Brent Field 3D Reservoir Simulation
Authors: Tollas J.M. , McKinney Andrew 
Published: December 2007

The Brent field consists of two separate reservoirs and multiple pressurezones with variable PVT fluid properties and condensate-rich gas caps. Thereservoirs are being developed simultaneously with common facilities, presenting many reservoir engineering challenges that cannot be met withclassic tools alone. Reservoir simulation has been an integral and essentialpart of reservoir studies and depletion planning. Increasingly sophisticatedmodels were developed as the tools became available and the reservoirdescription matured. This paper describes the third-generation, 3D model, characterized by detailed geologic description, extensive use of pseudos toreflect reservoir complexity, pseudos to reflect reservoir complexity, and anintricate well-management/ platform-processing program. The platform-processingprogram. The studies performed with this model confirmed the viability of thebase development plan while also quantifying the benefits of alternativedevelopment schemes.

Introduction

The Brent field, jointly owned by Esso E and P U.K. Ltd. and Shell U.K. Band P Ltd. and operated by Shell, was the first structure in the North Sea Viking graben to be proved oil-bearing and productive. The field, discovered in1971, is about 100 miles northeast of the Shetland Islands (Fig. 1), where theaverage water depth is around 460 ft. Delineation wells proved a productivearea about 11 miles long north/south and 3 miles wide east/west. The fieldcontains two separate reservoirs of Middle and Lower Jurassic Age, called the Brent and Statfjord reservoirs, respectively.

The two reservoirs are separated by the Dunlin shale (about 800 ft thick)and overlain by the Upper Jurassic Heather shale and Kimmeridge clay. The fieldis delimited to the north and south by major east/west faults, to the east byan erosional surface and slump faulting, and to the west by the oil/ watercontacts (OWC's). Both reservoirs, overpressured by about 2,000 psia, contain ahigh-shrinkage oil column with depth-dependent oil properties and acondensate-rich gas cap. Total in-place volumes of liquids and gas areestimated at 3.4 billion bbl and 7.0 Tscf, respectively.

Commercial production started in 1976 from the Brent Bravo platform. Subsequently, three more platforms were installed, and production rates of morethan 450,000 B/D production rates of more than 450,000 B/D have beenachieved.

Brent reservoir development has preceded that of the Statfjord, as indicatedby the January 1, 1988, recoveries for the two reservoirs of 37 and 28%original oil in place (OOIP), respectively. Since 1980, 3D numerical simulationstudies have become a useful aid to evaluate the effect of gas sales rates onreservoir performance, to optimize the remaining well locations and redrills, and to investigate future depletion strategies for the two reservoirs.

Reservoir Description

Structure.

The Brent and Statfjord reservoirs are contained in a westerlydipping (about 7 degrees), monoclinal structure. Fig. 2 is a simplified contourmap of the top of the Brent reservoir. The structure of the Statfjord reservoiris similar to that of the Brent but located deeper and farther east. Fig. 3 isan east/west schematic cross section of Brent field.

The original OWC's were at 9,040 and 9,690 ft subsea (ss), while theoriginal gas/oil contacts (GOC's) were interpreted to be at 8,560 and 9,100 ft55 in the Brent and Statfjord reservoirs, respectively. The original GOC's weredifficult to determine from well-log interpretation because the physicalproperties of the reservoir fluids at physical properties of the reservoirfluids at the contacts are very similar, especially for the Statfjordreservoir.

Stratigraphy.

The Middle Jurassic Brent reservoir (average thickness 750 ft)is stratigraphically divided into four major units, called cycles, on the basis of rock type, depositional environment, shale continuity, andpermeability/porosity variation. Reservoir performance during the later years of production revealed more extensive shale continuity within the upper cyclesthan previously thought. Currently, 12 pressure previously thought. Currently,12 pressure zones (subcycles) have been identified in this reservoir. Thedeepest stratigraphic unit, Cycle 4, is composed of a shaly, finegrained sandwith permeability increasing upward as the sand becomes a coarse-grained, barrier-beach sequence. Cycles 2 and 3, although separated by a fieldwidedelta-top, lagoonal shale (the Mid-Reservoir shale), were deposited basicallyin a similar lagoonal/delta-plain environment. The sands are primarily pointbars, channel deposits, and stream-mouth bars with minor beach deposits. Shaleand coal interbeds have considerable areal continuity.

Cycle 1 consists of a lower shaly, lagoon-al/ delta-plain interval somewhatsimilar to Cycle 2 and an upper marine-beach sand with excellent reservoirqualities.

JPT

P. 589