Naval oil shale lands may hold large Piceance gas potential

Thomas E. Hoak
Kestrel Geoscience LLC
Littleton, Colo.

Alan L. Klawitter
Consulting Geologist
Denver, Colo.

Kermit G. Witherbee
Bureau of Land Management
Lakewood, Colo.

For many years, federal agencies have debated the fate of the Naval Oil Shale Reserves by juxtaposing the value of their natural resources and recreational value against ongoing operating costs. Recently, the decision was made to commence divestiture of these properties, and the Bureau of Land Management was instructed to conduct lease auctions.

As part of this process, on Mar. 25, 1999, the BLM office in Lakewood, Colo., will accept oral bids at a lease auction for Naval Oil Shale Reserve No. 3 property in Colorado's central Piceance basin. This property is adjacent to large Grand Valley, Parachute, and Rulison gas fields, owned and operated by Barrett Resources Corp. of Denver, that straddle the large, basin-centered gas reservoir.

The central Piceance basin produces gas from multiple horizons in Cretaceous and younger sediments. The gas-centered basin geometry possesses a thick, gas-saturated section that significantly reduces exploration risk and leaves only reservoir thickness (a function of depositional systems) and reservoir quality or permeability (a function of natural fracturing) as unknown exploration variables.

As a result, exploration and drilling risk is extremely low. Because of low reservoir matrix permeability, natural fracturing is critical because it controls wellbore deliverability and the ultimate profitability of a well. Unfortunately, exploration methodologies developed to date for this basin cannot fully predict reservoir thickness from a depositional systems perspective. Significantly greater success has been achieved in our ability to predict the likelihood and location of tectonic fracturing. Deeper pay potential exists but at the present time is uneconomic.

Overview of the opportunity

A look at the properties shows existing producing wells on the properties and outlines the area's large infill and step-out potential (Fig. 1 [100,974 bytes]).

It is important to recognize that the northern half of the map area is bordered by the steep topography of the Roan Cliffs that effectively precludes drill pad development. It is possible, however, to exploit these areas by drilling directionally from the base of the cliff areas. It is currently uneconomic to do so, although future increases in gas prices may stimulate such activity.

Locally, Mesaverde wells intersecting natural fracture networks produce up to 2.5 bcf/well (TD range 7,850-9,500 ft).^1-3 Shallower Wasatch wells drilled from the same well pad can produce an additional 1 bcf (TD range 2,750-3,200 ft).

The U.S. Department of Energy operates and has working interests in wells on the four parcels that have produced 21 bcf with 12 bcf proved remaining reserves. Four parcels totaling 8,448 acres are to be offered at the auction.

It can be seen from Table 1 [85,272 bytes] that these properties can potentially produce an additional 318.6 bcf from the Mesaverde Group and an additional 182.2 bcf from the shallower Wasatch sands. These figures conservatively assume that each Wasatch well will produce 0.9 bcf and each Mesaverde Group well will produce 1.8 bcf.

Table 1 values also assume that all of the property is drillable on 40 and 160 acre spacings for the Mesaverde and Wasatch, respectively. Because of steep topography and land use restrictions, comprehensive infill of the area requires directional drilling, currently uneconomic. We have conservatively estimated that 50% of the area would require directional drilling. This reduction in conventional drilling area, however, still permits a very large development reserve potential of nearly 250 bcf.

Typical drilling and completion costs in the area range from $750,000-815,000 for a Mesaverde completion, and $265,000-320,000 for a Wasatch producer. These costs vary according to drilling depth, stimulation size, and the number of zones stimulated. Conversations with adjacent operators in the basin indicate that significant cost savings can be achieved through long-term drilling programs and economies of scale. Production costs for the DOE wells range from $700-1,000/month.

Exploration methodology

Over the past 21/2 years, Kestrel Geoscience LLC has developed an extensive data base and an integrated exploration methodology for identifying zones of enhanced natural fracturing in the Piceance basin subsurface.

In the gas-saturated basin center, the inability to predict Mesaverde Group fluvial sand depositional trends requires that exploration and drilling risk be minimized by predicting the characteristics of fracture systems in the tight gas sand reservoirs. As a result, significant effort has been focused on identifying, characterizing, and attempting to predict subsurface fracture characteristics.

The fractured nature of the Mesaverde and Wasatch reservoirs is well known from previous work^2-7 and subsurface image logs. An example of a typical fracture image log interval from a Mesaverde Group sandstone from within the DOE lease area is shown in Fig. 2 [348,712 bytes].

We have compiled subsurface fracture data from throughout the basin and integrated it with subsurface image logs from the DOE property and adjacent areas. Knowledge of fracture characteristics (e.g., density, aperture, genesis, and orientation) is critical to designing the most efficient drilling drainage pattern and identifying zones of enhanced wellbore deliverability from Mesaverde and Wasatch tight gas sand reservoirs.

Fractured reservoir exploration methodology is based on the recognition that basement faults and shallower structural features create zones of enhanced fracturing in the reservoir sands that overlie the deeper structures.³ The zones of enhanced fracturing are related to deformation processes that occur above the thrust fault tip.

An illustration of this relationship is shown in Fig. 3 [107,255 bytes], which outlines the fault tip source that appears to control subsurface fracture intensity. In this model, thrust-related shortening at deeper levels terminates up-section or updip of the fault into a series of fracture swarms. A 3D seismic section from northeast Rulison field illustrating this geometry is shown in Fig. 4 [240,231 bytes].³

The integrated interpretation of the central Piceance basin includes the following data sets: sand trend and thickness maps, high spatial resolution aeromagnetic surveys, high resolution 2D seismic lines, fracture imaging logs, and surficial geologic and detailed production mapping. This information has been further calibrated and augmented with data from the Multiwell Experiment (MWX) site, related GRI and DOE-sponsored research projects, and industry sources from throughout the basin.

It is critical to note that not all basement features observed in magnetic data packages will appear at shallower reservoir levels because of the presence of multiple detachment horizons in the basin (e.g., see seismic section in Fig. 4). Some previous workers have not fully appreciated the implications of this geometry.

Fig. 5 [165,050 bytes] outlines the fracture model in schematic cross-section for typical thrust-related fractured reservoirs in the basin. Linking aeromagnetic interpretations with available 2D seismic data permits the extrapolation of observed basement fault geometries and, when integrated with information about depositional systems and existing production trends, allows us to identify zones of highly-prospective fracture-enhanced production.

What's ahead

A significant acquisition opportunity in a proven, low-risk basin-center gas play awaits operators interested in acquiring existing production with significant development potential.

Shallow and moderate drilling depths to two producing formations are present, along with the possibility of hydrocarbon production from deeper Cretaceous targets. Drilling and production costs are moderate, and an extensive infrastructure system is already in place. Wells intersecting natural fracture systems in the reservoirs are very economic and require only minimal low-cost stimulations.

An exploration model has been developed that uses available data to identify the most likely locations to encounter the natural fracture zones at the reservoir level and best exploit natural fracture anisotropy for most efficient reservoir drainage.

Acknowledgments

The authors acknowledge the generous assistance and support of the BLM office in Lakewood, Colo. Significant assistance was also provided earlier by William Gwilliam, DOE Federal Energy Technology Center, Morgantown, W.Va.

References

1. Reinecke, K.M., Rice, D.D., and Johnson, R.C., Characteristics and development of fluvial sandstone and coalbed reservoirs of Upper Cretaceous Mesaverde Group, Grand Valley, Colorado, in Coalbed methane, Rocky Mountain Association of Geologists Publication, 1991, pp. 209-225.
2. Tyler, R., Kaiser, W.R., McMurry, R.G., Nance, H.S., Scott, A.R., and Zhou, N., Geologic characterization and coalbed methane occurrence: Williams Fork formation, Piceance basin, Northwest Colorado, annual report for Gas Research Institute, GRI-94-0456 (Contract No. 5091-2261), 1995, 218 p.
3. Hoak, T.E., and Klawitter, A.L., Prediction of fractured reservoir production trends and compartmentalization using an integrated analysis of basement structures in the Piceance basin, Western Colorado, in Hoak, T.E., Klawitter, A.L., and Blomquist, P.K., eds., Fractured reservoirs: characterization and modeling, RMAG Guidebook, 1997, pp. 67-102.
4. Lorenz, J.C., and Finley, S.J., Regional fractures I: A mechanism for the formation of regional fractures at depth in flat-lying reservoirs, AAPG Bull., Vol. 75, 1991, pp. 1,714-37.
5. Lorenz, J.C., Teufel, L.E., and Warpinski, N.R., 1991, Regional fractures II: Fracturing of Mesaverde reservoirs in the Piceance basin, AAPG Bull., Vol. 75, 1991, pp. 1,738-57.
6. Hoak, T.E., and Klawitter, A.L., Delineation of Piceance basin basement structures using multiple source data: implications for fractured reservoir exploration, Paper No. 9515, International Coalbed Methane Symposium (Intergas '95), 1995, 23 p.
7. Lorenz, J.C., Nadon, G.C., and LaFreniere, L., Geology of the Molina member of the Wasatch formation, Piceance basin, Colo., Sandia National Laboratories Report SAND96-1135, 1996, 29 p.

The Authors

Thomas E. Hoak is president of Kestrel Geoscience LLC, which specializes in the development and application of integrated basin and reservoir analysis methods for domestic and international E&D projects. He holds degrees in the geological sciences from Carleton College, State University of New York-Albany, and the University of Texas at Austin. E-mail: [email protected]

Alan L. Klawitter has more than 20 years of domestic and international experience in exploration geology and resource assessment with experience in the application of remote sensing imagery and GIS interpretations for geological evaluations. He has conducted numerous geological, geophysical, and geochemical surveys worldwide. E-mail: [email protected]

Kermit G. Witherbee is a supervisory geologist and presently serves as Deputy Group Manager, Fluid Minerals Group, Bureau of Land Management, Washington, D.C. He worked as an exploration geologist before joining the BLM in 1982. He received BS and MS degrees in geology from State University of New York-Oneonta. E-mail: [email protected]

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