Issues in Focus
Lower 48 Natural Gas Supply
Production from domestic natural gas resources is
projected to increase as demand grows. Much of the increase is expected
to be met from unconventional resources, changing the overall mix
of domestic natural gas supply. Of the 18.6 trillion cubic feet
of lower 48 natural gas production in 2002, 42 percent was from
conventional onshore resources, 32 percent was from unconventional
resources, and 26 percent was from offshore resources. By 2025,
43 percent of total lower 48 natural gas production (21.3 trillion
cubic feet) is projected to be met by unconventional resources (Figure
9).
The volume of estimated technically recoverable resources
is sufficient to support increased reliance on unconventional natural
gas sources. Lower 48 remaining technically recoverable resources
are identified in five categories (Figure 10):
- Conventional undiscovered nonassociated resources
are unproved resources of natural gas, not in contact with significant
quantities of crude oil in a reservoir, that are estimated to
exist in fields that have yet to be discovered, based on geologic
formations and their propensity to hold economically recoverable
natural gas. The estimate of lower 48 technically recoverable
undiscovered conventional nonassociated natural gas resources
as of January 1, 2002, is 222 trillion cubic feet.
- Conventional inferred reserves are gas
deposits in known reservoirs that are considered likely to exist
on the basis of a fields geology and past production but
have not yet been developed. The bulk of the estimated 232 trillion
cubic feet of lower 48 inferred reserves is in onshore reservoirs.
- Unconventional resources (tight gas, shale
gas, and coalbed methane), estimated at 475 trillion cubic feet,
make up the largest category of unproved resources.
- Associated-dissolved resources, the remaining
unproved lower 48 natural gas resource, occur in crude oil reservoirs
as free gas (associated) or as gas in solution with crude oil
(dissolved). They are estimated at a total of 136 trillion cubic
feet.
- Proved natural gas reserves are located
in known and developed reservoirs with demonstrated production
potential. As of January 1, 2002, lower 48 proved natural gas
reserves were estimated to be 175 trillion cubic feet.
Just a few years ago, it was believed that natural
gas supplies would increase relatively easily in response to an
increase in wellhead prices because of the large domestic natural
gas resource base. This perception has changed over the past few
years. While average natural gas wellhead prices since 2000 have
generally been higher than during the 1990s and have led to significant
increases in drilling, the higher prices have not resulted in a
significant increase in production. With increasing rates of production
decline, producers are drilling more and more wells just to maintain
current levels of production. A significant increase in conventional
natural gas production is no longer expected. Drilling deeper wells
in conventional reservoirs is expected to slow the overall decline
in conventional onshore nonassociated gas production, and drilling
in deeper waters is expected to offset the decline in shallow offshore
production. Increasing production from unconventional gas plays
is drilling and/or technology intensive and is likely to lead to
higher wellhead prices.
Conventional Sources
The share of natural gas production from conventional
resources is expected to decline over the projection period, from
68 percent in 2002 to 57 percent in 2025. Most of the projected
decline is in onshore conventional nonassociated natural gas production,
where the majority of exploration and development has occurred historically.
Lower 48 offshore natural gas production is expected to remain relatively
flat throughout the projection period, as production from fields
in the deep waters of the Gulf of Mexico offset the decline in the
production in shallow waters.
Onshore
With fewer and smaller new onshore conventional reserve
discoveries, emphasis is expected to focus on increasing the expected
recovery of currently known fields. Reserve additions from onshore
conventional natural gas wells, both exploratory and developmental,
are projected to add less than 1 billion cubic feet per well to
total reserves in 2025 (Figure 11). The development of deep reservoirs
(more than 10,000 feet) in both known fields and new discoveries
is projected to play an important role in slowing the decline in
the average finding rate for conventional onshore wells. However,
drilling to deeper depths increases the average cost of drilling
and places upward pressure on prices.
Because larger fields with higher levels of production
generally are found first, developed, and replaced with smaller
fields, production will tend to decline over time if drilling levels
are roughly constant; however, changes in prices influence drilling.
Conventional natural gas drilling is expected to increase throughout
the projection period, from 6,440 wells in 2002 to 9,140 wells in
2010 and 11,930 wells in 2025 (Figure 12). Less than 10 percent
of future natural gas drilling is expected to be exploratory, reflecting
the relative maturity of the lower 48 conventional onshore resources.
The projected increase in natural gas drilling enables producers
essentially to maintain conventional onshore nonassociated production
at the current level of approximately 6 trillion cubic feet.
Offshore
Offshore production, primarily in the Gulf of Mexico,
is expected to remain a key source of domestic natural gas supply
through 2025. Although natural gas production in the shallow waters
of the Gulf of Mexico has been declining since 1997, recent developments
in deep gas (more than 15,000 feet) in the shallow waters and deepwater
(water depth more than 200 meters, or 656 feet) have shown some
promise. To offset some of the high costs associated with drilling
deep gas wells and deepwater wells, the U.S. Minerals Management
Service has offered incentives in the form of royalty relief on
qualifying new leases and has proposed additional royalty relief
on some existing leases (see Legislation and Regulations).
Because the deep waters of the Gulf of Mexico contain
primarily oil resources, much of the increase in deepwater gas production
is expected to come from associated-dissolved gas. Table 7 shows
some of the principal deepwater fields that have recently started
production or are expected to start production before 2007. Many
of the small fields are being developed as subsea tie-backs
to existing infrastructure as a way of making them economically
viable. In addition to these deepwater fields, two significant
deep gas discoveriesJB Mountain and Mound Pond in shallow
waters off the coast of Louisianawere announced in 2003.
Given the discrete nature of offshore field development,
projected offshore natural gas production is expected to be uneven
over time. Lower 48 offshore natural gas production is projected
to peak in 2010 at 5.4 trillion cubic feet, 11.3 percent higher
than in 2002. Associated-dissolved gas, which is primarily in the
deep waters of the Gulf of Mexico, is projected to increase by more
than 50 percent, from 1.1 trillion cubic feet in 2002 to 1.6 trillion
cubic feet in 2010. Projected production of nonasssociated gas in
2010 is about the same as in 2002 at 3.8 trillion cubic feet. In
the Gulf of Mexico, shallow gas production is projected to decline
at an average annual rate of 0.4 percent, while deepwater gas production
is projected to increase at an average annual rate of 4.1 percent
between 2002 and 2010 (Figure 13). After 2010, lower 48 offshore
natural gas production drops to a low of 4.8 trillion cubic feet,
then increases to approximately 5 trillion cubic feet in 2025.
Unconventional Gas
Natural gas extracted from coalbeds (coalbed methane)
and from low permeability sandstone and shale formations (tight
sands and gas shales) is commonly referred to as unconventional
gas. Most of these resources must be subjected to a significant
degree of stimulation (e.g., hydraulic fracturing) or other unconventional
production techniques to attain sufficiently economic levels of
production. Unconventional gas has become an increasingly important
component of total lower 48 production over the past decade (Figure
14). From 17 percent (3.0 trillion cubic feet) of total production
in 1990, the unconventional gas share increased to 32 percent (5.9
trillion cubic feet) in 2002.
Exploration of these abundant (Figure 15) but generally
higher cost resources received a boost in the late 1980s and early
1990s with the successful implementation of tax incentives designed
to encourage their development. Since then, technologies developed
and advanced in pursuit of these resources have contributed to continued
growth in production in the absence of the tax incentives. Indeed,
increasing production from unconventional gas resources has actually
offset a decline in conventional gas production in recent years.
By 2025, unconventional gas production is projected to account for
43 percent (9.2 trillion cubic feet) of total lower 48 natural gas
production.
Undeveloped Resources
References to undeveloped unconventional resources
in AEO2004 refer to what the United States Geological Survey
(USGS) classified as Continuous-Type (Unconventional) Accumulations
in its 1995 Assessment [42]. The resource estimates in that
assessment represent the volume of unproved resources that remain
to be added to proved reserves utilizing the technology and development
practices existing at the time of the assessment (January 1994).
Continuous-type resources are defined to include those resources
that exist as geographically extensive accumulations that generally
lack well-defined oil/water or gas/water contacts [43].
This category encompasses coalbed gas, gas in many of the
so-called tight sandstone reservoirs, and auto-sourced
oil- and gas-shale reservoirs [44].
Undeveloped resources of unconventional gas are predominantly
located in three regions. The bulk of tight sands and coalbed methane
(71 percent and 78 percent, respectively) are in the Rocky Mountain
region. Sixty-eight percent of undeveloped gas shale resources are
in the Northeast region, with most of the remainder in the Southwest
region. There are small-to-moderate quantities of tight sands and
lesser amounts of gas shales and coalbed methane in the other regions.
For AEO2004, undeveloped unconventional resources
are adjusted to reflect changes indicated by Advanced Resources
International (ARI), an independent consultant specializing in unconventional
gas. Some plays have been updated to reflect new data, other plays
previously lacking data have been assessed as data became available,
and new unconventional plays have been identified when appropriate.
Two examples illustrating the importance of updating
are the shale gas (Barnett Shale) in the Fort Worth Basin and coalbed
methane in the Powder River Basin. In the 1995 USGS assessment,
the Barnett Shale was not assessed due to lack of sufficient data.
During the past few years, however, shale gas production from the
Fort Worth Basin has been growing at a rapid pace. By obtaining
from ARI an interim assessment of the shale gas potential in the
basin, EIA was able to project this significant component of current
natural gas supply more accurately.
The Powder River Basin was assessed by the USGS in
1995, but the abundant coalbed methane resources were substantially
underestimated on the basis of then-available data. Although the
USGS has significantly increased its assessment of coalbed methane
since 1995, interim consultation with ARI allowed EIA to make this
important adjustment years earlier. Several other basins in the
Rocky Mountains [45] have recently been reassessed by the
USGS, but there was insufficient time to reconcile those estimates
with the EIA values for comparable areas.
Proved Reserves
Proved reserves of unconventional gas are highest
in the Rocky Mountain region for coalbed methane and tight sands
and highest in the Northeast for gas shales (Figure 16). Approximately
83 percent (14.6 trillion cubic feet) of coalbed methane and 52
percent (26.8 trillion cubic feet) of tight sands proved reserves
are located in the Rocky Mountain region. Seventy-six percent (5.4
trillion cubic feet) of gas shales proved reserves are located in
the Northeast region, but substantial amounts also exist in the
Southwest (1.7 trillion cubic feet). Significant quantities of tight
sands proved reserves are located in all the other regions, except
for the West Coast. Coalbed methane proved reserves are limited
largely to the Northeast (1.5 trillion cubic feet) and the Gulf
Coast (1.2 trillion cubic feet), with a small amount (0.3 trillion
cubic feet) in the Midcontinent. No significant volume of unconventional
gas proved reserves exists in the West Coast region.
Production
Tight Sands. The two regions that are currently
the largest producers of gas from tight sands are the Rocky Mountain
region and the Gulf Coast region, which account for 39 percent and
37 percent, respectively, of total U.S. tight sands gas production
(Table 8). The Rocky Mountain region is projected to experience
the most growth in gas production from tight sandstone formations,
with 66 percent of total U.S. tight sands gas production expected
to originate from this region in 2025. Within the region, tight
sands production is projected to increase at the fastest rate (approximately
8 percent per year) in the Wind River basin, with development accelerating
in the later years of the forecast. Production from tight sands
in the Uinta basin is also expected to grow at a robust rate (about
5 percent per year).
In terms of quantity, the largest contribution from
the region will be the Greater Green River basin. AEO2004
projects the share of total U.S. tight sands gas production sourced
from the Green River basin to increase from 15 percent in 2002 to
36 percent by 2025. In the other Rocky Mountain basins, tight sands
gas production is projected to rise moderately, except for the Piceance,
where production is projected to decline by about 4 percent per
year between 2002 and 2025.
Tight sands production from the Gulf Coast region
is projected to increase into the middle of the forecast period
until primary tight sands plays in the two major basins reach maturity
and production begins dropping back toward current levels. Production
from tight sandstone formations in other U.S. regions is projected
to decline (Midcontinent and Southwest regions) or remain relatively
stable (Northeast region).
Coalbed Methane. AEO2004 projects coalbed
methane production to remain concentrated largely in the Rocky Mountain
region, but the regions share is projected to drop modestly
from 88 percent in 2002 to 81 percent by 2025 (Table 9). Within
the Rocky Mountain region, growth in coalbed methane production
from the prolific Powder River basin and in the Uinta and Raton
basins is expected to be offset somewhat by production declines
in the relatively mature San Juan basin. Overall growth in the region
averages about 1 percent per year.
Elsewhere, significant growth in coalbed methane production
is projected for the Northeast region, where the share of total
U.S. coalbed methane production increases from 4 percent in 2002
to 8 percent by 2025. Coalbed methane production in the Gulf Coast
region is expected to be fairly stable, with declines in the later
years of the forecast in the Black Warrior basin offset by increasing
production from the Cahaba basin. Although starting from a relatively
low level (10 billion cubic feet), coalbed methane production in
the Midcontinent region is projected to grow more rapidly than in
any other region.
Gas Shales. Natural gas production from tight
shale formations occurs predominantly in the Northeast region and
the Southwest region (Table 10). Total production from gas shales
in the Northeast region is projected to increase at a relatively
moderate pace, as production from the Antrim basin remains relatively
stable and production in the Appalachian basin grows at about 4
percent per year. In the Southwest region, continued development
of gas shales in the Fort Worth-Barnett basin is projected to increase
that regions share of total U.S. shale gas production from
39 percent in 2002 to 46 percent by 2025.
Notes
and Sources
Released: January 2003
|
Printer
Friendly Version
Field name |
Operator |
Type |
Water depth (feet)
|
Start Year |
Expected peak natural gas
production
(million cubic feet per day) |
Aconcagua |
TotalFinaElf
|
Gas
|
7,000
|
2002
|
80
|
Aspen |
BP
|
Oil/Gas
|
3,063
|
2002
|
30
|
Boomvang |
Kerr-McGee
|
Oil/Gas
|
3,548
|
2002
|
200
|
Camden
Hills |
TotalFinaElf
|
Gas
|
7,210
|
2002
|
175
|
Horn Mountain |
BP
|
Oil/Gas
|
5,400
|
2002
|
68
|
King Kong
|
Mariner
|
Oil/Gas
|
3,799
|
2002
|
150
|
Nansen |
Kerr-McGee |
Oil/Gas |
3,677
|
2002
|
200
|
Falcon |
Pioneer |
Gas |
3,419
|
2003
|
175
|
Matterhorn |
TotalFinaElf |
Oil/Gas |
3,850
|
2003
|
55
|
Medusa
|
Murphy
|
Oil/Gas
|
2,131
|
2003
|
110
|
Morgus
|
Shell
|
Oil/Gas
|
3,957
|
2003
|
55
|
Nakika
Fields |
Shell,
BP |
Oil/Gas
|
5,700-7,500
|
2003-2004
|
325
|
Front Runner |
Pioneer |
Oil/Gas |
3,329
|
2004
|
110
|
Harrier
|
Pioneer
|
Gas
|
3,400
|
2004
|
100
|
Marco Polo
|
Anadarko
|
Oil/Gas
|
4,286
|
2004
|
100
|
Gunnison
|
Kerr-McGee
|
Oil/Gas
|
3,132
|
2004
|
200
|
Mad Dog
|
BP
|
Oil/Gas
|
4,951
|
2004
|
40
|
Red Hawk
|
Kerr-McGee
|
Gas
|
5,334
|
2004
|
150
|
Llano
|
Shell
|
Oil/Gas
|
2,700
|
2005
|
74
|
Magnolia
|
ConocoPhilips
|
Oil/Gas
|
4,673
|
2005
|
150
|
Entrada
|
BP
|
Oil/Gas
|
4,642
|
2006
|
110
|
Great White
|
Shell
|
Oil/Gas
|
8,000
|
2006
|
125
|
Thunder
Horse |
BP
|
Oil/Gas
|
6,089
|
2006
|
55
|
|
Figure
data
Figure
data
Figure
data |
Printer
Friendly Version
Region/basin
|
Production |
2002 |
2005 |
2010 |
2015 |
2020 |
2025 |
Northeast Region |
Appalachian
|
232
|
202
|
214
|
243
|
246
|
212
|
Gulf Coast Region |
LA/MS
Salt/ Cotton Valley |
555
|
724
|
991
|
1,213
|
1,138
|
959
|
Texas
Gulf |
894
|
731
|
811
|
776
|
670
|
589
|
Total
|
1,449
|
1,455
|
1,802
|
1,989
|
1,807
|
1,548
|
Midcontinent Region
|
Arkoma
|
149
|
98
|
88
|
92
|
91
|
90
|
Anadarko
|
259
|
172
|
136
|
99
|
61
|
47
|
Total
|
408
|
271
|
224
|
190
|
152
|
138
|
Southwest Region
|
Permian
|
285
|
216
|
169
|
163
|
159
|
146
|
Rocky Mountain
|
Uinta
|
91
|
175
|
212
|
255
|
240
|
262
|
Wind
River |
95
|
120
|
194
|
304
|
410
|
588
|
Denver
|
109
|
143
|
172
|
201
|
211
|
188
|
Greater
Green River |
569
|
657
|
1,005
|
1,455
|
1,792
|
2,148
|
Piceance
|
100
|
97
|
78
|
73
|
54
|
37
|
San
Juan |
498
|
607
|
655
|
725
|
758
|
714
|
Northern
Great Plains |
40
|
33
|
44
|
53
|
61
|
61
|
Total
|
1,502
|
1,833
|
2,361
|
3,066
|
3,526
|
3,998
|
Printer
Friendly Version
Region/basin
|
Production
|
2002
|
2005
|
2010
|
2015
|
2020
|
2025
|
Northeast Region |
Appalachian
|
62
|
97
|
134
|
159
|
165
|
147
|
Illinois
|
0
|
0
|
0
|
3
|
8
|
11
|
Total
|
62
|
97
|
134
|
161
|
173
|
158
|
Gulf Coast Region |
Black
Warrior |
110
|
111
|
115
|
122
|
97
|
79
|
Cahaba
|
0
|
3
|
10
|
15
|
29
|
30
|
Total
|
110
|
113
|
125
|
137
|
126
|
109
|
Midcontinent
Region |
10
|
21
|
33
|
64
|
107
|
114
|
Rocky Mountain
|
San
Juan |
848
|
828
|
784
|
783
|
685
|
588
|
Powder
River |
325
|
357
|
407
|
531
|
586
|
617
|
Uinta
|
92
|
89
|
92
|
169
|
230
|
255
|
Raton
|
54
|
77
|
136
|
151
|
144
|
132
|
Other
|
1
|
3
|
1
|
0
|
6
|
20
|
Total
|
1,320
|
1,354
|
1,420
|
1,634
|
1,650
|
1,611
|
Total
|
1,502
|
1,586
|
1,712
|
1,997
|
2,056
|
1,992
|
Printer
Friendly Version
Region/basin
|
Production
|
2002
|
2005
|
2010
|
2015
|
2020
|
2025
|
Northeast Region |
|
|
|
|
|
|
Appalachian |
173
|
221
|
249
|
360
|
429
|
411
|
Antrim |
190
|
175
|
173
|
229
|
230
|
201
|
Illinois New Albany |
3
|
1
|
1
|
0
|
0
|
0
|
Total |
367
|
397
|
423
|
590
|
659
|
612
|
Southwest Region |
Fort Worth-Barnett |
233
|
222
|
374
|
434
|
500
|
520
|
Total |
600
|
619
|
797
|
1,024
|
1,159
|
1,132
|
Printer
Friendly Version
Access status
|
Unconventional
resources |
Officially
inaccessible |
23.44
|
Inaccessible
due to development constraints |
83.71
|
Accessible
with lease stipulations |
47.51
|
Accessible
under standard lease terms |
172.92
|
Total
|
327.58
|
Access Restrictions
A current natural gas development issue concerns the
ability of producers to access natural gas resources on Federal
lands. Most of the unconventional gas resources are in the Rocky
Mountains, where they are subject to a variety of access restrictions.
In 2002, the Federal Government, under authority of the Energy Policy
and Conservation Act (EPCA), conducted an interagency assessment
of access restrictions for five major basins in the Rocky Mountains
[46]. The access assumptions for the Rocky Mountains in AEO2004
reflect the results of the EPCA assessment.
In AEO2004, 7 percent of the undeveloped unconventional
gas resources are officially off limits to either drilling or surface
occupancy (Table 11). Included in the off-limits category are areas
where drilling is precluded by statute (e.g., national parks and
wilderness areas) and by administrative decree (e.g., Wilderness
Re-inventoried Areas and Roadless Areas). Also
included are those areas of a lease where surface occupancy is prohibited
to protect stipulated resources, such as the habitats of endangered
species of plants and animals. An additional 26 percent of the resources
are judged currently to be developmentally constrained because of
the prohibitive effect of compliance with environmental and pipeline
regulations created to effect such laws as the National Historic
Preservation Act, the National Environmental Policy Act, the Endangered
Species Act, the Air Quality Act, and the Clean Water Act.
Approximately 15 percent of the resources are accessible
but located in areas where lease stipulations, which affect accessibility,
are set by a Federal land management agency (either the U.S. Bureau
of Land Management or the U.S. Forest Service). The remaining 53
percent of undeveloped Rocky Mountain unconventional gas resources
are located either on Federal land without lease stipulations or
on private land, and are accessible subject to standard lease terms.
The treatment of access restrictions in the AEO2004
varies by restriction category. Resources located on land that is
officially inaccessible are removed from the operative resource
base. Resources located in areas that are developmentally constrained
because of environmental and pipeline regulations are initially
removed from the resource base, then made available gradually over
the forecast period to reflect the tendency of technological progress
to enhance the ability of producers to overcome difficulties in
complying with the restrictions. Resources that are accessible but
located in areas that are subject to lease-stipulated access limitations
are accounted for by making two adjustments: exploration and development
costs are increased to reflect the increased costs that access restrictions
generally add to a project; and time is added to the schedule to
complete a project to simulate the delay usually incurred as a result
of efforts to comply with access restrictions.
|