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A model for the evaluation of CO2-EOR projects has been developed. This model includes both reservoir simulation to handle reservoir properties, fluid flow and injection and production schedules, and a numerical economic model that generates a monthly cash flow stream from the outputs of the reservoir model. This model is general enough to be used with any project and provide a solid common basis to all of them. This model was used to evaluate CO2-EOR injection and production strategies and develop an optimization workflow. Producer constraints (maximum oil and gas production rates) should be optimized first to generate a reference case. Further improvements can then be obtained by optimizing the injection starting date and the injection plateau rate. Investigation of sensitivity of CO2-EOR to the presence of an aquifer showed that CO2 injection can limit water influx in the reservoir and is beneficial to recovery, even with a strong water drive. The influence of some key parameters was evaluated: the producer should be completed in the top part of the reservoir, while the injector should be completed over the entire thickness; it is recommended but not mandatory that the injection should start as early as possible to allow for lower water cut limit. Finally, the sensitivity of the economics of the projects to some key parameters was evaluated. The most influent parameter is by far the oil price, but other parameters such as the CO2 source to field distance, the pipeline cost scenario, the CO2 source type or the CO2 market price have roughly the same influence. It is therefore possible to offset an increase of one of them by reducing another.

Injection of low-salinity water showed high potentials in improving oil recovery when compared to high-salinity water. However, the optimum water salinity and conditions are uncertain, due to the lack of understanding the mechanisms of fluid-rock interactions. The main objective of this study is to examine the potential and efficiency of low-salinity water in secondary and tertiary oil recovery for sandstone reservoirs. Similarly, this study aims to help in understanding the dominant mechanisms that aid in improving oil recovery by low-salinity waterflooding. Furthermore, the impact of cation type in injected brines on oil recovery was investigated. Coreflood experiments were conducted to determine the effect of water salinity and chemistry on oil recovery in the secondary and tertiary modes. The contact angle technique was used to study the impact of water salinity and composition on rock wettability. Moreover, the zeta potential at oil/brine and brine/rock interfaces was measured to explain the mechanism causing rock wettability alteration and improving oil recovery. Deionized water and different brines (from 500 to 174,000 mg/l), as well as single cation solutions were tested. Two types of crude oil with different properties and composition were used. Berea sandstone cores were utilized in the coreflood experiments. Coreflood tests indicated that injection of deionized water in the secondary mode resulted in significant oil recovery, up to 22% improvement, compared to seawater flooding. However, no more oil was recovered in the tertiary mode. In addition, injection of NaCl solution increased the oil recovery compared to injection of CaCl2 or MgCl2 at the same concentration. Contact angle results demonstrated that low-salinity water has an impact on the rock wettability; the more reduction in water salinity, the more a water-wet rock surface is produced. In addition, NaCl solutions made the rock more water-wet compared to CaCl2 or MgCl2 at the same concentration. Low-salinity water and NaCl solutions showed a highly negative charge at rock/brine and oil/brine interfaces by zeta potential measurements, which results in greater repulsive forces between the oil and rock surface. This leads to double-layer expansion and water-wet systems. These results demonstrate that the double-layer expansion is a primary mechanism of improving oil recovery when water chemical composition is manipulated.

Certain strains of hydrophobic bacteria are known to play critical roles in petroleum-related applications. The aim of this study was to investigate how hydrophobic bacteria in their stationary phase could adsorb onto the hexadecane-water interface and alter its mechanical properties. The two strains of bacteria used in forming the interfacial films were Acinetobacter venetianus RAG-1 (a Gram-negative bacterium) and Rhodococcus erythropolis 20S-E1-c (Gram-positive). Experiments at two different length scales (millimetre and micrometre) were conducted and the results were compared. In addition, a simple flow experiment was designed in a constricted channel and the results were related to the intrinsic mechanical properties of bacteria-adsorbed films. On the millimetre scale, using the pendant drop technique, the film interfacial tension was monitored as the surface area was made to undergo changes. Under static conditions, both types of bacteria showed no significant effect on the interfacial tension. When subjected to transient excitations, the two bacterial films exhibited qualitatively similar, yet quantitative distinct rheological properties (including film elasticities and relaxation times). Under continuous reduction of surface area, the RAG-1 system showed a “paper-like” interface, while the interface of the 20S-E1-c system was “soap film-like.” These macroscopic observations could be explained by the surface ultrastructures of the two cell strains. On the micrometre scale, using the micropipette technique, colloidal stability of the bacteria-coated oil droplets was examined through direct-contact experiments. Both types of bacteria were seen to function as effective stabilizers. In addition, the adsorbed bacteria also interacted with one another at the interface, giving rise to higher order 2-D rheological properties. A technique of directly probing the mechanical properties of the emulsion drop surfaces revealed that (a) the films behaved as purely elastic sheets, and (b) with a reduction in cell concentration in the aqueous phase, less oil was emulsified, but the elastic moduli of the adsorbed films remained unchanged. These results are in contrast to the above millimetre-scale study. Therefore the rheological properties of these bacteria-adsorbed films appear to be length scale-dependent. An oil displacement experiment was designed to investigate the flow behaviour of micron-scale emulsion drops in a constricted channel. The qualitative results can be correlated with the interfacial rheological properties and may have valuable relevance to the study of multiphase flow through constricted channels in porous rocks (e.g. in MEOR operations). / Chemical Engineering

Thesis (Ph. D.)--University of Wyoming, 2005. / Title from PDF title page (viewed on Nov. 1, 2007). Includes bibliographical references (p. 179-192).

Thesis (M.S.)--West Virginia University, 2005. / Title from document title page. Document formatted into pages; contains ix, 153 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 151-153).

Thesis (Ph.D.)--University of Wyoming, 2008. / Title from PDF title page (viewed on June 24, 2009). Includes bibliographical references (p. 120-127).

Thesis (Ph. D.)--University of Texas at Austin, 1998. / Vita. Includes bibliographical references (leaves 204-213). Available also in a digital version from Dissertation Abstracts.

Finding a viable method to recover oil from the corn ethanol industry's co-products has considerable economic prospects for ethanol bio-refineries. This study examined the effects of enzymes and ethanol on oil recovery from dried distillers' grains with solubles (DDGS) and oil distribution in the whole stillage (WS). Protease and cellulase enzymes were tested either individually or in combination with the heavier fractions of DDGS and resulted in 18-20% more oil than the original DDGS. More than 90% of the oil was recovered from the heavier fraction of DDGS using ethanol at 30ºC with 30% solid loadings. Ethanol addition also improved oil partition in WS's liquid fraction by 17–20%. Overall, enzymes and ethanol treatments showed a positive effect on oil recovery from DDGS and WS. Ethanol bio-refineries may use these findings to recover oil as no significant changes are required in the ethanol plant's design.