Unconventional resources hold tremendous potential for the US market.

No matter whose forecast you read, the US Energy Information Agency's (EIA), the American Gas Association's or the National Petroleum Council's (NPC), natural gas is expected to play a major role in fueling the future US economy.
Developing resources at depths greater than 15,000 ft (4,575 m), in water depths beyond 4,000 ft (1,220 m), and in unconventional reservoirs, will be key to meeting future domestic demand for gas. Two regions in particular - the deepwater Gulf of Mexico and the Rocky Mountains - will be called on to contribute significantly to new US supplies.
As new discoveries from conventional supplies decline, future gas supplies increasingly will have to come from unconventional reservoirs. Several Rocky Mountain basins - Greater Green River, Piceance, Wind River and Uinta - contain significant volumes of such resources (tight gas sands and coal seams in particular). In its most recent study, NPC concluded unconventional production in the Rocky Mountain region would increase 1 Tcf per year by 2010 and as much as 1.5 Tcf per year by 2015. EIA's Annual Energy Outlook 2002 projected total natural gas production from the Rocky Mountains will increase from 3.1 Tcf in 2000 to 5.75 Tcf in 2020.
The US Department of Energy and National Energy Technology Laboratory (NETL) have researched low-permeability (tight) gas reservoirs for more than 30 years. Major field tests like the multiwell experiment and the multisite experiment at Rifle, Colo., provided tremendous insight into the characterization of low-permeability gas sands, associated natural fracture networks, and the implications of hydraulic fracturing.
Resource assessment
During the past 12 years, NETL has worked closely with the United States Geological Survey (USGS) to assess the potential of low-permeability sandstones in key basins. This work included exhaustive resource studies for the key basins of the Rocky Mountain region, including the Piceance (Johnson, et al, 1987), Greater Green River (Law, et al, 1989), Wind River (Johnson, et al, 1996) and Bighorn (Johnson, et al, 1999) basins. These studies estimate a staggering total of 6,800 Tcf of natural gas resource may be present in these four basins.
NETL's work in bringing basin-centered gas into the "light of day" has not only served to highlight the concept and importance of basin-centered gas, but has provided industry with a sound rationale for off-structure exploration and development. One major effort at the Strategic Center for Natural Gas has focused on reassessing the in-place resources of major, untapped domestic gas basins. This effort will produce detailed gas-in-place resource assessments for selected marginal gas plays (tight sands and deep plays), identify the technological advances required to accelerate entry of portions of this gas into the nation's gas reserve, and document the amount of gas beneath federal lands, where drilling is prohibited or restricted. The Greater Green River and Wind River basins are the first to be evaluated.
In the case of the Greater Green River Basin (GGRB), a series of stratigraphic cross-sections and sandstone isopach maps will illustrate the regional distribution of gas-bearing sandstones in the Lewis, Upper Mesaverde (Almond/Erickson), Lower Mesaverde, Frontier, Dakota and Madison plays. Plays characterized in the Wind River basin will include the Fort Union, Lance, Mesaverde, Frontier, Dakota, Nuggett, Tensleep and Madison.
This reassessment of the Greater Green River and Wind River basins was to be completed in June. A topical report providing details of the study (in-place resources by play, results of the advanced technology runs, impact of land use restrictions) will be posted on the Strategic Center for Natural Gas (SCNG) Web site. A CD-ROM that preserves relevant isopach maps and stratigraphic cross-sections will be made available to the gas industry. The Anadarko and Uinta basins are likely to be reassessed next.
Fracture-finding technologies
During the past several years, independents have indicated seismic and geophysical technologies have been among the most beneficial to their operations. In their efforts to develop more efficient methods for locating and developing tight sand gas, operators in the Rocky Mountains have identified two key goals: finding zones of high natural fracture density and avoiding water. NETL manages more than 10 projects designed to help industry improve its ability to achieve these goals (Table 1). Several are close to completion.
For example, under one contract, Geospectrum Inc. of Midland, Texas, is developing a methodology for identifying areas of high natural fracture density in the San Juan Basin using seismic attributes gleaned from multiazimuth seismic data. The company analyzed petrophysical data, borehole image data and production data for fractured plays in the Lower Dakota sandstone and found certain seismic attributes track high production. Specifically, areas of high seismic lineament density, favorable AVO anomalies, a phase difference that correlates with low clay content and seismically mapped paleo-channels correspond to those areas with the best producing wells and best natural fracture networks. Using these relationships, Geospectrum proposed a Lower Dakota well site. Industry partner Burlington Resources has approved the test, and results should be available soon.
Advanced Resources International (ARI) has demonstrated the application of geomechanical modeling to identify areas of open natural fracture networks. Its first study, in the Rulison field (Piceance Basin), showed that wells within a stress envelope indicating open fractures had estimated ultimate recoveries that were higher by 1.5 Bcf to 2 Bcf than wells outside the envelope. The model subsequently was used in a step-out mode to verify the proposed location of a horizontal well in the Frontier Formation in the GGRB. That well intercepted more than 400 open natural fractures.
In another project, Stanford University is using the principles of rock physics to quantitatively link seismic, geologic and log data in a study of fractured carbonate reservoirs in the James Limestone of the East Texas Neuville field. In analyzing a vertical seismic profile dataset, researchers found interval velocities are diminished and p-to-p wave reflections lose amplitude in areas of high fracture density. Also, travel time is delayed while scattering attenuation increases for seismic waves traveling orthogonal to oriented fracture sets. By combining these seismic attributes, researchers can distinguish between fractured and unfractured zones of the reservoir and predict the strike and dip of oriented fractures. In the project's ongoing third phase, researchers will apply this newly developed approach to a full 3-D seismic dataset to extend its utility to a larger geographic area. Industry partner Marathon Oil Co. is providing critical support for the project.
Avoiding water production
The presence of mobile water and high water production rates continues to plague certain producing areas in the Rocky Mountains. For example, Union Pacific Resources (now Anadarko Petroleum Corp.) drilled a 2,300-ft (702-m) lateral section, with more than 1,600 ft (488 m) in the Frontier Formation, at 15,000 ft (4,575 m) in the GGRB near Table Rock field (Rock Island 4H well). The well has produced 6.4 Bcf of gas in less than 3 years and is making nearly 4 MMcf/d of gas, supporting the potential benefits of drilling horizontal wells to intersect natural fractures. However, the well has produced a significant amount of water, at times more than 1,000 b/d, and this high rate has affected gas recovery. Portions of the Mesaverde Formation in the GGRB's Wamsutter area also are known to produce water, and in the Wind River Basin, significant water problems in hot plays like Cave Gulch are beginning to make operators apprehensive. But just where is this water coming from, and how can it be avoided? Two new SCNG projects will begin to address these issues.
Researchers at Innovative Discovery Technologies will remove some of the risks and uncertainty of drilling tight gas wells by developing a basinwide, 3-D model of the Wind River Basin that will provide detailed information about the reservoir before drilling begins. The model will map water and gas content, enhanced porosity and permeability areas (sweet spots), and characterize pressure boundaries. As a result, gas companies can avoid excessive water production by designing optimum drilling and completion programs.
Concurrently, ARI is assembling a high-quality, regional water composition database for the Greater Green River and Wind River basins by classifying water compositions and modes of occurrence. Field tests will establish and verify regional water storage and flow models using the Waltman/Cave Gulch field complex in the eastern Wind River Basin, Wyo., as the field test site. These models will provide options for avoiding or mitigating the problems caused by high water production.
Barrett Resources (now Williams Production) launched a methodical program of downspacing, first to 80 acres per well, next to 40 acres per well and finally to 20 acres per well.
Independent analysis by ARI of 30 closely spaced wells drilled in Section 20, T6S R94W of the Rulison field shows that each of these downspacings added significant reserves (59 Bcf in Section 20 alone), without any significant depletion of reserves or reservoir pressure in the previously drilled wells.

Editor's note: For more information on the status of the projects described, check out the Projects page at www.fetc.doe.gov/scng/index.html, or contact James Ammer, NETL project manager for natural gas supply and storage, (304) 285-4383 or james.ammer@nelt.doe.gov.

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