Early Performance and Evaluation of the Kuparuk Hydrocarbon Miscible Flood

Abstract

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^

Performance evaluation and optimization of the Kuparuk hydrocarbon miscible water-alternating-gas flood

“…The SSEOR project injection rate has averaged 34 MMScf/d (1 million Sm3/d). Further details about the project are reported by Reinbold et al (1992).…”

Kuparuk Large-Scale Enhanced Oil Recovery Project

“…A single-well tracer test indicated that the S orw after many PV's is approximately 27"3%. 9 The tracer-test results were dominated by a thief zone. These two independent values of S orw are reasonable estimates for S orw in a few of the subunits of the C-sand at field conditions, which range from low to high throughput.…”

“…An extensive fieldwide refracturing program was initiated in 1988 to increase withdrawal from the less prolific A-sand. 7,8 An EOR pilot was initiated in 1988 on two drillsites, 9,10 and subsequently expanded to one of the IWAG drillsites in 1993 to test the MWAG after IWAG process. Largescale expansion of EOR at Kuparuk is in progress.…”

“…9 Virtually all Kuparuk faults are normally oriented and behave as barriers to flow in some cases and as fluid conduits in others. Throws of up to 300 ft are observed in some of the larger faults; however, fault throws of 30 to 80 ft are most common.…”

“…The reservoir was undersaturated at the time of discovery, with an average reservoir pressure of 3,100 psi, an average bubblepoint pressure of 2,800 psi, and a solutiongas/oil ratio (GOR) of 500 scf/STB. 9 Oil gravity varies from 18 to 27°API throughout the field, but is 24°API on average. Table 1 contains a boiling-point breakdown of oil currently being shipped from the field.…”