Prediction versus Production: Waterflood Response of Heterogeneous Reservoirs in an Estuarine Valley-Fill, Little Bow Field, Alberta
John C. Hopkins, James M. Wood, Federico F. Krause, 1991. "Prediction versus Production: Waterflood Response of Heterogeneous Reservoirs in an Estuarine Valley-Fill, Little Bow Field, Alberta", 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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Upper Mannville G, U and W pools in the Little Bow field are hosted by separate parallel elongate estuarine sandstone bodies within an incised valley fill Each sandstone body is 3-4 km long, 300-500 m wide, up to 22 m thick, with an average porosity of 22%. Values of horizontal and (vertical) permeability vary widely and average 1324 (125) md in G pool, 2005 (472) md in U pool, and 258 (73) md in W pool.
G pool was discovered in 1972 and placed on primary production. Oil production declined gradually and was accompanied by modestly increasing GOR and WOR. U and W pools were discovered in 1982 and 1983 respectively, and produced by primary methods until initiation of waterflooding in 1985. Response to waterflooding these two pools has been a rise, then decline, in the GOR, followed by rapidly rising WOR, to values much greater than those predicted from reservoir modelling, currently up to 10:1 in wells adjacent to water injectors. Despite the wide variation in permeability values and the different production histories, similar proportions of oil have been produced: 9.2% OOIP in G Pool; 10.5% in U Pool; and 9.3% in W Pool. Production response indicates controls by mesoscale and microscale reservoir heterogeneities.
Mesoscale heterogeneities include permeable sandstone beds several meters thick that are continuous between adjacent wells, and stochastic shale beds up to 80 cm thick. Rapid breakth of water has occurred in producing wells adjacent to injectors due to channeling in thick permeable sandstone beds between
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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.