The Planning of a Large-Scale Miscible Flood at Prudhoe Bay

Williamson, A.S.; Gondouin, M.; Pavlas, Emmerick Joe; Olson, Jon E.; Schnell, L.W.; Bowen, R.R.

doi:10.2118/13600-pa

Cited by 12 publications

(5 citation statements)

References 4 publications

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“…All treatments were conducted at high pressure conditions . The following foam treatments tests were reviewed: a) Prudhoe Bay 34,35 ; b) Husky Oil 36 , c) Oseberg 37 ; d) UK North Sea 38 and e) Snorre Field 39--40 . It was clearly seen that a pre-formed foam performed better than a SAG foam.…”

Section: Cssmentioning

confidence: 99%

Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects

Turta¹,

Singhal²

2002

Journal of Canadian Petroleum Technology

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An in-depth analysis covering over forty foam applications in Enhanced Oil Recovery (EOR) projects and numerous production well treatment operations was conducted, to obtain insights on screening and design of such applications. Foam can be used to solve conformance problems caused by either a thief zone or gravity override; proper identification of the cause, as well as of the affected production well(s) is basic to definition of the problem. Either blocking/diverting foams or in-depth mobility control foams can be placed through the injection wells. On the other hand, foam is placed in production wells mainly to mitigate an override problem.The most important factors in foam assisted EOR projects are: (a) manner of foam placement in the reservoir (injection of pre-formed foam, co-injection foam and SAG or surfactant alternating gas foam), (b) reservoir pressure and c) permeability. While pre-formed foams are effective in the treatment of production wells, co-injection foam and SAG foam can be employed for solving specific sweep problems. For designing a steam-foam project (which is a low pressure foam application), foam quality in the range 45% to 80% should be considered. In this application, a co-injection foam is employed and the additives (surfactant and non-condensable gas) are injected intermittently (on and off), superimposed on a continuous steam injection. Injection cycles as short as 7 days are common. Under suitable conditions, an oil rate increase of 1.5 to 5 times, a decrease in water cut by 20 %, and an incremental oil recovery of 6%-12% OOIP can be achieved with this implementation. At high pressure, such as in gas miscible flooding, foam application can result in excessive mobility reduction factors, and injectivity reduction. Due to this reason, in these projects, alternate injection of surfactant solution and gas (SAG foam) is favoured over a coinjection mode of placement. Low Pressure Foam Application: Steam Drive.Out of 19 projects reviewed, 14 were in the Midway Sunset and Kern River fields in California 12-16 , where the reservoirs are shallow, with good porosity and permeability. Oil viscosity is between 1000 and 4000 mPa.s. Surfactant was injected along with a low pressure (0.7-3.5 MPa) steam injection to solve overriding problems. Patterns areas were in the range 0.5-4 ha, and at the time of foam injection, the steam drive was quite mature, having been in progress for 5 to 10 years, with a current oil recovery in the range of 30% to 60% OOIP. The most commonly employed surfactants were Chaser SD and Suntech injected at concentrations in the range of

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Section: Cssmentioning

confidence: 99%

Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects

Turta¹,

Singhal²

2002

Journal of Canadian Petroleum Technology

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“…A large scale miscible WAG injection project (Williamson et al 1986) (PBMGP) was initiated in 1987 in the peripheral waterflood areas of Prudhoe Bay, which contain 6.4 BSTB (1.02 = 109 m3) OOIP. Miscible flooding currently occurs in 90 patterns, with plans to expand to most of the remaining waterflood patterns.…”

Section: Flow Station Twomentioning

confidence: 99%

“…Early models represented discontinuous shales by reducing the effective KJK~ of the sand matrix, and not as explicit vertical permeability barriers (Williamson et al 1986;Nitzberg et al 1990;Dawson 1989 et al ).…”

Section: Reservoir Simulation Modellingmentioning

confidence: 99%

Prudhoe Bay: infill drilling in gravity dominated WAG floods

Wilcox

Polzin

Kuo

et al. 1995

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Many horizontal miscible gas floods experience relatively low vertical sweep efficiency due to gravity segregation of the injected solvent and reservoir liquids. This is true for the Prudhoe Bay Miscible Gas Project (PBMGP) in which the enriched-hydrocarbon miscible injectant (MI) is expected to sweep only approximately 30% of the reservoir volume in the project areas. The Prudhoe Bay reservoir has a relatively thick oil column, high inter-sand vertical permeability, high net-gross, and is generally developed on 80 acre (324 = 103 m2) well spacing.An infill drilling project was implemented in the Northwest Fault Block (NWFB) area of Prudhoe Bay (Fig. 1) to improve solvent sweep efficiency and increase EOR reserves. This project differs from many EOR infill drilling projects in that most of the additional recovery is attributable to EOR, with minimal improvement in waterflood recovery.The infill project is feasible because the reservoir is relatively thick, and sufficient EOR reserves are obtained from miscible displacement around new injectors. A significant increase in flood rate can also occur, resulting in production acceleration. Results of the project will guide analysis of infill drilling in other EOR areas at Prudhoe. The Prudhoe Bay Miscible Gas Project is the world's largest enriched-hydrocarbon miscible gas flood, and is located in northern Alaska, USA.

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“…(Ref. 10,11,12) The latest certification covers the entire waterflood area including prospective waterflood expansion targets adjacent to the current floods. Ultimately more than 130 injectors may be converted to water-alternating-gas (WAG) injectors.…”

Section: Waterflood Developmentmentioning

confidence: 99%

Prudhoe Bay: Development History and Future Potential

Szabo¹,

Meyers²

1993

Proceedings of SPE Western Regional Meeting

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Prudhoe Bay Field is the largest producing field in North America. Prudhoe Bay is currently 'expected to yield at least 25% more reserves than estimated at field start up. This paper briefly describes the history of the field and some of the key developments that have taken place which have contributed to imprOVed recovery efficiency. These incremental developments have resulted from a process of continuous surveillance, interpretation of field performance, management of multiple reservoir mechanisms, efficient utilization of the gas resource, and exploitation of the existing field infrastructure.

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The Planning of a Large-Scale Miscible Flood at Prudhoe Bay

Cited by 12 publications

References 4 publications

Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects

Field Foam Applications in Enhanced Oil Recovery Projects: Screening and Design Aspects

Prudhoe Bay: infill drilling in gravity dominated WAG floods

Prudhoe Bay: Development History and Future Potential

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