No description available.

No description available.

No description available.

No description available.

The solubility parameters for ten fractions of Athabasca vacuum residue were calculated from molecular representations via group additivity methods. Two methods were used; Marrero-Gani and Fedors. The calculated parameters were compared between the fractions for consistency, and also compared with other literature sources. The results from the Marrero-Gani method were satisfactory in that the values were in the expected range and the results were consistent from fraction to fraction. The final stage of the work on group additivities was to estimate the solubility parameter values at the extraction temperature of 473 K, and then compare the solutes to the solvents. The solubility parameters of the solvents were calculated from correlations and from the molecular dynamic simulation; the latter method did not result in fulfilling values. The most reasonable solvent and solute solubility parameters were used to assess the utility of the solubility models to explain the trends. The solubility models were not suitable for these types of materials. Stability of heavy oil fractions undergoing mild thermal reactions were predicted computationally for limited sample cracked molecules.

Thesis (Ph. D.)--Florida State University, 2005. / Advisor: Alan G. Marshall, Florida State University, College of Arts and Sciences, Dept. of Chemistry and Biochemistry. Title and description from dissertation home page (viewed Jan. 26, 2006). Document formatted into pages; contains xxi, 145 pages. Includes bibliographical references.

Heavy oil resources are huge and are currently produced largely with steam-driven technology. The purpose of this research was to evaluate an alternative to steam flooding in heavy oils: chemical EOR. Acidic components abundant in heavy crude oils can be converted to soaps at high pH with alkali, reducing the interfacial tension (IFT) between oil and water to ultra-low levels. In an attempt to harness this property, engineers developed alkaline and alkaline-polymer (AP) flooding EOR processes, which met limited success. The primary problem with AP flooding was the soap is usually too hydrophobic, its optimum salinity is low and the ultra-low IFT salinity range narrow (Nelson 1983). Adding a hydrophilic co-surfactant to the process solved the problem, and is known as ASP flooding. AP floods also form persistent, unpredictable and often highly viscous emulsions, which result in high pressure drops and low injection rates. Addition of co-solvents such as a light alcohol (typically 1 wt %) improves the performance of AP floods; researchers at the University of Texas at Austin have coined the term ACP (Alkaline Co-solvent Polymer) for this new process. ACP has significant advantages relative to other chemical flooding modes to recover heavy oils. It is less costly than using surfactant, and has none of the design challenges associated with surfactant. It shows the benefit of nearly 100% displacement sweep efficiency in core floods when properly implemented, as heavy oils tend to produce significant IFT reducing soaps. The use of polymer for mobility control ensures good sweep efficiency is also achieved. Since heavy oils can be extremely viscous at reservoir temperature, moderate reservoir heating to reduce oil viscosity is beneficial. In a series of core flood experiments, moderately elevated temperatures (25-75°C) were used in evaluating ACP flooding in heavy oils. The experiments used only small amounts of inexpensive co-solvents while recovering >90% of remaining heavy oil in a core, without need for any surfactant. The most successful experiments showed that a small increase in temperature (25°) can have very positive impacts on core flood performance. These results are very encouraging for heavy oil recovery with chemical EOR. / text

Crude oil plays an important role for the global energy system. As there is ample evidence that conventional oil production will have peaked by 2020, unconventional oil has attained a stronger focus. In particular, oil derived from bitumen from Canadian oilsands has been proposed as a possible remedy to global oil depletion. This study aims to test the hypothesis that forecasts on the Canadian oil sands published between about 2000 and 2010 have been overestimating production significantly. A large compilation of oil sands projects, prognoses and production data has been established using openly available databases and reports. Conversion, standardization and analysis of the data was done using the statistical programming language R. The resulting programming code and databases have been compiled into a package available free and open-source online. The statistical analysis shows a significant bias of the prognoses towards an overestimation of oil sands production. The compilation shows that most authors tend to overestimate the rate of expansion of the industry. Therefore, any prognosis on the expansion of the industry should be examined thoroughly before use.

It is estimated that Canada has 1. 7 trillion barrels of oil contained in oil sands located mainly in Alberta. However, the oil contained in the oil sands is a very viscous, tar-like substance that does not flow on its own and cannot be produced with conventional methods. Economical production of this vast resource requires new technology and research. Research in Canada has helped maintain leadership in heavy oil recovery technology. <br /><br /> One method of viscosity reduction is through dilution, which is controlled by two mechanisms&mdash;mass transfer and gravity drainage. In the vapour extraction (Vapex) process, vapour of a light hydrocarbon solvent is injected into the reservoir. The mass transfer of vapour into bitumen is driven by a concentration gradient; the vapour diffuses into the heavy oil, causing a reduction in viscosity. The viscosity reduced oil is referred to as "live oil" and is now able to flow by gravity to a horizontal production well. At the surface, solvent can be easily separated and recovered from the produced oil through a flash separation/distillation process. <br /><br /> Under reservoir conditions, extraction solvents such as butane and pentane would condense, increasing the amount of solvent required and decreasing the density difference between solvent and bitumen. The solvent can be maintained in a gaseous phase, by co-injecting a non-condensable gas (NCG), reducing the partial pressure of the solvent and thus preventing condensation. Two types of models were used to observe the VAPEX process while varying the concentration of air and pentane in the system. Experimental results will help to determine the effect of increasing NCG concentration on the rate of live oil production. <br /><br /> The apparatus consists of a porous media model saturated with bitumen and placed inside acrylic housing. NCG (air) exists in the housing before liquid pentane is added. Pentane vapour continuously evolves from a reservoir of liquid pentane, maintained at constant temperature. A concentration gradient was established allowing pentane to flow into the system where the partial pressure of pentane in the bitumen phase is lower than the vapour pressure of pentane. The bitumen, diluted at the bitumen-gas interface, drains under the action of gravity. The advancement of the bitumen-gas interface was monitored to determine the live oil production rate. By varying the temperature of liquid pentane, the partial pressure of pentane in the extraction vessel was varied. <br /><br /> Results from five experiments in trough models and two in micromodels show that the rate of interface advancement in the presence of a NCG is proportional to the square root of time. Similarly, cumulative volume of oil produced was proportional to the square root of time. Previous works [Ramakrishnan (2003), James (2003), Oduntan, (2001)] have shown that interface advancement and production using a pure solvent was proportional to time. In the experimental range examined (24-32°C) temperature did not effect the rate of production for a given time or interface location. <br /><br /> The average steady state effective diffusion coefficient was calculated from production data to be 0. 116 cm²/s, five times larger than estimated from the Hirschfelder Equation. <br /><br /> Live oil properties were found to be consistent throughout each experiment and between experiments. On average, live oil contained 46-48 wt% pentane and viscosity was reduced by four orders of magnitude from 23,000 mPa?s to 4-6 mPa?s.

It is estimated that Canada has 1. 7 trillion barrels of oil contained in oil sands located mainly in Alberta. However, the oil contained in the oil sands is a very viscous, tar-like substance that does not flow on its own and cannot be produced with conventional methods. Economical production of this vast resource requires new technology and research. Research in Canada has helped maintain leadership in heavy oil recovery technology. <br /><br /> One method of viscosity reduction is through dilution, which is controlled by two mechanisms&mdash;mass transfer and gravity drainage. In the vapour extraction (Vapex) process, vapour of a light hydrocarbon solvent is injected into the reservoir. The mass transfer of vapour into bitumen is driven by a concentration gradient; the vapour diffuses into the heavy oil, causing a reduction in viscosity. The viscosity reduced oil is referred to as "live oil" and is now able to flow by gravity to a horizontal production well. At the surface, solvent can be easily separated and recovered from the produced oil through a flash separation/distillation process. <br /><br /> Under reservoir conditions, extraction solvents such as butane and pentane would condense, increasing the amount of solvent required and decreasing the density difference between solvent and bitumen. The solvent can be maintained in a gaseous phase, by co-injecting a non-condensable gas (NCG), reducing the partial pressure of the solvent and thus preventing condensation. Two types of models were used to observe the VAPEX process while varying the concentration of air and pentane in the system. Experimental results will help to determine the effect of increasing NCG concentration on the rate of live oil production. <br /><br /> The apparatus consists of a porous media model saturated with bitumen and placed inside acrylic housing. NCG (air) exists in the housing before liquid pentane is added. Pentane vapour continuously evolves from a reservoir of liquid pentane, maintained at constant temperature. A concentration gradient was established allowing pentane to flow into the system where the partial pressure of pentane in the bitumen phase is lower than the vapour pressure of pentane. The bitumen, diluted at the bitumen-gas interface, drains under the action of gravity. The advancement of the bitumen-gas interface was monitored to determine the live oil production rate. By varying the temperature of liquid pentane, the partial pressure of pentane in the extraction vessel was varied. <br /><br /> Results from five experiments in trough models and two in micromodels show that the rate of interface advancement in the presence of a NCG is proportional to the square root of time. Similarly, cumulative volume of oil produced was proportional to the square root of time. Previous works [Ramakrishnan (2003), James (2003), Oduntan, (2001)] have shown that interface advancement and production using a pure solvent was proportional to time. In the experimental range examined (24-32°C) temperature did not effect the rate of production for a given time or interface location. <br /><br /> The average steady state effective diffusion coefficient was calculated from production data to be 0. 116 cm²/s, five times larger than estimated from the Hirschfelder Equation. <br /><br /> Live oil properties were found to be consistent throughout each experiment and between experiments. On average, live oil contained 46-48 wt% pentane and viscosity was reduced by four orders of magnitude from 23,000 mPa?s to 4-6 mPa?s.