An Integrated, Multidisciplinary Study of Reservoir Facies and Reservoir Performance of a Multilayer, No-Crossflow Gas Reservoir—Chase Group (Wolfcampian), Guymon-Hugoton Field, Oklahoma
M. J. Fetkovich, W. T. Siemers, J. J. Voelker, J. S. Williams, A. M. Works, D. J. Ebbs, 1991. "An Integrated, Multidisciplinary Study of Reservoir Facies and Reservoir Performance of a Multilayer, No-Crossflow Gas Reservoir—Chase Group (Wolfcampian), Guymon-Hugoton Field, Oklahoma", The Integration of Geology, Geophysics, Petrophysics and Petroleum Engineering in Reservoir Delineation, Description and Management, Robert Sneider, Wulf Massell, Rob Mathis, Dennis Loren, Paul Wichmann
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This paper summarizes a comprehensive study of the depositional, diagenetic, petrophysical, and production characteristics of the Chase Group (Wolfcampian) gas reservoirs, Guymon-Hugoton Field, Oklahoma. Integration of disciplines in geology, petrophysics, and reservoir engineering and management has resulted in accurate and meaningful geological and reservoir performance models for this field.
The Chase Group is composed of cyclical sequences deposited on a gently dipping-, low-relief, shallow marine shelf. Each cycle comprises laterally continuous, successively shallower water, marine carbonate (chiefly dolostone), siltstone and sandstone reservoir units capped and separated by shaly redbeds and paleosols. The lateral continuity, low permeability, and high threshold entry pressures of shaly layers produce effective regional barriers that prevent vertical fluid flow and pressure communication between reservoir layers. Although variable, depending on depositional and diagenetic history, porosity is continuous within a reservoir layer because of a well-developed intercrystalline pore network produced by pervasive dolomitization independent of depositional texture and other pore types.
Pressure differences measured between reservoir layers verify predicted reservoir and barrier qualities. A study of 83 replacement wells failed to identify any original field pressures (490 psia), indicating no significant volumes of gas not in communication with producing wells. All replacement well locations, therefore, have contributed to production from the original section well or other offset wells; no new gas-in-place has been found.
Petrophysically unique Archie saturation input parameters were computed based on the abundance of the various lithotypes within each of the reservoir layers. Their incorporation into the log analysis system provided a more accurate determination
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The Integration of Geology, Geophysics, Petrophysics and Petroleum Engineering in Reservoir Delineation, Description and Management
Bima Field, offshore northwest Java, is a sizeable reservoir containing reserves of approximately 700 MM bbls OOIP with a 50 BCF gas cap. At present only the northern 1/3 of the field is developed, with 7 platforms and 54 producing wells, of which 20 are horizontal. The field has multiple drive mechanisms and high viscosity oil (21 cp), resulting in rapid GOR and water-cut increase after 3 years of production. The high stakes (both reserves and facility investments) and the reservoir's complexities, make an effective reservoir management scheme critical. For this reason an integrated geological, geophysical and engineering description was carried out to provide a 3-D Reservoir Simulation Model to evaluate development options. Geologically, the Oligo-Miocene age Batu Raja Limestone was deposited on the Seribu Platform, a basement-controlled, fault- bounded structure. The Upper Batu Raja carbonate build-up is thickest on the structurally highest parts of the platform where the rock comprises a series of "cleaning upwards" cycles (muddy deposits overlain by progressively more grain-rich sediments). A Lower Miocene drop in sea-level caused subaerial exposure of much of the platform and leaching by meteoric fluids. This diagenetic event resulted in contrasts in the reservoir quality (porosity, permeability, fluid saturations) at various intervals of the Upper Batu Raja. Based on these dissimilarities, the reservoir was zoned into 6 model layers. Once zonation was established, well logs could be calibrated to whole and sidewall core. A dense grid of seismic data were used to map the Batu Raja structure. From these data, color seismic inversion sections were produced and calibrated to the well logs. The calibrated seismic data were then used to map the top of structure, the carbonate build-up's edges, the total thickness of the Upper Batu Raja (needed to control aquifer size in the model) and the thickness of the main pay zone (layers 1-3). Engineering reservoir description began with a detailed compilation of capillary pressure, relative permeability, production and DST data. The 3-D simulation model required special treatments, including varying the GOC depths to honor separate gas cap closures; making permeability pressure dependent in poorly-consolidated zones; and setting up horizontal well completion treatments. Results suggest that water injection into the oil rim and gas cap is an effective approach toward maximizing recoveries and minimizing gas cap resaturation. However, waterflood reserves are sensitive to injection timing. The synergistic approach of geological, engineering and geophysical input into the Bima reservoir study has had impact by delivering a reservoir management tool that can evaluate future development expansion and possible gas sales. The simulation model can also track fluid migration during the field's producing life. The geological/geophysical model led to an enhanced understanding of Batu Raja depositional and diagenetic processes that has potential in regional exploration strategies.