Mike Farhadi, 1991. "Intan Field Development—A Synergistic Approach", 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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In 1987 and 1988 MAXUS Southeast Sumatra Inc. discovered two fields in the Asri Basin offshore Indonesia with initial reserve estimates of 300 MMBO. Early development of the Intan Field along with the creation of a reservoir management team resulted in a final development plan for Intan that was successful in saving capital and time as well as minimizing undrained areas. The experience and knowledge gained from the modeling and development of the Intan Field is being applied effectively to the development of the Widuri Field with reserves of 250 MMBO.
The Intan Field is a NE-SW trending, faulted, anticlinal feature located on the northwest flank of the Asri Basin. A study of the environment of deposition reveals the reservoir sands to have been deposited by meandering and low sinuosity rivers flowing from the northwest and from the northeast into the Asri Basin. The discovery well Intan-1 was drilled in October 1987 and encountered 74 feet of net oil pay in the early Miocene Talang Akar formation. Intan-1 flowed at a combined rate of 5845 BOPD from two flow tests. Five additional delineation wells were drilled to confirm the size of the structure depicted by the seismic interpretation and to establish reservoir boundaries. Development drilling of the Intan A platform started in March 1989. Production commenced from 9 wells on the Intan A platform ahead of schedule on June 20,1989 into a temporary production, storage, and export facilities while permanent facilities were being constructed.
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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.