Sole Pit—Improving the Performance of a Tight Gas Reservoir, an Integrated Approach
Published:January 01, 1991
R. E. Wilson, J. F. R. Branco, B. G. van Heyst, R. H. Turner, 1991. "Sole Pit—Improving the Performance of a Tight Gas Reservoir, an Integrated Approach", 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 initial development plan for Clipper and Barque 'core' areas in the Southern North Sea, Sole Pit Basin called for conventional wells to intersect fissured zones wherever possible and where no open fissures were encountered, connection would be attempted via massive hydraulic, sand propped fracturing.
Since drilling began in 1988 the plan has benefited from a number of new developments:
Improvements have been made to the design and placement techniques of Massive Hydraulic Stimulation.
A new Borehole Televiewer that works in oil-based mud is providing information on the fissure type, orientation and density, impacting on the placement and design of later wells.
Dune slip-face sands have been identified which enable direct production from the matrix, without hydraulic stimulation.
Production results of highly successful, but now abandoned appraisal wells have been replicated by a technique named 'cloning'.
The application of horizontal drainage has been very successfully tested and will be extensively utilized in both fields.
Subtle features identified using 3D seismic derived attribute maps have explained the extent and distribution of the different free water levels.
Well completion techniques that do not incorporate a cemented liner are being investigated.
These developments have been made possible by close co-operation across the Petroleum Engineering disciplines organized into a small integrated team.
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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.