Statfjord Field: Development Strategy and Reservoir Management
- Sigurd A. Haugen (Statoil) | Oystein Lund (Statoil) | Leif A. Hoyland (Statoil)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 1988
- Document Type
- Journal Paper
- 863 - 873
- 1988. Society of Petroleum Engineers
- 1.2.3 Rock properties, 4.1.2 Separation and Treating, 6.5.2 Water use, produced water discharge and disposal, 3.3.1 Production Logging, 2.4.3 Sand/Solids Control, 4.1.9 Tanks and storage systems, 4.3.4 Scale, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.1.2 Faults and Fracture Characterisation, 5.5.8 History Matching, 5.1.5 Geologic Modeling, 2.4.5 Gravel pack design & evaluation, 5.4.1 Waterflooding, 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics, 1.6 Drilling Operations, 2.2.2 Perforating, 3.3 Well & Reservoir Surveillance and Monitoring, 5.5 Reservoir Simulation, 5.5.11 Formation Testing (e.g., Wireline, LWD), 5.4.2 Gas Injection Methods, 4.1.5 Processing Equipment, 5.4.9 Miscible Methods, 5.2.1 Phase Behavior and PVT Measurements, 2 Well Completion
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This paper reviews reservoir performance and management of the Statfjord field after 8 years of production. The reasons behind the reservoir development strategies and field experiences are presented. The field comprises three reservoirs produced simultaneously with designated wells for each reservoir: the Upper and Lower Brent and the Statfjord. The two Brent reservoirs are produced with a waterflood, while the Statfjord reservoir is produced with a high-pressure miscible gasflood.
The original development plans have been refined on the basis of field performance through an extensive monitoring program and use of reservoir simulation. The induced gamma ray spectra (IGRS) log is used to monitor water movement in the Brent reservoirs, while the compensated neutron tool (CNT) is the main tool used to monitor the gasflood in the Statfjord reservoir. The acquired data have improved the geologic model and the knowledge of fluid movements in all three reservoirs. This resulted in a large and complex reservoir simulation model with more than 20,000 gridblocks.
The Statfjord field, the largest producing oil field in Europe, is located in the prolific northern part of the Viking graben, 125 miles [200 km] northwest of Bergen, Norway, on the U.K./Norwegian boundary (Fig. 1). The field was discovered in March 1974 with the drilling of Well 33/12-1 and was delineated with drilling of 11 additional wells. The field lies mainly in Norwegian Blocks 33/12 and 33/9, but also extends into U.K. Blocks 211/24 and 211/25. The field was unitized in 1976 with Mobil as operator. The equity redetermination of 1979 resulted in 84.1 % of the field being in the Norwegian sector and 15.9 % in the U. K. sector. The operatorship was transferred from Mobil to Statoil in Jan. 1987.
The Statfjord field, which is 15 miles [24 km] long and averages 2.5 miles [4 km] in width, is located in a westerly tilted and eroded Jurassic fault block. The main recoverable reserves, about 75 %, are located in the Middle Jurassic Brent group, while the remaining 25 % is in the Lower Jurassic/Upper Triassic Statfjord formation. Both Brent and Statfjord have exceptionally good reservoir characteristics. The estimated ultimate recovery is around 3 x 109 bbl [475 x 106 M3] of oil and 3 x 10 12 Scf [85 x 109 std M3] of gas. Both Brent and Statfjord reservoirs contain highly undersaturated low-sulfur crude oil. Reservoir data and fluid properties are given in Tables 1 and 2.
The Statfjord field is being developed with three gravity-based Condeep-type platforms and single-point mooring for offshore oil tanker loading. Production from Platform A commenced in Nov. 1979, while Platform B came on production in Nov. 1982 and Platform C in June 1985. Regular gas sales by pipeline to the U.K. and the European continent began in Oct. 1985.
Eighty-nine development wells have been drilled to date to achieve the current average daily oil-production and water-injection rates of 750,000 STB/D [119 000 stock-tank M3 /d] and 1,050,000 B/D [ 167 000 M 3 /d], respectively. As of Dec. 1987, nearly 1.2 x 109 bbl [190 x 10(6) M3] Of oil. or about 40% of the recoverable reserves, has been produced.
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