An equation-of-state (EOS) fluid characterization has been developed to model three-hydrocarbon-phase equilibria. The fluid characterization was developed as part of the enriched-gas EOR research program for the Kuparuk hydrocarbon miscible flood on the North Slope of Alaska. Laboratory experiments with the Kuparuk fluid system have quantitatively identified the third hydrocarbon phase as a second equilibrium liquid, high in asphaltene content and heavier than the original oil. A three-phase EOS fluid characterization was developed to match both two-and three-phase experimental data using a modified Peng-Robinson EOS. Experimental observations identified a relationship between the development of the third phase and the oil's pentane-insoluble fraction. The characterization uses a total of 16 components, with the heaviest two representing the pentane-soluble and pentane-insoluble portions of the C36+ fraction. The properties of these heavy pseudocomponents control the development and behavior of the heavy phase. The EOS fluid characterization was used to study three-phase, enriched-gas-drive displacement mechanisms. For the Kuparuk fluids, a condensing/vaporizing displacement mechanism is predicted in a three-phase environment Reservoir-condition micromodel displacements were conducted to observe the phase behavior and displacement mechanisms during Kuparuk enriched-gas displacements. Micromodel observations are consistent with a near-miscible condensing/vaporizing mechanism and qualitatively agree with EOS predictions. Introduction A hydrocarbon miscible flood is being conducted in the Kuparuk River Field on the North Slope of Alaska. The EOR project covers an area of 5120 acres(2070 ha) at Drill Sites 1Y and 2Z. The flood is conducted in the A and C Sands of the Kuparuk River formation, a stratified and highly faulted sandstone reservoir. The enriched gas injected at the project is a blend of lean produced gas with scrubber and low-temperature separator liquids (enriching fluids)produced onsite. Project design calls for the injection of a 30% hydrocarbon pore-volume slug of enriched gas injected alternately with water at a 1:1volume ratio for mobility control. Fluid properties at Kuparuk vary somewhat across the areal extent of the reservoir. Oil gravities range from 18 to 25 degrees API (0.90 to 0.95 g/cm3)and asphaltene content (measured as pentane insolubles) from 3 to 17 weight percent of the C7+ fraction. An extensive laboratory program was undertaken to provide phase behavior data for designing and operating the EOR project. The laboratory program identified a third hydrocarbon phase when miscible injectant was mixed with reservoir oil. The three-phase equilibria observed with the Kuparuk oils and enriched gases differ from those reported in the literature for other enriched gas/crude oil mixtures and CO2/hydrocarbon mixtures. In the systems reported in the literature, three phases exist in a relatively narrow temperature-pressure composition window and consist of a liquid, a vapor, and a second liquid lighter than the first and rich in components comprising the injectant. In some systems, asphaltenic flocculation and deposition may also occur.

SPE Members Abstract A small-scale hydrocarbon miscible flood was initiated at the Kuparuk River Unit on the North Slope of Alaska in mid-1988, three years after the start-up of waterflooding. This Small Scale EOR (SSEOR) project, along with an infill drilling program, is improving recovery from a stratified and highly faulted sandstone reservoir. The project design was aided by limited compositional reservoir simulation. The design calls for the injection of a 30% hydrocarbon pore volume (HCPV) slug of miscible injectant (MI) which is injected alternately with water at a 1:1 water-alternating-gas (WAG) ratio for mobility control. An extensive laboratory program was conducted to understand the displacement process and to develop an equation of state (EOS) fluid characterization. The displacement process is characterized as a condensing/vaporizing gas-drive process, providing a high unit displacement efficiency. A comprehensive surveillance program was implemented to quantify reservoir continuity and vertical conformance. A gas tracer program has helped in interpreting the influence of faulting on interwell continuity and regional fluid flux. Injection and production well surveys indicate that permeability stratification controls vertical conformance. Preliminary evaluation of project performance indicates significant incremental recovery associated with both infill drilling and enriched gas injection. Typical EOR response includes a significant increase in the oil production rate, with an associated decreasing watercut and increasing gas-oil ratio. Introduction History. The Kuparuk River field was discovered in 1969 by Sinclair. Field delineation, however, was delayed until 1974 due to development activities at Prudhoe Bay, located 40 miles to the east Fig. 1 shows the location of Kuparuk and the outline of the production drill sites. Production at Kuparuk began in 1981. Cumulative recovery is approximately 835 million barrels of oil and the field currently produces 300,000 BOPD. Based on remaining reserves and current oil rate, Kuparuk is the second largest field in North America. Development drilling is ongoing at Kuparuk. The drilling program consists of a mix of 160-acre wells on the periphery of the field and 80-acre infill wells in the Core of the field. Wells are drilled from central drill sites to minimize the environmental impact. There are currently 42 developed drill sites at Kuparuk. Initially, the field produced under solution gas drive. Waterflooding was initiated in 1985, and is now the dominant recovery mechanism. A significant portion of the field (16 drill sites) is undergoing a unique immiscible gas injection EOR process. The Kuparuk SSEOR project is located at Drill Sites 1Y and 2Z, which encompasses an area of 5120 acres (Fig. 1). The current status of wells in the project area is shown in Fig. 2. The project area contains 13 Miscible WAG (MWAG) injection wells and 9 Immiscible WAG (IWAG) injectors at drill sites adjacent to 1Y and 2Z. Drill Site 1Y was developed and brought on production in early 1983. Drill Site 2Z was initially developed on 320-acre spacing with the completion of eight wells in 1983. Eight additional wells were drilled in 1985 to complete 160-acre development. Enriched gas injection was initiated in mid-1988, three years after initiating pattern waterflood. In late 1988, ten 80-acre infill wells, five at each drill site, were drilled in the EOR project area, and four producing wells were convened to injection (1Y-09, 1Y-11, 2Z-04, and 2Z-15). A "Bounded Area", defined by six water injectors along the northern, eastern and southern boundaries, and a major sealing fault to the west, was established to study waterflood performance on 80-acre well spacing (Fig. 2). Geologic Setting. The Kuparuk River formation was deposited during Early Cretaceous time on the south flank of the Barrow Arch. Trapping is a combination of stratigraphic pinchouts, erosional truncation, and oil-water contacts. The A Sand (lower producing member) was deposited during storms on a shallow marine shelf. Reservoir quality is a function of water depth and storm energy at the time of deposition. The A Sand contains approximately two-thirds of the OOIP. The C Sand (upper producing member) was deposited after regional uplift, erosion, and marine transgression. P. 769^

In 1988 a hydrocarbon miscible water-alternating-gas (MWAG) pilot was initiated in the Kuparuk River field, on the North Slope of Alaska. Project decline curve analysis showed a significant response to the MWAG process. The field data alone, however, could not be used to accurately project the ultimate performance of the process. A systematic, integrated approach to reservoir modelling was used to evaluate the MWAG process performance. Finely gridded one dimensional (1D) models were used to evaluate the process mechanisms. Then fine and coarsely layered 2D and 3D compositional models were used to evaluate the process efficiency. The areal effects, including faulting, were then incorporated by using a 3D, coarsely gridded, multi-well, modified black oil (MBO) model. The 3D, site-specific, model was history-matched for the waterflooding period. The miscible food performance was then predicted using a tuned MBO parameter and compared to the field performance. The 3D MBO model predicted that the ultimate incremental recovery would be 11% for a 30% HCPV slug. The model indicated that the miscible process can accelerate production of the waterflood reserves. The model was also used to evaluate the effects of total slug size, maturity of the preceding waterflood, and WAG ratio on the process efficiency.

This paper will review the history and current operations of the Kuparuk River Unit (KRU) field, the second largest field on the North Slope and one of the largest fields in the US. The field is a legacy asset in the ConocoPhillips portfolio with more than 6 BBO OOIP. The field came on line in December 1981 and has produced 2.25 BBO to date through water flood, immiscible water-alternating gas (IWAG) and miscible water-alternating-gas (MWAG) injections. Currently the field produces 90,000 bopd, 460,000 bwpd and 210 MMscf/d gas, and injects 570,000 bwpd and 160 MMscf/d miscible injectant. Some of the recent challenges at KRU include: maintaining pressure support (water injection) through an aging infrastructure, development and use of fit-for-purpose simulation models to support field management decisions, estimation of facilities back-out from a complex multi-field system, and optimization of one of the largest MWAG EOR floods in the world. History and current status of the KRU field will be discussed.

Through many phases of expansion, the Kuparuk hydrocarbon miscible water-alternating-gas (MWAG) project has grown from 10 patterns on 2 drillsites (Small Scale EOR, or SSEOR) to today's 283 patterns on 32 drillsites. It now covers an area with almost 4 billion barrels of STOOIP and has generated an estimated 120 MMSTB of incremental oil sales. The original goals of the MWAG project were twofold: First, there being no available market for produced gas, to efficiently store associated gas in the reservoir (avoiding the rapid recycling of gas observed with other processes); and second, to generate incremental tertiary oil production. The project is approaching its target maturity, especially in the C sand. But the lower throughput A sand has some immature patterns showing lower-than-expected tertiary oil response. Despite the relative maturity of the MWAG flood, expansion opportunities still exist. Based on fine grid compositional simulation, an expansion of MWAG to drillsite "A" is under evaluation. This paper provides a brief review of the Kuparuk MWAG project's history, an overview of current status and flood management practices, and describes the latest investigation into further expansions. Introduction The Kuparuk River Field, located on the North Slope of Alaska, was discovered in 1969. See field location map (Fig. 1). Field delineation commenced in 1974 and production began in 1981. Initial production from the Kuparuk field was by depletion drive from 40 wells located on 5 drill sites producing to a single Central Processing Facility (CPF1). Oil production from the initial development peaked at 80,000 BOPD. A second CPF (CPF2) was added in 1984 and a 300,000 BWPD seawater treatment plant was installed in 1985 to facilitate a field-wide waterflood project. A third CPF (CPF3) was added in 1986 and oil production peaked on December 15, 1991 at 353,000 BOPD. Due to lack of a gas market, gas management became a critical element of development and depletion planning at Kuparuk. Gas production in excess of field fuel demand must be re-injected into the reservoir. Gas storage on the eastern flank of the field was the initial solution, however, rapid gas movement and production impacts associated with high gas/oil ratio (GOR) production and compressor limits became apparent. In 1985, an immiscible water-alternating-gas (IWAG) project was implemented at 3 drillsites to improve recovery and to expand gas storage options. In 1988, the SSEOR MWAG pilot project was installed to evaluate the potential of hydrocarbon miscible flooding at Kuparuk. Positive results from the SSEOR pilot lead to the implementation a large-scale EOR (LSEOR) project in 1996. The Kuparuk field development now incorporates 43 drill sites and more than 1000 wells, producing 120,000 BOPD, while processing 500,000 BWPD and 490 MMscf/D of gas (including artificial-lift gas). Miscible flooding has been installed on 32 drillsites. To date, 990 BCF of miscible injectant (MI) has been injected, yielding an estimated 120 MMSTB of incremental oil production. EOR oil accounts for approximately one-third of the current field production. See Fig. 2 for a summary field development timeline.