Biological sequestration of carbon dioxide (CO2) in geological formations is one of the proposed methods to reduce the carbon dioxide released into the atmosphere. In this method, an enzyme is used to enhance the hydration and subsequent precipitation of CO2. In the present work, the effect of bovine carbonic anhydrase on the hydration of CO2, and its precipitation in the form of calcium carbonate, was studied. The enzyme enhanced the hydration reaction. The rate of hydration reaction increased with both the enzyme concentration and temperature. The precipitation of calcium carbonate was promoted in the presence of the enzyme. The concentration of the enzyme did not affect the precipitation; however, temperature impacted the precipitation of calcium carbonate. At higher temperatures, less calcium carbonate was formed. Also, in the presence of the enzyme, calcium carbonate settled more quickly. The enzyme activity was not influenced by the pH of the reaction mixture. In contrast, the formation of calcium carbonate was affected by the pH of the solution. A kinetic analysis was performed for the bovine carbonic anhydrase. Based on the experimental results, the activation energy and catalytic rate constant are estimated as 700.91 cal/mol and 0.65 s-1, respectively.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFor heavy oil reservoirs, the oil viscosity usually varies dramatically during production processes, such as thermal process or solvent injection. This paper presents an investigation of the effect of oil viscosity on relative permeability curves for heavy oil-water systems. Unsteadystate displacement tests were conducted in sandpacks under a typical injection flow rate in a heavy oil recovery process. A series of crude oils with a wide range of viscosities were used in the measurements. Large pore volumes of water were injected to minimize the errors caused by the extrapolation of the recovery data. History matching was used to obtain the relative permeability curves, in which capillary pressure was included. It was found that, for the same injection flow rate, heavy oil-water relative permeability curves systematically shifted with oil viscosity. With increasing oil viscosity, the residual oil saturation increased and the oil and water relative permeabilities decreased at the higher water saturation range. Irreducible water saturation tended to decrease with increasing oil viscosity. Micromodel experiments were conducted to visually investigate the difference in the flow behaviour between heavy oil-water and light oil-water systems. Interacting capillary bundle models were used to analyze the impact of oil viscosity on the residual oil saturation. This work aids in the laboratory measurement and determination of the representative relative permeability curves for heavy oil-water systems, as well as in the proper use of relative permeability curves in reservoir simulation for heavy oil development.

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Reducing the mobility of carbon dioxide through co-injection of CO2 and a suitable surfactant solution to form a CO2-foam system is a promising method for improving the oil recovery in carbon dioxide flooding projects. This paper presents the results of a set of experiments on screening and selecting a suitable surfactant for CO2 -foam purposes in a carbonate porous medium, as well as the effect of various parameters on the mobility of the CO2-foam system. Four surfactants were examined and the one that performed best throughout the screening experiments was used in the subsequent flow experiments. The surfactants tested were Surfonic N- 95, Surfonic L24–9, Bio-Terge AS-40, and Chaser CD-1045. The screening criterion selected was the fall in foam height with time at 60 ° C for 0.1 wt% solution of the above mentioned surfactants. Chaser CD-1045 performed best in all screening tests and was used during the flow experiments. Flow experiments were conducted through a porous medium made of crushed carbonate at pressures of 8,270 kPa and 10,336 kPa, and temperatures of 22 ° C and 50 ° C. Mobility of CO2 -brine (simulating the WAG process) and CO2-surfactant systems were compared through a series of experiments. The effect of operating pressure and temperature, brine concentration, and the ratio of the amount of CO2 to total foam (i.e., foam quality) on the mobility of a CO2-foam system were investigated and results are presented. The results indicate that additional oil is recoverable for CO2-foam vs. the co-injection of CO2 and brine simulating the WAG process. Introduction From the pore-scale point of view, dense carbon dioxide is an ideal displacement fluid for many crude oils because it can achieve miscibility with oil through a multi-contact miscibility process under the pressure and temperature conditions of a wide range of reservoirs. However, even when pressure conditions for miscibility are met, this high microscopic sweep efficiency is not often approached in reservoir operations due to the non-uniformity of the flow patterns. Large-scale reservoir heterogeneities, such as fractures or high-permeability streaks, cause early breakthrough of injected carbon dioxide, which will reduce oil recovery efficiency. One effective way of increasing the ultimate oil recovery under CO2 flooding conditions is by reducing the mobility of the injected carbon dioxide. The most common method for achieving this goal is through the injection of slugs of CO2 and water alternatively (i.e., the WAG process). During the WAG process, water reduces the mobility of carbon dioxide; but it also traps oil, increases water flow, and decreases extraction of hydrocarbons from oil by carbon dioxide(1). Another method for reducing the mobility of carbon dioxide is the CO2-foam technique. In this method, a surfactant solution is injected along with carbon dioxide into the reservoir. This combination forms foam in the reservoir, and the presence of foam reduces the mobility of carbon dioxide considerably. However, for any CO2 -foam project, there are challenges that must be met.