FRACTURED COALBED METHANE AND TIGHT GAS RESERVOIRS IN THE SAN JUAN BASIN

Based on a workshop sponsored by PTTC's Southwest Region on September 29, 1999 in Farmington, New Mexico.

BOTTOM LINE

Fractures associated with fault systems, both reactivated basement faults and postdepositional compactional faults, are responsible for commercial natural gas production from coals and tight sands in the San Juan and Green River basins. Potential is great for commercial tight gas production under similar structural conditions from other formations in these and other Rocky Mountain areas such as the Wind River, Piceance, and Uinta basins.

PROBLEM ADDRESSED

The workshop focused on defining the conditions that lead to commercial production of natural gas from coals and tight sands in the San Juan and Green River Basins. A high density of naturally occurring fractures has been known for some time to be a controlling factor for commercial success. For optimum infill drilling, one must understand the association between structure, faulting, and fracturing and know the distribution and orientation of key fracture systems. Common geologic settings are faulting associated with differential compaction over channel sandstones in deltaic environments and late Paleozoic and Laramide strike slip movement on reactivated basement faults. These faults can be detected and understood using an integrated reservoir characterization approach, and observed relationships can aid in exploration for new reservoirs in similar structural and stratigraphic contexts.

KEY WORDS:

Basement faults, Coalbed methane, Dual porosity, Fracture injection tests, Fracture swarms, Fractured reservoir production, Tight gas management

SPEAKERS

3-D Seismic in Cedar Hill Field, San Juan Basin
Robert Benson, Colorado School of Mines

Fracturing in Ute Dome field, San Juan Basin
Bruce Hart, NM Bureau of Mines and Mineral Resources

Coal Permeability Increase with Time, Cretaceous Shales
Bob Bereskin, Tesseract Corporation

Fracturing Associated with Reactivated Faults, Green River Basin
John Lorenz, Sandia National Laboratories

Fracture Injection Tests
David Craig, Halliburton

TECHNOLOGY OVERVIEW

Reservoir characterization using cores and wireline logs from horizontal boreholes and 3-D multicomponent seismic can help one understand the orientation, distribution, and causal association of faults and fractures in the subsurface. This knowledge leads to a further understanding of compartmentalization within current reservoirs as well as to a reduction in risk when extending existing production and exploring for new reservoirs.

P-wave and S-wave attribute analysis of 3-D seismic data, integrated with data from conventional geological, petro physical, and reservoir engineering sources, led to a basic understanding of conditions for commercial coalbed methane production from the Fruitland Formation at the Cedar Hill field in the San Juan Basin. Coalbed methane is produced by degassification/desorption and, contrary to traditional expectations, absolute permeability increases as production continues. At constant gas production rates, bottom hole pressures actually increase with time. In the San Juan Basin, coal resources of more than 230 billion tons in the Fruitland will provide adequate gas resources to sustain natural gas exploration and production for many years to come.

Complex depositional geometries and the fracture patterns generated by differential compaction of sediments around channel-fill sandstones can be successfully interpreted with these techniques and reservoir compartments identified. Use of seismic surveys through time, i.e., 4-D seismic, is a useful approach for measuring pressure changes in reservoir compartments. High fracture densities that contribute to economic production are also found in association with high-curvature wrench faulting. In both the San Juan and Green River basins, tight gas sand production from fractured zones is significant. Natural fractures of greater than regional density are a necessary accompaniment in these low-matrix-permeability sands to achieve commercial production. A typical tight gas field, Ute Dome, in the Paradox and Dakota formations on the Four Corners Platform near the San Juan Basin has matrix permeabilities in the 0.5% range (up to 5% in perforated intervals).

Economic production depends upon permeability enhancement through swarms of fractures associated with Pennsylvanian and Laramide strike slip (shear) movement on basement faults. Faults and their associated fractures are mappable using 3-D seismic, but interpretation has been aided by wireline logs, production data, and observations made on outcrop. A horizontal well in the Frontier Formation in the Green

River Basin produced 12 to 20 million cubic feet of gas per day from a densely fractured zone having a matrix permeability of only 25 microdarcys. Fracture density averaged one per foot, but with spacings varying from less than an inch to more than 17 feet, dependent on facies. Partial mineralization of some fractures enhanced their permeability by serving as proppants to keep them open. Reactivation of the fractures, however, was the most important event leading to the establishment of the "plumbing" that made commercial production possible. Similar un-reactivated fractures in nearby equivalent strata do not produce gas at economic rates.

Fractures in tight gas sands, in addition to enhancing permeability and deliverability to the wellbore, also introduce anisotropy corresponding to their preferential orientation. Understanding this orientation helps: (1) define elliptical drainage areas of wells, avoiding production interference and drainage overlap, (2) determine the amount of recoverable gas present, and (3) predict the optimal number and location of infill wells. Incorporation of information on permeability anisotropies also helps make more accurate predictions of potential recovery increases through infill drilling on a basin-wide basis. This method forecasts an additional recovery of gas from the Mesaverde Formation in the San Juan basin of 7.8 trillion cubic feet of gas.

Many Cretaceous shales of the Western Interior Seaway contain zones of sandy or silty beds that are potential commercial targets for tight gas and, at the same time, may serve as source beds. The Lewis Shale, an offshore marine, deep basinal shale, serves as a model, but other shales such as those in the nonmarine Almond and shales found in the basal part of the shallowing-upward sequence found in the Frontier Formation, are also candidates. The Lewis contains sandy subfacies with 2 to 4% matrix porosity and has a total organic carbon content in the 0.8 to 2.4% range. FMI and EMI tools are especially useful as direct indicators of zones of interest, but gamma ray logs, the potassium curve of the spectral gamma ray, deep resistivity and micro-resistivity curves, and neutron porosity curves are also helpful in determining potential reservoir quality.

Diagnostic fracture injection tests can help to optimize the development of tight gas reservoirs. As infill development goes on, individual sands will deplete and will jeopardize the completion/ stimulation of remaining sands at virgin pressure by diverting fracture treatments. Fracture injection tests help to identify potential pressure-dependent leakoffs, locate depleted sands, provide gas permeability estimates, and optimize multiple sand completions.

LESSONS LEARNED

No single tool delineates the combination of lithologies and geometries of faults and fractures associated with commercial coalbed methane or tight gas sand reservoirs. Seismic (especially multicomponent 3-D seismic), specialized wireline logs, conventional subsurface data, and reservoir engineering data are all necessary.

CONNECTIONS:

Robert Benson
Colorado School of Mines
1500 Illinois St.,
Golden, CO 80401
Phone: 303-273-3455, Fax 303-273-3478 E-mail rbenson@mines.edu

Bruce Hart
New Mexico Bureau of Mines and Mineral Resources
801 Leroy Pl.,
Socorro, NM 87801
Phone: 505-835-5420, E-mail hart@mailhost.nmt.edu

Bob Bereskin
Tesseract Corporation
2197 Doc Holliday Dr.,
Park City, Utah, U. S. A. 84060
Phone: 435-645-8499, Fax 435-645-8896

John Lorenz
Sandia National Laboratories
PO Box 5800,
Albuquerque, NM 87185-0750
Phone: 505-844-3695 Fax 505-844-7354, E-mail jcloren@sandia.gov

David P. Craig
Halliburton
410 17th St, Suite 900,
Denver, CO 80202
Phone: 303 899 4700, E-mail David.Craig@Halliburton.com

For information on PTTC’s Southwest region and its activities contact:
Robert Lee, Director,
Petroleum Recovery Research Center, New Mexico Tech,
801 Leroy Pl., Socorro, NM 87801
Phone: 505-835-5685, Fax 505-835-5210, E-mail lee@prrc.nmt.edu

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