Brent Field Reservoir Modeling: Laying the Foundations of a Brown Field Redevelopment

Summary

The Brent Field was discovered in 1971. It is now a mature asset and, in order to increase oil and gas ultimate recovery, will commence depressurization in 1997. The redevelopment of the field has been underpinned by extensive static and dynamic modeling studies. Developments in geological computing and the numerical processing power of reservoir simulation platforms significantly improved the quality of the Brent Field static and dynamic models. The static models have been used for a range of studies including gas cap volumetrics and bypassed oil investigations. Their functionality provides significant scope for target sizing as a basis for selecting the appropriate reservoir access well technology.

Introduction

The Brent Field, located 100 miles north east of Lerwick, Shetland Islands (Fig. 1) was discovered by well 211/29-1 in 1971. With total hydrocarbons initially in place of some 3.8 MMMbbl oil and 7.5 Tscf gas, the Brent Field ranked as one of the largest fields in the northern North Sea. Following 20 years of production, remaining reserves are estimated to be some 400 MMbbl oil and 2.6 Tscf gas and in these terms the Brent Field continues to rank as the largest field in the U.K. Sector of the North Sea.

The Brent Field is a mature asset. Facilities comprise four platforms providing a total of 154 well slots. Oil export is via the Brent systems pipeline to Sullom Voe and gas export via the FLAGS line to St. Fergus. Production from the extensive West Flank area commenced in 1976 and by January 1997 cumulative production amounted to 1.6 MMMbbl oil, some 80% of anticipated waterflood ultimate recovery, and 3.2 Tscf gas. In order to significantly increase ultimate recovery through field depressurization, an extensive brown field redevelopment project, costing £1.3 billion, was initiated in 1994. This is now reaching completion with depressurization commencing in 1997 and low-pressure operation in the year 2000. This project has extended the life of the field and increased ultimate recovery.

The redevelopment of the Brent Field involved extensive static and dynamic reservoir modeling studies,¹ which will continue to guide reservoir management during depressurization. This paper reviews the development of the current generation of static reservoir models and illustrates their use, not only as the basis for dynamic studies but also in delineating areas of bypassed oil and monitoring gas cap volumetrics.

Geological Summary

The Brent Field is a north-south oriented, westerly dipping fault block about 10.6×3.1 miles in size, located within the central part of a fault terrace on the western margin of the Viking Graben (Fig. 1). The terrace can be traced over some 40 miles from the North Alwyn Field in the south to the Statfjord Field in the north. It is some 12 miles wide from the western boundary, the Hutton-Dunlin-Murchison fault zone, to the eastern boundary, which is defined by a series of faults just to the east of the crestal slump area of the field.

The field comprises two crestally eroded reservoirs, the Upper Triassic/Lower Jurassic Statfjord Formation and the Middle Jurassic Brent Group, which are separated by the nonreservoir shales of the Lower to Middle Jurassic Dunlin Group (Fig. 2). The Statfjord reservoir, which is about 1,000 ft in thickness, is composed of a lower fluvial jigsaw/labyrinth reservoir-type² interval (the Eiriksson and Raude Members) and an upper layer-cake shoreface sand interval (the Nansen Member) (Fig. 3). The Brent reservoir, which is about 1,000 ft in thickness, is composed of the Tarbert, Ness, Etive, Rannoch, and Broom formations of which the Ness formation is mainly a delta plain jigsaw/labyrinth reservoir-type² and the others are shallow marine layer-cake and jigsaw types (Fig. 4).

Two different structural styles are superimposed on the Brent Field reservoir sequence (Fig. 2). The gently dipping West Flank area forms the up-dip eastern margin of the fault terrace. A series of steeply dipping west-east faults segment the West Flank and define the Main, Graben, and Horst Block elements of the Brent Field and partially delimit the Brent North area, Brent South, and Strathspey Fields (Fig. 1, Fig. 5). The development of the eastern terrace margin fault system was associated with the collapse of gravitationally unstable fault scarps and the formation of the crestal slope degradation complexes (which are referred to as slumps in field terminology). Separate slump systems formed within the Brent Group, where the master listric faults sole out in the Dunlin Group, and in the Statfjord formation where they sole out in the shaly lower part of the formation (Fig. 2).

The combination of reservoir sequence and structural style has resulted in the four different reservoir entities that comprise the main Brent Field; the West Flank Statfjord, the West Flank Brent, the Statfjord Slumps, and the Brent Slumps. A similar combination is also present in the Brent South Field and the Brent North area.

Field Development Summary

Development of the Statfjord and Brent West Flank reservoirs commenced in 1976. Both were developed with north-south rows of producers, those dedicated to the Statfjord being crestally positioned and those to the Brent targeted in mid-oil column positions at the top of each of the major reservoir units (Fig. 6). Pressure support for both reservoirs was provided by down-dip water injection wells. Gas produced excess to export requirements was reinjected into the reservoirs. This development strategy and the highly stratified nature of both reservoirs led to the evolution of numerous thin oil rims which, with continuing production, have become thinner and moved upwards into the originally gas-bearing crest of the West Flank. The future development of the West Flank reservoirs is focused on the depressurization and low-pressure operation.^1,3