Roger D. Shew, 1991. "Mid-Dip Tuscaloosa Trend: Analog Geological, Geophysical, and Engineering Data for Prospect Evaluation and Field Development", 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 Upper Cretaceous Mid-Dip Tuscaloosa trend occurs in southwestern Mississippi and parts of northeastern Louisiana (Figure 1). It is located on the south rim of the Mississippi Salt Basin and occurs updip of the Lower Cretaceous shelf margin. The Mid-Dip Tuscaloosa is primarily composed of terrigenous clastics derived from the Ouachita orogenic belt. Braided and meandering fluvial deposits unconformably overlie the Lower Cretaceous Washita-Fredericksburg Group. These initial progradational deposits were followed by an overall transgressive depositional sequence composed, from base to top, of fluvial, deltaic, and nearshore sediments encased in a dominantly shale-rich interval. These lenticular sandstones, particularly point-bar and channel deposits, are prospective for hydrocarbons in stradgraphic or combined structural/stratigraphic traps. The encasing mudstones and shales are excellent lateral and top seals for the hydrocarbons. Marine shales of the Middle Tuscaloosa cap the transgressive sequence and are interpreted to be the source rock. The mature Mid-Dip Trend has been estimated to have contained greater than one billion barrel equivalents of oil.
Three Shell fields, Little Creek, Olive, and Liberty, provide important analog data for further exploratory and enhanced recovery operation in the trend. Little Creek is by far the largest field with OOEP of 102 MMBO in a combined structural/stratigraphic trap. Olive (8 MMBO) and Liberty (7 MMBO) are typical of the remaining smaller stratigraphically-trapped accumulations. Detailed seismic stradgraphic interpretations, in combination with core and wireline data, are critical to the discovery, delineation, and development of these smaller reservoirs. Mappable seismic anomalies are associated with these porous, “soft” sandstones.
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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.