Kuparuk River field

The Kuparuk River oil field is west of the supergiant Prudhoe Bay oil field on Alaska’s North Slope and was discovered in 1969. It has approximately 5.9 billion bbl of stock tank original oil in place (STOOIP) and covers more than 200 sq. miles (see Fig. 1). The sandstone reservoir consists of two zones [A (62% of STOOIP) and C (38% of STOOIP)] that are separated by impermeable shales and siltstones. Sales oil is approximately 24°API with a viscosity at reservoir conditions of approximately 2.5 cp. The reservoir oil was approximately 300 to 500 psi undersaturated at the original reservoir pressure of approximately 3,300 psia. The reservoir is broken into segments by several north-to-south faults (density of approximately three faults per mile) that have sufficient throw to totally offset adjacent portions of the reservoir. The two major stratigraphic flow units exhibit considerably different properties, with the lower A zone having lower permeability, the C zone having considerably higher permeability, and the difference between them being approximately an order of magnitude.

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  Fig. 1 – Areal map of reservoir sands, Kuparuk River oil field. (CPF = central production facility. On this map, CPF 1, CPF 2, and CPF 3 refer to the areas of the Kuparuk River field that are producing into these three sets of facilities.)

Development

The oil field was developed in stages, starting with the initially discovered eastern portion. Initial development was on 160-acre well spacing, and production started in 1981. The waterflood began in 1983. Expansion of the water-handling and -injection facilities led to full-field waterflooding in 1985. To date, more than 600 patterns have been developed with approximately 850 wells from 42 drillsites. The pattern style—a 320-acre, nominally 1:1 east/west line drive—takes into consideration the fault alignment. Annual average production peaked at more than 320,000 barrels of oil per day (BOPD) in 1992. Water production began in 1983, and the water/oil ratio (WOR) slowly but steadily increased over the years to a value > 1 by 1990. The two intervals have been flooded at different rates because of their different reservoir properties. Practically all of the wells have been hydraulically fractured to enhance well productivity and injectivity.

Waterflooding

The most significant aspects of the Kuparuk River waterflood are the field pattern development taking into account the reservoir-fault alignment, the allocation of water injection into the dually completed water-injection wells, and the souring of what was originally an H₂S-free oil reservoir. Produced water is treated and reinjected with make-up seawater to balance pattern withdrawals. During the waterflood, the reservoir became inoculated with sulfate-reducing bacteria. Because of the sulfate content of the seawater, these bacteria flourished and multiplied at reservoir conditions, so that the produced gas began to contain H₂S.

Immiscible gas injection

The challenges in this field were that there was no initial gas cap on the reservoir into which to reinject the produced gas; the reservoir dip is very slight, and the reservoir intervals were not very thick, so gas/oil gravity drainage could not efficiently occur; the gas could not be flared; and there was no off-site location to which the residue gas could be sent. For these reasons, the gas had to be reinjected into one of the reservoir intervals for storage and to maintain the oil production rates. The challenge for the field engineers was how to reinject the residue gas in the most efficient way, given the various constraints.

After a few years of gas injection into the A sand in one area of the field in which the offsetting producers soon experienced rapidly increasing gas-oil ratios (GORs), the engineers decided to go to an immiscible water-alternating-gas (WAG) injection process. WAG could be applied at minimal cost and with few operational complications because most of the field was already being waterflooded. Calculations indicated that there were three beneficial effects to this approach.

• There would be some swelling of the oil because of the free gas
• Residual oil saturation could potentially be reduced by the presence of trapped gas
• WAG injection was used to reduce the high mobility of the gas by means of three-phase relative permeability effects (simultaneously having mobile gas, oil, and water in the pore system); also, a tapered WAG scheme helped in this regard

The overall effect was that oil recovery could potentially be increased by 1 to 3% of OOIP without resulting in significant gas cycling problems. To date, immiscible WAG injection has worked as expected and has been a satisfactory solution to the Kuparuk River gas disposal problem.

Ultimate recovery

Estimated ultimate-recovery factors for the Kuparuk River oil field are given in Table 1.

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  Table 1 - Estimated ultimate recovery factors for the Kuparuk River oil field.

The Kuparuk River waterflood has been very successful because of the field engineers’ constant monitoring and active intervention over the past two decades. Over the years, enhanced oil recovery (EOR) by immiscible water-alternating-gas (IWAG) and miscible water-alternating-gas (MWAG) injection has been used in various areas of the oil field to gain additional oil recovery (10% for Zone C and 6% for Zone A). Large-scale MWAG injection started in 1996 and has expanded to include more than 50% of the patterns.

Noteworthy papers in OnePetro

Stoisits, R.F., Scherer, P.W., and Schmidt, S.E. 1994. Gas Optimization at the Kuparuk River Field. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 25-28 September 1994. SPE-28467-MS. http://dx.doi.org/10.2118/28467-MS

External links

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See also

Waterflooding

Immiscible gas injection in oil reservoirs