An Evolving Description of a Fractured Carbonate Reservoir: The Lisburne Field, Prudhoe Bay, Alaska
R. A. Missman, J. Jameson, 1991. "An Evolving Description of a Fractured Carbonate Reservoir: The Lisburne Field, Prudhoe Bay, Alaska", 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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This paper traces the evolution in models of the Lisburne carbonate reservoir from early wildcat days, through the decision to fund primary development, to waterflood assessment. This work is an integration of geologic and reservoir studies based on nearly ten years of extensive data collection (well test, core, log, pressure and field performance data). Early reservoir descriptions assumed uniform enhancement of continuous pay layers resulting from small-scale fractures. Additional recovery over solution gas drive was expected by gravity drainage and waterflood. Integration of performance and geological data after field start-up reveal greater heterogeneity than originally thought: faults and irregularly distributed fractures dominate performance; much of the porosity is ineffective; and the producing oil- water contact (OWC) varies by as much as 300 ft [90 m]. The evolution in simulation techniques reflects the evolution in geologic models toward increased recognition of heterogeneities.
The complexity of the Lisburne reservoir is a result of faulting, two periods of uplift and erosion, and three distinct phases of porosity development. Particularly important among these diagenetic events is the youngest phase of porosity development, which post-dates significant faulting. As a result, many faults are open and conductive. An additional complexity is a high permeability layer created by a laterally extensive set of small open fractures beneath an unconformity at the top of the reservoir.
Initial development was based on models with limited data which understated the impact of these heterogeneities. In retrospect, several important dues and their implications were not fully appreciated. Despite extensive data collection, the unpredictable influence of fractures still creates uncertainties in reservoir description (e.g. well performance cannot be accurately predicted pre-drill). Recommendations for evaluating potentially complex carbonates include: give full weight to known uncertainties, conduct inter-well tests early in the evaluation, and minimize risk by proceeding gradually with field development.
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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.