API south of township
53, while Saskatchewan production data use a cutof
of under 20
o
API for heavy oil.
In 2009, production of Canadian conventional
heavy oil was 382 thousand barrels per day with pro-
duction in decline (5% per year on average over the
past 5 years). Combined production from Alberta and
Saskatchewan peaked in 1997. Recent declines are
attributed to the maturity of “easy” oil and the shift
in industry focus towards oil sands (Figure 1-37).
Key Development and Production
Technologies
Today, heavy oil uses similar production technolo-
gies as in situ oil sands, such as:
y Cold heavy oil production with sand (CHOPS) –
Recovery factors range from 3% to as high as 12%.
y Horizontal well technologies – Typically applied
to areas of the heavy oil belt with lighter gravity
crudes, similar recoveries to CHOPS.
y Secondary recovery – Water and polymer fooding
are used in lower viscosity reservoirs.
y Termal (cyclic steam stimulation and steam drive)
– Oil recovery has reached 60%.
Figure 1-37. Canadian Heavy Oil Production, 1988–2009
0
100
200
300
1988 1991 1994 1997 2000 2003 2006 2009
ALBERTA HEAVY OIL
SASKATCHEWAN HEAVY OIL
YEAR
D
A
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A
Y
Note: Alberta production heavy oil includes all oil under 25.7 API, while Saskatchewan production data is all production
under 20
o
API cutof for heavy oil.
Sources: Alberta Energy Resources Conservation Board (ERCB) and Saskatchewan Ministry of Energy and Resources.
Figure 1-37. Canadian Heavy Oil Production, 1988–2009
120 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
commonly known as “oil shales,” which refers to oil or
kerogen rich shales that are either heated in situ and
produced or if surface accessible mined and retorted.
Te most notable tight oil plays in North America
include the Bakken play in the Williston Basin, the
Eagle Ford play in Texas, the Cardium play in Alberta,
and the Miocene Monterey play of California’s San
Joaquin Basin (see map, Figure 1-38). Starting in
the mid-2000s, advances in well drilling and stimula-
tion technologies combined with high oil prices have
turned tight oil resources into one of the most actively
explored and produced targets in North America.
In terms of oil resources the tight oil plays are signif-
icant. Total estimated resources of the tight oil plays
identifed by this report range from 6 to 34 billion
barrels, and are based on reports for both producing
and prospective tight oil plays. It is likely that this
estimate signifcantly underestimates the amount
of recoverable oil when new tight oil techniques are
applied to these deposits. Te NPC Resource and
Supply Data survey, analyzing a wide set of studies
and private industry outlooks, provided the high
side estimate of 34 billion barrels.
Among the producing tight oil plays, the Bakken
play is currently considered the largest, with esti-
mates of recoverable resources or resources ranging
from 3.65 billion barrels of oil to 4.3 billion barrels.
With respect to the prospective tight oil resources,
it has been calculated that the Tuscaloosa Marine
Shale play of central Louisiana and southern Missis-
sippi may hold resources of 7.0 billion barrels.
According to the North Dakota Department of
Mineral Resources–Oil and Gas Division, production
from the Bakken Formation in North Dakota has
increased from approximately 20 thousand barrels
per day in 2007 to more than 220 thousand barrels
per day in 2010. From the information available at
the time of this study, the Bakken accounts for most
of the current tight oil production, almost 350 thou-
sand barrels per day including U.S. and Canadian
production. However, recent development within
the Niobrara and Eagle Ford plays suggest that their
productivity may be comparable to that of the Bakken
within a few years.
Key Development and Production Technologies
Horizontal drilling technology, combined with
advances in well completion and hydraulic fracture
stimulation methods, has opened up domestic tight
Similar to in situ oil sands, new methods have been
developed and applied to improve recovery factors
and extend the life of these resources. Tese technol-
ogies include:
y Termal steam-assisted gravity drainage (SAGD)
y Hybrid steam/solvent and solvent only processes
y In situ combustion
y Enhanced cold fow recovery.
Production Potential
By 2035, we estimate Canadian heavy oil produc-
ing in a range of 135 thousand barrels per day (con-
strained case) up to 350 thousand barrels per day
(relatively unconstrained case).
Te most likely, or expected, case is for 2035 pro-
duction of 250 thousand barrels per day, assuming
an ongoing 4% decline per year to 2035 for cold fow
production. Te amount of production using steam
method increases from about 30 thousand barrels per
day currently to 130 thousand barrels per day. Fur-
ther steam injection projects are limited as few por-
tions of the resource are thick enough to apply steam
methods.
Te high, or reasonably unconstrained, case is for
2035 production of 350 thousand barrels per day,
with technological innovation enabling upside from
the expected case. Between 2025 and 2035 success-
ful and economic pilots of both combustion and heavy
EOR) with gas reinjection could be demonstrated in
the heavy oil belt. By 2035, these two innovations
would add another 100 thousand barrels per day to
production.
Te low, or constrained, case is for 2035 production
of 135 thousand barrels per day, assuming an ongo-
ing 4% decline per year to 2035 for cold fow produc-
tion. Te amount of production from thermal meth-
ods does not increase substantially, as new thermal
projects are limited to the more economic oil sands
deposits to the north.
Tight Oil
History and Context
Te term “tight oil” refers to crude oil or conden-
sate found in sedimentary rock formations character-
ized by very low permeability. Tis resource should
not be (but often is) confused with resources that are
CHAPTER 1 - RESOURCES AND SUPPLY 121
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122 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
development of more known plays, could result in a
50% increase in the 2035 estimate, to 3 million bar-
rels per day from this resource type.
In a constrained development case, production
and development could be limited by restrictions on
hydraulic fracturing by state and federal regulatory
agencies; limited availability of water for hydraulic
fracturing; or changes in the tax rules for oil explora-
tion and production activities that reduce the fnan-
cial incentive to produce tight oil resources. Tese
types of constraints could limit production from tight
oil in 2035 to around 600 thousand barrels per day.
U.S. Oil Shalc
History and Context
Oil shale consists of rock and a solid organic sedi-
ment called kerogen. Tis naturally occurring source
of hydrocarbon has not yet undergone the full trans-
formation to oil and gas by heat and pressure over
long periods of geologic time, creating a unique devel-
opment and production challenge.
Oil shale represents one of the world’s largest
unconventional hydrocarbon deposits with an esti-
mated 8 trillion barrels of oil in place. Approximately
6 trillion barrels of oil in place is located in the United
States, with the most concentrated deposits found
in the Green River Formation in Colorado, Utah, and
Wyoming. Tis formation contains about 1.5 trillion
barrels of oil in place. About 80% of this resource lies
under U.S. federal lands.
Tere is a limited history of oil shale production in
the United States, dating back to the 1970s and early
1980s, following the Arab oil embargoes. When oil
prices fell in the 1980s, oil shale production activi-
ties were halted although research into development
and production technologies continued. Tis includes
eforts by the U.S. federal government, which awarded
six research, development and demonstration (RD&D)
leases in Colorado and Utah in 2006 and ofered more
leases in 2009. In addition, companies, like Shell,
have undertaken oil shale development research proj-
ects on private land.
Because of the long time cycle and high capital
requirements of an oil shale project, broad and con-
sistent government support would be required to
develop a commercial oil shale industry. Support-
ive government policy and regulatory certainty are
oil production in North America. Te successful pro-
duction of tight oil relies on a detailed understanding
of potential pathways to unlock hydrocarbons from
low permeability and low porosity formations that
may contain natural fracture networks. Application
of specifc technologies and drilling strategies, espe-
cially with respect to well completion and stimulation
techniques, almost certainly difers from play to play,
and often even within a play.
Te Bakken play is an example of this. Te exploita-
tion approach for the Bakken evolved from early verti-
cal wells perforated across the entire thickness of the
formation to horizontal drilling of the upper shale,
then to the horizontal drilling of the middle Bakken
(which is not typically shale, but may be composed
of silts, sands, or carbonates) utilizing single stage
fracturing. Te current trend of horizontal drilling
involves multistage fracturing of the middle Bak-
ken. Te horizontal drilling approaches in the Bakken
have also included a host of multilateral well types
drilled in various orientations to optimize the infu-
ence of natural fracture networks and natural stress
and strain forces on productivity. Te current trend
in the Bakken is towards single well pad locations
with various horizontals (up to 12) drilled from one
location covering two 1,280-acre spacing units. Tis
signifcantly reduces surface disturbance and can save
capital associated with multiple rig mobilization and
demobilization.
Production Potential
By 2035, production from tight oil plays across
the United States and Canada could range between
600 thousand barrels per day up to as high as 3 mil-
lion barrels per day, with a most likely estimate of
around 2 million barrels per day.
Te most likely estimate involves the application
of knowledge gained during successful development
of the Bakken towards other tight oil plays over this
period. Bakken production is expected to be between
400 and 600 thousand barrels per day by 2035. If
levels of Bakken production from Saskatchewan and
Montana are each about half the North Dakota pro-
duction, and similar productivity is realized from
just three other large tight oil plays (for example the
Eagle Ford, Niobrara, and Cardium) then more than
2 million barrels per day of production from tight oil
formations in North America in 2035 is likely.
In the reasonably unconstrained case, continuing
improvement in recovery technologies, as well as
CHAPTER 1 - RESOURCES AND SUPPLY 123
If these barriers and challenges are not met, there is
a plausible low, or constrained, case in which there
could be zero oil shale production by 2035.
However, in the most likely case, we assume that
three to fve projects can emerge from the existing
lease program and develop commercial production
from the early 2020s, after conversion of RD&D
leases to commercial leases around the middle of the
current decade. Tis should lead to production rates
of around 250 thousand barrels per day by 2035, with
prospects for considerable growth in subsequent
decades.
In the high, or relatively unconstrained case, more
rapid technological progress and a supportive market
and regulatory environment could allow the industry
to develop larger projects earlier. Large projects in
the 100–200 thousand barrels per day output range
would take 3–5 years for development and 5–7 years
to reach sustainable production. In this scenario,
total production could reach as high as 1 million bar-
rels per day by 2035.
U.S. Oil Sands
History and Context
U.S. oil sands resources show some important dif-
ferences from the Canadian oil sands, discussed previ-
ously. Factors such as more varied land ownership,
more complex and challenging oil sand composition,
and geographical dispersion add to the challenges
faced by U.S. oil sands development.
Of the estimated 54–63 billion barrels of original
bitumen in place, the resource in the Utah is the larg-
est, at about 20 billion barrels, and the best under-
stood. Covering nearly 1 million acres, or 150 square
miles, 11 major deposits are designated as Special Tar
Sand Areas (STSA) within the state of Utah.
An important diference between Canadian and
U.S. oil sands (principally Utah) is that the U.S. sands
are “oil-wet” rather than “water-wet.” Oil-wet U.S.
sands lack the flm of water layered between the sand
grain and the bitumen in Canadian water-wet sands.
Te oil-wet nature of U.S. oil sands leaves the depos-
its more highly consolidated (typically 3-4 times the
compressive strength), making initial mining and ore
conditioning operations more energy intensive than
in Canada’s oil sands.
crucial for private industry to assess risks and to com-
mit the billions of dollars of required investment.
Commercial scale technologies with economically
attractive recovery efciency and acceptable environ-
mental impacts will be required. Because the road
to commercialization is measured in decades not
years – a long time horizon will allow development to
continue through “boom and bust” oil and gas price
cycles.
Key Development and Production Technologies
Oil shale production technologies fall into two broad
categories: in situ and ex situ. In an in situ develop-
ment, the resource is converted to oil and gas without
mining the oil shale ore. In ex situ development, the
ore is mined and transported to a surface retort where
it is heated and converted into oil and gas.
Te rich accumulations in Colorado may be best
developed by in situ technologies because of high
mining costs associated with thick overburden cover-
ing the resource. Te shallow accumulations in Utah
are generally not as thick as the Colorado deposits and
may be developed using ex situ mining and surface
retort technologies near the resource outcrop.
Several development approaches are underway,
mainly focusing on in situ techniques. Some of this
work is proceeding on federal RD&D leases. Te main
technologies are the following:
y Heating kerogen with electric heaters down the
wellbore to achieve pyrolysis of the kerogen and
conversion to oil and gas, which can then fow to
the surface
y Fracturing and chemical conversion of kerogen
y Mining and surface retorting to recover hydrocar-
bons.
Several decades of continuing sustained research
will be necessary to prove, demonstrate and deploy
efective technologies to achieve material production
of oil and natural gas from oil shale deposits. Such
a sustained efort will require long-term commit-
ment from companies and a supportive fscal, leasing,
access, and research regime from the U.S. government.
Production Potential
Many technical, environmental, and regulatory
challenges will need to be met before oil shales become
a signifcant contributor to North American oil supply.
124 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Experts working on this study estimated most
likely 2035 production of about 25 thousand bar-
rels per day. Tis assumes that one of the current
research and pilot projects achieves technology suc-
cesses allowing it to step up to commercial-scale
operations.
In the low, or constrained, case 2035 production
is estimated at 10 thousand barrels per day, again
assuming that one project can move to commercial
scale, but the pace of development would be con-
strained by environmental and fnancial barriers.
In the high, or reasonably unconstrained, case
it is assumed that enhanced policy, access, and fs-
cal support for resource development will encour-
age additional private capital to enter this play, and
that production could grow to 150 thousand barrels
per day by 2035, continuing on a slow growth curve
thereafter.
Ovcrall North Amcrican Unconvcntional
Oil Production Outlooks
Table 1-14 summarizes the potential production
pathways for the sources of unconventional oil pro-
duction analyzed in this section.
Most Iikcly Unconvcntional Oil Supply Projcc-
tion (7 million barrcls pcr day by 20S5). Te pro-
jection assumes steady growth from existing supply
At the time of this report, there is no commercial
bitumen production from the U.S. oil sands. Tere are
three small pilot scale operations in Utah, operating
on surface mineable deposits.
Key Development and Production Technologies
It is expected that variations of technologies used
in the Canadian oil sands region can be applied in the
United States; however, they will need to be adapted to
ft the oil-wet nature of U.S. resources and will require
smaller scale operations, given the greater resource
dispersion. Surface mining techniques would be used
for early development, with in situ technologies,
adapted to Utah conditions, deployed later. Oil-wet
and highly consolidated oil sands deposits, like those
in Utah, do not necessarily require radical technol-
ogy changes, but innovation and adaptation based on
known technologies from Alberta.
Production Potential
A U.S. Department of Energy Task Force on Stra-
tegic Unconventional Fuels, reporting in 2007, envi-
sioned the potential for U.S. oil sands production to
grow from zero to 350 thousand barrels per day by
2035 (with a more aggressive scenario of 500 thou-
sand barrels per day). Tis outlook appears optimis-
tic given the status of resource development, invest-
ment, and current policy and regulatory frameworks.
Table 1-14. Production Potential from North American Unconventional Oil*
(Barrels per Day)
2009 Actual 2035 Limited 2035 Likely 2035 High
U.S. Oil Shale 0 0 250,000 1,000,000
Canadian Oil Sands 1,350,000
†
3,000,000 4,500,000 6,000,000
Canadian Heavy Oil 382,000 135,000 250,000 350,000
U.S. Oil Sands 0 10,000 25,000 150,000
Tight Oil 265,000 600,000 2,000,000 3,000,000
Total 2,000,000 3,700,000 7,000,000 10,000,000
* The total unconventional production is weighted for the two sources of supply that are not currently commercial (oil shale and
U.S. oil sands). If one reaches its full potential, it is likely the other one would not. Therefore, both projections are weighted 50%
in the production capacity roll-up, all others are relatively independent of each other and have 100% weightings.
† The production of bitumen is 1.49 million barrels per day, but after upgrading part of the bitumen to synthetic crude oil,
some volume is lost, and overall supply is lower.
CHAPTER 1 - RESOURCES AND SUPPLY 125
years. If the goal is to increase domestic oil supply and
increase energy security, unconventional resources
will surely need to be tapped. Tese types of resources
necessitate supportive government policy.
Finding 1: Conficting information on environ-
mental impacts of unconventional supply, includ-
ing the relative GHG emission intensity of oil sands
development or water quality impacts from tight oil
production, could lead to misinformed or inefec-
tive policy. As unconventional supply has a larger
environmental footprint, the environmental efects
associated with production growth should be consid-
ered and planned for.
Rccommcndation 1: Provide access to inde-
pendent and accurate information to support the
formation of policy. Establish a Federal Advisory
Committee Act (FACA) team to provide an
independent forum to research and clarify aspects
of unconventional supply. Tis will identify areas
of uncertainty and illuminate facts – ensuring that
government initiatives are both informed and efec-
tive. Te FACA committee could also contribute to
the development of early, long-range planning that
considers the environmental efects associated with
future unconventional supply growth.
Finding 2: For unconventional sources with no
production, specifcally U.S. oil shale and U.S. oil
sands – several ingredients that have been critical
to the successful development of the Canadian oil
sands are currently not in place.
Limited Access – Corporations and individuals
are constrained in the ability to assemble contigu-
ous leases with large resources. Without certainty in
resource size, there is less incentive for companies to
risk capital.
Additional Fiscal Measures to Spur Growth – Cana-
dian and Alberta government participation in oil
sands included broad-based science and technology
research, pre-commercialization investments, favor-
able fscal terms, loan guarantees, and direct fnan-
cial investment over decades. Te U.S. government
provides vital funding for basic research, but these
ideas must move from the laboratory into the feld –
the next critical step in resource development; fund-
ing is often an issue for entrepreneurial frms, which
sometimes struggle to fnance high-risk feld pilots.
Unconventional royalties are another opportunity to
sources and successful development of new, gradually
implemented technologies. U.S. oil sands and U.S.
oil shale require the largest innovations, and com-
mercial methods for production must be deployed.
Other supply sources require ongoing improvements
to existing extraction methods. Unconventional oil
production is projected to reach 7 million barrels per
day by 2035.
Iimitcd Unconvcntional Oil Supply Projcction
(S.7 million barrcls pcr day by 20S5). Te low pro-
jection assumes production growth is slowed by a
number of factors. For sources of supply with no cur-
rent production (U.S. oil sands and U.S. oil shale), bar-
riers to development include limited access to acre-
age, and minimal fnancial incentives and investment
capital to pursue research and eventual commercial
development. For sources of supply with current pro-
duction, challenged economics (higher environmental
costs and environmental limits) ultimately constrain
growth.
High Unconvcntional Oil Supply Projcction
(10 million barrcls pcr day by 20S5). Te projection
assumes a set of circumstances that would accelerate
production growth. Major innovations in unconven-
tional extraction occur, solutions minimize environ-
mental efects, and strong government support in
the United States and Canada fosters development.
New technology is developed and rapidly deployed.
Physical constraints are the main limits to growth –
requirements to build pipeline capacity, time to build
infrastructure, reasonable time to learn and ramp up
capacity, water constraints, labor constraints, manu-
facturing equipment or drilling constraints. In this
projection – a true “stretch case” for unconventional
supply – production reaches 9 million barrels per day
by 2035.
Kcy Findings and Rccommcndations
For each source of unconventional oil supply, the
path to eventual production will be unique. In some
cases, the advance of broadly applicable oil and gas
technology could lead to surprisingly rapid produc-
tion growth – potentially the case for tight oil. How-
ever, development of tight oil technology is likely
to be the exception, not the norm. Unconventional
resources require new techniques to extract the oil.
Learning from the Canadian oil sands example, the
yardstick for measuring the successful development
and deployment of new technologies is decades – not
126 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
an economically viable, socially acceptable, and envi-
ronmentally responsible manner. Fiscal measures
could include loan guarantees, severance tax incen-
tives, lower royalties, accelerated capital deprecia-
tion, and job creation programs (including retraining
and fnancial support). Other ideas include up-front
investments to pursue technology deployment and
creative oil and gas royalty and fscal structures that
consider the higher operating and capital costs of
unconventional production.
incentivize development. Current U.S. royalties are
12.5% – the same level as lower risk, established con-
ventional oil production.
Rccommcndation 2: Create an environment that
fosters innovation and results in production growth;
access to acreage with sizable oil resources and long-
term stable fscal regime with federal measures to
support the industry. Ideally the fscal environment
stretches over multiple decades, in order to provide
the certainty to develop unconventional resources in
Te shale gas revolution could take production
of natural gas liquids (NGLs) supplies to unprec-
edented levels. If natural gas production rises to
more than 100 billion cubic feet per day by 2035
as predicted, an NGL supply increase of 60% or
greater above 2010 levels could occur. Tis sharp
rise in anticipated NGL production has broad
implications for demand, infrastructure, and
import/export opportunities.
NGLs are ethane, propane, normal butane, iso-
butene, and natural gasoline (pentanes+), pro-
duced when wellhead natural gas is processed
for delivery to market. NGLS, in gaseous form at
the wellhead, are extracted by chilling the natu-
ral gas to very low temperatures, a process that
liquefes the gases. In some cases, NGL extrac-
tion is required to produce a natural gas stream
that meets required pipeline or industrial speci-
fcations. In other cases, when the price of NGLs
is higher than that of natural gas, NGLs are
extracted for economic reasons.
Te diference between crude oil and natural
gas prices is a key driver in NGL prices. As the oil
to gas price ratio grows, the value of NGLs rela-
tive to gas also increases. Rising NGL prices have
been a factor in recently increased rig activity in
oil and liquids-rich natural gas plays such as in
the Permian, Williston, and Eagle Ford basins.
Each component of an NGL barrel has a unique
supply/demand profle. Ninety percent of eth-
ane comes from natural gas processing plants.
Demand for ethane is from petrochemical plants,
which transform ethane into ethylene, an essen-
tial component of plastic. Ethane is uneconomic
and difcult to export so demand is constrained
to North America.
Sixty percent of propane comes from natural
gas processing plants. A third goes to petrochemi-
cal demand and two-thirds goes to home heating
demand. Weather, ethylene prices, and export
economics drive the demand for propane.
Te motor fuels market drives demand for
the remaining NGLs: normal butane and isobu-
tane and natural gasoline. Natural gas process-
ing plants produce 45% of the n-butane and 60%
of the isobutane. Ninety percent or more of the
butanes are used in motor fuels. Natural gas pro-
cessing plants also make most of the natural gas-
oline. Petrochemical plants use a third of it and
refneries use two-thirds for fuels.
Current NGL infrastructure may not be large
enough or interconnected enough to handle
potential production growth. Te market will
likely respond with new investment, allow-
ing NGL markets and their customers to gain
signifcant advantages in domestic and global
markets. To date, there have been announce-
ments for an additional 7.8 billion cubic feet per
day of processing capacity in the United States,
an increase of 12%. Tese projects, built close
to shale development, are needed even though
processing plants along the Gulf Coast have
30–50% open capacity. Several projects are also
underway to expand fractionation capacity by
438 thousand barrels per day by 2014. Transpor-
tation and storage capacity is also expected to
increase. Two NGL pipelines have been proposed
to take NGLs from the Bakken to market.
Natural Gas Liquids
CHAPTER 1 - RESOURCES AND SUPPLY 127
2. United States Gulf Coast (part of PADD III)
3. Midwest (northern part of PADD II)
4. Rocky Mountain (the same as PADD IV)
5. Western Canada including Washington State
(Washington State is currently part of PADD V)
6. Eastern Canada
7. California (currently part of PADD V)
8. Alaska (currently part of PADD V)
Figure 1-39 shows the geographical extent of the
PADDs (Petroleum Administration for Defense Dis-
tricts) in the United States, often used to defne
regional petroleum logistics and market issues.
PADDs have been used to defne the oil pipeline
regions covered in this study.
As of 2009, the United States had approximately
55,000 miles of crude oil trunk lines (typically
8–24 inches in diameter) connecting North Ameri-
can supply and market regions. Tis number does
not include tens of thousands of miles of gathering
lines used to move crude oil from production felds to
trunk lines, refned products lines to move products
from refnery to market, and LPG/NGL lines used to
move other commodities such as propane and ethane.
Since the last NPC study on oil pipelines, conducted
in 1987–1989, the United States has seen signif-
cant shifts in supply and demand for crude oil. Total
imports of foreign crude into the United States have
nearly doubled from just over 4.7 million barrels per
day in 1987 to roughly 9 million barrels per day in
2009. Tis is a continuation of the trend of domestic
U.S. production falling over most of the period, while
oil demand increased.
One of the most signifcant changes in the dynam-
ics of U.S. crude oil transportation has occurred over
the past decade as the United States trended away
from its reliance on waterborne imports, towards
imports from Western Canada. Since the 1987 NPC
report, U.S. imports of Canadian crude oil have tripled
to nearly 2.5 million barrels per day, with nearly 40%
of that growth occurring since 2000.
Te most direct impact of this shift is highlighted
by changes in the Midwest and Rocky Mountain
regions. In the Midwest, many pipeline networks
were originally established to supply domestically
Finding S: For unconventional supply with pro-
duction, primarily Canadian oil sands, develop new
technologies that lower the environmental footprint
and ofer higher, more sustainable, oil production lev-
els. For instance, Canadian oil sands have about 5–15%
higher GHG emission per barrel than the average crude
oil consumed in the United States. Development of
new technologies to lower GHG emission intensities
would help to close this gap. In turn, these technolo-
gies could be implemented domestically to improve the
environmental footprint of new U.S. unconventional
resources (oil shale and U.S. oil sands). Investments
in low or possibly zero-carbon emitting energy such as
low-energy extraction methods or small-scale nuclear
generation to fuel extraction, or CCS – all hold poten-
tial for reducing GHG emissions.
Rccommcndation S: Continue to participate in
international and bilateral activities – such as the
Energy Partnership of the Americas’ Heavy Oil
Working Group. Identify technology areas of mutual
interest between the United States and Canada –
areas that target more environmentally sustainable
methods of production. New technologies could
result in economic opportunities for U.S. frms, while
increasing energy security. New technologies will
most likely advance the development, and reduce
the environmental impact, of U.S. oil shale and
U.S. oil sands supply and may ultimately prove use-
ful to other extractive industries.
Crudc Oil Pipclinc Infrastructurc
Ovcrvicw
Oil infrastructure is critical to the North Ameri-
can energy supply chain that has evolved over the
last century. For the purposes of this paper, oil
infrastructure is limited to pipeline transportation
infrastructure available for crude oil in North Amer-
ica. While marine, rail, and trucking operations can
be important infrastructure components, the vast
majority of North American oil supply is moved via
pipeline.
A detailed regional analysis of the crude oil pipeline
system is included in Topic Paper #1-7, “Crude Oil
Infrastructure,” which is available on the NPC web-
site. Te regions covered are as follows:
1. Mid-Continent (currently part of PADD II [Petro-
leum Administration for Defense Districts])
128 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Like the PADD I region, the West Coast Region,
consisting of PADD V excluding Alaska, remains a
largely separate market from the rest of the United
States and faces a unique set of issues. California
has no intraregional or interregional pipelines. An
interregional pipeline corridor operated when the
1987 NPC study was completed, but the system has
since been converted to natural gas service, a result
of declining production and dwindling throughput.
Regional crude oil production has fallen to less than
half of what it was in the 1980s and is now less than
1.3 million barrels per day. With little historical
need for waterborne import infrastructure, and the
age of some facilities approaching 50 years, the Cali-
fornia Energy Commission has forecasted a need for
signifcant expansion of waterborne import facilities
and tankage by 2030 to accommodate imports.
In spite of shifts in market dynamics since the
previous NPC study, the Mid-Continent region, spe-
cifcally Cushing, Oklahoma, remains the nexus of
North American crude oil supply and movements. As
of 2008, Cushing holds 5–10% of total U.S. crude oil
produced light crude oil from Texas and the U.S.
Gulf Coast region to large refning hubs in PADD
II. Northbound corridors from Cushing, Oklahoma
and St. James, Louisiana, once formed the backbone
of the crude oil pipeline infrastructure in the Mid-
Continent, U.S. Gulf Coast, and Midwest regions.
Now, they are increasingly secondary to the growing
demand for southbound capacity.
A similar situation is occurring in the Rocky Moun-
tain region, where a growing surplus of light Rocky
mountain crude oil supply, coupled with increasing
availability of Canadian supply and lower refnery
demand, has overwhelmed takeaway pipeline capac-
ity on the Rockies to Midwest Interregional Corridor.
Also, growth of crude oil supplies in the U.S. Mid-
Continent, coupled with growth in Canadian produc-
tion, is causing an imbalance in the traditional market
dynamics around the Gulf Coast region. Te expected
surge in future ofshore domestic production com-
bined with Canadian imports and the capacity of cur-
rent infrastructure will likely reduce the need for the
Gulf Coast to increase foreign crude import capability.
Figure 1-39. U.S. Petroleum Administration for Defense Districts (PADDs)
PADD I: EAST COAST PADD III: GULF COAST PADD II: MIDWEST PADD IV: ROCKIES PADD V: WEST COAST, AK, HI
Source: Energy Information Administration, Oil Market Basics, Appendix A, “Map of Petroleum Administration for Defense Districts.”
Figure 1-39. U.S. Petroleum Administration for Defense Districts (PADD)
CHAPTER 1 - RESOURCES AND SUPPLY 129
tions in corridor capacity between supply regions
and demand hubs and demonstrate how the com-
modities markets determine infrastructure needs.
Te last 25 years has been a period of punctuated
market development. Regions that had produced
a relatively stable supply of crude oil began to slow.
In the latter half of 2010 and the beginning of 2011,
West Texas Intermediate priced at Cushing, Okla-
homa, was for the frst prolonged period ever priced
at a signifcant discount to Brent and other worldwide
benchmark crudes. Tis shows how changes in bal-
ance between markets can impact crude oil pricing.
Where market inefciencies occur, industry continues
to act as an efective balancing mechanism by identi-
fying an economic opportunity and developing infra-
structure to rebalance the market.
Public policy should continue to support existing
market mechanisms and encourage the market to
respond to infrastructure needs emerging in the fore-
seeable future. Tis is the case for newly constructed
or expanded infrastructure, and also when under-
used pipelines need to be reversed, idled, or undergo
changes in type of service.
Energy Security
Energy security is protected when markets and the
industry are encouraged and able to respond swiftly to
economic drivers. Tere is no better example of this
than today’s changing North American supply and
demand landscape. Rapidly growing production from
Northern Alberta’s vast energy reserves is met with
ample pipeline export capacity to the United States,
allowing crude oil to fow to major refning districts
in the Midwest, Mid-Continent, and ultimately the
Gulf Coast. Te robust energy supply position for
North America will support energy security for the
United States, as long as the necessary pipeline cor-
ridors are in place to continue to link production and
markets.
While changes in supply patterns across North
America will favor expansion of certain corridors,
declining use may merit capacity in others. Market
forces will continue to support U.S. energy secu-
rity even where use determines some corridors may
become unnecessary. Tough changing supply pat-
terns are shifting towards a predominantly North-
South fow from Canada into the Midwest and Mid-
Continent, some degree of import capacity from the
inventory and it remains the price settlement point
for the benchmark West Texas Intermediate on the
NYMEX. Several major pipeline corridors service
the Cushing hub, including supply from the Western
Canadian Sedimentary Basin, making the Cushing
hub and surrounding region strategic importance to
North American market dynamics.
In addition to evolving market dynamics, pressing
issues for the network of crude oil pipelines across
North America include the age of existing infra-
structure, combined with encroachment from urban
development leading to concerns about public safety.
Together these issues will likely lead to an increas-
ingly stringent regulatory environment, and addi-
tional capital will be required to enhance the safety
and securing of oil infrastructure.
Te overarching trend in oil infrastructure is the
requirement to respond to shifting market dynam-
ics caused by changing sources of domestic supply
and evolving transfer corridor capacity requirements.
Emerging alternative crude oil sources in the West-
ern Canadian Sedimentary Basin and North Dakota’s
Bakken play are pushing Midwest and Mid-Continent
pipelines to realign existing infrastructure to back out
traditional imports from the Gulf Coast in favor of
growing supply from the north.
Kcy Findings
As a whole, the petroleum pipeline industry and
infrastructure network will face a number of common
challenges over the next 50 years. Industry, policy-
makers, and regulatory bodies must be mindful of
these challenges to ensure a balance of diligence and
efciency that will best serve the interests of petro-
leum producers and consumers.
Changing Market Dynamics and Public Policy
Since the 1987 NPC oil pipeline study, the petro-
leum transportation industry has responded to the
needs of a changing North American crude oil mar-
ket landscape. Declining crude oil production in
regions such as PADDs III and V has been ofset by
ofshore imports, or U.S. imports from western Can-
ada. Refnery rationalization and Canadian imports
in recent years have led to increased reliance on
PADD II refnery hubs in Chicago and Wood River.
Such shifts have been met with expansions or reduc-
130 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
If and when a decision is made to idle or abandon
a pipeline, determinations about the remediation of
the asset must be made. From an environmental and
social perspective it may or may not be in the public’s
interests to remove a pipeline and fully remediate a
right of way. Such decisions will be dependent on the
specifc region or environment and the local munici-
palities.
Aging Infrastructure
Much of the pipeline infrastructure in North Amer-
ica was laid well before the last NPC oil pipeline study
was conducted in 1987. In 2010, several existing
systems are already 50 years old with no plans to be
decommissioned based on asset age alone. On systems
where asset integrity remains high, and market
demand still necessitates infrastructure, there is no
reason to retire assets so long as adequate mainte-
nance and integrity programs can guarantee system
safety.
Asset integrity cannot be directly predicted by age
alone, but, as time passes, overall infrastructure and
integrity issues could become more common with age.
Among age-related challenges are:
y Internal and external pipeline coating issues
y External corrosion
y Tird-party damage
y Weld seam failures
y Specifc integrity issue around fash welded pipe.
Tese challenges are cause for concern not only
because of public safety risk, but because of heavy
reliance on pipeline infrastructure in the North
American economy. Te U.S. relies on a small number
of key pipeline transportation corridors. Mitigation
and integrity programs are in place, but these pro-
grams may result in increased operating and mainte-
nance costs. Downtime for planned maintenance will
increase and be accompanied by an increased risk of
apportionment on key pipelines.
Regulatory Challenges
Development of new or greenfeld pipeline projects
often faces procedural challenges because of a compli-
cated regulatory environment in the United States.
Te lack of overarching federal oversight in the oil
pipeline permitting process leaves potential projects
subject to a patchwork of required state level environ-
mental, regulatory, and commercial approvals.
U.S. Gulf Coast into those regions should remain
available. Economics and pricing dynamics dictate
that the throughput on those corridors will continue
to act as a balancing mechanism for pricing hubs. Tis
will ensure that imports from the Gulf Coast or the
Strategic Petroleum Reserve will be available to the
Mid-Continent and Midwest even if the majority of
supply originates in the Western Canadian Sedimen-
tary Basin or the Bakken play.
Existing Infrastructure Use
Changing market dynamics between regions
impacts existing infrastructure use. For most of the
past 50 years, pipeline infrastructure was oriented in
a south-north alignment. However, increasing sup-
ply from Canada coupled with falling supply from
traditional production regions is causing a reversal to
north-south orientation.
Tis shift, along with other changes in market
dynamics resulting from shifting crude oil supplies,
has resulted in a number of reversals, conversions,
and idling of existing systems. For some pipelines,
this means using existing infrastructure with com-
modities for which they were not originally designed.
While this is not a signifcant issue, it is important
for the industry to be responsive to how a pipeline’s
original design parameters combine with its current
operation.
In other regions, supply and demand shifts have
resulted in signifcantly underused lines. Situa-
tions have emerged where one or two shippers will
continue to rely on a pipeline, but capacity demand
remains consistently below the pipeline’s economic
threshold. In cases where demand on an existing
pipeline falls below optimal fow rates, the question
begs whether the asset ought to remain in service at
a sub-optimal fow rate with potentially prohibitive
operating economics, or whether the asset ought to
be idled entirely.
In these instances the pipeline service provider is
left in a challenging predicament. Economics around
a particular asset may no longer be favorable to con-
tinued operation, but the provider is left open to ship-
per and regulatory scrutiny for the adverse impact the
asset’s idling or abandonment may have on another
business. Such cases need to be carefully examined in
Canada and the United States and the beneft to one
party must be weighed carefully against the harm to
another.
CHAPTER 1 - RESOURCES AND SUPPLY 131
environmental approvals should not be provided. In
these cases, federal mandate is required to show that
the project serves the public’s interests, albeit at a
national rather than state level.
State permitting processes multiply the number
of separate and unique approvals required for each
individual project. Tis increases the costs and time
required for the development of new projects and
introduces signifcant commercial risk that one state
In some cases, the public beneft of a project is clear
on the national level, but less so at the state level.
For example, an oil pipeline connecting supply in
one region to demand in another may easily travel
through one or more states without any intermedi-
ate receipts or deliveries. However, states between
the origin and destination may see no immediate eco-
nomic beneft to residents or businesses. At the state
level it may be determined that with no immediate
and primary beneft to local residents, regulatory and
Mexico has been, and continues to be, an impor-
tant trading partner with the United States for
energy. In particular, of most relevance to this
study, there is long-standing trade in crude oil and
natural gas to the beneft of both countries.
In 2010, Mexico exported 1.15 million barrels
per day of crude oil to the United States. As such,
the country was the second largest crude oil sup-
plier to the United States, after Canada (and ahead
of Saudi Arabia, Nigeria, and Venezuela). Tis
underlines Mexico’s importance as a North Ameri-
can crude oil producer and supplier. Mexico’s crude
oil production in 2010 was 2.96 million barrels per
day. Tis has declined in recent years (from its high-
est level of 3.82 million barrels per day in 2004) as
large felds, particularly the ofshore Cantarell feld
in the Bay of Campeche, have begun to decline, and
output from newer felds has not grown sufciently
to ofset this decline. Even so, newer develop-
ments, such as the nearby Ku-Maloob-Zaap felds,
now produce more than Cantarell. Onshore devel-
opments, such as the Chicontepec felds, have been
considered as a future source of production growth
potential, but have not yet become large contribu-
tors to Mexico’s crude oil production.
Prospects for continuing availability to the
United States of signifcant crude oil supplies from
Mexico will depend on Mexico’s ability to reverse
the recent decline in overall crude oil production,
at a rate which also exceeds Mexico’s own internal
market needs.
With regard to natural gas, Mexico is a net
importer, mainly by pipeline from the United
States, although, in recent years, Mexico has added
capacity to import LNG from international mar-
kets, with terminals both on its east coast and west
coast. In 2010, Mexico’s net natural gas imports
from the United States were 0.83 billion cubic feet
per day, representing almost 12.5% of Mexico’s gas
demand. Mexico has signifcant, and growing, nat-
ural gas production, which in 2010 totaled 5.3 bil-
lion cubic feet per day. However, Mexico’s natural
gas demand is growing at a faster rate than its pro-
duction, leading to an increased need for imports,
of which the United States supplies the most sig-
nifcant share. Tere is a well-established set of
natural gas pipeline interconnections between the
United States and Mexico, allowing this trade to
continue and expand.
However, recent trends in Mexican oil and natu-
ral gas production and consumption indicate that
the relationship between the United States and
Mexico will be quite diferent in the future. Sig-
nifcant recent declines in Mexican oil produc-
tion alongside rising domestic demand will likely
restrict Mexico’s ability to export oil to the United
States in the medium and long term. Increasing
internal Mexican demand for natural gas, mostly
as a result of rising electricity demands, will raise
Mexican demand for imported natural gas from
the United States and for liquefed natural gas
from other countries. Tese market dynamics will
take place in a context where the Mexican govern-
ment will be assessing its long-standing frame-
work for hydrocarbons production that restricts
private investment in the sector. However, even
important energy sector liberalization in Mexico
is unlikely to lead to quick change in Mexican oil
and natural gas production trends, as the lag time
between investment and production can be quite
long.
Mexico Oil and Gas
132 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
ral gas supply, and includes an overview of the con-
text and production history, where applicable, the
key technologies required for development, potential
production pathways to 2035 and beyond, and an out-
line of the key fndings. Te section concludes with
an overview of the natural gas infrastructure system
required to deliver this supply to market. Each of
these topics is described in more detail in topic papers
that are available on the NPC website.
Unlike oil, natural gas from the United States
and Canada has supplied the vast majority of mar-
ket needs in the region over the past 50 years. Both
nations are large natural gas producers, but produc-
tion and development activities have been almost
exclusively directed towards serving the North
American market. With one exception (Alaska LNG,
operational since 1969), only recently have serious
proposals been put forward regarding the potential
to export North American gas into global markets.
Indeed, this was preceded by several years in which
facilities to import LNG were developed on a large
scale, in anticipation of domestic supply falling short
of meeting market growth in the United States and
Canada.
Onshore natural gas, from both conventional and
unconventional reservoirs, forms the vast majority
of current and future supply potential. Supply pros-
pects have been transformed in recent years as natu-
ral gas companies have applied technology to develop
gas supplies that could not previously be produced
in economic quantities, particularly from shale gas
basins. In addition, large actual and potential produc-
ing natural gas supplies from ofshore and the Arctic
are discussed below.
O?shorc
Dcvclopmcnt and Production History
and Contcxt
U.S. Lower-48 O?shore
Te ofshore has been an active and important
contributor to North American natural gas and oil
supply, as described in a previous section. Natural
gas activity has been almost exclusively located in
the central and western zones of the Gulf of Mexico,
although signifcant resources and production poten-
tial are known to exist in other ofshore areas.
may approve a project while another frmly disap-
proves it.
As infrastructure demands from continental
regions such as the oil sands grow and aging infra-
structure requires replacement, a streamlined federal
level permitting process will be of greater value.
Public Perceptions
With continued urban growth, a growing percent-
age of pipeline right-of-way is in close proximity to
residential and commercial development. As this
trend continues it will be crucial to ensure public
awareness of the facilities and to manage public per-
ceptions around leak detection.
Challenges in the oil transportation industry have
highlighted vulnerabilities in leak detection technol-
ogy and reminded home and business owners of the
facilities in their area. As the average age of North
America’s pipeline network rises, it is important
to work with municipalities to ensure emergency
response plans are up to date and to educate indi-
viduals and businesses near pipeline facilities of the
importance of “Call Before You Dig” programs and
who to notify if they suspect a leak.
Security and Protection of Pipeline Assets
In 2009, there were approximately 55,000 miles of
crude oil trunk lines (typically 8–24 inches in diam-
eter) and tens of thousands of miles of additional
feeder lines, gas lines, and natural gas liquids pipe-
lines in the United States. Te challenges around
pipeline surveillance and the volume and volatility
of the liquids transported through pipelines place
them at a high risk for severe social and environmen-
tal fallout should pipeline integrity be compromised
accidentally or intentionally. Beyond the immediate
physical consequences of a severe pipeline disruption,
the economic ramifcations of taking a major pipeline
corridor ofine even temporarily could be far reaching
and result in crude oil shortages, refnery shutdowns,
and market disruptions.
PROSPECTS FOR NORTH
AMERICAN GAS DEVELOPMENT
Ovcrvicw
Each major heading in this section describes one
segment of this portfolio of current and future natu-
CHAPTER 1 - RESOURCES AND SUPPLY 133
As with oil, a shift in development focus from the
shallow water Continental Shelf of the Gulf of Mexico
to the deepwater frontier zones (with water depths
greater than 1,000 feet) began in the mid-1990s, and
accelerated after 2000. Tis trend is expected to con-
tinue as more discoveries and drilling activities occur
in the deepwater and ultra-deepwater areas of the
Gulf of Mexico. Beginning around 2000, the Gulf of
Mexico’s shallow water gas production has markedly
declined while deepwater production has increased.
Deepwater natural gas production rose from 382 Bcf,
or 7.5%, of total Gulf of Mexico production in 1997 to
around 1.4 Tcf in 2004, or 35%, of total Gulf of Mex-
ico natural gas production.
Apart from the central and western zones of
the Gulf of Mexico, other ofshore areas in the U.S.
lower-48 were subject to congressional moratoria
from 1982 to 2008. After these moratoria expired,
Natural gas production from the federal ofshore
grew from about 0.06 Tcf in 1954 to a maximum of
around 5.2 Tcf in 1997, accounting for just over 25%
of total U.S. natural gas production at that time. Since
then, federal ofshore natural gas production has
declined to around 2.4 Tcf in 2009, or 11% of total
U.S. gas production. Figure 1-40 shows gas produc-
tion as a percentage of total U.S. production from
1960 to 2009.
Currently, U.S. lower-48 ofshore oil and gas pro-
duction is restricted to the Gulf of Mexico and the
Pacifc OCS shelf regions. Much of the eastern Gulf
of Mexico is expected to be restricted to drilling until
2022, and the Pacifc and Atlantic OCS areas were
restricted from leasing consideration up until 2008.
For the purposes of this study, oil and gas develop-
ment on the Alaska OCS is included in analysis of the
Arctic region, rather than the U.S. ofshore region.
Figure 1-40. Ofshore Gas Production as a Percentage of Total U.S. Production, 1960–2009
0
10
20
30
0
2
4
6
1960 1965 1970 1975 1980 1985 1990 1995 2000 2005 2010
P
E
R
C
E
N
T
A
G
E
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
1980 – First fve-year leasing program initiated
1981 – OCS moratoria begins
1
2
1982 – Onset of area-wide leasing 3
1995 – Passage of deepwater Royalty Relief Act 4
2008 – Expiration of OCS leasing moratoria 5
1 2 3 4 5
FEDERAL OUTER CONTINENTAL SHELF OCS
FEDERAL OCS PERCENTAGE OF TOTAL U.S. PRODUCTION
Sources: Total U.S. production data obtained from the Energy Information Administration’s Monthly Energy Review and federal
ofshore data obtained from the Ofce of Natural Resources Revenue; Bureau of Ocean Energy Management,
Ofshore Stats and Facts.
Figure 1-40. Ofshore Gas Production as a Percentage of Total U.S. Production, 1960–2009
134 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Canada O?shore
In Canada, ofshore hydrocarbon production comes
exclusively from its Atlantic margin; natural gas and
oil are produced in Nova Scotia (Figure 1-42) and
Newfoundland ofshore, respectively. Commercial
ofshore natural gas production has been centered on
the Sable Island sub-basin of the Scotian shelf. Natu-
ral gas is also produced ofshore Newfoundland, in
the White Rose and Jeanne d’Arc basins, but here it
is reinjected into the felds. Gas production from the
Sable Ofshore Energy Project comes from fve shal-
low marine felds (25 to 75 meters) that commenced
production between 1999 and 2004. In 2009,
459 MMcf/d was produced at the Sable Ofshore
Energy Project. In April 2010, cumulative gas pro-
duction reached 1.6 Tcf. Gas is piped onshore where
it is distributed to market through the Maritimes &
Northeast Pipeline.
Also in Nova Scotia, the Deep Panuke gas feld
in the Scotian Shelf should commence production
in 2011. Te feld is estimated to contain up to
900 Bcf of gas with a planned daily production of
300 MMcf/d.
the administration proposed leasing strategies that
would include selected new areas, such as an expanded
eastern Gulf of Mexico zone and areas of the mid
and south Atlantic coastline. However, these plans
were reconsidered in the aftermath of the Macondo
oil spill in the deepwater Gulf of Mexico. Tere are
currently no plans for new leasing outside the central
and western Gulf of Mexico. Estimates of undiscov-
ered technically recoverable natural gas resources
in the U.S. ofshore moratoria areas vary from 77 to
231 Tcf. Tis is a signifcant proportion of the
Bureau of Ocean Energy Management Regulation and
Enforcement mean estimates of total U.S. lower-48
ofshore undiscovered technically recoverable natural
gas of 288 Tcf.
12
A signifcant resource base remains
available for future ofshore natural gas production.
Figure 1-41 shows oil and gas resource estimates in
areas formerly under moratoria or considered of-
limits to OCS oil and gas production.
12 Minerals Management Service, “Assessment of Undiscovered
Technically Recoverable Oil and Gas Resources of the Nation’s
Outer Continental Shelf, 2006,” February 2006. MMS Fact
Sheet RED-2006-01b.
Figure 1-41. Estimates of Oil and Gas Resources in U.S. Ofshore Areas Formerly under Moratoria
0
50
100
150
200
250
0
10
20
30
40
50
60
70
MEAN ARI HIGH ARI MIDDLE API ALTERNATIVE
API
MEAN UTRR
MMS
MEAN UTRR
NARUC
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
O
F
G
A
S
B
I
L
L
I
O
N
B
A
R
R
E
L
S
O
F
O
I
L
GAS
OIL
Notes: ARI = Advanced Resources International; API = American Petroleum Institute; MMS = Minerals Management Service;
UTRR = undiscovered, technically recoverable resources; NARUC = National Association of Regulatory Utility Commissioners.
Sources: American Petroleum Institute, 2005; National Association of Regulatory Utility Commissioners, 2010.
Figure 1-41. Estimates of Oil and Gas Resources In U.S. Ofshore Areas Formerly Under Moratoria
CHAPTER 1 - RESOURCES AND SUPPLY 135
and a reasonably constrained production outlook, or
limited potential case, have been examined. Tese
refect the enablers and challenges to ofshore devel-
opment identifed by the NPC expert subgroup and by
respondents to the data survey.
Te high potential pathway is characterized by a
favorable economic environment, with increased
access to ofshore lands, accelerated technological
progress, and favorable government policies towards
ofshore development. Conversely, the limited poten-
tial pathway assumes more limited access to ofshore
zones, slower technological improvement, and a more
stringent policy and regulatory environment.
As with ofshore oil supply outlooks, alternate
cases published in the EIA’s Annual Energy Out-
look have examined environments of expanded of-
shore access, accelerated technology deployment,
and high prices that would afect prospects for nat-
ural gas (see Figures 1-43, 1-44, and 1-45). Tese
characterize the high potential ofshore natural gas
production pathway. Production of natural gas in
U.S. lower-48 ofshore trends from a minimum of
2.4 Tcf in 2010, in the reference case, to a maximum of
As in the U.S. lower-48, other ofshore areas in
Canada are subject to moratoria and other similar
restrictions on exploration and development activity.
Tese are discussed in the oil ofshore section above.
Kcy Dcvclopmcnt and Production
Tcchnologics
Ofshore oil and natural gas resource develop-
ment has been characterized by continuous technol-
ogy development and innovation, appropriate for
moving into greater water-depths, high-pressure,
high-temperature subsurface environments, and
complex geological settings. Because most of these
technologies are developed and deployed for both
oil and natural gas production, discussion of them is
included in the ofshore oil potential section of this
chapter.
Production Potcntial Pathways
U.S. Lower-48 O?shore
For the U.S. lower-48 ofshore, a reasonably uncon-
strained production pathway, or high potential case,
Figure 1-42. Monthly Ofshore Gas Production – Nova Scotia
0
4
8
12
16
20
2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011
B
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
M
O
N
T
H
SOUTH VENTURE ALMA NORTH TRIUMPH VENTURE THEBAUD
This fgure replaces the version found in 8/24 draft per Thierno Sow;
could not recreate original art, source could not be found by author
Source: Canada-Nova Scotia Ofshore Petroleum Board – Sable Ofshore Energy Project.
Figure 1-42. Monthly Ofshore Gas Production – Nova Scotia
136 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-44. Projection of U.S. Lower-48 Ofshore Gas Production – High Natural Gas Production Pathway
0
1
2
3
4
5
2010 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011 AEO2011 HIGH OCS RESOURCE CASE 2011
AEO2011 HIGH PRICE CASE 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-43. Projection of U.S. Lower-48 Ofshore Gas Production – Impact of Reduced Access
0
1
2
3
4
5
2010 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011
AEO2011 REDUCED OCS ACCESS 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-44. Projection of U.S. Lower-48 Ofshore Gas Production – High Natural Gas Production Pathway
Figure 1-43. Projection of U.S. Lower-48 Ofshore Gas Production – Impact of Reduced Access
CHAPTER 1 - RESOURCES AND SUPPLY 137
Gulf of Mexico providing the technical challenges are
overcome.
With respect to the limited potential production
outlook, the EIA’s low price case is an indicator of the
impact of the multiple factors that could afect pro-
duction. Natural gas production forecasts vary from
2.6 Tcf in 2010, in the low oil price Case, to 4.3 Tcf in
2035, in the AEO2010 reference case. Results of the
AEO2011 show gas production ranging from 2.4 Tcf
in 2010 to 2.1 Tcf in 2035, in the low oil price case.
Tat trend translates into a growth rate range of neg-
ative 1.1% per year in the Gulf of Mexico and nega-
tive 0.6% per year in the Pacifc region. Te reference
case of the AEO2011 shows natural gas production
increase from 2.4 Tcf in 2010 to 3.1 Tcf in 2035. Tat
trend represents an annual growth rate of 0.4% in the
Gulf of Mexico and 3.5% in the Pacifc region. Over-
all, the range of annualized growth rate of natural gas
production in the constrained case path is negative
1.1% to positive 0.4%.
As in the case of oil, if widespread long-term of-
shore development moratoria are reinstated, leading
to no development ofshore outside of the central
3.8 Tcf in 2035 in the high price case, according to the
AEO2011. Tat translates into an annual growth rate
range of 0.4 to 0.7%.
Similar to oil, much of the expected increase in
U.S. ofshore natural gas production is likely to come
from new discoveries in the Gulf of Mexico, such as
the Lower Tertiary trend. Te extent of the efects of
the Lower Tertiary trend on expansion of ofshore gas
resources is exemplifed by the McMoRan discovery of
the Davy Jones feld, located in 20 feet of water at a
total reservoir depth of nearly 30,000 feet. Although
shallower, conventional horizons of the Gulf of Mex-
ico Shelf have been heavily produced, only a small
percentage of wells have been drilled to more than
15,000 feet below the mud line. McMoRan’s Davy
Jones prospect is believed to hold at least 1 Tcf of
gas. Tis discovery demonstrates that hydrocarbon-
saturated Lower Tertiary formations exist not only in
remote, deepwater locations, but also closer to shore,
where development requires less time and money,
and infrastructure is in place. A number of other
Lower Tertiary play prospects, scheduled to come
online between 2010 and 2020, hold the promise of
a signifcant increase in natural gas production in the
Figure 1-45. Projection of U.S. Lower-48 Ofshore Gas Production – Low Natural Gas Production Pathway
0
1
2
3
4
5
2010 2015 2020 2025 2030 2035
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
Y
E
A
R
YEAR
AEO2010 REFERENCE CASE 2010
AEO2011 REFERENCE CASE 2011 AEO2011 HIGH OCS COST CASE 2011
AEO2011 LOW PRICE CASE 2011
Note: OCS = Outer Continental Shelf.
Sources: Energy Information Administration’s AEO2010 Reference Case and AEO2011 Reference Case.
Figure 1-45. Projection of U.S. Lower-48 Ofshore Gas Production –
Limited Natural Gas Production Pathway
138 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
ultra-deepwater environments that lack basic
infrastructure needed to produce and to transport
the hydrocarbons to shore.
y Canadian ofshore production of natural gas is low
in comparison to the U.S. lower-48, and is confned
to the eastern shore in Newfoundland and Nova
Scotia. Removal of the formal and de facto mora-
toria will provide opportunities to increase natu-
ral gas development and production in ofshore
Canada.
Arctic
History and Contcxt
Te section on Arctic oil, earlier in this chapter,
describes the geographical scope of the Arctic as used
for this study and includes a map of the region stud-
ied. Tis section of the work looked at the regions of
Alaska, Canada, and Greenland subject to ice condi-
tions that impact hydrocarbon exploration and devel-
opment activities.
As with oil, this Arctic region contains very substan-
tial natural gas recoverable resources that can justif-
ably be termed as a world-scale natural gas resource
region. Te discovered undeveloped and technically
recoverable undiscovered volumes from Alaska, Arc-
tic Canada, and Greenland are currently estimated at
about 670 Tcf, on a mean, risked basis. Tis estimate is
roughly equal to the oil resource on an energy equiva-
lent basis. Figure 1-46 shows how this resource is dis-
tributed across the major basins of the region. And
Figure 1-47 shows how this resource is proportionately
split between Alaska, Arctic Canada, and Greenland,
including those areas under drilling moratoria or oth-
erwise unavailable for leasing.
Te long history of onshore and ofshore oil and
gas leasing, licensing, and exploration drilling in
the Arctic region has resulted in the discovery of
signifcant oil and gas reserves. Some reserves
have been developed and produced, most notably
the giant oil and gas feld at Prudhoe Bay on the
Alaska North Slope and the large oil and gas felds
(onshore and ofshore in Cook Inlet, Alaska). Tere
are also numerous stranded discoveries (no develop-
ment/production facilities and/or pipelines) such as
the Burger discovery in the U.S. Chukchi Sea. Tis
region also is believed to contain signifcant undis-
covered volumes, based on numerous government
agency estimates and supported by industry interest
and western zones of the Gulf of Mexico, overall
natural gas production could be 20% lower than this
outlook.
Kcy Findings
Comprehensive review of North American ofshore
oil and gas facts and prospects has led us to the fol-
lowing fndings:
y Natural gas development and production in the
U.S. lower-48 is signifcant, and may deliver posi-
tive production growth to 2050. Annual growth
rate of ofshore natural gas production is expected
to range from negative 1.1% to positive 0.7%
through 2035.
y According to the AEO2011, natural gas production
in the U.S. lower-48 ofshore is expected to decline
from 2.4 Tcf in 2010 to 2.1 Tcf in 2035 in the low
price case. Overall, U.S. lower-48 ofshore natural
gas production is also expected to rise from 2.4 Tcf
in 2010 to 3.8 Tcf in 2035 in the high oil price case.
y Beginning around 2020 and extending to 2050, we
expect the bulk of natural gas production in the
lower-48 ofshore to originate from the deepwater
Gulf of Mexico, the Gulf of Mexico Lower Tertiary
formations, and the Pacifc and the Atlantic of-
shore regions.
y Government policies favorable to accessing addi-
tional U.S. lower-48 ofshore lands are needed to
reach natural gas development and production
growth rates stated above.
y We expect a slow down and a postponement of of-
shore natural gas development and production if
unduly constraining operation safety requirement
and stringent environmental policies are imple-
mented in the OCS following the Macondo oil
spill in the deepwater Gulf of Mexico.
y Technological progress and innovation are the
key factors that would enable development and
production of natural gas in new frontier regions
located in deep water and in deeper reservoirs.
y Seismic innovative technologies that allow clearer
imaging of the subsalt horizons in the Gulf of
Mexico are pivotal to the expansion of hydrocar-
bon resources via additional newer discoveries.
y Subsea technology and an extended architecture
system will boost production of ofshore natu-
ral gas in remote and challenging deepwater and
CHAPTER 1 - RESOURCES AND SUPPLY 139
Figure 1-47. Split of Arctic Natural Gas Resource Potential
Note: Discovered undeveloped plus undiscovered (mean risked, technically recoverable) resources.
GREENLAND
AVAILABLE 21%
CANADA
AVAILABLE
28%
ALASKA
AVAILABLE
38%
ALASKA MORATORIA
AREA 5%
ALASKA POTENTIALLY
AVAILABLE FOR LEASE 2%
CANADA
UNAVAILABLE 5%
GREENLAND
UNAVAILABLE 1%
ALASKA'S TOTAL SHARE 45%
CANADA'S TOTAL SHARE 33%
GREENLAND'S
TOTAL SHARE
22%
Figure 1-47. Split of Arctic Natural Gas Resource Potential
Note: Discovered undeveloped plus mean risked, technically recoverable, undiscovered resources.
ARCTIC CIRCLE
TRILLION CUBIC FEET OF GAS
INTERNATIONAL BOUNDARY
DISPUTED ZONE
2
19.6
8.2
25
8.5
90.8
112.1
33.5
76.1
40
10.2
86.2
33.7
41.2
66
Figure 1-46. Arctic Gas Potential by Basin
Figure 1-46. Arctic Gas Potential by Basin
140 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
in 2010 following the Macondo oil spill in the deep-
water Gulf of Mexico. Te combined BOEMRE and
USGS total mean estimate of risked, undiscovered,
technically recoverable natural gas resources for the
Beaufort Sea is 33.5 Tcf gas. Te Chukchi Sea is also
signifcantly underexplored but is estimated to hold
76.8 Tcf of risked, undiscovered, technically recov-
erable resources of natural gas. Previous ofshore
exploration wells have demonstrated the occurrence
of natural gas, as described by BOEMRE, in both of
these basins (Burger, Kuvlum, Hammerhead, Sand-
piper, Seal, and Tern).
Central Alaska Onshore
Tis region contains several basins of possible
interest (Yukon Flats and Nenana Basin) but lacks
signifcant subsurface data. Various assessments
suggest that this region could contain natural gas
(5–11 Tcf).
South Alaska Onshore and Cook Inlet
Te Cook Inlet Basin covers some 15,000 square
miles; almost half are ofshore. Te Cook Inlet
onshore and state waters area has more than
300 exploration wells and numerous mature felds,
both onshore and ofshore, that have produced oil
and gas since the early 1900s. New exploration in this
basin waned after the 1968 giant Prudhoe Bay Field
discovery in north Alaska. Te basin is generally con-
sidered a mature province. Te mean, risked, undis-
covered, technically recoverable resources for the
Cook Inlet area are 25 Tcf of natural gas. Te other
basins in this region (Aleutian Peninsular [onshore
Bristol Bay and State Waters], Gulf of Alaska [onshore
and State waters], and Copper River) are believed to
have undiscovered reserve potential but lack a mod-
ern resource assessment. Exploration wells have been
drilled in these basins (Aleutian Peninsular, 36 wells;
Copper River, 11 wells; and Gulf of Alaska onshore
and state waters, 55 wells) but have not so far yielded
a commercial discovery.
South Alaska O?shore
Te Bering Shelf, North Aleutian Basin and Pacifc
Margin have been assessed as very prospective for
natural gas resources. Te Bering Shelf has 19.6 Tcf of
technically recoverable natural gas resources includ-
ing 8.6 Tcf on the Aleutian shelf, while the Pacifc
Margin has a further 8.2 Tcf. Te Aleutian Shelf plan-
ning area was considered for leasing within the 2007–
(leasing/licensing, historical 2D seismic and mod-
ern but limited 3D seismic, and renewed attempts
to secure regulatory permission to drill particularly
in the ofshore). Most of the signifcant yet-to-be-
found volumes are believed to be contained in the
ofshore, beneath the continental shelf. Unlike oil,
there has not been major natural gas production in
the Arctic, except within the Cook Inlet region of
Alaska, mainly as the large proved reserves under the
Prudhoe Bay and Point Tomson felds on the Alaska
North Slope and the felds on the Mackenzie Delta
have been unable to access the market as a result of
lack of pipeline infrastructure.
Following is a brief summary of the development
and production history for the most signifcant of the
main Arctic areas under consideration.
North Alaska Onshore
Exploration drilling in this region began in 1945
and discovered only non-commercial hydrocarbons
until the discovery of the giant Prudhoe Bay feld in
1968. Tis feld contained recoverable reserves of
15 billion barrels of oil and 27 Tcf of natural gas. Oil
has been produced from this feld since 1977, but the
produced associated natural gas has not been com-
mercialized due to the lack of a gas pipeline, and the
bulk of the produced gas has been and still is reinjected
back into the producing reservoir to enhance ongoing
oil recovery. Signifcant stranded gas (~8 Tcf) has also
been discovered at Pt. Tomson Field along the coastal
plain near the ANWR 1002 area. Many of the more
than 400 exploration wells drilled on or around the
North Slope coastal plain have shown non-associated
gas, particularly in the southern part of the region. In
addition, prospective areas outside of the North Slope
Coastal Plain (NPR-A, North Slope Foothills and the
ANWR 1002 area) are signifcantly underexplored.
Further, it is expected that the NPR-A and North Slope
Foothills region may have a higher endowment of gas
than oil.
North Alaska O?shore
Tere are 186 active leases in the Beaufort Sea,
most of which were issued following U.S. federal
lease sales held in 2005 and 2007. In the Chukchi
Sea, 487 leases were issued following a U.S. federal
lease sale in 2008. However, these leases had not
yet been drilled as of mid 2011, as a result of issues
outside the control of lessees, up to and including
the suspension of authorizations for Arctic drilling
CHAPTER 1 - RESOURCES AND SUPPLY 141
ventional oil and gas potential resides in immediately
ofshore basins with little potential in the adjacent
onshore areas. No quantitative assessments have
been conducted for the south and southeastern
ofshore margin of Greenland. Te ofshore acreage in
Greenland is administered by the Greenland Bureau
of Minerals and Petroleum.
Tcchnology
From the perspective of hydrocarbon exploration,
development, and production, natural gas activities
in the Arctic are subject to similar considerations as
those for oil, described in the Arctic oil section of this
chapter. Natural gas development in the Arctic faces
the additional challenge of required long-distance
pipelines to access markets in Canada and the United
States. Natural gas is not currently exported of the
North Slope, Mackenzie Delta/Canadian Beaufort,
Arctic Islands/Sverdrup Basin, or Labrador Shelf
because there is no gas pipeline infrastructure to
transport the gas to markets. Alternatives such as
tankering gas in the form of LNG or building a gas-
to-liquids plant which could convert the natural gas to
a higher density liquid product for transport through
the TAPS system have reportedly been studied,
but until recently have not been deemed economi-
cally competitive. Recent activity has been directed
toward developing the concept of a natural gas pipe-
line to move natural gas to market, as witnessed by
the Denali, TransCanada and Mackenzie Valley gas
pipeline proposals of recent years. Until export capa-
bilities are developed for the Alaska North Slope, the
majority of the gas will continue to be reinjected into
the producing reservoirs to enhance oil production,
and used locally for energy and heating. Meanwhile,
Mackenzie Delta and Canadian Beaufort gas remains
unproduced.
Potcntial Production Pathways
Given that no overall North American Arctic sup-
ply outlooks could be found in the public domain
(although there are a few basin-specifc analyses for
portions of Alaska and the Canadian Arctic), the Arc-
tic Subgroup developed three consensus cases: Lim-
ited Potential (reasonably constrained), Most Likely,
and High Potential (reasonably unconstrained).
Te adjective “reasonably” is used with care; it does
not imply that all constraints are either present or
removed. It represents the Subgroup’s informed view
of what may happen to Arctic development through
2012 5-Year Leasing Program. However, OCS Sale
214, scheduled for 2011, was removed from the sale
schedule by the Secretary of the Interior in the spring
of 2010 and the area is now under a Presidential with-
drawal from lease sales till June 2017.
Canadian North
Te Canadian North region contains onshore
basins in British Columbia, Yukon, Northwest Ter-
ritories, and Mackenzie Delta region, as well as the
ofshore Canadian Beaufort Sea area, Arctic Islands/
Sverdrup Basin area. Te National Energy Board of
Canada estimates the mean, risked, undiscovered,
technically recoverable resources for the Canadian
North Onshore basins as containing 1 Tcf gas. Te
NEB estimates the mean, risked, undiscovered,
technically recoverable resources for the Mackenzie
Delta/Canadian Beaufort Basin area as containing
52 Tcf gas. Te NEB estimates mean, risked, undis-
covered, technically recoverable resources for the
Arctic Islands/Sverdrup Basin as containing 28 Tcf
gas. In addition, the USGS has assessed the Canadian
Beaufort Outer Continental Slope region (outboard
of the Canadian Beaufort and Arctic Islands/Sver-
drup Basin areas) and estimates mean, risked, undis-
covered, technically recoverable resources of 15.1 Tcf.
Canadian East
Te Canadian East region is divided into the Cana-
dian Bafn Bay area (adjacent to the West Greenland)
and the Labrador/Newfoundland Shelf. Te southern
limit of the study area excludes the Scotian Shelf and
associated developments at Sable Island, where natu-
ral gas has been produced over the last decade. Te
Canadian Bafn Bay area is estimated to have a mean,
risked, undiscovered, technically recoverable natural
gas resource of 33.7 Tcf, based on ascribing 45% of
the USGS analysis of the West Greenland-East Canada
“Bafn basin” to the Canadian portion of this region,
while the Labrador-Newfoundland shelf is estimated
to hold 57 Tcf of natural gas.
Greenland
Te natural gas resources on the Continental mar-
gin ofshore Greenland are estimated as follows; West
Greenland 41.2 Tcf, North Greenland 10.2 Tcf, and
the East Greenland Rift Basins 86.2 Tcf, based on
ascribing 55% of the USGS analysis of the West Green-
land-East Canada “Bafn Basin” to the Greenland por-
tion of this region. Te USGS believes most of the con-
142 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
It should be noted that the Arctic Subgroup’s gas
production cases for Alaska may be conservative, as
compared to a published analysis by Northern Eco-
nomics suggesting that the U.S. Beaufort and Chuk-
chi OCS regions are capable of signifcant natural
gas production if the reported undiscovered hydro-
carbon resource assessment by the BOEMRE is vali-
dated by future exploration and appraisal drilling.
Te Northern Economics gas production forecast is
contained in Table 1-7 and Figures 1-29 and 1-30
(pages 99-100).
Kcy Findings
Te key fndings and recommendations relative
to Arctic development are included in the Arctic oil
section earlier in this chapter. Tere are no further
specifc fndings and recommendations relating only
to Arctic natural gas.
Onshorc Gas
Production History and Contcxt
Te onshore natural gas component of North
American supply includes both conventional and
unconventional gas as developed and produced in
onshore basins in the United States and Canada, with
the exception of onshore Arctic basins.
Currently, onshore gas from Canada and the United
States supplies over 95% of the natural gas con-
sumed in both these nations. Overall U.S. produc-
tion has increased signifcantly since 2005, with U.S.
2050, given economic, regulatory, and environmental
constraints that are less, or more, favorable to such
development.
Te three cases each outline a diferent production
scenario for major current or future developments.
Large, remote severely stranded resources (e.g., Cana-
dian Arctic Islands, NE Greenland Rift Basin) are not
included. Table 1-15 summarizes the assumptions
specifc to natural gas in these three scenarios.
Te most likely case is expected to lead to Arc-
tic production of 2 Tcf/yr (5.5 Bcf/d), based on
pipelines being developed in both Alaska and the
Mackenzie Delta/Canadian Beaufort to take gas to
market by around the middle of the 2020s. On the
Alaska side, this would amount to 1.6 Tcf/yr, with a
further 0.4 Tcf from the Mackenzie Delta and Cana-
dian Beaufort Sea.
In the Limited Potential case, these sources of gas
would remain stranded, assuming that the required
infrastructure development would not occur with
continuing economic and regulatory challenges act-
ing as a disincentive to the project proponents.
In the High Potential case, it is assumed that a
higher pace of resource development activity in
Alaska, including new ofshore areas and the Mack-
enzie Delta/Canadian Beaufort, would justify expan-
sions of the two pipeline systems by 2025, allowing
increases in production to a total of 2.9 Tcf/yr (almost
8 Bcf/d), of which about 2.2 Tcf would be from Alaska
and the remainder from the Canadian north.
Table 1-15. Three Potential Arctic Gas Production Pathways
Limited Potential Case Most Likely Case HIgh Potential Case
No Alaska gas pipeline Alaska gas pipeline;
4.5 Bcf/d, 2025
Alaska gas pipeline expansion;
5.9 Bcf/d, 2035
No Mackenzie gas pipeline Mackenzie gas pipeline;
1.2 Bcf/d, 2025
Mackenzie gas pipeline; expansion;
1.8 Bcf/d, 2035
No North Alaska, Chukchi or
Beaufort OCS, or Canadian Beaufort
production
North Alaska, Chukchi & Beaufort
OCS, and Canadian Beaufort
production; 15% resource
developed by 2050
North Alaska, Chukchi, and
Beaufort OCS, and Canadian
Beaufort production; 25% resource
developed by 2050
No Arctic Islands/Sverdrup Basin,
Labrador, or Grand Banks gas
No Arctic Islands/Sverdrup Basin,
Labrador, or Grand Banks gas
Labrador and Grand Banks gas;
10% resource developed by 2050
CHAPTER 1 - RESOURCES AND SUPPLY 143
begun in Canada, most notably in the Montney (silt-
stone) and the Horn River basin, but has not as yet
arrested the decline in overall production there.
U.S. (Bcf/d dry) and Canadian (Marketable)
Production Mix – Conventional and
Unconventional Sources 2000–2010
Unconventional production has increased from
approximately one-third of the total U.S. supply
mix in 2000, to nearly two-thirds in 2010, or from
33 to 63% of the total (Figure 1-48). Te increase
in U.S. production since 2005 is almost entirely due
to shale gas. Growth from this source alone exceeds
total U.S. production growth over this period. Shale
gas and coalbed methane represent a growing
percentage, currently approximately 11%, of overall
production in Canada. U.S. lower-48 and non-Arctic
Canada onshore gas production in 2009 is estimated
at 24.1 Tcf/yr.
Te focus on unconventional resource plays –
tight gas, coalbed methane, and shale gas – has also
arrested a previous decline in average well productiv-
ity, increased reserves per well drilled, and lifted the
dry natural gas production reaching an average of
57.8 Bcf/d in 2010. Tis dry production level repre-
sents an increase of 16% from the recent historic low
of 49.7 Bcf/d in 2005, and is the highest overall U.S.
production rate since 1973.
Production of natural gas from shale as a category
is largely responsible for the overall production
increase in the United States, having grown the most
in both absolute and percentage terms since 2000.
In 2000, shale gas production was approximately
1.0 Bcf/d, or about 2% of the U.S. supply mix. Shale
production had grown to approximately 11.6 Bcf/d
by 2010, representing approximately 20% of the
57.8 Bcf/d of estimated dry U.S. production
(Figure 1-48). Production from tight formations
has also increased in both absolute and percent-
age terms, increasing from 12.0 Bcf/d in 2000 to
19.9 Bcf/d in 2010, or from 23% to 34% of the total
over the period. When adding U.S. coalbed meth-
ane production, also considered “unconventional,”
production from unconventional sources has more
than doubled in the United States since 2000 –
increasing by 19.2 Bcf/d, from 17.2 Bcf/d in 2000,
to 36.4 Bcf/d in 2010. Shale gas production has also
Figure 1-48. U.S. and Canadian Production Mix, 2000–2010
0
20
40
60
80
2000 2002 2004 2006 2008 2010
B
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
D
A
Y
YEAR
U.S. CONVENTIONAL
U.S. SHALE
U.S. TIGHT
U.S. CBM CANADIAN CONVENTIONAL
AND TIGHT CANADIAN SHALE
CANADIAN CBM
Note: CBM = coalbed methane.
Sources: Energy Information Administration; National Energy Board of Canada; and Wood Mackenzie.
Figure 1-48. U.S. and Canadian Production Mix, 2000–2010
144 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
and reserve trends should be expected, as tight gas
and shale gas production profles exhibit substan-
tially higher initial production rates and recoverable
reserves than conventional wells. Although uncon-
ventional wells are fewer in number, their prolifc
production and reserve additions have reversed a
declining trend.
Te frst widespread deployment of new drill-
ing and completion technologies focused on shale
gas was concentrated in the Barnett Shale play, in
northeast Texas. Te play, in active development
since the early 1990s, grew in importance from the
mid-2000s. Breakthroughs in technology trans-
formed the play into a prolifc producing area start-
ing in 2005. Peak month production in the Barnett
shale play increased by at least 60%, or by more than
500 Mcf/d per well, in the 2005–2009 period, com-
pared to 1990–2000.
While the Barnett Shale was an early success in
shale gas development, other plays are still being dis-
covered, with the Eagle Ford, Montney (siltstone),
Horn River, and the Marcellus Shale still in early,
but rapid development (Figure 1-50). Additional
reserve life index. Shale gas plays are dominating the
unconventional spectrum, although both tight gas
and coalbed methane continue to contribute to this
trend of increased productivity.
As shown on an annual basis in Figure 1-49, total
North American gas production reached a new high
of 27.3 Tcf in 2009 following a period of approxi-
mately fat production over the previous nine years,
despite a 57% increase in the well count. Te upturn
in production since 2005 coincides with the rapid
development of unconventional gas within North
America, particularly shale gas. Figure 1-49 includes
production and well counts from the Gulf of Mexico,
as the ofshore component was not identifed sepa-
rately within this particular 20-year data set. Te
Gulf of Mexico accounts for about 10% of produced
volumes.
Production and reserves from newly drilled wells
have increased since 2006, suggesting that not only
do these newly drilled wells replace natural declines
in rates and reserves in historical wells but they add
considerably more incremental rate and reserves per
well. Such a reversal of historical gas production
Figure 1-49. North American Gas Production and Operating Gas Wells
0
10
20
30
0
200
400
600
800
1,000
1989 1995 2000 2005 2010
T
R
I
L
L
I
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N
C
U
B
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F
E
E
T
W
E
L
L
C
O
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N
T
T
H
O
U
S
A
N
D
S
YEAR
NORTH AMERICAN GAS WELLS
NORTH AMERICAN ANNUAL GAS PRODUCTION
Note: Gulf of Mexico gas production and well count is included in North American data.
Sources: Wood Mackenzie; U.S. Energy Information Administration.
Figure 1-49. North American Gas Production and Operating Gas Wells
CHAPTER 1 - RESOURCES AND SUPPLY 145
Key Technology – Commercialization of Shale
as a Resource
Shale gas production can be traced back to the
mid-1800s, but until recently was a rather insignif-
cant source of energy. Once considered only a mar-
ginal producer, a source rock for hydrocarbons, or
as an impermeable barrier or seal for conventional
reservoirs, it is now a primary target for commercial
drilling. Tese ultralow-permeability reservoirs are
routinely exploited. Tis is made possible through
a combination of technologies, directional drilling,
seismic, lateral wellbores (horizontal wells), and
hydraulic fracturing. Without these technologies,
most shale reservoirs would not be commercial today.
Hydraulic fracturing is the most critical advance for
natural gas supply for North America.
Key Technology – Hydraulic Fracturing
First implemented for natural gas production in
1947 in the Hugoton gas feld, fracturing increases the
contacted surface area within a reservoir. Reservoir
rock is fractured by pumping high-pressure water with
a sand slurry that props the fractures open. Because
shale resource plays, including the Duvernay, Utica,
Collingwood, and others, wait in the wings, providing
a large future resource base for North American natu-
ral gas supplies.
Kcy Dcvclopmcnt and Production
Tcchnologics
Development of natural gas has recently been
dominated by the application of new technology,
especially the development of cost-efective fracture
stimulation in horizontal wellbores. Both horizontal
drilling and fracture stimulation have been in use for
decades. Fracture stimulation was frst implemented
in a gas feld in 1947 in the Hugoton gas feld and gas
from shale has been produced for more than a cen-
tury. Experimentation with horizontal drilling goes
back as far as the 1920s, although the frst commer-
cial application didn’t take place until the mid-1980s
in the Austin Chalk formation.
Following are some key milestones in develop-
ment and application of technologies to unlock North
America’s natural gas resources follow.
Figure 1-50. Production by Shale Play: Growing Beyond the Barnett
0
4
8
12
2000 2001 2002 2003 2004 2005
YEAR
2006 2007 2008 2009 2010
B
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L
I
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N
C
U
B
I
C
F
E
E
T
P
E
R
D
A
Y
BARNETT FAYETTEVILLE WOODFORD HAYNESVILLE
MARCELLUS EAGLE FORD HORN RIVER MONTNEY AND DUVERNEY
Source: Wood Mackenzie.
Figure 1-50. Production by Shale Play: Growing Beyond the Barnett
146 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
It was not until the 1980s that notable commercial
horizontal wells were drilled in North America in the
Austin Chalk, Bakken, and Niobrara formations.
17
As technology improved, horizontal drilling enabled
previously, non-commercial formations to become
economic.
18
By the 1990s, more than 1,000 horizon-
tal wells had been drilled throughout the world.
19
After initial commercialization of the technique,
efciencies continued to improve, yielding longer
lateral lengths per well and ultimately continuing to
decrease surface disturbance. In 1987, the frst hori-
zontal wells in the Bakken Shale were of relatively
modest lengths of approximately 1,000 feet. By
the 1990s, as technology improved, lateral lengths
of 3,000 to 4,000 feet were possible, and today
wells are routinely drilled with lateral lengths of
10,000 feet.
Key Technology – Modern (3D) Seismic
Technology
Te increase in activity during the 1980s was also
spurred by the advent of 3D seismic technology. Te
exploration success rate increased, resulting in pre-
viously uneconomic plays becoming tenable. Today,
seismic data is processed using computer algorithms
that assist in identifying anomalies in the data. Tese
anomalies may be identifed as hydrocarbon depos-
its. From 1990 through 2001, the overall costs of
3D seismic imaging decreased by a factor of fve. Sur-
veys conducted by Te American Oil and Gas Reporter
as well as the Petroleum Technology Transfer Council
indicate that seismic technology has been highly ben-
efcial to the industry.
20
Modern seismic imaging techniques allow for
improved recognition of formation types and char-
acteristics. Te use of modern seismic technol-
ogy has allowed wells to be drilled while avoiding
17 Flores, C. P., “Technology and Economics Afecting Unconven-
tional Reservoir Development,” Master’s Tesis, Texas A&M
University, December 2008.
18 Joshi, S. D., “Cost/Benefts of Horizontal Wells,” SPE paper
83621 for SPE Western Regional/AAPG Pacifc Section Joint
Meeting, Long Beach, California, 2003.
19 Energy Information Administration, “Drilling Sideways – A
Review of Horizontal Well Technology and Its Domestic Appli-
cation,” Contract No. DOE/EIA-TR-0565, U.S. DOE, Washing-
ton, DC, April 1993.
20 Ammer, James, “Tight Gas Technologies for the Rocky Moun-
tains,” GasTIPS, Spring 2002, pages 18–23.
the frst fracturing treatment included no propping
agent to maintain conductivity within the induced
fractures, it proved unsuccessful. By 1949, hydrau-
lic fracturing was successfully implemented in the
Woodbine sands in East Texas and became commer-
cially viable.
13
Since then, many improvements have
been made to reliability and safety. By hydraulically
fracturing a gas reservoir, the efective permeability,
or capacity to fow, can be signifcantly increased. In
fact, with no stimulation treatment, many currently
producing reservoirs would be considered imperme-
able. Successful stimulation treatments can increase
permeability by fve to six orders of magnitude.
14
By
1955, more than 3,000 fracturing treatments were
pumped each month. Troughout the 1960s and
1970s, fracturing became better understood and
could be optimized for a particular formation.
15
Oper-
ational efciency improvements resulted in cost sav-
ings, making more plays economic. Today, coil tub-
ing fracturing technology has resulted in shorter time
requirements per fracture induced, and multiple zone
fractures can be completed in a short time. According
to the Independent Petroleum Association of Amer-
ica, approximately 90% of new gas well production
relies on hydraulic fracturing.
Key Technology – Horizontal Drilling
In horizontal well drilling, a well is drilled par-
allel to the formation, exposing more reservoir
rock than would be possible using a conventional
vertical completion technique.
16
By increasing
the length of the horizontal portion of the well,
multiple vertical well locations were replaced
with a single horizontal well for a fraction of the
cost, minimizing surface disturbance. As early
as 1927, the concept of drilling horizontally
through the producing formation was tested in
North America; however, many of the technique’s
early advances were made in Bashkiria, Russia.
13 Economides, M. J. and K. G. Nolte, Reservoir Stimulation, third
edition. (West Sussex: Wiley, 2000), page 367.
14 Economides et al., Petroleum Production Systems (New Jersey:
Prentice Hall, 1994), page 600.
15 Holditch, S. A., and N. R. Tschirhart, Optimal Stimulation
Treatments in Tight Gas Sands, SPE Paper 96104 for SPE Annual
Technical Conference and Exhibition, Dallas, Texas, 2005.
16 Sheikholeslami et al., “Drilling and Production Aspects of
Horizontal Wells in the Austin Chalk,” SPE Journal of Petroleum
Technology, July 1991, pages 773–779.
CHAPTER 1 - RESOURCES AND SUPPLY 147
tools to exact specifcations. Because of advances
in computer numerical control milling technology,
production times have been signifcantly reduced.
Downhole equipment is also more robust. Robotic
controllers are now used, especially in high-pressure
high-temperature environments. Prior to these
advances in electronic technology, many hydrocarbon
reservoirs were efectively inaccessible.
Advancing Technologies
Te following areas of ongoing research associated
with natural gas production will result in improved
recoveries and operational efciencies in the near
term:
y Fracturing technology
y Surface disturbance minimization
y Super-pad drilling
y Slim-hole completions
y Fit-for-purpose Coiled Tubing Drilling
y Multilateral wells.
potential water zones and areas of high faulting.
Although much work is still needed in this area, this
technology has increased the likelihood of drilling
locations of high productivity while decreasing the
chances of drilling low productivity wells.
Key Technology – Te Personal Computer
Technological improvements in computer process-
ing power have also resulted in tremendous efciency
gains. Prior to the widespread use of personal com-
puters, simulations and other rigorous mathematical
modeling required mainframe computer time. Tis
proved both cost and time prohibitive. Personal com-
puters have become ubiquitous in the industry, allow-
ing engineers and geologists to routinely execute
complex mathematical models to simulate reservoirs
and basins. Tis has been refected in metrics that
track worker productivity, as shown in Figure 1-51.
Te personal computer led to increases in worker
efciency and has enabled a host of other products.
Computer-aided design (CAD) software packages
are used in conjunction with computer numeri-
cal control machining to produce sophisticated
Figure 1-51. U.S. Total Well Count per Employee
0
2
4
6
8
0
100
200
300
400
1970 1980 1990 2000 2010
P
R
O
D
U
C
I
N
G
O
I
L
A
N
D
G
A
S
W
E
L
L
S
P
E
R
E
M
P
L
O
Y
E
E
N
U
M
B
E
R
O
F
E
M
P
L
O
Y
E
E
S
T
H
O
U
S
A
N
D
S
O
I
L
A
N
D
G
A
S
W
E
L
L
S
D
R
I
L
L
E
D
P
E
R
E
M
P
L
O
Y
E
E
X
1
,
0
0
0
YEAR
EMPLOYMENT IN EXPLORATION AND PRODUCTION
OIL AND GAS WELLS DRILLED/EMPLOYEE X 1,000
PRODUCING WELLS PER EMPLOYEE
Source: Bureau of Labor Statistics, 2010.
Figure 1-51. U.S. Total Well Count per Employee
148 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
For the production pathways analyzed here, the
NPC team used the resource data supporting the
Massachusetts Institute of Technology energy initia-
tives (MITei) report. Te data provide a reasonable
range of estimates in a format useful for scenario
building. MITei uses the North American supply
model developed by ICF, which provides for a high-
medium-low look using “current” technology and
the same for an “advanced” technology case, result-
ing in six diferent model outputs for consideration.
It should be noted that “current” refers to technol-
ogy applied in 2007 or earlier. Given recent break-
throughs, today’s application of technology renders
the “Advanced Technology” cases more relevant
today. For the purposes of this study, it was decided
to focus upon three onshore, non-Arctic resource
size cases:
y Case One – MITei/ICF Mean Resource Base, Cur-
rent (2007) Technology, Remaining Recoverable
Resource 1,901 Tcf, Estimated Ultimate Recover-
able Resource 2,996 Tcf. Te consensus view of the
NPC team is that this case is conservative and it is
highly probable that it will be surpassed.
y Case Two – MITei/ICF Mean Resource Base,
Advanced Technology, Remaining Recoverable
Resource 2,890 Tcf, Estimated Ultimate Recover-
able Resource 3,985 Tcf. Te consensus view of the
NPC team is that this case is also rather conservative
and it is probable that it will be surpassed.
y Case Tree – MITei/ICF High Resource Base,
Advanced Technology, Remaining Recoverable
Resource 3,561 Tcf, Estimated Ultimate Recover-
able Resource 4,656 Tcf. Te consensus view of the
NPC team is that this case is reasonable today and
could readily be surpassed.
Figure 1-52 illustrates the supply cost stack for
these three cases. Tis fgure shows gas resource
volumes on the horizontal axis plotted against cost
of supply ($/MMBtu) on the vertical axis. Te scale
is truncated at $30/MMBtu. Historical cumulative
gas production rose above 1,000 Tcf in 2006. The
estimated ultimate recoverable gas resources for the
three cases are plotted in Figure 1-52.
Te additional resources that might be recover-
able at costs above $20/MMBtu appear to be rela-
tively small, so comparisons among the cases can be
made at this level. Ultimate recoverable resources,
including cumulative production to date, range
Future Technology
Of natural gas production in the United States
in 2008, approximately 40% of the wells required
hydraulic fracturing stimulation to produce at
economic rates.
21
According to the Independent
Petroleum Association of America, approximately
90% of new gas wells rely on hydraulic fracturing to
produce.
22
Without both hydraulic fracturing and hor-
izontal drilling, future production growth in onshore
natural gas cannot be achieved and any reservoir
termed “unconventional” would be uneconomic. Te
EIA has modeled natural gas supply for a scenario
with no additional tight gas production. In this sce-
nario, natural gas production from onshore North
America falls by 39%. From these estimates it can be
seen that the future of natural gas supply in North
America will rely upon future availability and contin-
uous improvement in fracturing tight gas and shale
gas formations.
Production Potcntial
Potential for future production of onshore gas has
been transformed by development and application of
the technologies described in the previous section. A
number of studies have quantifed the resource base
and these assessments are included in Table 1-16.
Te most important realization from these stud-
ies is that in less than a decade, estimates of the
North America resource base have grown by more
than 150%. Te most recent study sponsored by
America’s Natural Gas Alliance includes a compre-
hensive geological and engineering based model of
32 unconventional plays, including shale gas, tight
gas sands, and coalbed methane formations. Tese
unconventional plays alone were projected to have
recoverable reserves over 2,600 Tcf. Tis recent
study, in combination with the consistent trend of
resource growth, provides a compelling argument
that the resource base is large. With sufcient con-
fdence in the underlying resource base, the focus
can shift to questions regarding supply and rates of
development.
21 Energy Information Administration, (2010a) Annual Energy
Outlook 2010 With Projections to 2035, (2010b) Natural Gas
U.S. Data. Retrieved fromhttp://www.eia.doe.gov/oil_gas/
natural_gas/info_glance/natural_gas.html.
22 Tiemann, Mary, Congressional Research Service, June 2, 2010.
Safe Drinking Water Act (SDWA): Selected Regulatory and
Legislative Issues, page 22.
CHAPTER 1 - RESOURCES AND SUPPLY 149
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150 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
(Should market needs be greater over this time
period, other supply sources, such as ofshore gas,
Arctic gas, or imported LNG would also be called
upon to complete the supply mix.)
y Restricted Supply Scenarios – Here assumptions
are analyzed to estimate the efects of various pos-
sible restrictions or constraints (such as limitations
on fracturing and resource access) on industry’s
ability to supply onshore gas. Two of these sce-
narios are illustrated in the following fgures: from
extreme limitations to supply (Figure 1-55) to mod-
erate limitations to supply (Figure 1-56). Clearly,
these assumptions would have a drastic efect on
the ability to supply North America gas domesti-
cally. Te remaining resource would be reduced by
over 70% compared to the unrestricted Flat Supply
scenarios, and potential plateau supply would be
eliminated entirely under the most extreme restric-
tions, such as disallowing hydraulic fracturing.
Plateau (fat) supply would be reduced from the
approximate 80–90 years, to approximately 40–50
years by assuming 33% restrictions on unconven-
tional supply.
from ~3,000 Tcf in Case One up to ~4,700 Tcf with
advanced technology in Case Tree.
With this understanding of the potential resource
base, we analyzed implications for supply potential
for the onshore non-Arctic segment of North Ameri-
can gas under several scenarios.
y Flat Supply Scenario – at a constant 24 Tcf/yr,
equal to current production rates, until beginning
of decline, the variation in remaining resource esti-
mates has a signifcant efect on the duration of pla-
teau supply length. As illustrated in Figure 1-53,
approximately fve to nine decades at this produc-
tion level are possible, followed by signifcant post-
plateau supply.
y Supply Growth Scenario – An increased rate of
supply scenario, whereby supply is assumed to
increase approximately 50% from 24.1 Tcf/yr to
36.5 Tcf/yr. Te increase takes place to achieve this
higher supply plateau in approximately one decade.
Tis plateau could be maintained for between two
and four decades after 2020, based on the resource
estimates used, as illustrated in Figure 1-54.
$0
$10
$20
$30
0 1,000 2,000 3,000 4,000 5,000 6,000
ULTIMATE RECOVERABLE RESOURCE (TRILLIONS OF CUBIC FEET)
Figure 1-52. Onshore Natural Gas Recoverable Resource Cases versus Cost of Supply at the Wellhead
WAS Figure ES-2
2,996
W
E
L
L
H
E
A
D
S
U
P
P
L
Y
C
O
S
T
(
D
O
L
L
A
R
S
P
E
R
M
I
L
L
I
O
N
B
T
U
)
3,985 4,656
100 YEARS OF
CONSUMPTION
AT CURRENT RATES
CUMULATIVE
PRODUCTION
THROUGH 2010
Note: See page 107 for case defnitions.
Sources: Energy Information Administration and MIT Energy Initiative (MITei)/ICF International.
CASE ONE
CASE TWO
CASE THREE
Figure 1-52. Onshore Natural Gas Recoverable Resource Cases versus Cost of Supply at the Wellhead
CHAPTER 1 - RESOURCES AND SUPPLY 151
Figure 1-54. Supply Growth Scenario
YEARS FLAT CONSUMPTION
2,100 TCF
TERMINAL
DECLINE
VOLUME
4,656 TCF
ULTIMATE
RESOURCE
1,500 TCF
TERMINAL
DECLINE
VOLUME
900 TCF
TERMINAL
DECLINE
VOLUME
3,985 TCF
ULTIMATE
RESOURCE
2,996 TCF
ULTIMATE
RESOURCE
20 0 31 33
1.4 TCF/YR GROWTH
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
HISTORY
Note: Supply Growth Scenario – 5% growth per year to 100 billion cubic feet per day.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
HISTORY
CASE ONE
CASE TWO
CASE THREE
Figure 1-54. Supply Growth Scenario
Figure 1-53. Flat Supply Scenario
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
YEARS FLAT CONSUMPTION
1,400 TCF
TERMINAL
DECLINE
VOLUME
4,656 TCF
ULTIMATE
RESOURCE
1,000 TCF
TERMINAL
DECLINE
VOLUME
600 TCF
TERMINAL
DECLINE
VOLUME
3,985 TCF
ULTIMATE
RESOURCE
2,996 TCF
ULTIMATE
RESOURCE
54 0 78 90
HISTORY
HISTORY
CASE ONE
CASE TWO
CASE THREE
Figure 1-53. Flat Supply Scenario
152 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-55. Extremely Restricted Supply Scenario – Extreme
YEARS FLAT CONSUMPTION
1,013
2,108
824
600
1,919
1,787
4 0
TCF ULTIMATE RESOURCE
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
HISTORY
CASE ONE
CASE TWO
CASE THREE
TCF TERMINAL
DECLINE VOLUME
Notes: Extremely restricted supply scenario – fracturing impact, no shale technology enabled.
Year-end 2009 cumulative = 1,095 TCF.
Cases Two and Three have immediate terminal decline.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
Figure 1-56. Moderately Restricted Supply Scenario
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
YEAR
HISTORY
Notes: Moderately restricted supply scenario – fracturing impact, 67% tight/coalbed methane/shale technology enabled.
Year-end 2009 cumulative = 1,095 TCF.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
YEARS FLAT CONSUMPTION
1,400
3,789
1,000
600
3,283
2,587
0 37 49 54
HISTORY
CASE ONE
CASE TWO
CASE THREE
TCF ULTIMATE RESOURCE
TCF TERMINAL
DECLINE VOLUME
Figure 1-55. Extremely Restricted Supply Scenario
Figure 1-56. Moderately Restricted Supply Scenario
CHAPTER 1 - RESOURCES AND SUPPLY 153
draw on any particular resource type, the potential
amount of natural gas that would be produced over
the lifetime of the wells drilled between 2010 and
2050 was checked against public estimates of recov-
erable resources by type.
Te estimated production by resource type and
pace of onshore natural gas drilling to maintain com-
bined U.S. and Canadian production at current levels
of roughly 66 Bcf/d for the Flat Supply Scenario is
indicated in Figures 1-58 and 1-59.
Increasing output of shale gas rises to about 60%
of the total and is able to ofset declines in conven-
tional and coalbed methane production to maintain
production. As shale gas wells produce at higher
rates than many of the conventional, coalbed meth-
ane, and tight gas wells relied on previously, the
absolute number of new onshore gas wells required
to maintain current production remains less than
60% of the peak 2006 level.
To achieve signifcant increases in combined
U.S. and Canadian production to roughly 100 Bcf/d
by 2020, and maintain that level thereafter, would
Figure 1-57 provides a summary of Flat Supply,
Supply Growth, and Extremely Restricted Scenarios
using the mid-range estimate of recoverable resources
(Case Two), and as such provides a guide to the poten-
tial for reasonably unconstrained, most likely, and
constrained production pathways.
To further test the reasonableness of these poten-
tial production pathways, the study team ana-
lyzed the magnitude of input requirements needed.
Details of the methodology and results are described
in Topic Paper #1-8, “Onshore Natural Gas,” available
on the NPC website. Here we summarize the indica-
tive requirements of rigs, industry personnel, tubular
(steel) tonnage, proppant, and fracture stimulation
water usage required to support both the Flat Supply
and Supply Growth scenarios.
Based on expectations of relative economics of
the major natural gas types, it was assumed that
increases in drilling would primarily target shale
gas, and to a lesser extent tight gas. Conventional
gas and coalbed methane drilling were assumed to
remain essentially fat at around current levels over
the period to 2050. To avoid a disproportionate
Figure 1-57. Comparison of Three Supply Scenarios:
Mean Resource Base, Advanced Technology, and 2007 Cost Index
0
10
20
30
40
1900 1920 1940 1960 1980 2000 2020 2040 2060 2080 2100 2120 2140 2160 2180 2200
YEAR
Note: Year-end 2009 cumulative = 1,095 TCF.
Sources: Canadian Association of Petroleum Producers; Cedigaz; Energy Information Administration; National Energy Board of Canada;
and United States Geological Survey.
HISTORY
FLAT SUPPLY
SUPPLY GROWTH
EXTREMELY RESTRICTED SUPPLY
T
R
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
T
C
F
P
E
R
Y
E
A
R
Figure 1-57. Comparison of Three Supply Scenarios: Mean Resource Base,
Advanced Technology, and 2007 Cost Index
154 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Figure 1-58. Onshore North American Gas Production in Flat Supply Scenario
0
20
40
60
80
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
B
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
D
A
Y
YEAR
SHALE TIGHT COALBED METHANE CONVENTIONAL
Figure 1-59. Projected Wells Required in Flat Supply Scenario
0
20
40
60
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
W
E
L
L
S
T
H
O
U
S
A
N
D
S
YEAR
SHALE TIGHT COALBED METHANE CONVENTIONAL
Figure 1-58. Onshore North American Gas Production in Flat Supply Scenario
Figure 1-59. Projected Required Wells Required in Flat Supply Scenario
CHAPTER 1 - RESOURCES AND SUPPLY 155
activity is generally consistent with historical levels.
Employment would increase. High horsepower rigs
(1,500 horsepower or more) are estimated at approxi-
mately 25 to 33% of the total gas rig count.
Figure 1-63 illustrates the fracture stimulation
activity-related input requirements for U.S. lower-48
and non-Arctic Canada onshore gas supply, including
fracture stimulation stages, fracture proppant, and
initial water (without diferentiation between pri-
mary and re-used water) required for fracture stimu-
lation. Te Flat Supply scenario is expected to require
historically similar overall numbers of fracture stimu-
lation stages and proppant compared to recent levels.
Te Supply Growth scenario would require approxi-
mately 50% greater fracture stimulations overall by
2050 than recent history. Water (primary and re-use)
for fracture stimulations would increase, depending
upon scenario, by approximately 50–125% overall
by 2050 compared to recent levels. Local increases
in water use could be greater. Nonetheless, even
in the Supply Growth scenario in 2050, estimated
total annual water used for fracture stimulations at
2.5 billion barrels is still less than 0.2% of the U.S.
daily consumption in 2000 (excluding hydroelectric
involve higher levels of drilling. As indicated in
Figures 1-60 and 1-61, shale gas again is projected to
account for about 60% of the production from 2020
onward. By 2050, the requirement for new onshore
natural gas wells would be projected to reach over
80% of the 2006 peak.
While the absolute number of new onshore natural
gas wells remains below previous peaks, the numbers
may not be strictly comparable since shale gas wells
tend to require greater amounts of labor, equipment,
and materials to drill and complete than earlier gen-
erations of onshore natural gas wells. To test the level
of inputs required for drilling under the scenarios
examined, the study team looked at such items as
fracture stages, water use for fracturing, proppant,
steel, and manpower. Te following charts illustrate
the requirements derived from the level of activity
analyzed.
Te frst fgure set (Figure 1-62) illustrates the
activity-related input requirements for U.S. lower-48
and non-Arctic Canada onshore gas supply; namely
rigs (total and high horsepower), direct employment,
well capital, and steel for well tubulars. Tis level of
Figure 1-60. Onshore North American Gas Production in Supply Growth Scenario
0
40
80
120
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
B
I
L
L
I
O
N
C
U
B
I
C
F
E
E
T
P
E
R
D
A
Y
YEAR
SHALE TIGHT COALBED METHANE CONVENTIONAL
Figure 1-60. Onshore North American Gas Production in Supply Growth Scenario
156 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
on critical inputs (particularly fracture stimulation,
water disposal, and land access) on a national level
will cause natural gas supply rate to decline.
Kcy Findings
y Recent technology advances have enabled develop-
ment of large-scale tight gas and shale gas resources
in North America.
y Estimates of remaining resources, particularly of
shale gas, have increased signifcantly in recent
years and in all resource studies.
? Horizontal drilling coupled with multi-stage
fracture stimulation plays a key part in this
increase, enabling greatly increased production
of shale gas and tight gas.
y Te remaining recoverable gas resource (as of Jan-
uary 2010) is estimated to be between 1,900 and
3,600 Tcf.
? Further advances in technology and play delin-
eation beyond the current level are expected to
further increase this quantity.
utilization) of 213 billion gallons per day (1.85 tril-
lion barrels per year).
23
Advances by the industry to
reuse stimulation water and use non-potable water
will likely substantially reduce actual water use below
this estimate.
Natural gas can continue to be a signifcant con-
tributor to the continent’s energy supply and secu-
rity. Ample natural gas is available in North America
to supply current consumption levels for decades
and to support signifcant growth into other sectors
as well. New techniques, including cost-efective
multiple-stage fracture stimulation in horizontal
wellbores, have enabled vast resources never before
considered economic at any reasonable price. Input
resource requirements (e.g., rigs, people, fracture
stimulation proppant, and water) are signifcant yet
manageable, and achieving these levels of supply is
within industry capabilities. Extreme restrictions
23 Susan S. Hutson et al., “Estimated Use of Water in the United
States in 2000,” U.S. Geological Survey Circular 1268, 15 fg-
ures, 14 tables. (2004, revised April 2004, May 2004, and Feb-
ruary 2005).
Figure 1-61. Projected Wells Required in Supply Growth Scenario
SHALE TIGHT COALBED METHANE CONVENTIONAL
20
40
2005 2010 2015 2020 2025 2030 2035 2040 2045 2050
YEAR
0
60
W
E
L
L
S
T
H
O
U
S
A
N
D
S
Figure 1-61. Projected Wells Required in Supply Growth Scenario
CHAPTER 1 - RESOURCES AND SUPPLY 157
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158 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
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Figure 1-63. Indicative Estimates of Well Stimulation–Related Inputs
YEAR
YEAR
YEAR
Figure 1-63. Indicative Estimates of Well Stimulation–Related Inputs
CHAPTER 1 - RESOURCES AND SUPPLY 159
mated to be available at 50% greater supply levels
than today, even accounting for a decade ramp up
and decline volumes.
y Supply costs should remain moderate as long as
development and production is not overly restricted
or unduly burdened.
y Requirements to support this resource develop-
ment are achievable based upon high level scoping:
? Directly employed personnel could increase
10–25% over 40 years.
? Legislative and regulatory constraints (particu-
larly on fracture stimulation) on development
activity could drastically reduce the available re-
coverable resource.
y Between fve and nine decades of fat supply at
2009 levels is estimated to exist, even accounting
for substantial (600–1,400 Tcf) resource being pro-
duced on a decline following the plateau.
y Onshore gas supplies can support increased use of
this resource. Up to three decades of supply is esti-
Liquefed Natural Gas (LNG) is a small but grow-
ing part of the global gas market. LNG consump-
tion in 2009 was 23.5 Bcf/d or 8.2% of total world
demand for natural gas, according to the BP Review
of World Energy. LNG demand has grown 6–7% per
year for the last two decades, far faster than the
overall 2–4% growth in the total global natural gas
market.
Liquefed natural gas is created by cooling natu-
ral gas to -161
o
C. At that temperature, natural gas
becomes a liquid and volume drops by a factor of
approximately 600. Tat decrease in volume allows
natural gas to be economically transported by spe-
cialized ships to distant markets.
Te United States began importing LNG in 1971
to a regasifcation terminal in Massachusetts but
importation had a ftful start. By 1982, four other
import terminals had opened and three of them
had closed. Reliance on imports picked up in the
1980s when proved U.S. gas reserves declined as
domestic demand continued to rise. Te inopera-
tive terminals reopened and eventually expanded.
By 2003, a report on LNG by the Energy Infor-
mation Administration (EIA) cited 11 diferent
domestic regas projects and listed seven more
in the Bahamas, Canada and Mexico that were
designed to supply natural gas to U.S. markets.
Te projects enabled import growth to 2.11 Bcf/d
in 2007, 3.3% of total U.S. consumption.
However, the diference between U.S. LNG pric-
ing and global LNG pricing complicates import
eforts. Te price of LNG globally is linked to the
primary alternative fuel, oil. In the United States,
LNG is linked to the domestic price of gas. When
oil prices are high and U.S. natural gas prices are
low, LNG providers prefer to ship supply to Asia or
Europe.
Te expected need for LNG imports continued
to drive U.S. expansion activities. In 2007, the
United States had 5 operating terminals and 24
projects approved for construction: 19 onshore
and 5 ofshore. In addition, 14 more projects had
been formally proposed.
About that time, however, it became apparent
that U.S. proved reserves of natural gas were rap-
idly growing due to development of tight gas sands
and coalbed methane reserves. Promising results
from the Barnett play were just becoming public.
By 2008, the assumption that the United States
had to import large quantities of LNG to meet ris-
ing demand was called into question. Expectations
for LNG imports plummeted by the end of the
decade and a number of projects were suspended or
cancelled. Today, the 18.3 Bcf/d of terminal regas
capacity is expected to operate at low load factors
for the foreseeable future.
Tree factors – abundant domestic supply, low
prices and anticipated fat natural gas demand
through 2035 – have turned the focus to exports.
Apache and EOG are developing the Kitimat
LNG project in British Columbia – once intended
for imports – with plans to supply the planned
700 MMcf/d from the Horn River play. Cheniere is
developing a liquefaction facility in Louisiana that
could produce up to 2.6 Bcf/d from four trains. Free-
port LNG and Macquarie Energy have announced
plans to construct 1.4 Bcf/d of liquefaction from
four trains at the existing 1.65 Bcf/d Freeport LNG
terminal in Freeport, Texas. All three projects have
applied for export permits.
Liquefed Natural Gas Overview
160 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
Natural gas transmission pipelines transport
natural gas from production areas to market areas.
Transmission pipelines receive gas from gathering or
processing facilities and deliver it to end users, local
distribution companies, or other transmission pipe-
lines for further transportation to market. FERC is
charged with approving construction and operation
of interstate natural gas pipeline facilities. Currently,
there are approximately 220,000 miles of interstate
pipeline in service in the United States. In addition,
the EIA estimates that there are over 76,000 miles of
intrastate pipeline in operation. Construction and
operation of intrastate pipelines is regulated by the
states in which the pipelines are located.
In addition to FERC’s responsibility to review and
authorize interstate natural gas and storage facilities
in the United States, multiple other federal statutes
afect the construction of interstate natural gas pipe-
lines and storage facilities. Tese include the Clean
Air Act, the Clean Water Act, the Endangered Species
Act, the Coastal Zone Management Act, the Fish and
Wildlife Coordination Act, the Historic Preservation
Act, the Rivers and Harbors Act, the Mineral Leas-
ing Act, the Federal Land Policy Management Act,
and the Wild and Scenic Rivers Act. Additional state
and local agencies provide approvals for gathering
and processing facilities, and may present additional
requirements for pipeline and storage projects.
Natural gas storage facilities help meet gas demand
peaks when demand exceeds production and long-
haul pipeline throughput levels. When cold weather
or other market conditions create more demand for
gas than domestic production or imports can satisfy,
gas in storage makes up the diference. When sup-
plies of natural gas exceed demand (e.g., between
seasonal peak demand periods), storage allows gas
producers to continue production without interrup-
tions. Tis lowers the need to cut back on production
or to shut in wells, which could damage their integ-
rity. In North America, gas is typically injected dur-
ing the summer (April to October) and withdrawn in
the winter (November to March). Storage can also
be used for seasonal system supply or for peak intra-
day demands, in particular where high deliverability
storage is needed to supply gas-fred power genera-
tion activated for peak electric power loads.
FERC has jurisdiction over underground storage
sites owned and operated by interstate pipelines,
as well as independently operated storage sites that
ofer services in interstate commerce. EIA reports
? Te rig count required is manageable and within
historical levels, although a higher level of high
horsepower rigs is anticipated.
? Well capital and steel needed for pipelines,
tubing and casing is similarly manageable and
comparable to recent historical levels.
? Proppant needed for fracture stimulation may
double or treble versus 2010 estimates (fat to
double versus 2008) over 40 years.
? Water (including primary and re-use) needed
for fracture stimulation could increase 50–150%
to approximately 2.5 billion barrels of water
annually, less than 0.1% of U.S. water withdrawal
in 2000 (less than 0.2% of U.S. water withdrawal
in 2000 excluding hydroelectric use).
Natural Gas Infrastructurc
History and Contcxt
Te U.S. natural gas infrastructure system com-
prises a network of buried transmission, gathering
and local distribution pipelines, natural gas process-
ing, LNG, and storage facilities. Natural gas gather-
ing and processing facilities are necessarily located
close to sources of production. Tey gather gas from
producing wells and remove water, volatile compo-
nents and contaminants before the gas is fed into
transmission pipelines, which transport natural gas
from producing regions to consuming regions. Stor-
age facilities are located in both production areas
and near market areas, subject to geological limi-
tations and market forces. North American natu-
ral gas infrastructure has developed over the past
30 years to link regions of supply with regions of
demand. Major production basins in the Gulf of
Mexico, Appalachia, Western Canada, and the Rocky
Mountains connect to population centers in the
Northeast, Upper Midwest, West Coast, and South-
east markets.
Natural gas gathering and processing infrastruc-
ture collects natural gas from producers, processes
it to meet the specifcations of pipeline quality gas,
and delivers it into the pipeline grid. Tere are cur-
rently 38,000 miles of gas gathering infrastructure
in the United States and approximately 85 Bcf/day
of gas processing capacity. Gathering and processing
facilities are generally subject to oversight by state
regulators.
CHAPTER 1 - RESOURCES AND SUPPLY 161
Existing infrastructure will come under pressure in
some regions, particularly regions with higher sup-
ply costs that are unable to maintain or grow pro-
duction in competition with lower cost shale gas.
Shifting gas supply will result in the closing of some
processing facilities and may drive business clo-
sures and consolidations in some regions. In other
regions, new infrastructure will be required, includ-
ing gathering pipelines and processing plants in pro-
ducing regions, and possibly new pipelines to trans-
port ethane and other natural gas liquids.
there are 401 active underground natural gas
storage felds with a total working gas capacity of
approximately 4.2 Tcf. Of that amount, 2.6 Tcf
serves interstate commerce.
Infrastructurc Dcvclopmcnt Issucs
Gathering and Processing
Te rapid growth of shale gas production and its
transformative efect on North American gas supply
is changing the gathering and processing industry.
Gas hydrate is a solid naturally occurring sub-
stance consisting predominantly of methane gas
and water that occurs throughout Arctic regions
and beneath the outer continental shelves through-
out the world. In hydrates, water molecules form
an open, solid lattice that encloses methane. Many
scientists believe gas hydrates are one of the larg-
est storehouses for carbon on the planet. Te U.S.
Geological Survey frst assessed technologically
recoverable gas volumes in 2008 and estimated 85
Tcf of gas could be recovered from Alaska’s North
Slope. A 2009 Minerals Management Service
(MMS) assessment reported more than 21,000
Tcf of gas in place in hydrate form in the Gulf of
Mexico with a mean, statistical estimate of more
than 6,700 Tcf.
It’s still unclear whether gas can be commercially
developed from hydrates, though feld tests in
Korea, India and China have been promising. Field
production test experiments in the United States
are still pending with the frst planned for the Alaska
North Slope. Looking forward through 2050, sce-
narios suggest production from gas hydrates in
the United States could range from 10 Bcf/yr to
10 Tcf/yr. Tere are several technological chal-
lenges to producing gas hydrates. Hydrates are
found only in deep waters or the arctic. Te dis-
association of the hydrates once removed from its
temperature/pressure regime requires develop-
ment of specialized equipment to recover and pre-
serve the gas. Domestically, research into hydrates
as a resource is primarily conducted by federal
agencies and academia. Global R&D eforts sug-
gest that gas hydrates found in sand reservoirs are
the best target for early production due to higher
methane saturation levels and the suitability of
sand to well development. After the MMS report
on hydrates in the Gulf of Mexico, the gas hydrates
Joint Industry Project conducted logging-while-
drilling operations at seven wells at three sites
with the intent of discovering sand reservoirs with
gas hydrates. Six of the seven wells confrmed pre-
dictions of sand with gas hydrates, most of them at
high saturation levels.
Research on production technologies in the
United States and Japan is focused on production
via well bores. Researchers have ruled out surface
dredging or shallow-subsea mining. Te environ-
mental harm is too great and the energy in such
deposits is likely too small to be of value. Of the
various well-based approaches proposed, reservoir
depressurization and chemical exchange are the
most promising. Depressurization breaks the gas
hydrate into gas and water components. Both are
driven to the well bore and produced to the sur-
face. Chemical exchange – CO
2
for CH
4
– ofers the
potential to sequester CO
2
while releasing the gas.
Te challenge is that CO
2
immediately forms into
a hydrate when it reaches water in the formation,
creating the potential for only limited injection of
CO
2
and production of methane. To further evalu-
ate the potential for exchange, DOE is collaborat-
ing with Conoco Phillips to conduct a short feld
trial in Alaska this year. Gas hydrates have strong
climate implications. Te fndings to date suggest
gas hydrates can play a signifcant role in large,
acute and global climate events such as those that
occurred in the Earth’s ancient past.
Methane Hydrates
162 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
state pipeline to transport Marcellus shale basin gas
are under construction, 449 miles are pending, and
almost 1,000 miles of potential projects have been
announced. An interesting characteristic of the Mar-
cellus Basin area pipelines is that while the total capac-
ity proposed will be large, the mileage will be seem-
ingly small when compared to long haul pipelines in
the west. Tis is due to the proximity of this supply to
highly populated east coast markets.
Another important potential source of gas supply
for the lower-48 states is the North Slope of Alaska,
with approximately 35 Tcf of gas reserves. Beginning
with the passage of the Alaska Natural Gas Transpor-
tation Act in 1976, projects have been considered to
transport Alaskan gas. In 2004, Congress passed the
Alaska Natural Gas Pipeline Act with the objective
to facilitate the timely development of an Alaskan
natural gas transportation project to transport natu-
ral gas from the North Slope of Alaska to the lower-
48 states. Te Act also confrmed the Commission’s
authority to authorize a pipeline to transport Alaskan
natural gas to the lower-48 states and designated the
Commission to be the lead agency for processing the
National Environmental Policy Act documentation.
Te TransCanada Alaska Pipeline project is a joint
venture of TransCanada Alaska Company LLC and
ExxonMobil. Tis project is designed to transport up
to 4.5 Bcf/d of Alaskan North Slope gas to the Alaska-
Canada border, approximately 750 miles. Te project
has a Canadian afliate proposing to construct facili-
ties from the Alaska-Canada border to existing facili-
ties in Alberta. From Alberta, the gas would be trans-
ported through existing facilities to delivery points in
the United States. However, based on the apparent
economics of Alaskan gas versus shale gas, it seems
unlikely that Alaskan gas will be delivered to the
lower-48 states in the foreseeable future.
Te United States used an average of 66.1 Bcf/d of
natural gas in 2010. Tis is far lower than the inter-
state capacity of 183 Bcf/d. Nearly half the capacity
we have today has been built since 1972. Because
pipeline systems must be sized and designed for
peak capacity rather than average capacity, much of
apparent overcapacity is refected in these numbers.
Although this redundancy creates a robust and reli-
able transmission system, it is not evenly distributed
across North America. Pockets of constraints and
areas of overcapacity still exist because of local supply
and demand factors.
Shale gas production will be an increasingly impor-
tant source of new production. Te growth in shale
gas development also has increased the recognized
reserves of NGLs in the United States. However, the
growth in liquids from all gas shale plays is not uni-
formly distributed across the country. Te NGL-rich
gas plays are the Barnett in Texas, the western por-
tion of the Marcellus in Pennsylvania, the Woodford
in Oklahoma, the Eagle Ford play in southern Texas,
and the Niobrara play in Colorado, Nebraska, and
Kansas. Te Fayetteville in Arkansas, the Haynesville
in Louisiana, and the Horn River in Western Canada
are dry by comparison.
Shale gas basins in new regions, such as the Mar-
cellus in the Northeast and mid-Atlantic, will require
an entirely new set of NGL pipelines to connect to
markets. Te public in some areas of this region is
not accustomed to, and may be actively opposed to,
production and processing facilities. Efective public
outreach and consultation will be necessary for suc-
cessful development.
Transmission Pipelines
Since 2000, FERC has approved over 16,000 miles
of interstate pipeline and nearly fve million horse-
power of compression. Tese projects can be catego-
rized either as greenfeld pipelines (new pipelines in
new rights-of-way) or as enhancements (i.e., looping
of an existing pipeline, addition of compression, or
extensions or laterals of an existing system). About
14,000 miles of interstate pipeline and 4.6 million
horsepower of compression have also been placed into
service.
Recent development of shale gas basins in the
southeast U.S. has spawned a boom in transmis-
sion pipeline construction in that part of the coun-
try. Shale gas supplies have been connected, via new
pipelines, to the traditional long-line pipelines that
transport natural gas from the Gulf of Mexico to the
mid-Atlantic and northeast U.S. Over 2,400 miles of
interstate pipeline has been approved to move south-
east U.S. shale gas.
Looking to the future, pipeline construction will
continue in the southeast U.S. to access shale gas
deposits. However, a major build-out of interstate
pipeline capacity in the mid-Atlantic and northeast
U.S. will be needed to transport gas from the Mar-
cellus basin to markets. In fact, 201 miles of inter-
CHAPTER 1 - RESOURCES AND SUPPLY 163
umes of new gas supply to the existing pipeline grid.
Te requirement for new gas processing infrastruc-
ture will be driven by the large volumes of new gas
production that are expected to be connected over the
forecast period, and by the expectation that relatively
strong oil prices will encourage investment in the
extraction of natural gas liquids.
Te June 2011 INGAA Foundation study on
North American natural gas infrastructure needs
through 2035 projects a cumulative need for almost
414,000 miles of gathering pipelines, including indi-
vidual well connections, for a cumulative investment
requirement (in nominal dollars) of about $50 bil-
lion. Te same study projects a need for 32 Bcf/d of
gas processing capacity additions through 2035 for
a total investment of $22 billion (in nominal dol-
lars). Tis may need to be supplemented by new NGL
pipelines, in particular from the Marcellus region to
markets in the Midwest or Gulf Coast.
New Transmission Pipeline Requirements
Future pipeline infrastructure expansion will be
driven by a shift in production from mature basins
to areas of unconventional (i.e., shale) natural gas
production. Regions with unconventional production
growth, such as the Marcellus basin in the Appala-
chian region of the northeast U.S., will experience the
greatest infrastructure investment.
A demand-side factor that will infuence construc-
tion of more transmission pipeline is the expected
increase in gas-fred electric generation as coal-fred
generation is afected by expected environmental and
carbon regulation. Gas-fred generation, given the
amount of domestic shale gas, is likely to be relatively
cheaper than in previous years and has approximately
half the emissions of coal-fred generation.
Te INGAA Foundation 2011 study estimates that
by 2035 the expanded market will require about
36,000 miles of transmission pipelines and a fur-
ther 14,000 miles of shorter lateral pipelines needed
to connect new gas-fred power generation capac-
ity, gas storage, and processing plants. Tis would
require cumulative investments of nearly $130 billion
(in nominal dollars) by 2035.
New Storage Requirements
Very few states have suitable depleted reservoirs,
aquifers, and salt formations available for storage
Storage
FERC has authorized almost 970 Bcf of new under-
ground storage capacity – either as expansions of
existing storage felds or as new storage sites – since
2000. Since 2002, 416 Bcf of new capacity has actu-
ally gone into service. Similar to historical pipeline
expansion, storage development has mainly occurred
in the south central U.S. to frst accommodate the
expected increase in imported liquefed natural gas,
and, more recently, to store the gas produced from
shale basins. Tis trend in the location of storage
facilities is expected to continue.
Storage feld development is limited by the chal-
lenges of fnding sites with the appropriate combina-
tion of geological features, pipeline proximity, and
the ability to obtain land, rights, and permitting.
Large portions of the United States, including much
of the Northeast, do not have geological structures
conducive to underground gas storage.
Strong growth in gas demand for power gen-
eration has increased demand for fexible, high-
deliverability storage that can be cycled several
times annually. Most of the value that these facili-
ties create comes from short-term price volatility
rather than the summer/winter price spreads that
have underpinned traditional storage development.
Futurc Natural Gas Infrastructurc
Rcquircmcnts
Estimating levels of needed infrastructure growth
requires consideration of future supply and demand for
natural gas. Fluctuating levels of supply and demand
within an integrated market produces price signals
that elicit an infrastructure investment response. For
example, if supply develops in a region without suf-
fcient pipeline capacity, a price diference develops
between the supply area and downstream demand
centers. If this diference is high enough, it signals a
need for new pipeline capacity to allow more gas to
fow. When seasonal price spreads develop, a signal
is sent to the market to store gas in lower priced peri-
ods and extract it when prices are higher. In addition,
price volatility signals value for more storage capacity
to provide a physical tool for shorter term balancing.
New Gathering and Processing Requirements
Te requirement for new gas gathering infrastruc-
ture will be driven by the need to connect large vol-
164 PRUDENT DEVELOPMENT: Realizing the Potential of North America’s Abundant Natural Gas and Oil Resources
NORTH AMERICAN OIL AND GAS
PRODUCTION PROSPECTS
TO 2050
Preceding sections of this chapter describe the most
signifcant current and potential sources of North
American oil and natural gas production available
over the next several decades. Tere are many plau-
sible permutations of the mix and timing of develop-
ment of these resources and their translation into
productive capacity. Factors that enable or constrain
supply capacity development, be they geologic, tech-
nical, or the result of public policy choice, can play
out in many diferent ways, so this report does not
present a defnitive vision of North American oil and
gas production in either 2035 or 2050. Te ranges
of production pathways shown earlier in this report
suppose either a reasonably smooth path of develop-
ment, surmounting the barriers which may exist, or a
more limited outlook, in which barriers signifcantly
constrain production capacity. Such enablers and
challenges will, of course, exist beyond 2035, out to
2050 and beyond. However, if North America fnds
itself on the constrained pathway as 2035 approaches,
it would be unwise to assume that it is possible to
change course and expect to recover productive capac-
ity by 2050, given the long lead times and develop-
ment challenges involved in activating resources
which have not already been the focus of attention.
With this perspective, it is reasonable to assume
continuity in the trends to 2035 under either devel-
opment case. In a development-constrained world,
some supply sources would have declined to zero or
a low number as existing reservoirs continue their
natural decline and are not replenished by new drill-
ing activity. Tis would be the case with the Arctic, for
example, relying on a single pipeline to enable crude
oil production to occur and be transported to mar-
ket. Without further exploration, the pipeline will
be shut down when fows fall below operational mini-
mum rates, which would probably occur at some time
during the 2040s. Ofshore oil and gas output would
also have declined to low production rates by 2050 if
development is confned to the Gulf of Mexico. Just
as existing production would be subject to decline,
new sources would likely not be developed in the con-
strained world. New Arctic exploration would not
be deemed viable, other ofshore areas would prob-
ably remain restricted to development, and onshore
conventional and unconventional oil supplies would
development. Areas without much storage potential
include Nevada, Idaho and Arizona, the Central Plains
states, Missouri and almost the entire East Coast
(except for portions of western New York, western
Pennsylvania, and West Virginia). Any target storage
formation must frst be reasonably close to a major
pipeline before storage development can be consid-
ered.
Salt cavern storage is expected to dominate new
storage development, essentially doubling over the
forecast period. Te 2011 INGAA Foundation study
estimates approximately 590 Bcf of new storage
capacity is required by 2035 to meet market growth
for a cumulative investment of about $5 billion (in
nominal dollars).
Kcy Findings
y Growing shale gas supply will create a signifcant
requirement for new gathering, processing, and
pipeline infrastructure.
y New storage requirements for the growing natural
gas market are relatively modest.
y Strong oil prices relative to gas prices are driving
development to liquids-rich areas and creating a
need for new processing infrastructure.
y New pipelines may be required to move natural gas
liquids from producing areas to established markets.
y Development of shale supply from new basins will
put pressure on existing infrastructure in high cost
supply regions.
y Existing infrastructure should be used, when prac-
tical, to reduce capital requirements and environ-
mental impacts.
y Development of a pipeline from Alaska’s North
Slope to the integrated North American market
would require signifcant investment.
y Te growing gas infrastructure grid can support
signifcant switching from coal to gas in electric
generation and underpin the use of natural gas as
a transport fuel.
y Te development of shale gas supply further
increases the reliability of the natural gas infra-
structure by increasing production from regions
not prone to hurricanes, and by geographically
diversifying natural gas supply.
y Governments should ensure that efcient siting and
other regulatory processes are in place to underpin
necessary infrastructure investment.
CHAPTER 1 - RESOURCES AND SUPPLY 165
can support supplies for decades to come and by 2050,
given sustained technology development, it is likely
that currently assessed resources will be augmented
by methane hydrates from the Arctic and the Gulf
of Mexico. Te size of this potential resource could
reasonably be expected to supply the North American
natural gas market into the next century, and provide
opportunities for deployment of those technologies
in other regions of the world where methane hydrate
resources are identifed. On the oil side, vast Canadian
oil sands resources could enable continued growth in
production through 2050, allowing Canada to remain
one of the largest oil producing countries, with
considerable benefts for the North American econ-
omy and energy security. Oil shale from the Colorado
and Utah kerogen deposits could become a very signif-
icant supply of oil – again, if technology development
and access is sustained in the interim period.
be faced with increasingly stringent challenges.
Methane hydrates and oil shale development would
also be seriously at risk from prolonged access and
development constraints. In the case of natural gas,
conventional resources that do not depend on hydrau-
lic fracturing would be mostly played out well before
2050 leaving the North American gas market to be
largely supplied by imports. Te additional demand
for global natural gas supplies would probably amplify
the supply/demand stresses in the global market with
potentially serious consequences for the economy and
for energy security.
In contrast, if prudent development, in all its
senses, is enabled over the long-term, through 2050
and beyond, a large contribution to North America’s
oil and natural gas market requirements can be met
from domestic production. Te natural gas resource
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