Successful Miscible Gas Injection in a Mature U.K. North Sea Field
Authors: Jethwa D.J. , Rothkopf B.W. , Paulson C.I. 
Published: December 2007

South Brae is a large, mature oil field located in the UK North Sea. In excess of 265 MMSTB oil have been produced since 1983, primarily through waterflooding. This paper demonstrates how the first miscible gas injection project in the UK North Sea was started in this field. A pilot project justified by laboratory experiments and reservoir simulations was implemented in 1994. The successful field results were integrated into a second generation of simulations to evaluate full field gas injection, which is now in progress.

The field has experienced good recovery to waterflooding because of an excellent water-to-oil mobility ratio. However, average remaining oil saturations in excess of 40% are present after the waterflood front has passed by. Laboratory coreflood experiments showed that the remaining oil saturation could be reduced to less than 10% by following the initial waterflood with miscible gas injection and a second waterflood.

A pilot gas injection project was carried out in a waterflooded part of the reservoir. A total of 22 Bcf of gas was injected before reverting to water injection. Four to ten-fold increases in oil production rate were observed at four production wells with associated increases in gas-oil ratio (GOR) and decreases in water-cut. Over 80% of the 2.7 MMSTB incremental oil expected from the pilot had been produced within five years of initial gas injection. Reservoir modelling of full field gas injection shows that 18–32 MMSTB incremental oil can be recovered by injecting 200 Bcf of gas, the equivalent of more than half of which will be produced back. The injected gas has a negligible opportunity cost owing to sales gas export constraints. This combination of factors yields a highly economic project.

Introduction

Location

The South Brae Field is 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 coarse-grained 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 6,000 psi and 253°F.

The water viscosity in the reservoir is also 0.3 cp, giving rise to a low water to 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 crestal produced gas re-injection. Water injection was phased in from 1984 onwards and eventually replaced gas injection. Oil production plateaued in excess of 100,000 BOPD at the end of 1984 and declined severely after water breakthrough at the main producers in 1989. A second plateau of 10,000 BOPD was then maintained for several years by a vigorous remedial workover and infill well drilling program (Fig. 2).

The pilot miscible gas injection project was started in 1994 and breakthrough observed in 1997. The successful results from the pilot helped justify gas injection for full field implementation.

Location

The South Brae Field is 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 coarse-grained 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 6,000 psi and 253°F.

The water viscosity in the reservoir is also 0.3 cp, giving rise to a low water to 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 crestal produced gas re-injection. Water injection was phased in from 1984 onwards and eventually replaced gas injection. Oil production plateaued in excess of 100,000 BOPD at the end of 1984 and declined severely after water breakthrough at the main producers in 1989. A second plateau of 10,000 BOPD was then maintained for several years by a vigorous remedial workover and infill well drilling program (Fig. 2).

The pilot miscible gas injection project was started in 1994 and breakthrough observed in 1997. The successful results from the pilot helped justify gas injection for full field implementation.