Resolution of Carbonate Reservoirs at Depth—An Integrated Approach to Lower Development Risk, Smackover Trend, Alabama
Timothy J. Petta, J. Gregory Bryant, 1991. "Resolution of Carbonate Reservoirs at Depth—An Integrated Approach to Lower Development Risk, Smackover Trend, Alabama", 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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Porous Smackover algal mounds associated with granite knobs produce oil throughout southwestern Alabama. A detailed gravity survey over Vocation Field demonstrates lateral density contrasts between reservoir and non-reservoir rocks can be measured even when the reservoir depth exceeds 14,000 feet (4270 m). A similar gravity survey combined with standard seismic and subsurface interpretation methods could have drastically increased the success rate and lowered development costs.
Vocation Field will produce nearly 5 million barrels of oil from high energy algal mound and ooid facies deposited on the flanks of the basement knob. Porosity is dolomite intercrystalline, moldic and interparticle. Most of the porosity was inherited from the original high energy rock fabric. Porosity values as high as 18 percent occur within the pay section. Effective porosity exceeds 250 feet on the flanks of the structure. The trap was not filled to the spill point. Water provides the reservoir drive and recovery is expected to exceed 40 percent of the oil in place. Eight of the sixteen wells have produced.
The basement high is a slight anomaly on regional gravity and aeromagnetic surveys. Seismic lines over the feature indicate structural closure but near the crest the Smackover and basement events are indistinguishable. The first wells were drilled near the crest and were successful discovery and confirmation wells. Only six of the remaining fourteen wells drilled were successful, a disappointing rate of 42 percent. Some of these wells were structurally low and wet, others structurally high and tight. Seismic data provided no clue
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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.