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.

This study presents an investigation of the concept of harvesting geothermal energy that remains in heavy oil reservoirs after abandonment when steamflooding is no longer economics. Substantial heat that has accumulated within reservoir rock and its vicinity can be extracted by circulating water relatively colder than reservoir temperature. We use compositional reservoir simulation coupled with a semianalytical equation of the wellbore heat loss approximation to estimate surface heat recovery. Additionally, sensitivity analyses provide understanding of the effect of various parameters on heat recovery in the artificial geothermal resources. Using the current state-of-art technology, the cumulative electrical power generated from heat recovered is about 246 MWhr accounting for 90percent downtime. Characteristics of heat storage within the reservoir rock were identified. The factors with the largest impact on the energy recovery during the water injection phase are the duration of the steamflood (which dictates the amount of heat accumulated in the reservoir) and the original reservoir energy in place. Outlet reservoir-fluid temperatures are used to approximate heat loss along the wellbore and estimate surface fluid temperature using the semianalytical approaches. For the injection well with insulation, results indicate that differences in fluid temperature between surface and bottomhole are negligible. However, for the conventional production well, heat loss is estimated around 13 percent resulting in the average surface temperature of 72 degrees C. Producing heat can be used in two applications: direct uses and electricity generation. For the electricity generation application that is used in the economic consideration, the net electrical power generated by this arrival fluid temperature is approximately 3 kW per one producing pattern using Ener-G-Rotors.

Upon request of the VPR and the thesis advisor this item has been made administrative access only until further notice. / Biodegradation of petroleum has been observed to be one of the most important factors that can alter reservoir chemistry. Biodegradation of petroleum has been connected to the generation of heavy oil at the expense of light hydrocarbon components. Generally, heavy oil is associated with the increasing in metal and sulfur content as well as viscosity. In addition, petroleum biodegradation will result in the production of certain metabolites that are implicated in forming emulsions and corrosion problems in the producing and refining facilities. However, identifying the microrganisms that catalyse this biodegradation is crucial to understanding their role in the hydrocarbons alteration. In this thesis, I addressed the connection between the petroleum biodegradation and the formation of light hydrocarbon components at the expense of heavy hydrocarbon components, and the increase in gas/oil ratio. A comparison between light, extra light, and medium sour crudes lends support to the hypothesis of light hydrocarbons formation through biodegradation of long chain oil components. The results suggested that there was no direct relationship between the relative density of oil and the level of biodegradation, but, there was a positive correlation between the level of biodegradation, the formation of light hydrocarbons, and an increase in the gas/oil ratio. As a first step in investigating this correlation, a metagenomics approach was used to identify and characterize the biodiversity in a European oil field. Extrapolation of the oilfield microbiome data based on an analysis of 200 species generated a hypothetical metabolic map that suggests a new model for petroleum formation and degradation that challenges the accepted dogma in which aerobic and anaerobic petroleum degradation is taking place in the hydrocarbons reservoir, as it is a matter of rate; where the aerobic petroleum degradation targets the short-chain hydrocarbons specifically methane and result in heavy oil generation; whereas the anaerobic petroleum degradation leads to form the gaseous components such as methane, carbon dioxide and hydrogen sulfide. Hence, the gaseous components have a direct impact on the oil density when they represent the majority of the oil field composition by making it more gaseous than liquid.

No description available.

Steam assisted gravity drainage (SAGD) has been demonstrated as a proven technology to unlock heavy oil and bitumen in Canadian reservoirs. Given the large energy requirements and volumes of emitted greenhouse gases from SAGD processes, there is a strong motivation to develop enhanced oil recovery processes with lower energy and emission intensities. In this study, the addition of solvents to steam has been examined to reduce the energy intensity of the SAGD process. Higher oil recovery, accelerated oil production rate, reduced steam-to-oil ratio, and more favorable economics are expected from the addition of suitable hydrocarbon additives to steam. A systematic approach was used to develop an effective hybrid steam/solvent injection to improve the SAGD process. Initially, an extensive parametric simulation study was carried out to find the suitable hydrocarbon additives and injection strategies. Simulation studies aim to narrow down hybrid steam/solvent processes, design suitable solvent type and concentration, and explain the mechanism of solvent addition to steam. In the experimental phase, the most promising solvents (n-hexane and n-heptane) were used with different injection strategies. Steam and hydrocarbon additives were injected in continuous or alternating schemes. The results of the integrated experimental and simulation study were used to better understand the mechanism of hybrid steam/solvent processes. Experimental and simulation results show that solvent co-injection with steam leads to a process with higher oil production, better oil recovery, and less energy intensity with more favorable economy. Solvent choice for hybrid steam/solvent injection is not solely dependent on the mobility improvement capability of the solvents but also reservoir properties and operational conditions such as operating pressure and injection strategy. Pure heated solvent injection requires significant quantities. A vaporized solvent chamber is not sustainable due to low latent heat of the solvents. Alternating steam and solvent injection provides heat for the solvent cycles and increases oil recovery. Co-injection of small volumes (5-15% by volume) of suitable solvents at the early times of the SAGD operation considerably improves the economics of the SAGD process.

The vapour extraction process, or &amp / #8216 / VAPEX&amp / #8217 / has attracted a great deal of attention in recent years as a new method of heavy oil or bitumen recovery. The VAPEX (vapour extraction) can be visualized as energy efficient recovery process for unlocking the potential of high viscosity resources trapped in bituminous and heavy oil reservoirs. A total of 20 VAPEX experiments performed with Hele-Shaw cell utilizing three different Turkish crude oils. Two different VAPEX solvents (propane and butane) were used with three different injection rates (20, 40 and 80 ml/min). Garzan, Raman and Bati Raman crude oils were used as light, medium and heavy oil. Apart from normal Dry VAPEX experiments one experiment was conducted with CO2 and another one with butane + steam as Wet VAPEX experiment. All experiments were recorded by normal video camera in order to analyze visually also. For both VAPEX solvents, oil production rates increased with injection rates for all crude oils. Instantaneous asphaltene rate for Garzan oil, showed fluctuated performance with propane solvent. Butane showed almost constant degree of asphaltene precipitation. Instantaneous asphaltene rate for Raman and Bati Raman oils gave straight line results with the injection rate of 20 ml/min for both solvent. When the injection rate increased graphs showed the same performance with Garzan oil and started to fluctuate for both solvent. For asphaltene precipitation, propane gave better results than butane in almost all injection rates for Garzan and Raman oil. In the experiments with Bati Raman oil, butane made better upgrading than propane with the injection rate 80 ml/min. With the other two rates, both solvents showed almost same performace.