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 field’s 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 discoveries—JB Mountain and Mound Pond in shallow waters off the coast of Louisiana—were 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 region’s 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 region’s share of total U.S. shale gas production from 39 percent in 2002 to 46 percent by 2025. 

Notes and Sources

Released: January 2003