cterial populations returned at 48 hr incubation.
Jack et al. (22) considered that emulsification of viscous crude oil in situ is not feasible because of the problems in transporting the bacteria through the reservoir rock.
Yarbrough and Coty (23) recently reported on a field test they performed in 1954 in Arkansas. A 2% solution of beet molasses in fresh water was injected during a 6-month period, along with 18 200-gal containers of broth containing Clostridium acetobutylicum. Freshwater breakthrough occurred at the production well 70 days after injection started. Fermentation products (short-chain fatty acids, CO2, and traces of ethanol, 1-butanol, and acetone) and sugars appeared 80 to 90 days after the injection started. No increase in hydrogen content was noted. Production of oil increased from 0.6 bbl/day to 2.1 bbl/day. The experiment was considered successful, but no further field tests were conducted.
Bond (24) injected 5,000 gal of 290 agar gel agent medium containing sand and Desulfovibrio hydrocarbonoclasticus (no longer a valid species) into a sandstone reservoir at a depth of 3,000 ft. Prior to the injection, the well produced 15 bbl/day. After the injection, the well was shut in for 3 months to allow the bacteria to act. When the well was placed back on production, it produced 25 bbl/day.
Johnson (25) injected 150 stripper wells in the U.S. that produced, on an average, 2 bbl/day, with no wellhead pressure. The reservoir porosities were 10 to 30%, depths 200 to 1,000 ft, with an average reservoir temperature of 38 °C. The work was done during the years 1977-81. The inoculum was 1 to 10 gal of a mixed culture of Bacillus and Clostridium spp. (non-hydrocarbon-utilizing) with crude molasses and mineral salts. In the typical situation, the bacterial inoculum required 10 to 14 days to adequately multiply within the treated area of the reservoir. The results varied, but in suitable reservoirs, 20 to 30% additional oil-in-place was recovered. These suitable conditions include oil of 15 to 30° API gravity, formation water of less than 10 x 104 ppm salt content, preferably a carbonate reservoir, and a temperature of approximately 38 °C.
Petrogen, Inc. did some preliminary field testing with 24 wells during 1977-82. Wells varied in depth from 300 to 4,600 ft. Some 75% of the wells showed a pressure increase of 10 to 200 psi. The type of microbial or nutrient injectant was not defined. Four wells doubled production for 6 months, and 12 increased production by 50% for 3 months. The production increase was indicated to average 42%; however, the final results remain to be reported (26).
The first MEOR project in the Rocky Mountains was initiated in 1983 (27). An independent oil operator purchased three field service operations from Petroleum Bio-Resources Company. These were (a) a reservoir field conditioning system to avoid plugging; (b) use of a microorganism that produces gas and surfactant; and (c) use of a microorganism that produces a polysaccharide for mobility control. The most recent information regarding this field project indicated that production immediately doubled, which was attributed to well stimulation, whereas the remainder of the wells in the field increased from 26 to 60 bbl/day, which was considered due to mobilization of oil by microorganisms and waterflooding (28).
Microbial flooding is being tested for oil recovery in an oil field near Nowata, Oklahoma, by NIPER, the U.S. Department of Energy, and two industrial paticipants (29). A microbially enhanced waterflood is being implemented in a field that has been waterflooded for more than 35 years and in a lease where the average oil production per well is currently 0.4 bbl/day. This microbial waterflood test is a carefully monitored field experiment, and should provide much needed documentation and information for future MEOR testing. Laboratory compatibility testing and coreflooding studies were done to optimize microbial formulations for this test (30, 31, 32).
Bryant and Douglas (30) have demonstrated the oil recovery efficiency of several differ