An Evaluation of Post-Waterflood Depressurisation of the South Brae Field, North Sea

Abstract

Abstract Depressurisation of waterflooded reservoirs can economically increase recovery and extend the life of mature fields. The process is underway in the Brent Field in the North Sea [1] and is under evaluation in several others [2]. Most of the previous published studies on depressurisation have focused on the critical gas saturation as the crucial factor in determining the recovery potential [3,4]. Recent experiments using reservoir condition, three-phase in-situ saturation measurements have enabled critical gas saturations and gas relative permeabilities to be determined during depressurisation [5]. This work has shown conclusively that conventional external gas drive experiments do not represent the depressurisation process and that actual gas relative permeabilities can be several orders of magnitude lower than conventional data. This paper describes the modelling of results from an experimental coreflood, and demonstrates the effect of using the resulting relative permeability curves in a full-field simulation of depressurisation in the South Brae field. The results indicate that less hydrocarbons are produced then predicted in earlier field assessments and emphasizes the need for representative experimental measurements when making field development plans. Introduction Location. The South Brae Field is a large, mature oil field located in Blocks 16/7a and 16/7b of the UK North Sea, 160 miles northeast of Aberdeen (Fig. 1). It has been developed and produced from Brae Alpha, which is a fixed leg platform in 350 ft of water. Geology. The field lies on the western margin of the South Viking Graben, within the Upper Jurassic Brae formation. The reservoir is comprised of thick conglomerate and sandstone units, deposited in the proximal region of a submarine fan. The conglomerates predominantly occur as debris flows infilling large incised channels up to 2 miles from the sediment entry point. Thick distal sandstone units were deposited up to 10 miles further east on the basin floor. Fine-grained sediments are generally found at fan margins or in inter-channel areas. Overall, sediments grade from thick conglomerate sequences inter-bedded with thin sand stringers at the crest with thickening sand and shale deposits to the east. Reservoir Properties. The reservoir porosity ranges from 3% to 25% with an average of 11% and the permeability ranges from 10 md to 2,000 md with an average of 130 md. The reservoir oil gravity is 33°API with an initial solution GOR of 1,400 scf/stb and viscosity of 0.3 cp at average reservoir conditions of 414 barg (6,000 psi) and 123°C. The water viscosity in the reservoir is also 0.3 cp, giving rise to a low water/oil mobility ratio, which results in good reservoir sweep through waterflooding. However, oil saturations in excess of 40% are seen to remain after the passage of the water flood front. Development Strategy. Production began in July 1983, initially supported by natural aquifer influx and produced gas re-injection in the crest. Water injection was phased in from 1984 onwards and eventually replaced gas injection. Oil production plateaued in excess of 100,000 bbl/day at the end of 1984 and declined severely after water breakthrough at the main producers in 1989. A second plateau of 10,000 bbl/day was then maintained for several years by a vigorous remedial workover and infill well drilling program. In excess of 265 MMbbl have been produced since 1983. The pilot miscible gas injection project was started in 1994 and breakthrough was observed in 1997. The successful results from the pilot helped justify gas injection for full-field implementation [6], which is now underway. Full-field depressurisation is also being considered to follow the full-field gas injection project for additional improved oil and gas recovery.