The Use of Simulation in Decision Making for the Kuparuk River Field Development
- Peter Richard Clutterbuck | Simon Edward Dance
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1983
- Document Type
- Journal Paper
- 1,893 - 1,901
- 1983. Society of Petroleum Engineers
- 5.5.8 History Matching, 4.1.2 Separation and Treating, 3 Production and Well Operations, 5.4.1 Waterflooding, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 6.5.2 Water use, produced water discharge and disposal, 2.4.3 Sand/Solids Control, 5.6.2 Core Analysis, 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 4.2 Pipelines, Flowlines and Risers, 1.6.9 Coring, Fishing, 1.6 Drilling Operations, 5.5.2 Core Analysis, 5.1.2 Faults and Fracture Characterisation, 5.6.4 Drillstem/Well Testing, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 3.1.6 Gas Lift, 5.5 Reservoir Simulation, 5.7.5 Economic Evaluations, 5.6.9 Production Forecasting, 5.1 Reservoir Characterisation
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A multicomponent system of simulators has been used successfully for development decisions on the Kuparuk River field. This paper describes the field, the simulators chosen, and some decision examples. The system was found to be fast, flexible, and cost effective.
The Kuparuk River field, west of Prudhoe Bay in Alaska, shares many problems with recently developed fields in the offshore and Arctic environments because capital costs are extremely high, lead times are long, and many of the development plans are made before useful production history is obtained. During the early development-planning phase, reservoir data acquisition accelerated and facility design revisions were frequent. BP Alaska Exploration Inc, (BPAE) and the Sohio Alaska Petroleum Co. (Sohio) are major shareholders in the Kuparuk River Unit and contributed to development plans. The BPAE/Sohio development team faced the need to compare options by using a rapidly changing data base, recommending decisions for a program that was fixed by target startup dates and seasonal windows. Output from the studies formed the basis for discussion with ARCO Alaska Inc. (ARCO), the Unit Operator, and for the adoption of a mutually agreed development plan. ARCO carried out similar studies concurrently, and all major field-development decisions were made jointly. This paper explains the system used by BPAE/Sohio to arrive at several major decisions through both simulation and experienced judgment to obtain an acceptable degree of confidence. The system used five simulators, either separately or combined, allowing a small team of technical staff to check the validity of results at intermediate stages. This was fast, flexible, and efficient. The views expressed, and the reservoir parameters quoted, reflect the authors' opinion and do not necessarily imply full agreement with other Kuparuk River unit working-interest owners.
BP Alaska Inc. and Sinclair Oil Co. discovered the Kuparuk River field in 1969 on leases now held jointly by ARCO, BPAE, and Sohio. The field is 25 miles (40 km) west of Prudhoe Bay and covers an area of up to 200 sq miles (518 km2) of developable acreage. Fig. 1 shows the location of the field, the route of the Trans Alaska Pipeline System (TAPS) to the ice-free port of Valdez for tanker loading, and the summer sealift route. Fig. 2 shows a map of the field, and Fig. 3 records the field's discovery, appraisal, and development. Since Dec. 1981, the field has been unitized and produced at an average rate of 90,000 B/D (14 309 m3/d) oil. Fig. 4 outlines the probable development plan. A gathering system supplies oil from 40 to 50 drillsites to three central production facilities (CPF's). The first, CPF-1, produced oil initially from five drillsites, each with eight 320-acre (1.3 x 10 6 -m2) producing wells.
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