Oil recovery experiments using Bacillus licheniformis JF-2 (ATCC 39307) and a sucrose-based nutrient were performed with Berea sandstone cores (permeability 0.084 to 0.503 "m [85 to 510 md]). Oil recovery efficiencies for four different crude oils (0.9396 to 0.8343 g/cm3 [19.1 to 38.1 ° API]) varied from 2.8% to 42.6% of the waterflood residual oil. Microbial systems reduced interfacial tension (IFT) ... 20 rnN/m [ ... 20 dyne/cm] for all oils tested. After the microbial flood experimentation, organisms were distributed throughout the core, with most cells near the outlet.

The secondary recovery processes of waterflooding and polymer flooding commonly used in the Minnelusa formation are compared. Flood efficiency is improved using polymer technology. Less water is injected and less water produced to recover a barrel of oil. Flood life is shortened. Results of the Simpson Ranch polymer flood show that investment in polymer technology is profitable. Introduction The first significant Minnelusa production in the northeastern Powder River Basin was discovered by True Oil Company in March, 1957 in the Donkey Creek Field. The discovery well, Burrows B-6, flowed 31 deg. API black oil at the rate of 28 BBLS per hour from a 20 foot section in the top of the Minnelusa. Little did True Oil Company know, that t heir discovery would spur extensive development of the Minnelusa formation in the Powder River Basin. Development continues with several new reservoirs discovered in 1983. Located in the northeast portion of the Powder River Basin (Figure 1), the Minnelusa trend is mainly east of Gillette, Wyoming, running both north and south. "Minnelusa" is a Sioux Indian name for "rapid water." The formation outcrops at Rapid River, miles above Rapid City, South Dakota in the Black Hills. Minnelusa, or "rapid water" is an appropriate name for the formation where waterflooding is a common and successfully practice for increasing oil recovery. Technology to improve volumetric sweep is also widely used in the Minnelusa. This paper compares the performance of straight waterfloods with polymer augmented processes in the Minnelusa. The polymer augmented processes in the Minnelusa. The efficiency of the flooding process is examined to determine if benefits are gained by utilizing polymer flooding technology. Data from 35 reservoirs is studied. The Simpson Ranch Unit, an on-going polymer flood, is reviewed to show the incremental benefits gained by applying volumetric sweep improvement technology. MINNELUSA GEOLOGY The Minnelusa formation is a white crystalline sandstone, very dolomitic and anhydritic, of Pennsylvanian and Lower Permian age. Two producing Pennsylvanian and Lower Permian age. Two producing zones ("A" and "B") usually exist in the Upper Minnelusa formation. The "B" sand is the more predominant of the two Minnelusa reservoirs, and generally thins from the southwest to the northeast. Sand "A", which is the Upper bench, generally thins from the south to north and west to east. The "A" sand, where present, generally has the better reservoir characteristics. A third major sand ("C") immediately below the "B" is separated by alternating intervals of dolomites and anhydrites, and is usually "wet". The three sand consist of shallow marine and eolian sandstone, carbonates and evaporites. The top zone is an erosion surface overlain by impervious red shale of the Opeche formation. Trapping of Minnelusa oil accumulations is due to the following factors;Post Minnelusa topography in the up-dip presence of relatively deep valleys parallel to the structural strike filled with impermeable Opeche shale.Up-dip porosity/permeability pinchouts.Structural closure.Combinations of the three. Most of the active fields show both truncation and differential sand deposition on an uneven existing topography. RESERVOIR CHARACTERISTICS Minnelusa rock is a fine-grained sandstone with an average porosity of 16.2%. The formation contains little clay and is loosely cemented by carbonate and anhydrite. The average permeability ranges from 50 to 647 millidarcies. Dykstra Parsons permeability coefficients from 15 Minnelusa reservoirs give an average variance of 0.75. Depths vary from 7000 feet to 11000 feet with reservoir temperatures ranging from 120 deg. to 250 deg. F. Pertinent well data for 159 Minnelusa producers shows an average connate water saturation of 25.5% and an average pay thickness of 29.3 feet. p. 347

The Moorcroft West Minnelusa Sand Unit is a confined reservoir that provides an ideal setting for evaluation of EOR technologies because there is minimal opportunity for off pattern operations to influence interpretation of results. The unit initially represented a marginal waterflood prospect with two wells (40 acre spacing) in the reservoir producing a total of 4 BOPD. Although unsupported by geological analysis, reservoir engineering. and fluid analysis suggested strongly that the two wells were producing from a common 805 ac-ft reservoir. Oil recovery and cash flow projections indicated that if the reservoir would respond to water injection, a polymer augmented process would markedly increase recovery. Design and installation of a multipurpose waterflood plant was staged to keep monetary investment and risk at a minimum until communication between the wells was demonstrated. In August, 1989, oil production increased from 3 to 6 BOPD demonstrating well communication. Thereafter, a skid-mounted water injection plant containing a dry solids feed system, liquid chemical storage and proportioning equipment, and a small triplex pump was installed. Polymer injection for volumetric sweep improvement was started in October 1989. An alkaline/polymer (A/P) process designed to reduce residual oil saturation was initiated in September 1991.

This report covers research results for FY 1990 for the microbial enhanced oil , recovery (MEOR) and wettabilityresearch program conducted by EG&G Idaho, Inc.