Diverse gas plays lurk in gas resource pyramid

EMERGING U.S. GAS RESOURCES-6 (CONCLUSION)

Vello A. Kuuskraa
Advanced Resources International Inc.
Arlington, Va.
James W. Schmoker, Thaddeus S. Dyman
U.S. Geological Survey
Denver

This final article on the outlook for U.S. future natural gas supplies expands on the concept of the natural gas resource pyramid. A series of poorly understood but potentially significant emerging gas plays is introduced. These plays reside at various levels within the resource pyramid.

These emerging resources include sub-volcanic gas, shale gas, deep coalbed methane, and unrecognized tight gas sands. In the main, these are plays that have yet to be included in natural gas resource forecasts.

Dynamic pyramid

In the first article of this series, we reviewed the concept of the resource pyramid for natural gas as developed by Enron Corp. and others. The basic idea is that currently defined gas resources can be arrayed by quality, with a smaller volume of high quality resources at the apex of the pyramid and progressively larger volumes of lower quality resources toward the base of the pyramid.

In this article, we expand on the fundamental and conceptually powerful resource-pyramid analog in two ways (Fig. 1 [65,718 bytes]).

First, we do not know the full contents or limits of the resource pyramid for natural gas. The ultimate size and the final base of the pyramid are not yet in sight. Improved technology and geologic knowledge continue to expand the resource pyramid by adding new gas plays and improving recovery from old fields.
Second, the natural gas plays within the resource pyramid are dynamic. Plays can move with the aid of advancing technology and knowledge from an initial low quality foothold to a position of much higher quality, which is equivalent to moving from a position of high costs to economically producible reserves.

An example of a gas resource whose relative position in the resource pyramid has shifted is coalbed methane (CBM), which not long ago was viewed as "moon beam gas" at the base of the pyramid. With the discovery of the San Juan Basin "Fairway" play and its development with well cavitation technology, coalbed methane has moved up in the pyramid to a position shared with conventional gas reserves, providing 10.6 tcf of proved reserves plus 4.9 tcf of past production (as of the end of 1996).

A second example is the thick Upper Cretaceous Mesaverde tight gas sands of the southern Piceance basin. With advances in natural fracture detection and hydraulic fracturing technology, supported by industry, the Department of Energy/ Fossil Energy (DOE/FE), and the Gas Research Institute (GRI), these resources have shifted upward within the resource pyramid to become a productive play with growing proved reserves.

Fig. 2 [74351 bytes] (in three parts) shows how technology progress in well location and well completion has improved gas recoveries per well and thus the economics of the Mesaverde Williams Fork tight gas play in Rulison field. Fig. 2a shows the steady improvement, in reserves per well from 1985 to today. Fig. 2b shows how recompletion technology has improved the performance of the older wells, dramatically upgrading the economic outlook and resource potential for this tight gas field. Fig. 2c illustrates how advances in natural fracture detection technology could further upgrade the ability to target the higher productivity areas and help portions of this large, continuous-type tight gas sand play move up in the resource triangle.

The progression of resource forecasts by the U.S. Geological Survey (USGS) also illustrates the dynamic nature of the resource pyramid. In 1995, the USGS added continuous-type (unconventional) gas deposits in sandstones, shales, and chalks to its assessment and thus to the resource pyramid. In 1996, the USGS prepared a special quantitative assessment of the Mississippian-age Barnett shale of the Fort Worth basin,¹ carving a location within the pyramid for this resource. With the detailed work by the USGS on the Tertiary and Upper Cretaceous formations in the Wind River basin,^2-3 these tight gas sand resources will also have a prominent place within the resource pyramid in future assessments.

The process of moving into and expanding the resource pyramid is not yet bounded by any definable limits of the natural gas resource base but is greatly influenced by progress in E&P technology. But progress in E&P technology is not a commodity, available to be purchased when needed. Rather, it stems from the accumulation of small gains in the knowledge base and from long term investments in research. In the past, progress in technology has maintained the lead over resource depletion-the future outcome, given the extreme budgetary pressures on the natural gas R&D enterprise, is much less certain.

Expanding the pyramid

With the knowledge gained in recent years, a series of overlooked natural gas resources may now be highlighted and placed into the resource pyramid. Some of these resources, such as the Devonian to Mississippian-age New Albany (Illinois basin) and Upper Cretaceous Lewis (San Juan basin) gas shales, are already being produced. For these, the question is one of recognizing the position they occupy in the resource pyramid.

Other resources, such as the sub-volcanic gas plays, remain hypothetical. For these types of resources, our aim is to increase their recognition, counting on advances in knowledge and technology to secure their eventual position in the resource pyramid.

The emerging natural gas resources we discuss in this article are:

Sub-volcanic gas plays in the Columbia plateau, the Snake River downwarp, and the Bighorn and San Juan basins;
Emerging gas shale resources in the Illinois, San Juan, and San Joaquin basins;
Deep coalbed methane in the Piceance and Greater Green River basins; and
Emerging basin-centered (continuous) gas accumulations, not yet fully assessed.

Sub-volcanic gas plays

A number of natural-gas plays underlie regionally extensive surface-volcanic areas of the U.S. Surface volcanic fields degrade the resolution of geological and geophysical exploration methods, masking the nature of the petroleum system and making sub-volcanic exploration targets difficult to define. In addition, drilling through thick volcanic sequences is costly. For these reasons, sub-volcanic gas plays have been largely overlooked and constitute an emerging gas resource. The eight plays identified in Table 1 [144,939 bytes] and mapped in Fig. 3 [87,141 bytes] underlie three volcanic fields:

Miocene-age Columbia River basalts east of the Cascade Range in Washington and Oregon;
Holocene and Pleistocene-age Snake River basalts in southern Idaho; and
Eocene-age Absaroka volcanics in the western Bighorn basin, Wyo. All of these sub-volcanic plays are hypothetical, meaning that none has a significant gas discovery. These plays were established by the USGS in their 1995 National Assessment of U.S. oil and gas resources.⁴ The following discussion is drawn from a USGS Open-File Report by Schmoker and others.¹

Columbia River basalts

The surface of the Eastern Oregon-Washington Province is dominated by the middle to late Miocene Columbia River Basalt Group, a series of basalt flows at least 10,000 ft thick. The only commercial oil or gas production from this province has been in southern Washington from small Rattlesnake Hills gas field, which has produced an estimated 1.3 bcf of gas from two vesicular zones in basalt flows sealed by clay interbeds at depths of 700-1,300 ft. One unconventional and two conventional gas plays are defined in this province (Table 1).

Northwestern Columbia Plateau Gas Play (501). This play coincides with the inferred extent of a sequence of lower Tertiary fluvial and lacustrine sedimentary rocks beneath the Columbia River Basalt Group. Potential reservoir rocks consist of Eocene or Oligocene arkosic fluvial sandstones of the Swauk, Chumstick, Roslyn, and Wenatchee formations, and possibly fractured, vesicular basalt flows of the Columbia River Basalt Group.

Eight deep exploratory wells have been drilled in the play since the 1950s. Several of these were drilled to sub-basalt depths of 6,000-11,000 ft (maximum total depth is 17,518 ft), proving the presence of at least 11,000 ft of sedimentary rocks. Drill-stem tests in one well yielded 5-6 MMcfd of gas.

Play 501 is considered by the USGS to have a high probability of small gas accumulations, and a moderate probability (0.60) of at least one gas accumulation exceeding 6 bcf. Reservoir quality adequate for conventional gas accumulation larger than a few tens of billions of cubic feet has not been demonstrated, despite the possible presence of large traps. The mean risked technically recoverable resource estimate for this play 235 bcf.

Central and Northeastern Oregon Paleogene Gas Play (502). This play lies south of Play 501 (Fig. 3). Outcrop samples of fluvial or deltaic sandstone of the Paleocene or Eocene Herren and Clarno formations show adequate reservoir-rock quality. This unit is, at most, about 2,000 ft thick and consists of feld- spathic sandstone, carbonaceous shale, and coal, the distributions of which are poorly known. Only about 20 exploratory wells have been drilled in this gas play. An 8,726 ft well on the north flank of the Blue Mountains uplift, drilled in 1957, encountered Clarno formation volcanics overlying Mesozoic basement. A 9,000 ft well drilled in 1989 north of Heppner was abandoned within the Clarno formation. Several wells in the Ochoco sub-basin drilled between 1955 and 1981 demonstrated the presence of sedimentary rocks and had gas shows beneath the Columbia River basalts but found no commercial hydrocarbons.

Given the large area of this play and the number of untested traps, along with widespread seeps and shows, at least a few small gas accumulations are likely to be present. The possibility of larger accumulations (tens of billions of cu ft) exists but is not considered to be high because of concerns regarding the lateral continuity of adequate reservoir rocks. The mean risked technically recoverable resource estimate for this play is 78 bcf.

Columbia Basin-Basin-Centered Gas Play (503). This play is based on the interpreted presence of a basin-centered (continuous) gas accumulation, similar in concept to some of the established basin-centered gas accumulations of the Rocky Mountain basins. Reservoir rocks within the play are assumed to be pervasively charged with gas. The continuous gas accumulation of Play 503 is below the discrete, conventional gas fields of Play 501 (Fig. 3).

Data from five widely spaced wells show an overpressured interval that begins at depths ranging from 9,500-12,700 ft and is at least 6,400 ft thick. Within this overpressured interval, gas has been recovered on drill-stem tests at initial rates as high as 3.1 MMcfd with little or no produced water. The spatial dimensions of the proposed basin-centered gas accumulation are imprecisely known because of insufficient deep drilling.

What little exploration activity has taken place in the play area has focused on conventional structural accumulations. The hypothesis that a basin-centered gas accumulation exists leads to a mean resource estimate of 12,200 bcf of gas for Play 503 (Table 1).

Snake River basalts

The southern part of the Idaho-Snake River Downwarp Province contains an arcuate structural graben about 350 miles long and 50-100 miles wide across southern Idaho from southeastern Oregon to Yellowstone National Park (Fig. 3).

Prior to development of the downwarp, this area of southwestern Idaho was occupied by a basin in which sediments of early Tertiary age are assumed to have been deposited. By early Miocene time, this basin was occupied by a large lake (Lake Bruneau) in which 5,000-7,000 ft of primarily lacustrine sediments of the Miocene-age Sucker Creek formation were deposited. Rifting and graben development in Pliocene time led to the formation of Lake Idaho, in which as much as 9,000 ft of fluvial and lacustrine sediments were deposited. Four conventional sub-volcanic gas plays are defined for this province (Table 1).

Miocene Lacustrine (Lake Bruneau) Play (1701). This play is based on the presence of thick sediments of the Sucker Creek formation in the southwestern half of the Snake River downwarp. Potential reservoir rocks are lacustrine and perhaps fluvial sandstones and algal carbonates. Play 1701 is considered to be a high risk, gas-prone play. Numerous gas and some oil shows have been reported in lacustrine beds of the Sucker Creek formation in both shallow water wells and wells drilled for petroleum. Temperature gradients are high in much of the area, and reservoir quality may be adversely affected by diagenesis of intermixed volcanic material. The mean risked technically recoverable resource estimate for this play is 11 bcf of gas.

Pliocene Lacustrine (Lake Idaho) Play (1702). This play is based on the presence of thick sediments, of primarily Pliocene age, in the southwestern half of the Snake River downwarp. Potential reservoir rocks are fluvial and lacustrine sandstones and conglomerates and algal carbonates. Play 1702 is gas prone and high risk. Because of its low play probability (0.10), this play was not quantitatively assessed by the USGS.

Pre-Miocene Play (1703). This play is based on the possible presence of Paleozoic and Mesozoic rocks in Laramide thrusts beneath the northeastern half of the Snake River downwarp. Potential reservoir rocks are marine carbonates and sandstones, which might be highly fractured and are possibly metamorphosed. Play 1703 is gas prone and highly speculative. Because of its low play probability (0.07), this play was not quantitatively assessed by the USGS.

Older Tertiary Play (1704). This play is based on the probable presence of a thick section of early Tertiary rocks (potentially partly marine) in the southwestern corner of the Snake River downwarp. Potential reservoir rocks are fluvial, lacustrine, and marine sandstones and carbonates. Play 1704 is deep and gas prone with very high risk. Quantitative data are sparse to absent. Because of its low play probability (0.06), this play was not quantitatively assessed by the USGS.

Bighorn basin

The Bighorn basin is an asymmetric intermontane basin of the Rocky Mountain foreland, located in north-central Wyoming and south-central Montana. The surface of the western margin of the Bighorn Basin Province, west of Cody, Wyo. (Fig. 3), is dominated by Eocene-age volcanic rocks of the Absaroka volcanic plateau. Approximately 2.7 billion bbl of oil and 1,800 bcf of gas have been discovered (as of yearend 1990).

The majority of production has been from basin-margin anticlinal structures. The basin tends to be oil prone, and the few fields discovered beneath the Absaroka volcanics to date have been oil fields. Although Play 3405 was assessed by the USGS as an oil play, it is included here because of the possibility of unrecognized gas potential beneath the volcanics.

Sub-Absaroka Play (3405). This play is based on the presence of hydrocarbon-productive Paleozoic and Mesozoic-age rocks of the Bighorn basin beneath Eocene-age volcanic rocks. The limits of the play to the north, east, and south coincide with the extent of the Absaroka volcanics. To the west, the play is bounded by subcropping sedimentary strata.

Based on nearby production, quartzose sandstone of the Pennsylvanian Ten- sleep sandstone is the primary reservoir. Other potential reservoir rocks include carbonates of the Mississippian Madison and Permian Phosphoria and Dinwoody, and sandstones of the Pennsylvanian Darwin, Triassic Chugwater, and Jurassic Curtis formations.

Six small oil fields have been found beneath (but near the eastern edge of) the volcanics. The potential for significant new-field discoveries for Play 3405 is considered to be good, but uncertainty exists as to whether geologic conditions might support nonassociated gas fields. Play 3405 was not quantitatively assessed by the USGS for gas.

Other sub-volcanics

As industry improves its exploration methods, in part by applying experience gained in subsalt offshore plays, other sub-volcanic gas plays will likely emerge.

One such recently identified play underlies the San Juan volcanic field of south-central Colorado that conceals the San Juan sag, a potential hydrocarbon-containing basin formed during the Laramide orogeny (Fig. 4 [43,252 bytes]). Prospective formations include the Late Cretaceous Mancos shale and the stratigraphic equivalents of Tertiary and Cretaceous-age reservoir rocks in the San Juan basin. To date, 13 oil and gas tests have been drilled in the San Juan sag. All of these wells had oil or gas shows, but none established commercial production.

Emerging gas shale resources

Following successful development in the Antrim shale (Michigan basin) and Barnett shale (Fort Worth basin), the gas-bearing shale resource has gained new attention. Of particular interest has been the exploration and delineation drilling in the New Albany (Illinois basin) and Lewis (San Juan basin) gas shales. Initial appraisals and reservoir characterization are also under way in the Monterey shale (San Joaquin basin).

The National Petroleum Council's 1992 study⁵ provided a preliminary estimate for gas in place and recoverable resources for some of these gas shale plays (Table 2 [37,206 bytes]), but because of "limited knowledge" did not include these resources in its gas supply projections. The USGS 1995 Assessment provided quantitative resource forecasts for the New Albany shale (Illinois basin) and the closely related Devonian black shales (Cincinnati arch) gas play, adding these resources to the resource pyramid.

New Albany shale

The Upper Devonian to Lower Mississippian New Albany shale is both the source rock and reservoir for a developing unconventional (continuous) gas play in the Illinois basin. The play boundary, which encompasses about 15,200 sq miles, is defined by vitrinite reflectance (Ro) values of 0.6% or greater in the organic-rich shale facies in the southeastern part of the basin. Maturation levels tend to increase southward, with the highest Ro values reported in southeastern Illinois and adjacent western Kentucky. The depth of the play ranges from 500-5,300 ft. The presence of a thick, organic-rich shale section and a high intensity of natural fractures are two important exploration criteria in this gas play.

Small amounts of natural gas have been produced from this play along the southeastern border of the basin. In the 1995 National Assessment, the USGS estimated 1,889 bcf (mean) of technically recoverable gas and categorized the New Albany shale gas play as hypothetical. The average well was expected to produce 0.12 bcf, with production from the best wells ranging up to 1 bcf. Drilling success rate was estimated at only 50%, given the limited knowledge available for this play at the time the USGS assessment was prepared.

The New Albany shale continuous gas accumulation may consist of two distinct plays.⁶ A water-free gas play is indicated in west-central Kentucky, south of the Rough Creek fault system that extends into southern Illinois. Thus far, the reported gas rates from the few exploration wells in this play area have not been sufficient to maintain exploration interest. A second gas play, in which wells produce water, occurs in southern Indiana, where natural fractures caused by basement faults and folds provide enhanced permeability. The bulk of recent exploration and development wells are in this second area and have yielded highly variable results.

Lewis shale

The Lewis shale in the San Juan basin of New Mexico and Colorado is an Upper Cretaceous-age package of sandy mudstone and shale, deposited in a lower shoreface to offshore marine setting. The Lewis shale averages 1,400 ft thick and lies stratigraphically above the Cliff House sandstone. It has a typical reservoir pressure of 1,150 psi and holds a maximum of 88 bcf/sq mile of gas in place. About 90% of the stored gas is adsorbed on the organic matter in the shale and muddy sandstone. Gas in place for the north-central portion of the basin has been estimated at 24 tcf.⁷

The productive potential of the Lewis shale was first established in the 1970s by uphole completions of 16 wells drilled to deeper objectives (Fig. 5 [86,114 bytes]). Initial production from these wells ranged from 1-10 MMcfd of gas with estimated ultimate recoveries reported by the operator of 5-70 bcf/well. Fig. 6 [25,967 bytes] provides the production history for one of the Lewis shale gas wells. By early 1997, nearly 90 wells including re-entries of existing wells and uphole recompletions were producing from Lewis shale, 11 new or re-completed wells along the eastern edge of the Lewis trend flowed 100-540 Mcfd of gas after stimulation.

A horizontal Lewis well (Howell L #5 in 34-30n-8w), with 2,100 ft of lateral section, was drilled in 1991. The well encountered a partly depleted reservoir, with a reservoir pressure of 486 psi, due to a highly prolific offset producer. This horizontal well has averaged 300 Mcfd of gas and has produced about 0.6 bcf in five years. Higher pressured, undepleted portions of the Lewis shale reservoir, completed with multiple laterals, may perform better.

An attractive development strategy for this play might be to identify the higher productivity, naturally fractured parts of the trend and then recomplete uphole some of the roughly 3,000 Lewis shale penetrations that are favorably located with respect to naturally fractured "sweet spots."

Monterey shale

The Miocene-age Monterey (Antelope) shale has long been viewed as an oil play. However, production of gas far in excess of solution gas in the oil, along with recent core and desorption data,8 indicates that these organic-rich shales may hold substantial volumes of adsorbed gas. Initial estimates indicate gas concentrations on the order of 100-120 bcf/sq mile in favorable portions of the basin, with adsorbed gas on the organic matter in the shale accounting for about 70% of the in-place resource.

The most intensive development of the Monterey shale has been in Buena Vista field in the southeast portion of the San Joaquin basin, at depths of 4,000-5,000 ft. The 105 wells in the Honolulu (East) anticline in this field have produced 168 bcf. The 12 best wells have produced 4-10 bcf each. The 56 wells in the United (West) anticline have produced 47 bcf, with the best six wells having recovered 2-4 bcf each. Reservoir studies indicate that one-half to two-thirds of this production is from adsorbed gas in the shale. Additional adsorbed gas would be liberated by reducing the reservoir pressure below the current 500-700 psi in these two reservoir units.

Deep coalbed methane

An unevaluated but perhaps significant portion of the coalbed methane resource, which is not included in the resource pyramid at present, resides in deep coals, that is coals at depths below 5,000-6,000 ft. Industry has been reluctant to pursue gas in these "deep coals" for at least four reasons:

Limited subsurface data;
Higher drilling costs;
Assumed unfavorable desorption characteristics; and,
Assumed low permeability.

Of these reasons for avoiding deep coals, the decrease of permeability with increasing depth is the one most often mentioned. The low permeabilities encountered at GRI's Deep Coal Seam Test Site (Red Mountain, Piceance basin) and the unfavorable permeability versus depth charts presented in various technical reports are commonly cited as evidence for insufficient permeability in deep coals. Yet, if adequate permeability were available, deep coals could be highly attractive exploration targets because of their high gas contents and pressures. The USGS in 1995 did not assess the resource potential of coalbed methane below 6,000 ft.

Piceance basin

Approximately 50 tcf of the 84 tcf of coalbed methane estimated to be in place in the Piceance basin is in coals below 6,000 ft. The primary reservoir is the Cameo coal in the lower part of the Upper Cretaceous Williams Fork formation (Mesaverde Group) at depths of 6,000-8,000 ft (Fig. 7 [62,180 bytes]).

Numerous deep Cameo coalbed methane wells were drilled in Grand Valley field in the late 1980s, usually as dual coal and sandstone completions. Barrett Resources reported that 23 Grand Valley Cameo coalbed producers had collectively produced over 2 bcf of gas from their initial production in late 1989 through November 1990. Currently, the coalbed methane production from wells in Grand Valley/Parachute and Rulison fields is commingled with uphole tight gas sand completions, making the appraisal and reporting of deep coalbed methane performance difficult. Other deep coalbed methane development in the Piceance basin includes the following:

The discovery well at Pinyon Ridge field, the Federal A-1, in Rio Blanco County of the northern Piceance basin, was drilled in late 1991 and perforated in 30 ft of net coal at 5,501-5,772 ft. This well tested 959 Mcfd of gas plus 13 b/d of condensate. It produced 1.6 bcf of gas before being shut in. The other eight coalbed methane wells in this field are completed at 5,700-6,800 ft. Pinyon Ridge field is shut-in because of high water production.
White River coalbed methane field, operated by Tom Brown Inc. in Rio Blanco County south of Pinyon Ridge field, produces from the Cameo and Coal Ridge coals at depths of 5,090-7,547 ft. The field is currently producing about 3 MMcfd of gas from 10 active wells (Fig. 8 [23,928 bytes]).

These developments show that deep coalbed methane in the Piceance basin can be produced in geologically favorable areas, with the use of appropriate completion technologies. Deep coalbed methane may need to be addressed in future resource assessments and added to the resource pyramid.

Green River basin

The Greater Green River basin is estimated to hold 267 tcf (in place) of deep coalbed methane (below 6,000 ft) in three formations:⁹ the Tertiary Fort Union with 33 tcf, the Upper Cretaceous Almond with 141 tcf, and the Upper Cretaceous Rock Springs with 93 tcf (Table 3 [30,757 bytes]).

The Fort Union deep coals, while extensive and persistent throughout the basin, appear to have low gas contents, on the order of 100 scf/ton. The deep coals in the Almond formation appear to have high gas contents of 350-530 scf/ton but are generally thin except in the southern Sand Wash area of the basin. The Rock Springs deep coals with high gas contents of 350-550 scf/ton and well developed sequences north and west of the Rock Springs uplift have uncertain permeability.

Finding areas (sweet spots) where the deep coalbed methane resources of the Greater Green River basin are economically productive remains a challenge, as shown by the following two examples:

One well, the 2 UPRC-1 at 4,735 ft, averaged 78 Mcfd of gas and 200 b/d of water during a 530 day test (in 1991-92) of the Rock Springs coals on the north flank of the Rock Springs uplift. This well provides evidence that gas production may be possible from the deeper coals in this basin.

Three wells drilled at 7,000 ft in Table Rock field (east central basin) tested low permeability in the Almond coals, indicating that, in this area, the deep coals may be unproductive. These wells were subsequently completed in Almond sandstones.

Other accumulations

A fourth group of emerging gas resources is continuous-type accumulations, large single fields having spatial dimensions equal to or exceeding those of most conventional plays.

These accumulations are not discrete entities delineated by down-dip hydrocarbon-water contacts, as are conventional fields, and cannot be assessed using probabilistic methods based on the sizes and numbers of discrete fields. Rather, a combination of geologic and engineering methods is required to evaluate these resources. Continuous-type gas accumulations include basin-centered gas, gas in many of the so-called "tight" sandstone reservoirs, shallow biogenic gas, and gas in fractured shales and carbonates. Schmoker10 provides a detailed discussion of continuous-type plays and their assessment.

In 1995, the USGS identified 61 continuous-type oil and gas plays in sandstones, shales, and chalks. Of the 61 identified plays, 47 were assessed by the method described above, of which 34 were gas plays. Estimates of technically-recoverable gas resources from continuous-type sandstones, shales, and chalks range from 219 tcf (95th fractile) to 417 tcf (5th fractile), with a mean estimate of 308 tcf. Table 4 [41,568 bytes]contains mean estimates of continuous gas by geologic province for sandstones, shales, and chalks.

The list of Table 4 is not inclusive. Four categories of continuous-type plays can be identified with the new data and perceptions since the USGS 1995 Assessment:

Continuous-type plays described in the 1995 study that may need to be updated with new data; these plays will not be addressed further in this report;
Continuous-type plays that may have been identified incorrectly as conventional plays and assessed as such in 1995;
Continuous-type plays that were identified in 1995 but were not assessed because of lack of data; and
New continuous-type plays that were not identified in 1995.

Table 5 [171,205 bytes] (based on an analysis of data available since 1995) contains examples of potential continuous-type accumulations in five regions of the U.S. that may lead to new gas plays that may be added to the resource pyramid. These potential accumulations vary qualitatively from low to high probability of existence and may or may not survive rigorous geologic scrutiny during a full geologic assessment.

Continuous-Type Accumulations Previously Assessed as Conventional Plays
Four potential continuous-type accumulations listed on Table 5 were assessed (at least in part) as conventional plays by the USGS in 1995, and a reassessment might significantly change the resource estimates. As an example, in the 1995 Assessment, the USGS estimated a mean technically recoverable undiscovered resource of 0.9 tcf of gas from two conventional plays involving the Forbes-Kione formations of the Sacramento basin.⁴ The Late Cretaceous Forbes formation was identified as both a source and reservoir rock in both plays. Gas was assumed to be associated with combination structural-stratigraphic traps sealed by interbedded shales. An alternate model, for continuous-type plays, might increase the resource estimate because of the larger in-place "continuous" resource.
Previously Identified But Not Assessed Continuous-Type Accumulations
As an example of this category, in 1995, the USGS identified the Barnett shale as a continuous-type play but did not assess it because of a lack of data. Subsequently, resource estimates by Schmoker and others¹ and by Kuuskraa and others¹¹ have forecast a mean recoverable resource of 3.4 tcf (1996 assessment) and possibly as much as 10 tcf (1998 estimate). The most recent estimate assumes the intensive development of higher quality areas in the play in which wells are projected to be drilled at closer, 80 and 160 acre, spacing than assumed in the 1996 study. Other examples of identified but not assessed plays in Table 5 include the Wind River and Bighorn basins. The basin-centered accumulation in the Wind River basin in the Rocky Mountain region has been recently evaluated by the USGS.^2-3 The Cretaceous and Tertiary continuous-type reservoirs of the Bighorn basin are being evaluated with the aid of mudlogs, drill stem test, and thermal maturity data from 14 significant wells to determine the areal extent of the accumulation.¹²
3. Previously Unidentified Continuous-Type Accumulations Five potential accumulations are listed in Table 5 that were not identified by the USGS in 1995. These accumulations are located in northern and central Alaska, the Raton and Hanna basins of the Rocky Mountain region, and the Ardmore-Marietta-Arkoma basins of the Midcontinent region. The probability seems high that at least some of these plays (as well as others yet to be identified) will eventually contribute to the resource pyramid for natural gas.

Summary

The U.S. is in a race between gas reserves depletion stemming from high volumes of annual production and gas resource-base expansion resulting from advancing E&P technology. The concept of a dynamic resource pyramid and the identification of emerging gas plays help to illustrate how the gas resource base may expand and shift in the future.

Even though we have identified a number of "new" natural gas resources, this list is far from exhaustive. Our aim has been to bolster, with data, the thesis that the U.S. contains significant gas resources that have yet to be fully defined or intensively developed.

Acknowledgments

The authors express their appreciation to the Gas Research Institute, particularly Tom H. Fate and Charles F. Brandenburg, for supporting this study of emerging natural gas resources. This work was funded in part by the U.S. Geological Survey's Energy Resources Program and a Cooperative Research and Development Agreement (Crada) with Advanced Resources International Inc. in Arlington, Va., and the Gas Research Institute, Chicago. Iris Drayton for her administrative support and patience.

References

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Tyler, R., Kaiser, W.R., Scott, A.R., Hamilton, D.S., and Ambrose, W.A., Geologic and hydrologic assessment of natural gas from coal, Greater Green River, Piceance, Powder River, and Raton basins, Western U.S., IR No. 228, University of Texas at Austin, Bureau of Economic Geology, Austin, 1995, p. 219.
Schmoker, J.W., Method for assessing continuous-type (unconventional) hydrocarbon accumulations, in Gautier, D.L., Dolton, G.L., Takahashi, K.I., and Vornes, K.L., eds., 1995 National Assessment of U.S. Oil and Gas Resources, 1995.
Kuuskraa, V.A., Schmoker, J.W., Koperna, G., and Quinn, J.C., Barnett shale is rising star in Fort Worth basin, OGJ, May 25, 1998, pp. 67-76.
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Gries, R.R., Clayton, J.L., and Leonard, C., Geology, Thermal Maturation, and Source Rock Geochemistry in a Volcanic Covered Basin: San Juan Sag, South-Central Colorado: AAPG Bulletin, Vol. 81, No. 7 (July 1997), pp. 1,133-60.
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This series

Part 1-Kuuskraa, Vello A., Outlook bright for U.S. natural gas resources, OGJ, Apr. 13, 1998, p. 92.

Part 2-Dyman, Thaddeus S., Schmoker, James W., and Root, David H.., USGS assesses deep undiscovered gas resource, OGJ, Apr. 20, 1998, p. 99.

Part 3-Reeves, S.R., Kuuskraa, J.A., and Kuuskraa, V.A., Deep gas poses opportunities, challenges to U.S. operators, OGJ, May 4, 1998, p. 133.

Part 4-Collett, Timothy S., and Kuuskraa, V.A., Hydrates contain vast store of world gas resources, OGJ, May 11, 1998, p. 90.

Part 5-Kuuskraa, V.A., Koperna, George, Schmoker, J.W., and Quinn, John C., Barnett shale is rising star in Fort Worth basin, OGJ, May 25, 1998, p. 67.

End Part 6 of 6