Determination of Hydraulic Fracture Orientation in the Kuparuk River Field, Alaska
J. S. Blundell, R. J. Hallam, 1991. "Determination of Hydraulic Fracture Orientation in the Kuparuk River Field, 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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The Kuparuk River field on the North Slope of Alaska (Figure 1) is the second largest producing oil field in North America. Currently the production from the Lower Cretaceous Kuparuk formation exceeds 300,000 barrels of oil per day under waterflooding. This reservoir is overlain by the Colville, West Sak, and Ugnu reservoirs which contain an estimated 20 billion barrels of oil in place. These formations are unconsolidated, have widely varying fluid and rock properties, and will require waterflooding and enhanced oil recovery processes. Development options for all of these reservoirs include hydraulic fracturing of the injection and production wells; hence, characterization of the in-situ stress field is critical for optimizing field performance and recovery.
The regional crustal stress field on the North Slope is extensional with maximum principal horizontal stress oriented northwest-southeast. Previous work on fracture direction in Kuparuk, however, indicated that the in-situ stress field was more complex in its orientation. The Kuparuk reservoir occurs within a broad northwest to southeast-trending anticline which plunges to the southeast. Normal fault patterns within the Kuparuk River field show two dominant strike trends: (1) northwest-southeast and (2) north-south.
In this study the hydraulic fracture direction, at both shallow and deep horizons, was determined by integrating geologic, engineering, petrophysical and geophysical data. Dipmeter logs were processed and interpreted to determine wellbore breakout directions for both shallow and deep horizons. Formation microscanner (FMS) images were used to discriminate between incipient wellbore breakout zones and mechanical fracturing from drilling. Hydraulic fracture screenout data were correlated
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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.