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.

It is estimated that the shallow reservoirs of Ugnu, West Sak and Shraeder Bluff in the North Slope of Alaska hold about 20 billion barrels of heavy oil. The proximity of these reservoirs to the permafrost makes the application of thermal methods for the oil recovery very unattractive. It is feared that the heat from the thermal methods may melt this permafrost leading to subsidence of the unconsolidated sand (Marques 2009; Peyton 1970; Wilson 1972). Thus it is necessary to consider the development of cheap non-thermal methods for the recovery of these heavy oils. This study investigates non-thermal techniques for the recovery of heavy oils. Chemicals such as alkali, surfactant and polymer are used to demonstrate improved recovery over waterflooding for two oils (A:10,000cp and B:330 cp). Chemical screening studies showed that appropriate concentrations of chemicals, such as alkali and surfactant, could generate emulsions with oil A. At low brine salinity oil-in-water (O/W) emulsions were generated whereas water-in-oil (W/O) emulsions were generated at higher salinities. 1D and 2D sand pack floods conducted with alkali surfactant (AS) at different salinities demonstrated an improvement of oil recovery over waterflooding. Low salinity AS flood generated lower pressure drop, but also resulted in lower oil recovery rates. High salinity AS flood generated higher pressure drop, high viscosity emulsions in the system, but resulted in a greater improvement in oil recovery over waterfloods. Polymers can also be used to improve the sweep efficiency over waterflooding. A 100 cp polymer flood improved the oil recovery over waterflood both in 1D and 2D geometry. In 1D geometry 1PV of polymer injection increased the oil recovery from 30% after waterflood to 50% OOIP. The tertiary polymer injection was found to be equally beneficial as the secondary polymer injection. It was also found that the combined application of AS and polymer did not give any major advantage over polymer flood or AS flood alone. Chemical EOR technique was considered for the 330cp oil B. Chemical screening studies showed that microemulsions could be generated in the system when appropriate concentrations of alkali and surfactant were added. Solubilization ratio measurement indicted that the interfacial tension in the system approached ultra-low values of about 10-3 dynes/cm. The selected alkali surfactant system was tested in a sand pack flood. Additionally a partially hydrolyzed polymer was used to provide mobility control to the process. The tertiary injection of ASP (Alkali-Surfactant-Polymer) was able to improve the oil recovery from 60% OOIP after the waterflood to almost 98% OOIP. A simple mathematical model was built around viscous fingering phenomenon to match the experimental oil recoveries and pressure drops during the waterflood. Pseudo oil and water relative permeabilities were calculated from the model, which were then used directly in a reservoir simulator in place of the intrinsic oil-water relative permeabilities. Good agreement with the experimental values was obtained. For history matching the polymer flood of heavy oil, intrinsic oil-water relative permeabilities were found to be adequate. Laboratory data showed that polymer viscosity is dependent on the polymer concentration and the effective brine salinity. Both these effects were taken into account when simulating the polymer flood or the ASP flood. The filtration theory developed by Soo and Radke (1984) was used to simulate the dilute oil-in-water emulsion flow in the porous media when alkali-surfactant flood of the heavy oil was conducted. The generation of emulsion in the porous media is simulated via a reaction between alkali, surfactant, water and heavy oil. The theory developed by Soo and Radke (1984) states that the flowing emulsified oil droplets clog in pore constrictions and on the pore walls, thereby restricting flow. Once captured, there is a negligible particle re-entrainment. The simulator modeled the capture of the emulsion droplets via chemical reaction. Next, the local water relative permeability was reduced as the trapping of the oil droplets will reduce the mobility of the water phase. This entrapment mechanism is responsible for the increase in the pressure drop and improvement in oil recovery. The model is very sensitive to the reaction rate constants and the oil-water relative permeabilities. ASP process for lower viscosity 330 cp oil was modeled using the UTCHEM multiphase-multicomponent simulator developed at the University of Texas at Austin. The simulator can handle the flow of three liquid phases; oil, water and microemulsion. The generation of microemulsion is modeled by the reaction of the crude oil with the chemical species present in the aqueous phase. The experimental phase behavior of alkali and surfactant with the crude oil was modeled using the phase behavior mixing model of the simulator. Oil and water relative permeabilities were enhanced where microemulsion is generated and interfacial tension gets reduced. Experimental oil recovery and pressure drop data were successfully history matched using UTCHEM simulator. / text

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.

Production in Canada’s oil sands has been increasing, with a projected rate of 4.5 million barrels per day by 2025. Two production techniques are currently used, mining and in-situ, with the latter projected to constitute ~57% of all production by that time. Although in-situ extraction methods such as Steam Assisted Gravity Drainage (SAGD) are less invasive than mining, they result in more greenhouse gas (GHG) emissions per barrel and require large amounts of water that must be treated and recycled with a make-up water requirement of about 10%. CanmetENERGY is developing a steam generation technology called the High Pressure Oxy-fired Direct Contact Steam Generator (HiPrOx/DCSG, or DCSG for short) that will reduce these water requirements and sequester GHGs. This study evaluates the technical feasibility of this technology using process simulations, bench-scale testing, and pilot-scale testing. At first, a method in which to integrate the DCSG into the SAGD process was presented and process modeling of expected system performance was undertaken. The process simulations indicated that DCSG decreased the energy intensity of SAGD by up to 7.6% compared to the base SAGD case without carbon capture and storage (CCS), and up to 12.0% compared to the base SAGD case with CCS. Bench-scale testing was then performed using a pressurized thermogravimetric analyzer (PTGA) in order to investigate the effects of increased pressure and high moisture environments on a Canadian lignite coal char’s reactivity. It was found that under reaction kinetic-controlled conditions at atmospheric pressure, the increased addition of steam led to a reduction in burning time. The findings may have resulted from the lower heat capacity and higher thermal conductivity of steam compared to CO2. At increased pressures, CO2 inhibited burnout due to its higher heat capacity, lower thermal conductivity, and its effect on C(O) concentrations on the particle surface. When steam was added, the inhibiting effects of CO2 were counteracted, resulting in burnout rates similar to pressurized O2/N2 environments. These preliminary results suggested that the technology was feasible at a bench-scale level. Conflicting literature between bench-scale and pilot-scale studies indicated that pilot-scale testing would be advantageous as a next step. At the pilot-scale, testing was performed using n-butanol, graphite slurry, and n-butanol/graphite slurry mixtures covering lower and upper ends in fuel reactivity. It was found that stable combustion was attainable, with high conversion efficiencies in all cases. With the n-butanol, it was possible to achieve low excess oxygen requirements, which minimizes corrosion issues and reduce energy requirements associated with oxygen generation. With graphite slurry, it was found that it was possible to sustain combustion in these high moisture environments and that high conversion was achieved as indicated by the undetectable levels of carbonaceous materials observed in downstream equipment. Overall, these studies indicate that DCSG is technically feasible from the perspectives of energy and combustion efficiencies as well as from a steam generation point of view. Future work includes the investigation of possible corrosion associated with the product gas, the effect of CO2 on bitumen production, the nature of the mineral melt formed by the deposition of the dissolved and suspended solids from the water in the combustor, and possible scaling issues in the steam generator and piping associated with mineral deposits from the dissolved and suspended solids in the produced water is recommended.

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.

Orientador: Osvair Vidal Trevisan / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências / Made available in DSpace on 2018-08-18T05:59:26Z (GMT). No. of bitstreams: 1 VidalVargas_JanethAlina_M.pdf: 7697532 bytes, checksum: 8343ada0aa83b2ec03f35bcb622bc792 (MD5) Previous issue date: 2011 / Resumo: O processo de combustão in situ (CIS) é um método térmico de recuperação melhorada que gera calor no reservatório, diminuindo a viscosidade e aumentando a mobilidade do óleo, pela combustão de uma parte do óleo in place. A frente de combustão é mantida pela injeção continua de ar enriquecido com oxigênio. O processo CIS depende basicamente das reações químicas de combustão que acontecem quando o óleo está em contato com o ar injetado. Portanto, o sucesso do processo CIS é determinado pelo conhecimento e compreensão do comportamento cinético destas reações. O objetivo deste trabalho é determinar os parâmetros cinéticos da reação de combustão de um óleo pesado brasileiro, através da realização de ensaios experimentais usando um calorímetro de taxa acelerada (ARC) com fluxo (sistema aberto). Os testes foram feitos com 2 g de amostra de óleo de 12°API, 20,4 atm (290 psi) de pressão, injeção continua de ar com fluxo de 40-60 ml/min e as amostras foram aquecidas até 550°C. Também se realizaram testes com misturas de óleo e areia, óleo e argila e óleo/areia/argila para simular melhor o comportamento das reações no reservatório. A temperatura de autoignição foi de 290°C para o óleo. Quando areia ou argila foram misturadas ao óleo na proporção 25/75, a temperatura de autoignição se reduziu a 170°C. Identificou-se a presença das reações OBT (oxidação de baixa temperatura) num intervalo de temperatura de 170 a 300 °C, as OMT (oxidação de media temperatura) entre 300 e 420°C e as OAT (oxidação de alta temperatura) de 420°a 550°C aproximadamente. Todos os testes apresentam uma zona de transição em 320°C. Também foram realizados testes com asfalteno/argila e malteno/argila na proporção 25/75, para os quais se identificaram temperaturas de autoignição de 180 e 170 °C respectivamente. A energia de ativação para a maioria das reações é da ordem de grandeza de 105[J/mol], e a ordem da reação entre 0 e 1 / Abstract: In situ combustion (ISC) is a thermal method of enhanced recovery that generates heat in the reservoir, to reduce viscosity and increase the mobility of the oil, after the combustion of a portion of the oil in place. The combustion front is maintained by the continuous injection of air enriched with oxygen. ISC depends basically on the chemical reactions of combustion that happen when the oil is in contact with the injected air. Therefore the success of ISC relies on the knowledge and understanding of the kinetic behavior of these reactions. The objective of this project is to determine the kinetic parameters of the combustion reaction of Brazilian heavy oil through accelerating rate calorimetry (ARC) with flow (open system). The tests were made with 2 g of oil samples of a 12°API oil, at 20 bar pressure, continuous air injection at 40-60 ml/min flow rate and the samples heated up to 550°C. Tests were also carried out with mixtures of oil and sand, oil and clay and oil/sand/clay to better simulate the behavior of the reactions in the reservoir. The auto ignition temperature was of 290°C for the oil. When sand or clay had been mixed to the oil at a 1/3 ratio, the auto ignition temperature is reduced to 170°C. Presence of LTO (low-temp oxidation) reactions was identified in the temperature range of 170 to 300 °C, MTO (medium temperature oxidation) reactions in 300 to 420°C and the HTO (high temperature oxidation) reactions in 420° to 550°C approximately. All tests presented a transition zone at 320°C. Additional tests were carried with mixtures of asphaltene/clay and maltene/clay at a 1/3 ratio, for which auto ignition temperatures were identified at 170 and 180°C, respectively. The energy of activation for the majority of the reactions was the order of 105 [J/mol], and the order of the reaction between 0 and 1 / Mestrado / Reservatórios e Gestão / Mestre em Ciências e Engenharia de Petróleo

Production in Canada’s oil sands has been increasing, with a projected rate of 4.5 million barrels per day by 2025. Two production techniques are currently used, mining and in-situ, with the latter projected to constitute ~57% of all production by that time. Although in-situ extraction methods such as Steam Assisted Gravity Drainage (SAGD) are less invasive than mining, they result in more greenhouse gas (GHG) emissions per barrel and require large amounts of water that must be treated and recycled with a make-up water requirement of about 10%. CanmetENERGY is developing a steam generation technology called the High Pressure Oxy-fired Direct Contact Steam Generator (HiPrOx/DCSG, or DCSG for short) that will reduce these water requirements and sequester GHGs. This study evaluates the technical feasibility of this technology using process simulations, bench-scale testing, and pilot-scale testing. At first, a method in which to integrate the DCSG into the SAGD process was presented and process modeling of expected system performance was undertaken. The process simulations indicated that DCSG decreased the energy intensity of SAGD by up to 7.6% compared to the base SAGD case without carbon capture and storage (CCS), and up to 12.0% compared to the base SAGD case with CCS. Bench-scale testing was then performed using a pressurized thermogravimetric analyzer (PTGA) in order to investigate the effects of increased pressure and high moisture environments on a Canadian lignite coal char’s reactivity. It was found that under reaction kinetic-controlled conditions at atmospheric pressure, the increased addition of steam led to a reduction in burning time. The findings may have resulted from the lower heat capacity and higher thermal conductivity of steam compared to CO2. At increased pressures, CO2 inhibited burnout due to its higher heat capacity, lower thermal conductivity, and its effect on C(O) concentrations on the particle surface. When steam was added, the inhibiting effects of CO2 were counteracted, resulting in burnout rates similar to pressurized O2/N2 environments. These preliminary results suggested that the technology was feasible at a bench-scale level. Conflicting literature between bench-scale and pilot-scale studies indicated that pilot-scale testing would be advantageous as a next step. At the pilot-scale, testing was performed using n-butanol, graphite slurry, and n-butanol/graphite slurry mixtures covering lower and upper ends in fuel reactivity. It was found that stable combustion was attainable, with high conversion efficiencies in all cases. With the n-butanol, it was possible to achieve low excess oxygen requirements, which minimizes corrosion issues and reduce energy requirements associated with oxygen generation. With graphite slurry, it was found that it was possible to sustain combustion in these high moisture environments and that high conversion was achieved as indicated by the undetectable levels of carbonaceous materials observed in downstream equipment. Overall, these studies indicate that DCSG is technically feasible from the perspectives of energy and combustion efficiencies as well as from a steam generation point of view. Future work includes the investigation of possible corrosion associated with the product gas, the effect of CO2 on bitumen production, the nature of the mineral melt formed by the deposition of the dissolved and suspended solids from the water in the combustor, and possible scaling issues in the steam generator and piping associated with mineral deposits from the dissolved and suspended solids in the produced water is recommended.

A 16×16×5.6 in. scaled, three-dimensional, physical model of a quarter of a 9-spot pattern was constructed to study the application of two processes designed to improve the efficiency of steam injection. The first process to be tested is the use of propane as a steam additive with the purpose of increasing recovery and accelerating oil production. The second process involves the use of a novel production configuration that makes use of a vertical injector and a smart horizontal producer in an attempt to mitigate the effects of steam override. The experimental model was scaled using the conditions in the San Ardo field in California and crude oil from the same field was used for the tests. Superheated steam at 190 – 200ºC was injected at 48 cm3/min (cold water equivalent) while maintaining the flowing pressures in the production wells at 50 psig. Liquid samples from each producer in the model were collected and treated to break emulsion and analyzed to determine water and oil volumes. Two different production configurations were tested: (1) a vertical well system with a vertical injector and three vertical producers and (2) a vertical injector-smart horizontal well system that consisted of a vertical injector and a smart horizontal producer divided into three sections. Runs were conducted using pure steam injection and steam-propane injection in the two well configurations. Experimental results indicated the following. First, for the vertical configuration, the addition of propane accelerated oil production by 53% and increased ultimate recovery by an additional 7% of the original oil in place when compared to pure steam injection. Second, the implementation of the smart horizontal system increased ultimate oil recovery when compared to the recovery obtained by employing the conventional vertical well system (49% versus 42% of the OOIP).