Performance and Economics of Minnelusa Polymer Floods

Mack, James C.; Duvall, M.L.

doi:10.2118/12929-ms

Cited by 19 publications

(7 citation statements)

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“…This is analogous to many Minnelusa fields in the area which have exhibited performance leading to ultimate waterflood recoveries (primary plus secondary) of 40% OOlP. 2 Polymer mobility control flooding was evaluated as a method to improve sweep efficiency in the reservoir. This method is expected to produce the same amount of crude oil as waterflooding, but in less time and with less pore volumes of injected fluid.…”

Section: Geologymentioning

confidence: 99%

Design and Application of an Alkaline-Surfactant-Polymer Recovery System for the West Kiehl Field

Clark¹,

Pitts²,

Smith³

1993

SPE Advanced Technology Series

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The West Kiehl Unit, Crook County, Wyoming produces from the Minnelusa Lower "B" Sand reservoir. Original oil in place (OOlP) is estimated at 238,481 m 3 . Estimated ultimate primary production is 27,028 m 3 or 11% OOlP. Four enhanced oil recovery methods were considered for application in this reservoir: conventional waterflood, polymer flood, an alkaline-polymer flood, and an alkalinesurfactant-polymer (ASP) flood.Estimated ultimate recoveries are 95,392 m 3 (40% OOlP), 95,392 m 3 (40% OOlP), 95,392 m 3 (40% OOlP), and 135,934 m 3 (56% OOIP), respectively. The polymer flood is expected to deplete the field faster than a conventional waterflood without an increase in ultimate recovery, while the ASP technology is expected to extend the field life and increase ultimate recovery dramatically. The ASP process has been implemented and early performance is very good.Two purposes are being served by implementation of the West Kiehl alkaline-surfactant-polymer flood. The rust is to recover additional oil not recoverable by a waterflood or a polymer flood. The second is to pilot this potentially significant enhanced oil recovery (EOR) technique for other Minnelusa reservoirs. If this method proves successful, it will represent a sizable increase in ultimate recovery with the incremental oil recovery ranging as high as 25% OOIP. This paper discusses the goal for utilizing the alkalinesurfactant-polymer technology at the West Kiehl. Further, it details the development of the West Kiehl Field project including laboratory studies, reservoir parameters, initial injection and production history, facilities design, and operations of the flood.

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Section: Geologymentioning

confidence: 99%

Design and Application of an Alkaline-Surfactant-Polymer Recovery System for the West Kiehl Field

Clark¹,

Pitts²,

Smith³

1993

SPE Advanced Technology Series

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“…Step 1: Estimate per-pattern HCPV. Mack and Duvall (1984) would yield a somewhat higher estimate of 85,052,000 rb.) Assuming that 80% of the total reservoir area will be covered with 80-acre patterns (our baseline maximum pattern size) the CO 2 flood will have pat-n‫ס‬ceil(0.8•2,975/80)‫03ס‬ terns.…”

Section: Appendixmentioning

confidence: 92%

“…Step 1: Estimate per-pattern HCPV. Mack and Duvall (1984) provide a direct estimate of RCM's OOIP, so we estimate HCPV for the reservoir as a whole as ‫ס‬ 81,169,000 rb.…”

Section: Appendixmentioning

confidence: 99%

The Economics of Enhanced Oil Recovery: Estimating Incremental Oil Supply and CO2 Demand in the Powder River Basin

Veld

Phillips²

2010

The Energy Journal

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Expanding the use of CO 2-enhanced oil recovery (EOR) promises to both significantly increase recovery from existing U.S. oil reserves and possibly form a bridge to large-scale CO 2 capture and sequestration. An important input into planning for such expansion are estimates of how both the supply of incremental oil and the derived CO 2 demand from EOR are likely to vary with the prices of oil and CO 2. We demonstrate how the "analog" method of predicting oil and CO 2 flows can be used to readily generate such estimates, and apply the method to Wyoming's Powder River Basin.

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“…Total oil-zone volume is 10,650 acre-ft [13.1 X 10 6 m 3 ] for 13.5 x 10 6 STB [2.15 X 10 6 stock-tank m 3 ] oil.…”

Section: Geologic and Reservoir Characteristicsmentioning

confidence: 99%

“…Waterflood predictions gave an additional recovery over primary recovery of3.5x 10 6 STB [556x 10 3 stock-tank m 3 ] …”

Section: Waterflood Performancementioning

confidence: 99%

Performance and Operation of the Hamm Minnelusa Sand Unit, Campbell County, Wyoming

Doll¹,

Hanson²

1987

Journal of Petroleum Technology

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Summary The Hamm Minnelusa Sand Unit was discovered in 1966 and produced from the Minnelusa B sand. The field was under fluid-expansion primary recovery until water injection began in Dec. 1972. Waterflood response peaked at a higher monthly rae than that of primary recovery. Water production indicated channeling through high-permeability zones. In Oct. 1975, a volumetric-sweep improvement program was initiated into the single-injection wellbore. Anionic polyacrylamide and aluminum citrate were injected to provide in-depth vertical conformance. A second well was converted to injection in April 1976, and sweep improvement started 26 months later. The third well was converted to injection and the chemical-oil-recovery program began in Aug. 1982. The first two injectors were converted to produce water disposal at that date. The polymeri-augmented waterflood was terminated in Jan. 1985. Water injection continues. This paper details flood performance up to July, 1985. Cumulative water injection is 76.6% of the total PV. A 39.5% PV chemical slug has been injected. Total recovery to date is 48.7% of the original oil in place (OOIP). Field Discovery The Hamm field is located in Sections 20 and 29, Township 51N, Range 69W, Campbell County, WY. The field was discovered during drilling of the Heptner No. 1–4229 in March 1966. Fig. 1 is a Minnelusa B sand net pay isopach base map for the Hamm Unit. Development of the field continued, resulting in four producing wells and four dry holes. Unitization became effective Dec. 1, 1972, and water injection started into Hamm No. 4 water injection well (WIW). Hamm No. 6 was drilled in Sept. 1975 to improve the waterflood pattern. Hamm No. 7 was drilled in Oct. 1975 as a western-boundary extension well, then was converted to injection in April 1976. Hamm No. 8 was drilled in Jan. 1977 as a northern boundary extension and to improve the waterflood pattern. The well was abandoned after stimulation failure. The unit currently has three producing wells - Hamm No. 1, Hamm No. 2, and Hamm No. 6 - and three injection wells - Hamm No. 4 WIW, Hamm No. 7 WIW, and Hamm No. 3 WIW. Geologic and Reservoir Characteristics The Minnelusa formation, Pennsylvanian Age, is a clean, fine-grained, moderately cemented sandstone. Throughout the Powder River basin, three reservoir zones may exist: from the youngest to the oldest, A, B, and C. At Hamm, the A zone is not present because of pre-Opeche truncation. The B sand reservoir is limited to the west and north by truncation of beds, to the east by loss of porosity from facies change, and downdip to the south by an oil/water contact (OWC). Table 1 presents rock and fluid properties.1 The permeability range from 1 to 3,000 md with a permeability variation of 0.76 indicates poor volumetric sweep. A mobility ratio of 17.3 adds to the potential for low recoveries with straight waterflood. The OOIP was determined volumetrically from the OWC, net pay isopach (porosity greater than 12%), and reservoir limits. Total oil-zone volume is 10,650 acre-ft [13.1×106 m3] for 13.5×106 STB [2.15×106 stock-tank m3] oil. Primary Performance The primary producing mechanism was fluid expansion. Fig. 2, the total-field-performance curve, indicates a primary decline rate of about 19% per year. The curve flattens, indicating the possibility of some water influx from the aquifer. Cumulative primary production to Dec. 1972 (unitization and initiation of waterflood) was 1,538,638 STB [245×103 stock-tank m3] oil or 11.4% of the OOIP. Waterflood Peformance In Dec. 1972, the Hamm Innelusa B reservoir was unitized. Waterflood predictions gave an additional recovery over primary recovery of 3.5×106 STB [556×103 stock-tank m3] oil or 26% of the OOIP.2 See Figs. 3 and 4. Waterflooding began during Dec. 1972 with water injection into Hamm No. 4. Hall slope averaged 0.61 psi-D/bbl [26.45 kPa·d/m3] injected. Water/oil ratio (WOR) increased from <0.02 to 0.75. Because water breakthrough in the Hamm No. 3 producer was severe, the well was shut in during Nov. 1976. Water cut increased at Hamm No. 1. A casing leak at Hamm No. 2 was repaired, eliminating extraneous water production. Two separate chemical tracer tests in March 1978 and Oct. 1980 confirmed rapid injected water movement from Hamm No. 4 WIW to the three remaining producing wellbores - Hamm No. 2, Hamm No. 6, and Hamm No. 1. See Figs. 5 through 10. Minnelusa Waterflood Comparisons On the basis of previously presented data,3 evaluation of 16 Minnelusa waterfloods indicated an average recovery of 35% of the OOIP. The cumulative WOR averaged 0.84, with an average cumulative injection/production ratio of 2.76. Average flood life was 76% PV or 14.3 years. Polymer Flood Design The chemical-oil-recovery program for the Hamm Minnelusa Sand Unit was designed to reduce the adverse permeability variation of 0.76 and to reduce the high mobility ratio of 17.3. Both result in premature water breakthrough and poor sweep efficiency if not reduced by sweep improvement. The polymer flood design incorporates two process technologies4 designed to reduce permeability variation: cationic/anionic polymer and in-situ gelling.2 Cationic polyacrylamide spearhead provides excellent adsorption/retention properties that enable it to enter high-permeability rock to provide an anchor for the anionic polyacrylamide. In-situ gelation provides in-depth permeability unification by building progressive layers of resistance to water flow in the formation because of the crosslinking with the anionic polymer.

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Performance and Economics of Minnelusa Polymer Floods

Cited by 19 publications

References 2 publications

Design and Application of an Alkaline-Surfactant-Polymer Recovery System for the West Kiehl Field

Design and Application of an Alkaline-Surfactant-Polymer Recovery System for the West Kiehl Field

The Economics of Enhanced Oil Recovery: Estimating Incremental Oil Supply and CO2 Demand in the Powder River Basin

Performance and Operation of the Hamm Minnelusa Sand Unit, Campbell County, Wyoming

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