along with nutrients into a reservoir. He asserted that the spores would germinate in the reservoir and enhance removal of oil from reservoir rock. The hypothesis was tested in the laboratory by using an oil-saturated sandpacked column. An aqueous solution containing spores of Clostridium roseum and molasses was passed through the column and an improved release of oil (about 30%) was obtained.
Later patents by Hitzman concern the use of microorganisms that feed on injected polymers and the byproducts of CO2 floods, to produce chemicals for EOR, i.e. gases, acids, solvents, and surfactants (20). In polymer floods the injected organisms feed on polymer that was adsorbed on the reservoir rock. In CO2 floods, the microbes feed on soluble compounds of carbon, nitrogen, and sulfur left behind the CO2-crude oil slug. The process has mobilized residual oil in sandpack tests but no core or field tests are reported.
Knapp et al. (21) reported the isolation of 22 microorganisms that produce biopolymers and emulsifiers. One strain was isolated that grew in 10% salt concentrations, over a pH range of 4.6 to 9.0, at temperatures up to 50 °C, and in the presence of crude oil. They demonstrated in the laboratory that glucose, ammonium sulfate, and potassium phosphate were easily transported through sandstone cores. Viable bacterial cells in aqueous solutions of 2% NaCl and 0.01% CaCl2 injected into these cores were not recovered in the effluent. The addition of glucose to cores previously inoculated with bacteria resulted in a significant decrease in permeability, indicating that bacteria were multiplying and plugging the pores. Bacteria indigenous to all of the cores treated were Pseudomonas sp., Bacillus sp., and Actinomycetes. A major problem in these experiments was in determining how much of the plugging was caused by
injected bacteria and how much by indigenous bacteria. The problem persisted even when cores were steam-cleaned and autoclaved. "Sterilization" of cores with chlorine dioxide diminished the problem, but the bacterial 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,