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.

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.

The extraction of mercury species (methylmercury, ethylmercury, phenylmercury and inorganic mercury(II)) from fish tissue, its determination by reverse phase HPLC, UV-photochemical generation of cold vapour, and detection by atomic absorption spectrometry is described in this work. Various extraction agents and digestion methods were compared in order to find the best alternative. The mixture of 6.25% tetramethylammonium hydroxide and 0.05 mol·l-1 hydrochloride acid was chosen as the best extraction agent. In addition to the high extraction efficiency, the solution involved positively not only UV-photochemical generation, but also separation of observed species. On the contrary, the poor repeatability was achieved with the microwave-assisted digestion due to the proved sorption of mercury species on the Teflon vessels. Therefore, the extraction by high temperature (50-60 řC) in glass bottles was preferred. The results of the determination of the mercury species after the extraction from the real samples were compared to the outcomes obtained by AMA 254. The proposed extraction technique together with the RP-HPLC-UV-CVG-QTAAS is suitable for the speciation analysis of mercury.

Canada has the second largest proven oil reserves next to Saudi Arabia which is mostly located in Alberta and Saskatchewan but is unconventional heavy oil and bitumen. The tar sands are found at the surface and are mined, yet 80% of the 173 billion barrels of heavy oil and bitumen exist in-situ according to the Canadian Association of Petroleum Producers (CAPP). Two factors inhibit the economic extraction and processing of Canadian heavy oil; its enormous viscosity ranging from 1000 to over 1 million mPa.s and the asphaltene content (high molecular weight molecules containing heavy metals and sulphur). Heavy oil and bitumen were only included in the reserves estimates through the efforts of Canadian enhanced oil recovery (EOR) research. Viscosity reduction is the one common element of in-situ methods of heavy oil recovery with the exception of cold production. Currently, steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are being used commercially in the field where the oil’s viscosity is reduced by injecting steam. Thermal methods are energy intensive requiring vast volumes of water such that any improvement would be beneficial. Solvent extraction is one alternative requiring no water, the solvent is recoverable and reusable, and depending on the mode of operation the heavy oil is upgraded in-situ. Vapour Extraction (VAPEX) and enhanced solvent extraction (N-SolvTM) are two such methods. VAPEX and N-Solv reduce the bitumen’s viscosity via mass transfer and a combination of mass and heat transfer, respectively. A light hydrocarbon solvent (instead of steam) is injected into an upper horizontal well where the solvent mixes with the heavy oil, reduces its viscosity and allows the oil to drain under gravity to a bottom production well. The idea of using solvents for heavy oil extraction has been around since the 1970s and both VAPEX and N-Solv are patented processes. However, there is still much to be learned about how these processes physically work. Research to date has focused on varying system parameters (including model dimensions, permeability, heavy oil viscosity, solvent type and injection rate, etc.) to observe the effect on oil production from laboratory scale models. Based on an early mass balance model by Butler and Mokrys (1989) and an improvement by Das (1995), molecular diffusion alone cannot account for the produced oil rates observed from laboratory models. Until recently, very little progress had been made towards qualifying and quantifying the mass transfer mechanisms with the exception of the diffusivity of light hydrocarbons in heavy oil. Mass transfer can only be by diffusion and convection. Differentiating and quantifying the contribution of each is complex due to the nature and viscosity of the oil. The goal of this thesis is to investigate the mass transfer mechanisms during the solvent recovery of heavy oil. Quantifying the diffusion of light hydrocarbon solvents has been an active topic of research with limited success since the mid 1990’s. The experimental approach presented here focused on capturing the rate of solvent mass transfer into the bitumen by measuring the bitumen swelling and the butane uptake independently. Unlike early pressure decay methods, the pressure is held constant to not violate the assumed equilibrium solvent concentration at the interfacial boundary condition. The high solubility of solvent in heavy oil complicates the physical modeling because simplifying assumptions of a constant diffusion coefficient, constant density and a quiescent liquid should not be used. The model was developed from first principles to predict the bitumen swelling. The form of the concentration dependent diffusivity was assumed and the diffusivity coefficients initially guessed. The swelling (moving boundary) was fixed by defining a new dimensionless space coordinate and the set of partial differential equations solved using the method of lines. Using the non-linear regression (lsqnonlin) function in MATLAB®, optimising for the difference in predicted and experimentally found bitumen heights and independently validating the result using the solvent uptake, the diffusivity of butane in heavy oil (at 25oC) was found to be Dsb = 4.78 x 10-6ωs + 4.91 x 10-6 cm2/s where ωs is the solvent mass fraction. Diffusion alone has proven inadequate in predicting oil recovery rates from laboratory scale models. It is logical to assume that convective mass transfer plays a role at mixing the solvent and bitumen while draining via gravity through the reservoir porous matrix. Solvent extraction experiments were conducted in etched glass micromodels to observe the pore scale phenomena. The pore scale mechanisms were found to differ depending on how the solvent extraction was operated, with non-condensing (VAPEX) or condensing (N-SolvTM) solvent. Observations show increased convective mixing and an increased rate of interface advancement when the solvent condenses on the bitumen surface. Evidence of trapped butane vapour being mobilised with the draining live oil and a technique of observing solvent extraction using UV light confirm that the draining live oil is on average one pore deep. While the interface appears from a distance to be uniform, at the pore scale it is not. Live oil can drain from one to two pores via capillary displacement mechanisms in one section of the interface and via film flow only in another area (James and Chatzis 2004; James et al. 2008). This work also shows the detrimental impact of having a non-condensable gas present during solvent extraction (James and Chatzis 2008). In summary, this work emphasises the mass transfer and drainage displacement mechanisms of non-condensing (VAPEX) and condensing (N-Solv) solvent extraction methods of heavy oil recovery.

Canada has the second largest proven oil reserves next to Saudi Arabia which is mostly located in Alberta and Saskatchewan but is unconventional heavy oil and bitumen. The tar sands are found at the surface and are mined, yet 80% of the 173 billion barrels of heavy oil and bitumen exist in-situ according to the Canadian Association of Petroleum Producers (CAPP). Two factors inhibit the economic extraction and processing of Canadian heavy oil; its enormous viscosity ranging from 1000 to over 1 million mPa.s and the asphaltene content (high molecular weight molecules containing heavy metals and sulphur). Heavy oil and bitumen were only included in the reserves estimates through the efforts of Canadian enhanced oil recovery (EOR) research. Viscosity reduction is the one common element of in-situ methods of heavy oil recovery with the exception of cold production. Currently, steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) are being used commercially in the field where the oil’s viscosity is reduced by injecting steam. Thermal methods are energy intensive requiring vast volumes of water such that any improvement would be beneficial. Solvent extraction is one alternative requiring no water, the solvent is recoverable and reusable, and depending on the mode of operation the heavy oil is upgraded in-situ. Vapour Extraction (VAPEX) and enhanced solvent extraction (N-SolvTM) are two such methods. VAPEX and N-Solv reduce the bitumen’s viscosity via mass transfer and a combination of mass and heat transfer, respectively. A light hydrocarbon solvent (instead of steam) is injected into an upper horizontal well where the solvent mixes with the heavy oil, reduces its viscosity and allows the oil to drain under gravity to a bottom production well. The idea of using solvents for heavy oil extraction has been around since the 1970s and both VAPEX and N-Solv are patented processes. However, there is still much to be learned about how these processes physically work. Research to date has focused on varying system parameters (including model dimensions, permeability, heavy oil viscosity, solvent type and injection rate, etc.) to observe the effect on oil production from laboratory scale models. Based on an early mass balance model by Butler and Mokrys (1989) and an improvement by Das (1995), molecular diffusion alone cannot account for the produced oil rates observed from laboratory models. Until recently, very little progress had been made towards qualifying and quantifying the mass transfer mechanisms with the exception of the diffusivity of light hydrocarbons in heavy oil. Mass transfer can only be by diffusion and convection. Differentiating and quantifying the contribution of each is complex due to the nature and viscosity of the oil. The goal of this thesis is to investigate the mass transfer mechanisms during the solvent recovery of heavy oil. Quantifying the diffusion of light hydrocarbon solvents has been an active topic of research with limited success since the mid 1990’s. The experimental approach presented here focused on capturing the rate of solvent mass transfer into the bitumen by measuring the bitumen swelling and the butane uptake independently. Unlike early pressure decay methods, the pressure is held constant to not violate the assumed equilibrium solvent concentration at the interfacial boundary condition. The high solubility of solvent in heavy oil complicates the physical modeling because simplifying assumptions of a constant diffusion coefficient, constant density and a quiescent liquid should not be used. The model was developed from first principles to predict the bitumen swelling. The form of the concentration dependent diffusivity was assumed and the diffusivity coefficients initially guessed. The swelling (moving boundary) was fixed by defining a new dimensionless space coordinate and the set of partial differential equations solved using the method of lines. Using the non-linear regression (lsqnonlin) function in MATLAB®, optimising for the difference in predicted and experimentally found bitumen heights and independently validating the result using the solvent uptake, the diffusivity of butane in heavy oil (at 25oC) was found to be Dsb = 4.78 x 10-6ωs + 4.91 x 10-6 cm2/s where ωs is the solvent mass fraction. Diffusion alone has proven inadequate in predicting oil recovery rates from laboratory scale models. It is logical to assume that convective mass transfer plays a role at mixing the solvent and bitumen while draining via gravity through the reservoir porous matrix. Solvent extraction experiments were conducted in etched glass micromodels to observe the pore scale phenomena. The pore scale mechanisms were found to differ depending on how the solvent extraction was operated, with non-condensing (VAPEX) or condensing (N-SolvTM) solvent. Observations show increased convective mixing and an increased rate of interface advancement when the solvent condenses on the bitumen surface. Evidence of trapped butane vapour being mobilised with the draining live oil and a technique of observing solvent extraction using UV light confirm that the draining live oil is on average one pore deep. While the interface appears from a distance to be uniform, at the pore scale it is not. Live oil can drain from one to two pores via capillary displacement mechanisms in one section of the interface and via film flow only in another area (James and Chatzis 2004; James et al. 2008). This work also shows the detrimental impact of having a non-condensable gas present during solvent extraction (James and Chatzis 2008). In summary, this work emphasises the mass transfer and drainage displacement mechanisms of non-condensing (VAPEX) and condensing (N-Solv) solvent extraction methods of heavy oil recovery.