Prudhoe Bay Well- Management Routine Enhances Simulator Performance
- Frank Bergren (Arco Alaska Inc.) | Jean E. Carruthers (Arco Oil and Gas Co.) | Charles Martin (Arco Oil and Gas Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1989
- Document Type
- Journal Paper
- 1,210 - 1,215
- 1989. Society of Petroleum Engineers
- 4.1.2 Separation and Treating, 5.4 Enhanced Recovery, 5.5.1 Simulator Development, 5.4.1 Waterflooding, 4.1.3 Dehydration, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 4.2 Pipelines, Flowlines and Risers, 6.5.2 Water use, produced water discharge and disposal, 4.1.5 Processing Equipment, 6.1.5 Human Resources, Competence and Training, 4.1.9 Tanks and storage systems, 5.4.9 Miscible Methods, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex)
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A new well-management routine, developed for use in predictive simulation studies of predictive simulation studies of facility-constrained unbounded pattern floods in the Prudhoe Bay field, has made long-term predictive simulations of large multipattern floods practical. The routine automatically practical. The routine automatically balances reservoir injection and production rates in each pattern while production rates in each pattern while honoring the operational constraints imposed on floods in the field. These constraints include injection-facility, production-facility, injection-well production-facility, injection-well bottomhole-pressure (BHP), and production-well hydraulic limits. production-well hydraulic limits. Injection- and production-well rates are modified to meet these criteria as the character of the produced-fluid stream or the facility limits change. The routine can manage wells in waterfloods and water-alternating-gas (WAG) miscible floods.
This paper describes the logical structure, capabilities, and options of the routine. Examples illustrate the utility and performance of the routine.
A well-management routine is used in a numerical reservoir simulator to control the individual wells in the modeled region. To generate meaningful predictions. the nature of the control exerted by such a routine must be similar to that imposed on the actual reservoir. In pattern floods at the Prudhoe Bay field, the control imposed on the actual reservoir will balance injection and production rates in the patterns while meeting production rates in the patterns while meeting numerous operational constraints.
The routine described in this paper is capable of modeling three injection facilities and one production facility. The three injection facilities are the miscible-gas, seawater, and produced-water injection facilities. The production facility is a flow station. The routine is capable of managing the wells in a waterflood, a WAG miscible flood, or a combination WAG/waterflood. To date, the routine has been installed and is being used in two numerical simulators.
The input data for this routine consist of injection- and production-facility limits and pattern relationships. The injection-facility pattern relationships. The injection-facility limits include those on the WAG water injection rate, non-WAG (or waterflood) water injection rate, and miscible-solvent injection rate.
Limits imposed by the production facility are also entered. These are the low-pressure (LP) -gas, the total-gas, the produced-water, and the oil limits. In the eastern operating area of the Prudhoe Bay field, the production facilities are flow stations. These flow stations separate the produced water and gas from the oil, process the gas for transit to a central injection facility, and pump the oil to the Trans-Alaska Pipeline System for shipment to market.
Each flow station contains three separation trains. Each separation train may be operated as either a high-pressure (HP) train with a first-stage separation pressure of about 600 psi [4137 kPa] or an LP train with a psi [4137 kPa] or an LP train with a firststage separation pressure of about 175 psi [1207 kPa]. If a train is operated as an HP train, about 90% of the gas produced to the train does not require any compression before dehydration. The remaining 10% must be compressed from the second- and third-stage separation pressures of 75 and 25 psi [517 and 172 kPa], respectively, to 600 psi [4137 kPa] before dehydration. All gas produced to HP separation trains is designated "HP gas" in the reservoir simulator. This category includes only formation gas from those wells produced to the HP train.
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