An Immiscible WAG Injection Project in the Kuparuk River Unit
- J.H. Champion (Arco Alaska Inc.) | J.B. Shelden (Arco Alaska Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- May 1989
- Document Type
- Journal Paper
- 533 - 540
- 1989. Society of Petroleum Engineers
- 3.1.6 Gas Lift, 4.1.2 Separation and Treating, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.4.1 Waterflooding, 2.4.3 Sand/Solids Control, 5.5.8 History Matching, 5.4 Enhanced Recovery, 4.2 Pipelines, Flowlines and Risers, 5.5 Reservoir Simulation, 4.1.9 Tanks and storage systems, 5.6.4 Drillstem/Well Testing, 5.3.2 Multiphase Flow, 1.8 Formation Damage, 6.5.2 Water use, produced water discharge and disposal, 5.4.2 Gas Injection Methods, 4.6 Natural Gas, 3.2.3 Hydraulic Fracturing Design, Implementation and Optimisation, 5.1.1 Exploration, Development, Structural Geology
- 0 in the last 30 days
- 709 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
Immiscible water-alternating-gas (WAG) injection has been successfully used in the Kuparuk River Unit as a means of controlling excess gas production. Additionally, simulation results have indicated that WAG injection can increase economic oil recovery by improving waterflood conformance. WAG recovery mechanisms, simulation results, field performance, and field surveillance are discussed.
The Kuparuk River Unit lies on the North Slope of Alaska about 40 miles [64 km] west of the Prudhoe Bay Unit, Fig. 1 shows the location of the field, which covers about 1 15,000 acres [46 500 ha]. Oil production currently averages 290 MSTB/D [46 x 10(3) M3/d] with an associated gas production rate of 320 MMscf/D [9.1x10(6) std M3/d]. After fuel usage and limited gas sales, about 240 MMscf/D [6.8 x 106 Std M3/d] of the gas is injected back into the formation. Effective utilization of the injected gas is crucial to the near-term oil rate and long-term oil recovery of the unit.
The Kuparuk reservoir structure is a slightly dipping northwest/southeast-trending anticline at about 6,000 ft [1829 m] subsea. The outline of the field is defined by a stratigraphic pinchout and truncation to the west and south and along the line of an oil/water contact to the east and north.
Two marine sandstone producing intervals are found within the Kuparuk reservoir. Both sands were initially undersaturated at reservoir pressures of about 3,100 psi [21 MPa] and an initial reservoir temperature of 158 degrees F [70 degrees C]. Kuparuk crude oil has an average stock-tank gravity of 24 degrees API [0.91 g/cm3]. oil viscosity is 2 cp [2 mPa - s] at the initial pressure of 3, 1 00 psi [21 MPa], and solution gas is 450 scf/STB [80 std m3/stock-tank m3] at the bubblepoint pressure of 2,950 psi [20 MPa]. The total recoverable reserves for the unit are more than 1,700 MMSTB [270 x 106 stock-tank m3]. The upper sand body, designated Sand C, contains about one-third of the original oil in place (OOIP). It is moderately fractured with an average permeability/thickness, kh, of 4,000 md-ft [ 1200 md - m] and an average porosity of 22 %. The lower sand body, designated Sand A, contains the bulk of the reserves with an average kh of 1,500 md-ft [460 md - m] and an average porosity of 24%. Sand A, which has very few natural fractures, is more continuous than Sand C. The two sands are separated by the nonproductive B interval, which is made up of siltstones, shales, and some sandstones. Fig. 2 is a type log of the sands and Fig. 3 is a field map showing the approximate areal extent of Sands C and A.
The Kuparuk field began producing in Dec. 1981 under solution-gas drive. Lacking a market for the majority of the produced gas, the unused portion was injected into two areas of Sand C. Thin, relatively horizontal sands and the lack of an original gas cap resulted in early breakthrough of the injected gas. Limited gas-handling facilities dictated that high-WR wells be shut in, deferring oil production from the gas injection areas. To date, more than 500 MMSTB [80 x 106 stock-tank m3] of the OOIP in Sand C has been adversely affected by gas injection. The areal extent of the gas-affected Sand C is depicted by the thin solid lines in Fig. 3. Limiting the expansion and accelerating the blowdown of this gas-affected area is clearly important to maximizing near-term oil rate.
In evaluating the gas-handling problem, alternative projects were considered on five premises: the project must have favorable economics, it must not adversely affect oil reserves, it must be environmentally safe. it must use the gas efficiently, and it must be capable of implementation in a relatively short amount of time. Potential opportunities that satisfied all of these constraints included miscible injection, offsite sales for fuel gas, offsite injection into other horizons, foam injection, and immiscible WAG injection. Although several of these alternatives were ultimately used, this paper deals specifically with immiscible WAG injection.
|File Size||648 KB||Number of Pages||8|