A production forecasting model that uses linear programming concepts has been developed to generate composite forecasts from multiple streams produced through a common facility. The model treats petroleum processing as a linear optimization problem to maximize oil production under a set of independent constraints. The model represents production streams competing for limited facility capacity on a consistent basis. This approach allows resolution of production streams of varying character [GOR, gas/liquid ratio (GLR), or WOR] into a composite rate forecast while facility capacity is used optimally. In particular, the model may be used to forecast production of several unrelated fields producing through a common facility. The model was applied to forecast production for three Alaska North Slope reservoirs (Kuparuk, Lisburne, and Point Mcintyre) for development and facility-expansion evaluations.
Summary The Kuparuk River field on the Alaskan North Slope produces from twostratigraphically produces from two stratigraphically independent sands of the Kuparuk River formation. A full-field reservoir model was constructed tosupport field management and development planning. The model captures planning. The model captures essential aspects of two independent producing horizons, hydraulically producing horizons, hydraulically coupled at the wellbores, andsimulates dynamic interactions between the reservoir sands and surfacefacilities. The field model is used to plan field development on the basis ofperformance ranking of drillsite performance ranking of drillsite expansions, to assess depletion performance effects of reservoir performance effects ofreservoir management strategies, and to evaluate alternative depletionprocesses and associated reservoir and facility interactions of fieldprojects. Introduction A variety of development options are under evaluation for potentialimplementation at the Kuparuk River field. Several competing depletionmechanisms currently exist in the field. Introducing new projects will add tothe complex interrelationship of these depletion processes. Full-fieldreservoir simulation is used to forecast production performance under existingand future field performance under existing and future field configurations, toevaluate reservoir and facility interactions associated with field developmentalternatives, and to support ongoing field operation and management. This paperdiscusses the application of full-field paper discusses the application offull-field simulation to development planning and reservoir management at the Kuparuk River field. Motivation for Field-Scale Simulation. Using large-scale simulation forreservoir performance appraisal and development performance appraisal anddevelopment decision making has increased steadily* since the early developmentof black-oil reservoir simulators. Full-field reservoir simulation allowsreservoir depletion processes to he fully integrated with surface-facilityoperating constraints, resulting in resolution of dynamic interactions betweenthe reservoir and facilities. The need to quantify reservoir performanceexpectations more accurately spurs the development of more rigorous and complexfull-field reservoir models. Increased understanding and certainty derived fromadvanced field-scale simulation contributes to the decisionmaking process andpartially mitigates the risk associated with the large capital expendituresrequired for reservoir development. Kuparuk Reservoir Characteristics. The Kuparuk River field is located about40 miles [64 km] west of the Prudhoe Bay Unit (Fig. 1). Discovered in 1969, the Kuparuk reservoir contained an estimated 5 billion bbl of original oil in place(OOIP) with estimated recoverable reserves of nominally 1.6 billion bbl. The reservoir is made up of two distinct sandstone members within the Kuparuk River formation, a Lower Cretaceous, shallow, marine-shelf sanddeposit. The members are separated by a major unconformity, and two units arerecognized within each member. As Fig. 2 shows, the lower member contains Units A and B (informally named), with reservoir-quality sands present primarily in Unit A. The upper present primarily in Unit A. The upper member contains Units C and D, with reservoirquality sands present only in Unit C. Fig. 3 illustratesthe lateral extent of the Kuparuk sands. The A sand extends over the entirefield; the C sand covers a smaller area. Fig. 4 shows the dominant structural aspects of the Kuparuk sands. The Kuparuk interval forms a gently dipping anticline ranging in depth from 6,500to 8,500 ft across the structure. The trapping mechanism is a combination ofstratigraphic pinchout, erosional truncation, structural closure, pinchout, erosional truncation, structural closure, and a water/oil contact. Thereservoir is highly faulted by normal faults with up to several hundred feet ofthrow, which has a significant impact on flow unit continuity and fluidmovement. The predominant north/south fault trend density is nominally 3faults/sq mile. Faulting occurred during different depositional periods of the Kuparuk sands, influencing the character of the sand accumulations. Faultingoccurred primarily postdepositional to the A sand and postdepositional to the Asand and syndepositional with the C sand. Consequently, faulting frequency andpatterns are dissimilar for the two sand bodies. The Kuparuk sands are fairly thin, averaging 50 to 100 ft of grossthickness, but laterally extensive, covering roughly 200 sq miles. The C sandcontains several highly permeable, very prolific, interbedded zones permeable, very prolific, interbedded zones having an average permeability thickness of5,000 md-ft. Reservoir quality of the C sand, expressed by the distribution ofreservoir properties, is highly influenced by diagenesis and indirectly relatedto depositional facies. The A sand is characterized by sheet-like sandstonebodies interbedded with shales and mudstones. The A sand reservoir quality iscontrolled by depositional environment, and this sand, with its averagepermeability thickness of 1,000 md-ft, is permeability thickness of 1,000md-ft, is much less productive than the C sand. JPT P. 974
Decisions concerning future development options at the Kuparuk River Field are complex and interrelated. Various development strategies are being evaluated. To help address these issues, a facilities model has been added to a full field reservoir simulator. Facility limits are used with a well ranking system to shut in marginal production when equipment capacity constraints are exceeded. The model simulates field operating strategies which maximize production. Operational strategies are modelled using (1) a wellbore hydraulic routine that enables bottom hole pressures to change (reflecting the benefit of various gas lift rates), (2) a gas lift allocation correlation that was determined from field data, and (3) a gas management routine which optimizes oil production while honoring gas capacity constraints and field gas production while honoring gas capacity constraints and field gas lift needs. These gas management and hydraulic features are essential to properly evaluate future projects in a gas capacity constrained environment and can be applied to other reservoir simulation tools. An example of how the reservoir simulator is being used to address a key issue in the large scale facility expansions evaluation is included. Introduction The Kuparuk River Reservoir contains approximately five billion barrels of original oil in place. The reservoir is located on the Alaskan North Slope, approximately forty miles west of the Prudhoe Bay Field. The field produces from two physically independent sands of the Kuparuk River Formation, a lower cretaceous, shallow marine sandstones The productive sands are Informally named the A and C Sand members. The C Sand overlies the A Sand and is highly permeable, having an average permeability thickness of 5000 md-ft (1.5 mu m2-m). The A Sand is considerably less productive than the C Sand, having an average permeability thickness of 1000 md-ft (0.3 mu m2-m). The two sands do not communicate within the reservoir; however, they are hydraulically coupled through the wellbores. Many development issues have faced the Kuparuk River Field Unit Owners since startup in 1981. The field has experienced a variety of development processes including primary production, waterflood, a water alternating immiscible gas injection (immiscible WAG) project, and a pilot scale miscible WAG project. With these various recovery mechanisms, the field has grown in complexity. An uncertain economic climate further complicates development decisions. The Kuparuk River Field has reached a point in field development where decisions concerning future strategies are usually complex and interrelated. Various development strategies are simultaneously being investigated: infill drilling, further peripheral development, and enhanced oil recovery projects. Some of these strategies require facility additions with long equipment lead times, which necessitates early identification of field development plans and reliable rate projections. In addition, future operating strategies centering around a maturing waterflood are also uncertain. Gas lift gas requirements for wells with steadily increasing water cuts are still being investigated. Factoring these possibilities and uncertainties into the evaluation of development options at Kuparuk required enhanced simulation tools. To address the complex nature of these decisions, a Kuparuk-specific facilities model and well management logic for a gas capacity constrained system have been added to a full field reservoir simulator. A modelling scheme specific to the Kuparuk River Field was needed because of the unique facility configuration. Equipment limits are used with a well ranking system to shut in marginal production when facility limits are exceeded. To properly simulate field operations in a compression capacity constrained environment, additional features were developed for the well management package. A wellbore hydraulics routine that enables flowing bottom hole pressures to change as a function of gas lift rates, fluid production characteristics, and reservoir pressure was implemented. p. 297
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.