Interdisciplinary Effort Optimises Field Developments in the U.K. North Sea Brae Area
Published:January 01, 1991
T M Alqassar, W Gallacher, S de Moss, 1991. "Interdisciplinary Effort Optimises Field Developments in the U.K. North Sea Brae Area", 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 Braefields,operated by Marathon Oil (UK) Limited, are situated in Block 16/7 in the UK, NorthSea. The first of the Brae fields was discovered in 1975 with the testing of a rich gas condensate accumulation, later named North Brae. Further drilling led to the discovery of three oil fields, West, Central and South Brae, and appraisal drilling concentrated on South Brae.
After four wells had been drilled to appraise South Brae a fan delta sedimentary model was developed to explain the geology. The South Brae plan of development was based on this model. Early development drilling in 1983/4 came up with major surprises and indicated that the reservoir system was more complex than originally assumed. As the planned production profile appeared difficult to achieve a combined study involving geophysical, geological and reservoir engineering was instigated to understand the geological model and achieve optimal well locations. The available 2D seismic although lacking in quality and resolution was an essential part of this study. After a new geological model had been developed further development wells were more successful. This enabled the field to achieve predicted production rates and enabled an effective waterflood to be put in place to improve recovery.
By 1982 North Brae had been appraised and the development plan for this reservoir was assessed using a compositional reservoir simulator. Gas cycling with partial pressure maintenance was selected as the best development option. Prior to the platform being installed in 1987 a 3D seismic programme was completed. With experience gained from South Brae and integrating geological and geophysical interpretations a refined geological model was rapidly and efficiently developed. Subsequent development drilling was highly successful and the field produced at plateau rates earlier than expected. Reservoir simulation incorporating the complex geology confirmed that gas cycling was indeed the best option and that excellent recoveries could be expected.
The multi-disciplinary study on South Brae successfully achieved its objectives and using the experience gained from this study enabled the development of North Brae to be rapidly optimised with excellent results.
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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.