Role of 3D Seismic Interpretation in Reservoir Identification and Characterization, Mississippi Canyon Block 109 Field, Offshore Gulf of Mexico
D. A. Herron, W. W. Wilson, M. T. Currie, 1991. "Role of 3D Seismic Interpretation in Reservoir Identification and Characterization, Mississippi Canyon Block 109 Field, Offshore Gulf of Mexico", 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 Mississippi Canyon Block 109 field, which is located approximately 18 miles offshore from the Mississippi Delta in water depth of 950-1100 feet, was discovered in 1984 and declared commercial by BP Exploration in 1989. The field consists of middle and upper Pliocene reservoir sands, with oil accumulations in both structural-stradgraphic and entirely stratigraphic traps. A 3D seismic survey, acquired and processed in late 1984-1985 and reprocessed in 1987, has been and continues to be instrumental in the development of this field.
The 3D survey was acquired after drilling of the MC 109 #1 discovery well in 1984 and was first used to resolve the complex structure of the field. Integration of the results of initial drilling with this structural interpretation strongly suggested that there was a significant stratigraphic component to entrapment of hydrocarbons in the field. In conjunction with a revised depositional model for the reservoir sands, a new interpretation of the reprocessed 3D survey was used to identify these reservoirs and describe them in terms of reflection character and amplitude. The new interpretation was confirmed by the successful drilling of the MC 109 #3 and #3 ST wells in 1988, after which Block 109 was transferred to production for additional detailed work and assessment of development potential. The MC 109 #4 and #4 ST wells were subsequently drilled to confirm hydrocarbon pays in an untested fault block, and the MC 109 #5 well was drilled to obtain information bn fluid properties and additional geological data needed for field development plans.
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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.