Despite 21 years of production, the Brent field still holds the largest remaining hydrocarbon reserves of any field in the UK North Sea. The drive to optimise ultimate recovery of oil and gas has led Shell UK Exploration and Production to invest 20 man-years in a thorough revamping of the Brent Full Field Model to ensure the availability of an up-to-date reservoir management tool for the upcoming depressurisation of the field. For the first time a three-dimensional modelling approach was used to create the geological model, with a significantly greater level of detail and more geological layers than were modelled previously. Reprocessed seismic data and revised geological interpretations were used to assign rock and fluid properties to the 70 million building blocks that make up the new "static" model of the field, while pseudo relative permeability and capillary pressure curves were derived to conserve as much as possible of this detail after upscaling to the simulation model. The corresponding "dynamic" model consists of 88,060 grid blocks, three times as many as in the previous model. Reservoir fluids were also re-characterised to better represent the depth dependency of the fluid properties. During the project a large number of hardware and software problems had to be overcome. These were related both to the use of new software and the large size of the Brent model.
The early results of the Full Field Model provided the confidence to increase the field's by 127 MMstb of oil and an additional 200 bscf of gas. Furthermore, the tool allows numerous "what if" questions to be tested, resulting in further optimisation of field development. In investment terms, the value added to Brent by the Full Field Model has already vastly exceeded its building cost and many further benefits are foreseen.
The Brent Field, located in the UK sector of the northern North Sea (Fig. 1), is Shell Expro's largest Field and has been producing since end 1976. The Field consists of two westerly dipping formations, the Brent and the underlying Statfjord formation, separated by the non-reservoir Dunlin Group. To the East both reservoirs are present in a number of slump blocks which are in limited communication with the major part of the Field. The initial development plan called for oil and gas production together with down dip water injection in both reservoirs for pressure maintenance purposes. Current plans are to depressurise the field in order to develop the gas dissolved in the by-passed and residual oil. At present (1.1.1997) the remaining oil reserves after 20 years of production are estimated at 400 MMstb of which approximately 30% are located in the Slumps and 34 MMstb are related to depressurisation. Gas reserves are currently 2.6 Tscf of which 1.5 Tscf is related to the depressurisation of the Field.
Since 1988 the Brent Full Field Model (FFM) has been an invaluable tool in the management of the Field and for the preparation of the development plan for depressurisation. However, it had become more difficult to match the production from the crestal wells and the Slumps due to the simplified way of modelling the crestal volumes and permeability barriers. In August 1991 the decision was taken to upgrade the Full Field Model using the latest technology and modelling tools. It was argued that where the existing simulation model was adequate for the conceptual design of the depressurisation development plan, the new model should be suitable for the detailed design. The objectives of the Full Field Model Upgrade project were:
- –
To incorporate the latest geological and petrophysical interpretation of the Field and in particular to improve the modelling of the crestal area and the Slumps.
- –
To improve the representation of the depth dependent fluid properties in the simulation model.
P. 115^
