Characterization of the Distal Margin of a Slope-Basin (Class-III) Reservoir, ARCO-DOE Slant Well Project, Yowlumne Field, California
Michael S. Clark, John D. Melvin, Rick K. Prather, Anthony W. Marino, James R. Boles, Douglas P. Imperato, 1999. "Characterization of the Distal Margin of a Slope-Basin (Class-III) Reservoir, ARCO-DOE Slant Well Project, Yowlumne Field, California", Reservoir Characterization—Recent Advances, Richard A. Schatzinger, John F. Jordan
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Yowlumne is a giant oil field in the San Joaquin Basin, California, that has produced over 16.7 million m3 (105 million bbl) of oil from the Stevens Sandstone, a clastic facies of the Miocene Monterey Shale. Most Yowlumne production is from the Yowlumne Sandstone, a layered, fan-shaped, prograding Stevens turbidite complex deposited in a slope-basin setting. Well log, seismic, and pressure data indicate seven depositional lobes with left-stepping and basinward-stepping geometries.
Log-derived petrophysical data, constrained by core analyses, indicate trends in reservoir quality. Concentration of channel and lobe facies along the axis and western (left) margin of the Yowlumne fan results in average net/gross sandstone ratios of 80%, porosity (cj>) of 16%, and liquid permeability (KUquid) °f 10-20 md. By contrast, more abundant levee and distal margin facies along the eastern margin result in shale-bounded reservoir layers with higher clay contents and lower net/gross sandstone ratio (65%), porosity (12%), and permeability (2 md). Although a waterflood will enable recovery of 45% of original oil in place along the fan axis, reservoir simulation indicates 480,000 m3 (3 million bbl) of oil trapped at the thinning fan margins will be abandoned with the current well distribution. Economic recovery of this bypassed oil will require high-angle wells with multiple hydraulic fracture stimulations to provide connectivity between the reservoir layers.
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Optimum reservoir recovery and profitability result from guidance by an effective reservoir management plan. Success in developing the most appropriate reservoir management plan requires knowledge and consideration of (1) the reservoir system, including rocks, fluids, and rock-fluid interactions, as well as wellbores and associated equipment and surface facilities; (2) the technologies available to describe, analyze, and exploit the reservoir; and (3) the business environment under which the plan will be developed and implemented. Reservoir management plans de-optimize with time as technology and the business environment change or as new reservoir information becomes available. Reservoir characterization is the process of creating an interdisciplinary high-resolution geoscience model that incorporates, integrates, and reconciles various types of geological and engineering information from pore to basin scale. The reservoir data are then conceptually and quantitatively modeled and compared to the historical production data and fluid flow distribution patterns within and beyond the limits of the reservoir to match well production histories and predict their behavior. The goals of reservoir characterization are to simultaneously (1) maintain high displacement efficiency, (2) optimize high sweep efficiency, (3) provide reliable reservoir performance predictions, and (4) reduce risk and maximize profits. Notice that in addition to the technical concepts that we normally associate with "characterization," maximizing profits is an essential element of this process. Papers from the Fourth International Reservoir Characterization Technical Conference (1997), sponsored by the U.S. Department of Energy, this publication is a unique compilation of 27 papers covering every aspect of reservoir characterization and has been a popular AAPG publication since that time. Using an interdisciplinary approach, the papers address qualitative information as well as integrated quantified data and culminate in a fully integrated study.