Current Challenges in the Brent Field
- W.M. Schulte (Shell E&P) | W. van de Vijver (Shell E&P)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1994
- Document Type
- Journal Paper
- 1,073 - 1,079
- 1994. Society of Petroleum Engineers
- 6.5.2 Water use, produced water discharge and disposal, 7.3.3 Project Management, 5.5 Reservoir Simulation, 5.4.1 Waterflooding, 3.1.6 Gas Lift, 5.1.2 Faults and Fracture Characterisation, 3 Production and Well Operations, 4.1.9 Heavy Oil Upgrading, 4.2 Pipelines, Flowlines and Risers, 5.6.9 Production Forecasting, 2 Well Completion, 5.2.1 Phase Behavior and PVT Measurements, 2.4.5 Gravel pack design & evaluation, 4.1.2 Separation and Treating, 5.1.1 Exploration, Development, Structural Geology, 2.4.3 Sand/Solids Control, 1.6 Drilling Operations, 3.1.2 Electric Submersible Pumps, 4.3.4 Scale, 4.6 Natural Gas, 3.1 Artificial Lift Systems, 4.1.5 Processing Equipment, 1.10 Drilling Equipment
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This paper describes the main challenges of the Brent field, which are related to the final stage of the currently executed pressure-maintenance waterdrive and preparations for field depressurization. These challenges are grouped into three categories: timely development of all reserves, production optimization before deep depressurization, and proper execution of the redevelopment project.
Located in about 460 ft of water roughly 100 miles northeast of Shetland (Fig. 1), the Brent field is one of the largest hydrocarbon accumulations in the U.K. sector with 3,600 million STB original oil in place (OOIP) and 6.9 Tscf original gas in place (OGIP). Estimated ultimate recoveries are 1,980 million bbl oil and 5.5 Tscf wet gas. Oil and gas are exported through two pipeline systems: the Brent system for oil and the FLAGS system for gas. These systems form a large part of the total infrastructure in the northern North Sea.
The Brent field can be considered a mature field, with about 77% of its waterflooded ultimate oil recovery produced to date. To enhance the ultimate recovery of both oil and gas beyond that possible by the current waterflood at near-initial reservoir pressures, low-pressure operations facilities and gas lift will be installed during 1994-97, and the field will be depressurized in a controlled fashion beginning in 1997. To make the change to low-pressure operations/depressurization and to cater for the longer life expected of the Brent field, extended platform shutdowns are required, so one of the four platforms will be out of service between mid-1994 and early 1998. The redevelopment project, costing an estimated #1.3 billion,* is unique in scale, complexity ("brown" field engineering) and implementation (it will be executed while ongoing operations are maximized).
The optimization of oil recovery from the Brent field under this new long-term development strategy is exceptionally complicated. It requires proper integration of waterflood tail-end production from a complicated crestal region with the transition to depressurization, all in a limited time frame. Well operations play a key role in developing all future reserves and integrating redevelopment well activities. In addition, increased emphasis is given to all initiatives that increase potential and productivity. Any deferment of oil production will put ultimate recovery at risk in view of the slow loss of lift in oil-producing wells after the year 2000.
The Brent field, discovered in Aug. 1971, is one of the largest hydrocarbon accumulations on the U.K. Continental Shelf. Its discovery marked the start of extensive activity for exploration of hydrocarbons in the northern North Sea. Located in Block 211/29, the Brent field comprises four installations and a remote flare (Fig. 2). Brent Alpha is a steel piled structure; Brent Bravo, Charlie, and Delta are concrete gravity structures. Together, these structures provide 154 well slots.
The field is operated by Shell U.K. E&P on behalf of the Shell/Esso joint venture in the U.K. sector of the North Sea.
Oil production started in 1976 and peaked at a yearly average of 416,000 B/D in 1985 and 1986. Oil is exported through the Brent systems pipeline to Sullom Voe. Gas export to St. Fergus started in 1982 through the FLAGS line, with all gas sales to British Gas.
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