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This research is a study of the in-situ upgrading of Jobo crude oil using steam, tetralin or decalin, and catalyst (Fe(acac)₃) at temperatures of 250 °C, 275 °C and 300 °C for 24 hours, 48 hours and 72 hours using an autoclave. Viscosity, API gravity and compositional changes were investigated. We found that tetralin and decalin alone were good solvents for heavy oil recovery. Tetralin or decalin at concentrations of 9% (weight basis) could reduce the Jobo crude oil viscosity measured at 50 °C by 44±2% and 39±3%. Steam alone had some upgrading effects. It could reduce the oil viscosity by 10% after 48 hours of contact at 300°C. Tetralin, decalin or catalyst showed some upgrading effects when used together with steam and caused 5.4±4%, 4±1% and 19±3% viscosity reduction compared with corresponding pre-upgrading mixture after 48 hours of reaction at 300°C. The combination of hydrogen donor tetralin or decalin and catalyst reduced the viscosity of the mixture the most, by 56±1% and 72±1% compared with pre-upgrading mixture. It meant that hydrogen donors and catalyst had strong synergetic effects on heavy oil upgrading. We also found that 300 °C was an effective temperature for heavy oil upgrading with obvious viscosity reduction in the presence of steam, hydrogen donors and catalyst. Reaction can be considered to have reached almost equilibrium condition after 48 hours. The GC-MS analysis of the gas component showed that light hydrocarbon gases and CO₂ were generated after reaction. The viscosity reduction from decalin use is larger than that of tetralin because decalin has more hydrogen atoms per molecule than tetralin. A mechanism of transferring H (hydrogen atom) from H₂O and hydrogen donors to heavy oil, which can lead to structure and composition changes in heavy oil, is explained. The study has demonstrated that in-situ heavy oil upgrading has great potential applications in heavy and extra heavy oil recovery.

Experimental and analytical studies have been carried out to better understand the effects of additives on viscosity, density and surface tension of intermediate and heavy crude oils. The studies have been conducted for the following oil samples: San Francisco oil from Columbia with specific gravity of 28o-29o API, Duri oil with gravity of 19o-21o API, Jobo oil with gravity of 8o-9o API and San Ardo oil gravity of 11o-13o API. The additive used in all of the experiments is petroleum distillate. The experiments consist of using petroleum distillate as an additive for different samples of heavy crude oils. The experiments include making a mixture by adding petroleum distillate to oil samples and measuring surface tension, viscosity and density of pure oil samples and mixtures at different temperatures. The petroleum distillate/oil ratios are the following ratios: 1:100, 2:100, 3:100, 4:100 and 5:100. Experimental results showed that use of petroleum distillate as an additive increases API gravity and leads to reduction in viscosity and surface tension for all the samples. Results showed for all petroleum distillate/oil ratios viscosity and interfacial tension decreases with temperature. As petroleum distillate/oil ratio increases, oil viscosity and surface tension decrease more significantly at lower temperatures than at higher temperatures. After all experiments were completed an analytical correlation was done based on the experiment results to develop “mixing rules”. Using this correlation viscosity, density and surface tension of different petroleum distillate/oil mixtures were obtained (output).These had properties of pure oil and petroleum distillate, mixture ratios and temperatures at which measurement is supposed to be done (output). Using this correlation a good match was achieved. For all of the cases (viscosity, density and surface tension), correlation coefficient (R²) was more than 0.9 which proved to be optimum for a really good match.

Experimental and analytical studies have been carried out to better understand production mechanisms of heavy oil under steam injection with propane and petroleum distillate as steam additives. The studies have been conducted for heavy oil from San Ardo field (12oAPI, 2800 cp at 53.3oC), under current reservoir conditions. The experiments consist of injecting pure steam, steam-propane, and steampetroleum distillate into a vertical cell containing a mixture of sand, water and San Ardo oil. The injection cell (68.58 cm long with an ID of 7.376 cm) is placed inside a vacuum jacket, set at the reservoir temperature of 53.3oC. Superheated steam at 230oC is injected at 5.5 ml/min (cold-water equivalent) simultaneously with propane or a petroleum distillate slug. The cell outlet pressure is maintained at 260 psig. Six runs were performed, two runs using pure steam, two steam-propane runs using 5:100 propane:steam mass ratio, and two steam-petroleum distillate runs using 5:100 petroleum distillate:steam mass ratio. We develop a simplified analytical model that describes steam front advancement and oil production for the 1D displacement experiments. The model incorporates heat and material balance, fillup time and Darcy’s law pertaining to the injection cell. The analytical model results are compared against the experimental data to verify the validity of the model. The main results of the study are as follows. First, experimental results indicate that compared to pure steam injection, oil production was accelerated by 30% for 5:100 propane:steam injection and 38% for 5:100 petroleum distillate:steam injection respectively. Second, steam injectivity with steam-propane and steam-petroleum distillate increases to 1.4 and 1.9 times respectively, compared with pure steam injection. Third, steam front advancement and oil production data are in good agreement with results based on the new analytical model. The analytical model indicates that the oil production acceleration observed is due to oil viscosity reduction resulting from the addition of propane and petroleum distillate to the steam. Oil viscosity at the initial temperature with pure steam injection is 2281 cp, which is reduced to 261 cp with steam-propane injection and 227 cp with steam-petroleum distillate injection.

Radiation technology can economically overcome principal problems of heavy oil processing arising from heavy oil’s unfavorable physical and chemical properties. This technology promises to increase considerably yields of valuable and environmentally satisfying products of thermal cracking; to simplify complexity of refinery configuration; and to reduce energy expenses of thermal cracking. Objectives of the present study are: ● Evaluate heavy oil viscosities with respect to absorbed dose and effect of different solvents on the viscosity of irradiated crude oil by comparing selected physical properties of irradiated samples to a non-irradiated control group; ● Investigate effect of e-beam radiation on the yields of light fractions comparing yields of radiation-thermal cracking to yields of conventional thermal cracking. The viscosity was used as an indicator of the change in the molecular structure of hydrocarbons upon irradiation. We found that the irradiation of pure oil leads to the increase of the molecular weight calculated from the Riazi-Daubert correlation. Thus, irradiation up to 10 kGy resulted in a 1.64% increase in the molecular weight, 20 kGy ─ 4.35% and 30 kGy ─ 3.28%. It was found that if irradiated oil was stored for 17 days, its viscosity increased by 14% on average. The irradiation of samples with added organic solvent in the following weight percentages 10, 5, 2.5wt.% resulted in the increase in the viscosity by 3.3, 3.6 and 14.5%, respectively. The irradiation of the sample with added distilled water also resulted in an increase in the viscosity. This increase mainly happened because the thermal component was absent in the activation energy and hydrogen, produced from radiolysis of solvent and water molecules in mixture with crude oil, and was not consumed by hydrocarbon molecules and no reduction in molecular size occurred. Implementation of radiation to the thermal cracking increased yields of light fractions by 35wt.% on average compared to the process where no radiation was present. The last chapter of this thesis discusses a profitability of installation the hypothetical radiation-thermal visbreaking unit. The calculation of profitability was performed by a rate of return on investment (ROI) method. It showed that implementation of radiation-thermal processing resulted in an increase of ROI from 16 to 60%.

An experimental study has been conducted to compare the effect of steam injection and caustic steam injection in improving the recovery of San Ardo and Duri heavy oils. A 67 cm long x 7.4 cm O.D (outer diameter), steel injection cell is used in the study. Six thermocouples are placed at specific distances in the injection cell to record temperature profiles and thus the steam front velocity. The injection cell is filled with a mixture of oil, water and sand. Steam is injected at superheated conditions of 238oC with the cell outlet pressure set at 200 psig, the cell pressure similar to that found in San Ardo field. The pressure in the separators is kept at 50 psig. The separator liquid is sampled at regular intervals. The liquid is centrifuged to determine the oil and water volumes, and oil viscosity, density and recovery. Acid number measurements are made by the titration method using a pH meter and measuring the EMF values. The interfacial tensions of the oil for different concentrations of NaOH are also measured using a tensionometer. Experimental results show that for Duri oil, the addition of caustic results in an increase in recovery of oil from 52% (steam injection) to 59 % (caustic steam injection). However, caustic has little effect on San Ardo oil where oil recovery is 75% (steam injection) and 76 % (caustic steam injection). Oil production acceleration is seen with steam-caustic injection. With steam caustic injection there is also a decrease in the produced oil viscosity and density for both oils. Sodium hydroxide concentration of 1 wt % is observed to give the lowest oil-caustic interfacial tension. The acid numbers for San Ardo and Duri oil are measured as 6.2 and 3.57 respectively.

The presence of asphaltenes in heavy oil is related to its high viscosity which is a major constraint in heavy oil processing and transportation. Moreover, problems associated with the deposition of asphaltenes at different stages of the heavy oil refining steps increase the cost of heavy oil processing. In this research project, we have achieved viscosity reduction of heavy oil by treating it through the novel JetShear destructuring process. Subsequently we have studied the adsorption of the asphaltenes over specific solid adsorbents. Characterization of the raw and treated heavy oil has been conducted. We have experimentally shown that the JetShear destructuring process reduces diluent requirements (up to 50%), decreases the initial viscosity of heavy oil and lowers the oil density (increasing its API degree) thus providing a solution for pipeline transportation.The asphaltenes content of the treated product oil was also found to decrease slightly during the JetShear destructuring as per SARA fractions determination. This implies incipient cracking of the heavy oil induced by the JetShear treatment. Adsorption of asphaltenes over practical adsorbents was conducted to determine whether asphaltenes could be selectively removed from the oil aiming at establishing the basis of a process. that could lead to breakthrough technology in heavy oil processing. Investigations of adsorption of asphaltenes were centered onto two objectives: firstly, asphaltenes characterization based on molecular size and separation of asphaltenes into acidic and basic fractions; secondly, asphaltenes interaction with adsorbents was studied. Experiments using virgin and destructured heavy oil showed that asphaltenes were preferentially removed following a multilayer adsorption model in the pores with significant and practical yields (0.25~0.36 g asphaltenes/g adsorbent) in the 150 [degree centigrade] range. Maximum uptake required 200 min of contact time at heavy oil/adsorbents ratios in the 5:1 range.The adsorption reduced the asphaltenes remaining in the treated heavy oil by allowing the asphaltenes to lodge in the pores as well as getting adsorbed on the surfaces of the adsorbent particularly the lower molecular weight asphaltenes.The combined treatment (i.e. destructuring and adsorption) also changed the functional group of the asphaltenes, and induced loss of heteroatoms lowering sulfur content in the final oil.

Vapour Extraction (VAPEX) is an in-situ bitumen recovery technique that utilizes light hydrocarbons to reduce the viscosity of bitumen. The mechanism of VAPEX is governed by the mass transfer of light hydrocarbons into bitumen and gravity drainage. The focus of this research is three-fold: 1) to validate a new annulus apparatus design 2) to investigate the effect of connate water and solvent condensation on live oil and bitumen production rates, solvent chamber growth, and solvent requirements, and 3) to develop a numerical model to simulate the solvent chamber growth of VAPEX under isothermal conditions and constant pressure operation.

Vapour Extraction (VAPEX) is an in-situ bitumen recovery technique that utilizes light hydrocarbons to reduce the viscosity of bitumen. The mechanism of VAPEX is governed by the mass transfer of light hydrocarbons into bitumen and gravity drainage. The focus of this research is three-fold: 1) to validate a new annulus apparatus design 2) to investigate the effect of connate water and solvent condensation on live oil and bitumen production rates, solvent chamber growth, and solvent requirements, and 3) to develop a numerical model to simulate the solvent chamber growth of VAPEX under isothermal conditions and constant pressure operation.

Steam injection with added surface active chemicals is one of general EOR processes aimed to recover residual oil after primary production processes. It has been demonstrated that, after waterflooding, an oil swept area can be increased by steam surfactant flow due to the reduced steam override effect as well as reduced interfacial tension between oil and water in the formation. To investigate the ability to improve recovery of 20.5oAPI California heavy oil with steam surfactant injection, several experiments with a one-dimensional model were performed. Two experimental models with similar porous media, fluids, chemicals, as well as injection and production conditions, were applied. The first series of experiments were carried out in a vertical cylindrical injection cell with dimensions of 7.4 cm x 67 cm. The second part of experiment was conducted using a horizontal tube model with dimensions of 3.5 cm x 110.5 cm. The horizontal model with a smaller diameter than the vertical injection cell is less subject to channel formation and is therefore more applicable for the laboratory scale modeling of the one-dimensional steam injection process. Nonionic surfactant Triton X-100 was coinjected into the steam flow. For both series of experimental work with vertical and horizontal injection cells, the concentration of Triton X-100 surfactant solution used was chosen 3.0 wt%. The injection rates were set to inject the same 0.8 pore volumes of steam for the vertical model and 1.8 pore volumes of steam for horizontal model. The steam was injected at superheated conditions of 200oC and pressure of 100 psig. The liquid produced from the separator was sampled periodically and treated to determine oilcut and produced oil properties. The interfacial tension (IFT) of the produced oil and water were measured with an IFT meter and compared to that for the original oil. The experimental study demonstrated that the average incremental oil recovery with steam surfactant flood is 7 % of the original oil-in-place above that with pure steam injection.