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.

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.

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.

Even in times of renewable energy revolution fossil fuels will play a major role in energy supply, transportation, and chemical industry. Therefore, increasing demand for crude oil will still have to be met in the next decades by developing new oil re-serves. To cope with this challenge, companies and researchers are constantly seeking for new methods to increase the recovery factor of oil fields. For that reason, many enhanced oil recovery (EOR) methods have been developed and applied in the field. EOR methods alter the physico-chemical conditions inside the reservoir. One possibility to achieve this is to inject an aqueous solution containing special chemicals into the oil-bearing zone. Polymers, for example, increase the viscosity of the injected water and hence improve the displacement of the oil to the production well. The injection of surfactant solutions results in reduced capillary forces, which retain the oil in the pores of the reservoir. Some surfactants form viscoelastic solutions under certain conditions. The possibil-ity to apply those solutions for enhanced oil recovery has been investigated by some authors in the last years in low salinity brines. Reservoir brines, however, often contain high salt concentrations, which have detrimental effects on the properties of many chemical solutions applied for EOR operations. The Triphenoxymethane derivatives, which were the subject of study in this thesis, form viscoelastic solutions even in highly saline brines. The aim of this thesis was to investigate the efficiency and the mode-of-action of this new class of chemical EOR molecules with respect to oil mobilization in porous media.

This paper establishes Low-Tension-Gas (LTG) as a method for sub-miscible tertiary recovery in tight sandstone and carbonate reservoirs. The LTG process involves the use of a low foam quality surfactant-gas solution to mobilize and then displace residual crude after waterflood. It replicates the existing Alkali-Surfactant-Polymer (ASP) process in its creation of an ultra-low oil-water interfacial tension (IFT) environment for oil mobilization, but instead supplements the use of foam over polymer for mobility control. By replacing polymer with foam, chemical Enhanced Oil Recovery (EOR) methods can be expanded into sub-30 mD formations where polymer is impractical due to plugging, shear, or the requirement to use a low molecular weight polymer. Overall results indicate favorable mobilization and displacement of residual crude oil in both tight carbonate and tight sandstone reservoirs. Tertiary recovery of 75-95% ROIP was achieved for cores with 2-15 mD permeability, with similar oil bank and other ASP analogous process attributes observed. Moreover, similar recovery was achieved during testing at high initial oil saturation (56%), indicating high process tolerance to oil saturation and potential application for implementation at secondary recovery. In addition, a number of tools and relations were developed to improve the predictive relationship between observed coreflood properties and actual mobilization or displacement mechanisms which impact reservoir-scale flooding. These relations include qualitative dispersion comparison and calculation of in-situ gas saturation, macroscopic mobility ratio at the displacement fronts, and apparent viscosity of injected fluids. These tools were validated through use of reference gas and surfactant floods and indicate that stable macroscopic displacement can be achieved through LTG flooding in tight formations. Furthermore, to better reflect actual reservoir conditions where localized fractional flow of gas can vary substantially depending on mixing or gravity phenomenon, two additional sets of data were developed to empirically model behavior. Through testing of LTG co-injection at a number of discrete fractional flow values over a wide range, recovery was shown to achieve a relative maximum at 50% gas fractional flow which also corresponded with optimal observed mobility control as measured by the previously established tools. Likewise, through testing of surfactant-alternating-gas (SAG) injection cycling, displacement and overall recovery were shown to be improved versus reference co-injection flooding. Finally, by comparing the observed displacement and mobility data among co-injection and surfactant-alternating-gas floods, a new displacement mechanism is introduced to better relate actual displacement conditions with observed macroscopic mobility data. This mechanism emphasizes the role of liquid rate in actual displacement processes and a mostly static gas saturation (independent of gas rate) in altering liquid relative permeability and diverting injected liquid into lower permeability zones. / text

The purpose of this work was to study polymer degradation mechanisms as well as ways to mitigate it. In the area of chemical stability, defined as divalent cation tolerance of acrylic polymers as hydrolysis increases, use of the n-vinyl pyrrolidone (NVP) monomer helps to preserve viscosity and tolerate higher calcium concentrations over those polymers without NVP. Also, ethylenediaminetetraacetate tetrasodium salt (EDTA-Na+4) is shown to sequester calcium ions at alkaline conditions (pH>10) and, in the case of lab-aged post-hydrolyzed poly(AM-co-AMPS), helps to retain full viscosity at all calcium concentrations when EDTA is present at a stoichiometric equivalence of calcium. Many discrepancies exist in the literature concerning the presence or absence of degradation under various field or laboratory conditions. Carbonate and bicarbonate, which are typically present in natural waters but often neglected in lab-prepared brines, prove to be a hidden variable in resolving why Shupe (1981) saw no loss in viscosity when sodium dithionite was added to polymer in the presence of oxygen (with bicarbonates) but others (Knight, 1973 and Levitt and Pope, 2008) observed severe degradation under similar conditions (but without bicarbonates). A commercial HPAM polymer (Flopaam 3630S) has been shown to be stable in the presence of ferrous iron in the absence of oxygen, clarifying an apparent discrepancy in the literature between the results of Yang and Treiber (1985) and Kheradmand (1987). Dissolved oxygen (DO) levels, and not redox potential (ORP) measurements, are often reported in polymer stability research on oxidative degradation. ORP is shown to be a better measure of the onset of degradation because oxygen is initially being consumed and may not appear until substantial degradation has occurred. Although generally believed to be a detriment to polymer stability in the field, aeration of iron-laden source water prior to hydration of polymer may be beneficial in certain cases where exposure to air in unavoidable. Also, a novel process of safely producing sodium dithionite in the field proves to perform better in terms of long-term polymer stability in anaerobic conditions than the traditional method of using a solution made from powder dithionite. Finally, a pre-sheared 5 million Dalton HPAM is successfully injected into a 3 mD carbonate reservoir core plug. Remarkably, permeability reduction factors remain at values close to unity. However, pressure data from ASP tertiary corefloods suggest that polymer is not feasible for field injections. / text