The Computer-Aided Geological Characterization of a Sandstone Reservoir, North Ward Estes Field, Ward and Winkler Counties, Texas
Published:January 01, 1991
Albert S. Wylie, Jr., E. K. Davidsen, J. D. Gillespie, R. S. Butler, R. G. Stanley, J. H. Beck, 1991. "The Computer-Aided Geological Characterization of a Sandstone Reservoir, North Ward Estes Field, Ward and Winkler Counties, Texas", 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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The North Ward Estes Field is located along the western edge of the Central Basin Platform in Ward and Winkler Counties, Texas. The field is part of an Upper Guadalupian productive trend that extends uninterrupted for 90 miles on the edge of the platform. The North Ward Estes Field has produced over 388 MMBO (one-third of the trend's cumulative production) from more than 3300 wells since its discovery in 1929. Production in the field is from back-reef lagoonal sandstones of the Yates, Seven Rivers and Queen Formations.
A correlation scheme was developed for the field based on laterally continuous key dolomites that bracket the productive sands and segment the reservoir into discrete mappable units. Applying this scheme, more than 68,000 correlation markers were selected and loaded into a computer database. Concurrently, 15 million curve feet of log data, 30,000 feet of core analysis data, and 125,000 feet of core lithology data were digitized. Core analyses and lithologies were depth-corrected. Logs were normalized using a 60-foot interval of laterally continuous anhydride dolomite. Core porosity data were cross-plotted verses bulk density log values to develop equations (transforms) for derivation of porosity. Corrections for hole rugosity, overburden pressure, and lithologic complications were applied to refine the porosity transform. Structure and porosity-feet maps were then merged with fluid contact and water saturation data to calculate volumetries. Facies and permeability relationships and actual to apparent pay ratios were applied to determine effective hydrocarbon pore volume.
Computer generated net isopach maps of the sands display a north-south
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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.