Performance and Operation of the Hamm Minnelusa Sand Unit, Campbell County, Wyoming
- T.E. Doll (Tiorco Inc.) | M.T. Hanson (Home Petroleum Corp. Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1987
- Document Type
- Journal Paper
- 1,565 - 1,570
- 1987. Society of Petroleum Engineers
- 5.4.1 Waterflooding, 5.6.5 Tracers, 5.3.2 Multiphase Flow, 4.1.5 Processing Equipment, 5.7.2 Recovery Factors, 1.2.3 Rock properties, 4.1.2 Separation and Treating, 1.14 Casing and Cementing, 4.1.9 Tanks and storage systems, 1.6 Drilling Operations, 6.5.2 Water use, produced water discharge and disposal, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 5.2 Reservoir Fluid Dynamics, 2.4.3 Sand/Solids Control
- 0 in the last 30 days
- 150 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
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).
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.
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.
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.
|File Size||376 KB||Number of Pages||6|