Effect of Horizontal and Vertical Permeability Restrictions in the Beryl Reservoir

Abstract

Summary The Beryl formation, the primary reservoir in the Beryl field, has acomplicated distribution of pressures and fluids controlled by horizontal andvertical permeability restrictions. Horizontal permeability restrictions, theresult of extensive faulting, divide the reservoir into eight interrelated areas as determined by careful analyses of pressure and production historiesand fluid monitoring. Vertical permeability production histories and fluidmonitoring. Vertical permeability restrictions, which are the consequence of thin lithologic breaks within the massive sandstone sequence, further dividethe eight reservoir areas into seven layers, as evidenced by careful review ofrepeat formation tester (RFT) data, pressure-transient tests, cased-hole logs, and reservoir performance data. A detailed reservoir model identified areas andperformance data. A detailed reservoir model identified areas and intervals ofunswept hydrocarbons, resulting in an aggressive workover and drilling program. The model was an essential component in the success of the subsequent reservoirsimulation Introduction The Beryl field is located in Block 9/13 of the U.K. of the North Vikinggraben, North Sea The field is estimated to contain 2100 × 10(6) STB originaloil in place, and supports production from Platforms Beryl A and B. This paperdiscusses reservoir behavior in the Beryl A portion of the field, where acombination of a long production history, detailed data acquisition, and a concentrated reservoir management effort has given insight into complex fluidmovement and reservoir behavior. The Beryl A portion of the field is anorth-south-oriented portion of the field is a north-south-oriented horst with hydrocarbons in six reservoir horizons that range in age from Upper Triassic to Upper Jurassic. The Middle Jurassic age Beryl reservoir contains about 73% ofthe total estimated ultimate recovery in the area (370 × 10(6) bbl oil). Beryloil production began in June 1976, gas injection in production began in June1976, gas injection in Nov. 1977, and water injection in Jan. 1979. The reservoir currently is managed by 16 producing wells, two water injectors, andproducing wells, two water injectors, and three gas injectors (Fig. 1). By Dec.1990, the reservoir had produced 285 × 10(6) bbl of oil, and 490 Bcf of gas and170 × 10(6) bbl of water had been injected. Reserves are estimated to be 85 ×10(6) bbl oil and 535 Bcf gas. Fluid movement within the Beryl reservoir iscomplicated, as evidenced by observations of (1) adjacent areas in pressurecommunication with apparent gas/oil contacts (GOC's) that differ by several hundred feet and (2) water overlying oil or oil overlying gas in massive sandsequences. Gas sales to begin in 1992 will have a dramatic effect on fluid distribution within the Beryl reservoir. A simulation model is being developed to predict the most efficient to satisfy the gas contract while maximizing hydrocarbon recovery. Past efforts to simulate the Beryl reservoir have been time-consuming and of limited success because of incomplete reservoir models. In a reservoir as complicated as Beryl, a conceptual reservoir model explainingthe interplay between the geologic and reservoir data must be developed beforesimulation begins. A simulation exercise can only support and quantify the reservoir model; it is an inefficient tool for determining the parameters that control the reservoir behavior. This paper describes a dynamic reservoir model paper describes a dynamic reservoir model developed by examining the reservoir pressure and fluid histories within the confines pressure and fluid histories within the confines of recently recognized horizontal and vertical permeability restrictions. Reservoir Description The Beryl reservoir in the Beryl A area has an oil column of 1,950 ft, ranging from 9,600 ft subsea at the crest to 11,530 ft subsea at the oil/watercontact (OWC). The variable reservoir thickness ranges from 150 ft on the crestto 600 ft on the flanks because of syndepositional faulting. East of the platform, the reservoir is eroded by the platform, the reservoir is eroded by the overlying base of a Cretaceous unconformity and is thus limited in extentto only the crest and west flank of the Beryl A horst. From the crest of thestructure, which is near the Platform Beryl A, the reservoir dips structurally at 10 degrees to 25 degrees toward the west, northwest, and southwest. The structure spills to the south and appears to be filled to the mapped structuralspill point. To the north, the reservoir continues point. To the north, the reservoir continues with limited communications into the Beryl B area. The Beryl formation is a Middle Jurassic (Bajocian to Callovian) transitionaldeltaic/marine system. Net gross ratios range from 0.8 to 1.0, porosities from 13% to 20% and permeabilities from 50 to 2,000 md. The formation islithostratigraphically divided into Units 1 through 5. Unit 2 is 50-ft shalebed that forms an effective permeability restriction, resulting in Unitpermeability restriction, resulting in Unit 1 being produced separately from Units 3 through 5. Unit 1 development in the Beryl A area did not begin until1989 and is not the subject of this paper. Gravity drainage augmented by reinjection of associated gas into a secondary gas cap is the major production mechanism for the reservoir in the Beryl A area. Water injection on the flanks, primarily in the south, has augmented natural aquifer support. JPT P. 1502