Society's growing demands for energy results in rapid increase in oil consumption and motivates us to make unconventional resources conventional resources. There are enormous amounts of heavy oil reserves in the world but the lack of cost effective technologies either for extraction, transportation, or refinery upgrading hinders the development of heavy oil reserves. One of the critical problems with heavy oil and bitumen is that they require large amounts of thermal energy and expensive catalysts to upgrade. This thesis demonstrates that electron beam (E-Beam) heavy oil upgrading, which uses unique features of E-Beam irradiation, may be used to improve conventional heavy oil upgrading. E-Beam processing lowers the thermal energy requirements and could sharply reduce the investment in catalysts. The design of the facilities can be simpler and will contribute to lowering the costs of transporting and processing heavy oil and bitumen. E-Beam technology uses the high kinetic energy of fast electrons, which not only transfer their energy but also interact with hydrocarbons to break the heavy molecules with lower thermal energy. In this work, we conducted three major stages to evaluate the applicability of E-Beam for heavy oil upgrading. First, we conducted laboratory experiments to investigate the effects of E-Beam on hydrocarbons. To do so, we used a Van de Graff accelerator, which generates the high kinetic energy of electrons, and a laboratory scale apparatus to investigate extensively how radiation effects hydrocarbons. Second, we studied the energy transfer mechanism of E-Beam upgrading to optimize the process. Third, we conducted a preliminary economic analysis based on energy consumption and compared the economics of E-Beam upgrading with conventional upgrading. The results of our study are very encouraging. From the experiments we found that E-Beam effect on hydrocarbon is significant. We used less thermal energy for distillation of n-hexadecane (n-C16) and naphtha with E-Beam. The results of experiments with asphaltene indicate that E-Beam enhances the decomposition of heavy hydrocarbon molecules and improves the quality of upgraded hydrocarbon. From the study of energy transfer mechanism, we estimated heat loss, fluid movement, and radiation energy distribution during the reaction. The results of our economic evaluation show that E-Beam upgrading appears to be economically feasible in petroleum industry applications. These results indicate significant potential for the application of E-Beam technology throughout the petroleum industry, particularly near production facilities, transportation pipelines, and refining industry.

Steam Assisted Gravity Drainage (SAGD) is used widely as a thermal recovery technique in Canada to produce a very viscous bitumen formation. The main research objectives of this simulation and experimental study are to investigate oil recovery mechanisms under SAGD process with different injection fluids, including steam, solvent or steam with solvent. 2D simulation studies based on typical Athabasca reservoir properties have been performed. Results show that a successful solvent co-injection design can utilize the advantages of solvent and steam. There is an optimal solvent type and concentration ratio range for a particular reservoir and operating condition. Long, continuous shale barriers located vertically above or near the wellbore delay production performance significantly. Co-injecting a multi-component solvent can flush out the oil in different areas with different drainage mechanisms from vaporized and liquid components. Placing an additional injector at the top of the reservoir results only in marginal improvement. The pure high-temperature diluent injection appears feasible, although further technical and economic evaluation of the process is required. A 2D scaled physical model was fabricated that represented in cross-section a half symmetry element of a typical SAGD drainage volume in Athabasca. The experimental results show co-injecting a solvent mixture of C7 and xylene with steam gives better production performance than the injection of pure steam or steam with C7 at the study condition. Compared to pure steam injection runs ( Run 0 and 1), coinjecting C7 (Run 2) with steam increases the ultimate recovery factor of oil inside the cell from 25 percent to 29 percent and decreases the ultimate CSOR from 2.2 to 1.9 and the ultimate CEOR from 4892 J/cm 3 to 4326 J/cm 3 ; coinjecting C7 and Xylene (Run 3) increases the ultimate recovery factor of oil from 25 percent to 34 percent, and decreases the ultimate CSOR 2.2 to 1.6 and the ultimate CEOR from 4892 J/cm 3 to 3629 J/cm 3 . Analyses of the experimental results indicate that partial pressure and the near wellbore flow play important roles in production performance. In conclusion, a successful solvent injection design can effectively improve the production performance of SAGD. Further research on evaluating the performance of various hydrocarbon types as steam additives is desirable and recommended.

This study presents the results of nano-particle and surfactant-stabilized solvent-based emulsion core flooding studies under laboratory conditions that investigate the recovery mechanisms of chemical flooding in a heavy oil reservoir. In the study, bench tests, including the phase behavior test, rheology studies and interfacial tension measurement are performed and reported for the optimum selecting method for the nano-emulsion. Specifically, nano-emulsion systems with high viscosity have been injected into sandstone cores containing Alaska North Slope West Sak heavy oil with 16 API, which was dewatered in the laboratory condition. The experiment results suggest that the potential application of this kind of emulsion flooding is a promising EOR (enhanced oil recovery) process for some heavy oil reservoirs in Alaska, Canada and Venezuela after primary production. Heavy oil lacks mobility under reservoir conditions and is not suitable for the application of the thermal recovery method because of environmental issues or technical problems. Core flooding experiments were performed on cores with varied permeabilities. Comparisons between direct injection of nano-emulsion systems and nano-emulsion injections after water flooding were conducted. Oil recovery information is obtained by material balance calculation. In this study, we try to combine the advantages of solvent, surfactant, and nano-particles together. As we know, pure miscible solvent used as an injection fluid in developing the heavy oil reservoir does have the desirable recovery feature, however it is not economical. The idea of nano-particle application in an EOR area has been recently raised by researchers who are interested in its feature-reaction catalysis-which could reduce in situ oil viscosity and generate emulsion without surfactant. Also, the nano-particle stabilized emulsions can long-distance drive oil in the reservoir, since the nano-particle size is 2-4 times smaller than the pore throat. In conclusion, the nano-emulsion flooding can be an effective enhancement for an oil recovery method for a heavy oil reservoir which is technically sensitive to the thermal recovery method.

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The Upper Devonian Grosmont shelf complex is the worlds largest heavy oil deposit hosted in carbonates, with an estimated >50 billion cubic meters (318 to probably 406 bbls) of initial volume in place. At present the Grosmont is not yet under production. This study involves log interpretation, core examination; facies description; strontium, sulphur, carbon, and oxygen isotope analysis. The Grosmont is subdivided into four shallowing-upward cycles. Most Hondo evaporites are part of the Upper Grosmont 3 and Lower Grosmont and were deposited in a series of small, shallow subaqueous brine ponds or in an extensive lagoon. In the eastern part of the area, the Hondo appears to be dissolved resulting in solution-collapse breccias. Other diagenetic processes that were important in shaping the present reservoir characteristics were pervasive dolomitization and dolomite recrystallization, fracturing, and karstification.

Solids-stabilized water-in-oil emulsions have been suggested as a drive fluid to recover viscous oil through a piston-like displacement pattern. While crude heavy oil was initially suggested as the base oil, an alternative oil ? used engine oil was proposed for emulsion generation because of several key advantages: more favorable viscosity that results in better emulsion injectivity, soot particles within the oil that readily promote stable emulsions, almost no cost of the oil itself and relatively large supply, and potential solution of used engine oil disposal. In this research, different types of used engine oil (mineral based, synthetic) were tested to make W/O emulsions simply by blending in brine. A series of stable emulsions was prepared with varied water contents from 40~70%. Viscosities of these emulsions were measured, ranging from 102~104 cp at low shear rates and ambient temperature. Then an emulsion made of 40% used engine oil and 60% brine was chosen for a series of coreflood experiments, to test the stability of this emulsion while flowing through porous media. Limited breakdown of the effluent was observed at ambient injection rates, indicating a stability of the emulsion in porous media. Pressure drops leveled off and remained constant at constant rate of injection, indicating steady-state flows under the experimental conditions. No plug off effect was observed after a large volume of emulsion passed through the cores. Reservoir scale simulations were conducted for the emulsion flooding process based on the emulsion properties tested from the experiments. Results showed significant improvement in both displacement pattern and oil recovery especially compared to water flooding. Economics calculations of emulsion flooding were also performed, suggesting this process to be highly profitable.

An experimental study was conducted to verify experimentally whether sand consolidation by high-temperature alkaline treatment was possible in the heavy oil Bachaquero-01 reservoir. The experiments were conducted using sand samples from a core taken from well LL-231 from Bachaquero-01 reservoir. The sample was placed in a vertical 18 in. long aluminum cylindrical cell with an ID of 1.5 in. The top half of the cell was thermally insulated and the bottom half was cooled. The alkaline treatment (pH 11 -12) at 230ºC - 250ºC and 900 – 1000 psig was injected at 20 ml/min for 3 to 6 hours at the top of the cell and liquid produced at the bottom of the cell. After each experiment, the cell contents were removed and analyzed to determine if consolidation occurred. An electron microprobe was used to analyze both loose and polished epoxy-mounted sand grains to determine any change in texture and composition of the sand pack and precipitation and growth of secondary phases. Results showed that under the experimental conditions reached in the laboratory; the consolidation of Bachaquero-01 sand did not occur. However some secondary materials were produced in the runs where sand samples were cleaned of oil. It was noticed that the amount of these secondary phases was not sufficient to bridge the sand grains. These results indicate that further research is needed to better understand and optimize the parameters affecting the consolidation of Bachaquero-01 sands.

Simulation study has shown oil production is accelerated when propane is used as an additive during steam injection. To better understand this phenomenon, distillation experiments were performed using San Ardo crude oil (12oAPI). For comparison purposes, three distillation processes were investigated: dry-, steam-, and steam-propanedistillation, the latter at the propane-to-steam mass ratio of 0.05 at steam injection rate 0.5 g/min. Two sets of the distillation experiments were carried out. In the first set of experiments, the distillation temperatures ranged from 115ºC to 300ºC. Distillation pressures ranged from 0 psig to 998 psig for steam- and steam-propane distillation. The temperature-pressure combination used represented 15ºC superheated steam conditions. In the second set of experiments, the distillation temperatures ranged from 220oC to 300oC at 260 psig. The temperature pressure combination used represented field conditions for crude oil. For both conditions, the cell was kept at each temperature plateau (cut) until no increase occurs in distillation yields. Distillation yields were collected at each cut, and the volume and weight of water and hydrocarbon measured. Based on these experiments, a thermodynamic modeling framework was developed that describes distillation effect and oil production for steam distillation experiments. The model is based on composition of crude oil, molecular weight of heavy fraction. The analytical model results are compared against the experimental data for synthetic crude and crude oil to verify the validity of the model. Main results of the study may be summarized as follows. The yields for steam distillation for saturated conditions of Tsat+15 o C and Psat is 10 % and with addition of 5% of propane to steam no significant increase occurs in distillation yields. The yields for steam distillation for field conditions of 260 psig and temperature range (220 ~300oC) is 18 % and with addition of 5% of propane to steam no significant increase in distillation yields. The results indicate that propane has minimal distillation effect on the heavy oil. This occurs possibly because of lesser amount of light fractions in the heavy oil that enhance the separation of components in the oil caused by the concentration gradient.

In this study, we used biofuel crops to treat the soils contaminated by heavy oil by using phytoremediation biotechniques. The experiments of this study were divided into tree stages. In the first stage, we simulated real situation, and planted biofuel crops ( soybeans, the sunflower),while the mycorrhizal fungi of Gloums mosseae inoculated the plants in the soils contaminated by oil pollution of fuel (10,000 ppm) artificially. In the soils, the plants were cultivated in pots of 63 days through the experiment. The experiment results revealed that the removal rate of oil was 70%. In the second stage, fuel oil was degraded and tested for the plants of biofuel crops ( soybeans, the sunflower). The specics of Gloums mixed with other species of mycorrhizal fungi were used in the soils contaminated by fuel (5000 ppm) artificially. In the soils, plants were cultivated in a pot of 30 days through the experiment. The experiment result revealed that the fuel oil removal rate was 60% in soils. In the third stage, the seed greasy dirt tolerance experiment were run for the biofuel crops ( soybeans, the sunflower, rape, maize).The fuel oil with three different concentrations (5000 ppm, 10,000 ppm, 30,000 ppm)were used in the polluted soils cultivated in a pot for 30 days through the experiment. The experimental result reveals, that sunflower and maize were found less apt to receive the inhibition of the fuel oil. During the first stage and second stage, the plant species of soybeans inoculated by mycorrhizal fungi, soybean presented significant phytostabilization and rhizodegradation, while the plant species of sunflower inoculated by mycorrhizal fungi also exhibited significant phytoextraction and rhizodegradation. In the future, they can match the other biofuel crops inoculated by different mycorrhizal fungi, which will increase the ability to remove fuel oil in the soil.

High oil-viscosity is a major concern for the recovery of oil from heavy-oil reservoirs. Introducing energy to the formation has proven to be an effective way of lowering the oil viscosity by raising the temperature in the formation. The application of low-frequency heating, also known as electrical resistance heating, is limited by water vaporization near the wellbore which breaks the conductive path to the reservoir, and limits the heating rate as well as the resulting production rates. Electromagnetic (EM) heating, also called high-frequency heating, can be used instead. Although its potential was recognized during the late 70’s, no simulation results or detailed modeling studies have yet been published that completely model the complex interactions of EM energy and multiphase flow. One of the main drawbacks of proposed models is the use of the EM adsorption coefficient as a constant regardless of the properties of the medium, which can obscure the important effect of this parameter on the extension of the reservoir area heated. This dissertation presents a multiphase, two-dimensional radial model that describes the three-phase flow of water, oil, and steam and heat flow in a reservoir within confining conductive formations. The model accounts for the appearance and/or disappearance of a phase, and uses the variation in temperature and water saturation to update the EM absorption coefficient. This model allows determining the temperature distribution and the productivity improvement from EM heating when multiple phases are present. For the numerical simulations of EM heating, I used COMSOL Multiphysics, a Lagrange-quadratic finite element simulator, and its partial differential equations (PDE) application. Several simulations were made for hypothetical reservoirs with different fluid and rock properties. Also, analytical solutions for a single-phase EM heating model were developed and used to validate the numerical solutions. Special attention is focused on reservoirs with characteristics for which steam injection is not attractive or feasible such as low permeability, thin-zone, and extra-heavy oil reservoirs. Results showed that EM heating is feasible based on the power source and frequency used to maintain an optimum absorption coefficient and to obtain higher production rates. Comparisons showed that cumulative oil production and recovery factor obtained by EM heating are better than what is achieved by cyclic steam stimulation (CSS) for reservoirs with the above mentioned characteristics. / text