FLUID DISTRIBUTION IN THE BERYL RESERVOIR
The Beryl Formation, the primary reservoir in the Beryl Field, has a complicated distribution of pressures and fluids. Horizontal permeability restrictions. the result of extensive faulting, subdivide the reservoir into eight inter-related areas as determined by careful analyses of pressure histories, production histories and fluid pressure histories, production histories and fluid monitoring. This paper describes the methodology for constructing a conceptual reservoir model for the Beryl reservoir to identify areas of unswept hydrocarbons, resulting in an aggressive drilling programme, and optimise the effort in simulation history matching.
The Beryl Field (1) is located in Block 9/13 of the UK sector of the North Viking Graben, North Sea. The field is estimated to contain 2100 MMB STOIIP, and supports production from the Beryl A and Beryl B platforms. This paper discusses reservoir behaviour in the Beryl A portion of the field, where a combination of a long production history. detailed data acquisition and a concentrated reservoir management effort has given insight into complex fluid movement and reservoir behaviour. The Beryl A portion of the field is a north-south oriented horst with hydrocarbons in six reservoir horizons ranging in age from Upper Triassic to Upper Jurassic. The Middle Jurassic age Beryl reservoir contains about 73% of the total estimated ultimate recovery in the area. or 370 MMBO. Beryl oil production began in June 1976, gas Injection commenced in November 1977 and water injection in January 1979. The reservoir is presently being managed by 16 producing wells, two water presently being managed by 16 producing wells, two water injectors and three gas injectors (Fig 1). As of December 1990, 285 MMB of oil have been produced from the reservoir, while 490 BCF of gas and 170 MMB of water have been injected. Reserves are estimated at 85 MMBO and 535 BCFG.
Fluid movement within the Beryl reservoir is complicated. as evidenced by observations of adjacent areas in pressure communication having apparent gas/oil interfaces differing by several hundred feet. Gas sales will begin in 1992 and will have a dramatic effect on fluid distribution within the Beryl reservoir. A simulation model is being developed to predict the most efficient method to satisfy the gas contract predict the most efficient method to satisfy the gas contract while maximising hydrocarbon recovery. Past efforts to simulate the Beryl reservoir have been time consuming with limited success because of incomplete reservoir models. In a reservoir as complicated as Beryl. a conceptual reservoir model explaining the interplay between the geologic and reservoir data must be developed before simulation begins. A simulation exercise can only support and quantify the reservoir model, it is an inefficient tool for determining the parameters which control the reservoir behavior. This paper describes a dynamic reservoir model which was developed by examining the reservoir pressure and fluid histories within the confines of recently recognised horizontal permeability restrictions.
The Beryl reservoir in the Beryl A area has an oil column of 1950 ft. ranging from 9600 ftss at the crest to 11550 ftss at the oil/water contact. Reservoir thickness is variable ranging from 150 ft on the crest to 600 ft on the flanks due to syndepositional faulting. Eastward of the platform, the reservoir is eroded by the overlying base of Cretaceous (J) unconformity and is thereby limited in extent to only the crest and west flank of the Beryl A horst.