Batanga Sandstone Reservoir: A Turbidite Stratigraphic Trap
Published:January 01, 1991
D. R. Smith, S. B. Desantis, L. A. Dunne, B. L. Faulkner, R. E. West, 1991. "Batanga Sandstone Reservoir: A Turbidite Stratigraphic Trap", 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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A synergistic approach was instrumental in conducting an exploitation study of the Upper Cretaceous Batanga reservoir of Gabon. The Batanga reservoir is an oil productive, turbidite channel sequence deformed by syn- and post-depositional salt piercement and intrusion. This study illustrates how several techniques derived from geological, geophysical, petrophysical, and reservoir engineering disciplines were integrated into a comprehensive description of this reservoir.
These Oguendjo “B” and “C” fields were discovered in 1981. Nineteen wells have produced 38 MMBO from stratigraphic traps associated with salt diapirism. Oil column heights and productive acreage average 165 feet and 650 acres, respectively, in these two fields.
Regional and local depositional trends were interpreted from isopach maps derived from three dimensional seismic data and from true stratigraphic thickness (TST) log cross sections. Salt uplift contemporaneous with deposition resulted in thicker sands on the flanks of salt piercements. Five separate depositional sequences were identified in each field and are composed of laterally discontinuous proximal channel, medial levee, and distal overbank facies. Using a statistical analysis of wireline log data, the oil productive channel and levee facies were discriminated from non-reservoir rock.
Log analysis and net pay identification of thinly bedded turbidites was accomplished using the “Dual-Water” model for water saturation calculations and the M-N crossplot technique for V-shale calculations. Routine and special core analyses further refined these models. True Vertical Thickness (TVT) logs were used to generate net pay and hydrocarbon pore volume (HPV) estimates for each well.
An estimate of the original oil-in-p1ace based on isochore
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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.