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Abstract VAPEX (vapour extraction) is an oil recovery process, in which heavy oil or bitumen is mobilized by injection of a low molecular weight hydrocarbon solvent and is drained by gravity to a horizontal production well. It has attracted considerable attention because of its potential applicability to problematic reservoirs and the potential for in-situ upgrading of heavy oil during the process. Oil drainage rate under VAPEX is controlled by the viscosity of solvent diluted oil and can be affected substantially by de-asphalting. In-situ de-asphalting can be advantageous because it reduces the oil viscosity and leads to production of upgraded oil. However, the precipitated asphaltenes can also plug the pores of the formation and cause severe damage to the permeability. The objective of the current work was to determine whether the beneficial effects of asphaltene precipitation would outweigh any formation damage. The effects of in-situ precipitation and deposition of asphaltenes on the rate of oil drainage and the quality of the produced oil under different operating conditions were experimentally evaluated. The experiments were conducted in a physical model, packed with 140 - 200 mesh sand, and propane was used as the solvent. The quality of the produced oil samples was evaluated through the SARA technique and viscosity measurements. The experimental results show that the oil produced at higher injection pressures was substantially upgraded, but the viscosity reduction by asphaltene precipitation did not lead to higher production rates. The effect of viscosity reduction was negated by the accompanying damage to formation permeability. The huff and puff injection of toluene into the production well, to remove damage from the near well zone, was tried but proved to be ineffective. It led to production of oil with higher asphaltene content with no improvement in the rate of oil production compared to the lower pressure operation without asphaltene precipitation. However, co-injection of toluene with propane was successful in increasing the rate of production and the extent of upgrading obtained was encouraging.
- North America > United States (0.68)
- Asia (0.68)
- North America > Canada > Alberta (0.29)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Abstract Solvent-based heavy oil recovery methods are of interest as environmentally friendly alternatives for thermal techniques. The phase behaviour data from a heavy oil/solvent system are important information required for feasibility studies and numerical simulation of such processes. The scarcity of experimental data in the literature is a challenge in modelling of solvent involving processes. The variety of the solvent/oil mixtures, which are being evaluated within ongoing researches such as the VAPEX (vapour extraction of heavy oil) process, requires accurate description of the system's pressure, volume and temperature (PVT) properties. In this study, an experimental setup was designed to perform a series of PVT experiments and viscosity measurements. The results of the PVT tests conducted with the Frog Lake heavy oil and butane as a solvent are presented. The same oil/solvent pair was used in the VAPEX experiments previously reported by the authors. The measurements include the solvent solubility in the oil, mixture density and mixture viscosity at different saturation pressures. To simulate the phase behaviour of the system, an equation of state (EOS) was tuned using the measured experimental data and a phase behaviour package (WINPROP). The predicted densities and saturation pressures by the EOS are in very good agreement with the experimental data. A mixing viscosity correlation was also tuned with the measured data and found to be representative for describing the viscosity of the system. The viscosity data were compared with the predictions of several other available correlations, and it was shown that Shu's model reproduces acceptable data for reservoir simulation purposes. Introduction Solvent-involving recovery processes have recently gained some attention. These processes often involve relatively light hydrocarbon solvents such as C3 - C7, which are sometimes co-injected with non-condensable gases such as CO2, CH4 and N2. Numerical simulation studies of such processes are, however, in early stages to investigate the feasibility of field implementation, improvement and optimization. Numerical modelling of these processes is mostly performed on compositional simulators to capture the potential compositional changes, asphaltene precipitation and diffusion/dispersion mechanisms. Phase behaviour of the heavy oil/solvent system is one of the most vital pieces of input data that can be predicted and produced by either a series of k values or a tuned EOS. Nonetheless, both methods rely on accurate experimental phase behaviour information.
Abstract The motion and shape of a liquid drop through another continuous liquid phase (conveying phase) in a vertical Hele-Shaw cell with two different apertures were investigated experimentally. Two different liquid/liquid systems were tested. In all cases, the continuous phase was more viscous and wetted the bounding walls. In the capillarity-dominated region, the irregular shape of the discontinuous phase changed with time and distance, with much lower velocity than that of the conveying phase. In contrast to gas/liquid systems, the velocity of these stabilized, elongated drops was 2.5 to almost 5 times higher than that of conveying liquid. Despite the similarities between flow in vertical and horizontal Hele-Shaw cells, the velocity of droplets in a vertical fracture is different from that of a horizontal fracture. A new correlation is derived from dimensionless analysis and the experimental data to predict the elongated drop velocity as a function of the dimensionless parameters governing the system. Introduction Two-phase flow in micro-fractures is fundamental to many different fields of advanced science and technology, such as chemical process engineering, bioengineering, medical and genetic engineering, as well as petroleum engineering. For instance, understanding the flow of two-phase fluids in near-parallel gaps through fractured rocks has a significant effect on design of different recovery methods for naturally fractured reservoir. The flow pattern of two-phase immiscible flow in a fracture depends on the flow rates of the phases, the geometry, aperture, roughness of the fracture, the flow properties of the phases and interfacial tension between the phases. The flow patterns in a fracture are different from that in macro-sized rectangular ducts or pipes because of the small aperture, which can enhance capillary effects. The flow structure in the fracture affects the flow and transport through the surrounding porous matrix blocks. The slug flow pattern in a fracture, which occurs over a wide range of parameters, is frequently encountered in oil-wet fractured reservoirs during the immiscible displacement of viscous oil. It also occurs in natural gas reservoirs during displacement of water during gas production.
Abstract Heavy oil and bitumen are expected to become increasingly important sources of fuel in the coming decades. SAGD is a commercially viable and widely used recovery technique for heavy oil and bitumen. However, it remains an expensive technique and requires large energy input in the form of steam. Energy intensity of SAGD, environmental concerns and the threat of a carbon tax make it imperative to find new oil extraction technologies. Co-injecting a hydrocarbon additive with steam offers the potential of higher oil rates and recoveries with lower energy and water consumption. A reservoir simulation study using a 20?12?15 3D Cartesian model and Athabasca fluid and reservoir properties was conducted to evaluate this hybrid process. The role of hydrocarbon additive in the steam chamber and its effect on the performance of SAGD was investigated. Simulation results revealed the parameters that will have the greatest impact on the process performance and determined the effectiveness of each hydrocarbon additive in improving the performance of SAGD. The results also showed that selecting the most suitable hydrocarbon additive depends on the operating condition as well as the original reservoir fluid composition. Introduction Over 90% of the world's heavy oil and bitumen trapped in sandstones and carbonates are deposited in Canada and Venezuela. There are extensive deposits in Alberta that can be the principal source of fuel in the coming century. The Athabasca Oil Sands, the largest petroleum accumulation in the world, are deposits of heavy oil and bitumen which mostly occur at depths that are suitable for in-situ bitumen extraction. At original condition, the viscosity of Athabasca bitumen is over one million centipoises. The key parameter to produce this bitumen is to lower its viscosity and mobilize it to the production well. There are two main techniques for the reduction of bitumen viscosity: first is to increase heavy oil temperature, and second is to dilute the viscous bitumen by lighter hydrocarbon solvents. The Steam Assisted Gravity Drainage (SAGD) process was developed to recover heavy oil and bitumen by draining the heated oil from around the growing steam chamber, driven by gravity, to the production well2. In this method, steam is injected into the reservoir via a horizontal well. Injected steam forms a steam chamber in the depleted area of the reservoir and this steam chamber grows upward and laterally as the process advances. At the edge of steam chamber, bitumen has extended contact with steam, where steam releases its latent heat to the bitumen and increases its temperature. Further, at the edges of the steam chamber, heated oil and steam condensate drain, forced by gravity, to the horizontal production well, positioned 5 m to 10 m below and parallel to the injection well. Figure 1 displays a cross section of the steam chamber and injection and production well. This method is taking advantage of temperature for lowering the viscosity of heavy oil. Figure 2 shows the effect of temperature on the viscosity of Athabasca bitumen which was plotted by using Mehrotra and Svrcek3 correlation, Equation 1.
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.60)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract The solubility of pure carbon dioxide in Athabasca bitumen was measured and compared with the literature data. Multiple liquid phases were observed at carbon dioxide contents above approximately 12 wt%. A correlation based on Henry's law was found to fit the saturation pressures at carbon dioxide contents below 12 wt%. The saturation pressure and solubility of carbon dioxide and propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for three ternary mixtures at temperatures from 10 to 25 °C. Two liquid phases (carbon dioxide-rich and bitumen-rich) were observed at 13 wt% carbon dioxide and 19 wt% propane. Only liquid and vapour-liquid regions were observed for the other two mixtures (13.5 wt% propane and 11.0 wt% carbon dioxide; 24.0 wt% propane and 6.2 wt% carbon dioxide). The saturation pressures for the latter mixtures were predicted using the correlation for the carbon dioxide partial pressure and a previously developed correlation for the propane partial pressure. The mixture viscosities were predicted with the Lobe mixing rule. Introduction In Part I of this work, mixtures of carbon dioxide and propane were identified as a potential solvent for the VAPEX process. At typical heavy oil reservoir conditions (pressure of ~1.2 MPa and temperature of ~10 °C), propane and butane have sufficient solubility to reduce the oil viscosity to a level where gravity drainage can occur in an economic time scale. However, propane and butane are expensive solvents and the success of the process depends on how much solvent can be recovered. As well, the VAPEX process operates below the saturation pressure of the solvent and, therefore, propane and butane cannot be used at higher reservoir pressures where they exist only in the liquid phase. Methane can be added to achieve the desired pressures. However, carbon dioxide may also be a better VAPEX solvent than methane because it is more soluble in heavy oil and significantly reduces the viscosity. Mixtures of carbon dioxide and propane may achieve the desired reduction in viscosity while minimizing the required propane volumes. Hence, there is an incentive to evaluate mixtures of carbon dioxide and propane as a VAPEX solvent. VAPEX performance depends on the viscosity and density of the liquid phase that forms at the edge of the vapour chamber. In order to design and optimize VAPEX and other solvent-based processes, it is critical to be able to determine the diffusivity of the solvent in the heavy oil, identify the phases that form in the solvent and heavy oil mixtures at various temperatures and pressures, and determine the density and viscosity of the liquid phase. Other solvent-based processes (steam and solvent injection for heavy oil recovery and solvent extraction of oil sands) require similar data. In Part I of this work, saturation pressures and liquid phase densities and viscosities were measured for propane and Athabasca bitumen. There are also considerable data in the literature for mixtures of carbon dioxide and crude oils. Simon and Graue measured the solubility, swelling and viscosity of mixtures of carbon dioxide and nine different oils.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract Some heavy oil reservoirs under solution gas drive show abnormally high final recoveries. One of the mechanisms to explain these phenomena is the foamy oil flow effect which occurs under certain operating conditions. It has been studied extensively, yet remains poorly understood and difficult to model. The objective of this work was to investigate the effect of oil foaminess on the performance of solution gas drive in heavy oil reservoirs. In this research, the first step was to find a foaming agent that will have a measurable effect on foam stability of a viscous mineral oil. A simple experimental procedure was developed to quantify the oil foaminess in the presence of an added foaming agent. Several depletion tests were conducted with the added foaming agent at different depletion rates using a two metre long sandpack. The experimental results showed that the increased foaminess of oil did not have a significant effect on the solution gas drive performance when the depletion rate was high. However, in a slow depletion test, the effect of oil foaminess was significant. Introduction With high oil prices and the continuous decline of conventional resources, attention is shifting towards heavy oil in many parts of the world. Six to nine trillion barrels, or more than two-thirds of the world's oil resources, are heavy viscous crudes that remain difficult to produce. Heavy oil promises to play a major role in the future of the oil industry. Therefore, understanding heavy oil behaviour and improving the recoveries in heavy oil reservoirs is crucial to meeting future energy demand. The high viscosity of heavy oils, typically in the range of 500 to 50,000 cP, results in low recovery factors in primary production. However, some Canadian heavy oil reservoirs produce more than what is expected by the conventional analogs. Primary recovery from these reservoirs could be as high as 15%. In conventional solution gas drive, the gas evolves in the pore space and connects with the gas in the other pores forming a free continuous gas resulting in higher gas rates. In heavy oil reservoirs, the gas bubbles tend to remain dispersed within the viscous oil because of the high viscosity, low diffusion rates and higher pressure gradients. This behaviour results in higher oil rates, lower gas-oil ratios and slower pressure decline within the reservoir. The production from this type of reservoir is usually accompanied by sand. The two-phase flow of oil and dispersed gas bubbles is usually referred to as foamy oil flow. Smith appears to be the first researcher who provided an analysis to the anomalous behaviour of the heavy oil reservoirs under solution gas drive using field data. The most common techniques used to produce heavy oil from underground formations involve thermal recovery processes. However, extensive developments in Canada in the period from 1985 to 2005 have resulted in several new heavy oil exploitation technologies. One of the major new technologies in the last two decades is cold heavy oil production with sand (CHOPS).
- North America > United States (0.93)
- North America > Canada (0.67)
Abstract The saturation pressure and solubility of propane in Athabasca bitumen, as well as the liquid phase densities and viscosities, were measured for temperatures from 10 to 50 °C. Equilibration proved challenging for this fluid mixture and required some experimental modifications that are discussed. Only liquid and liquid-vapour phase regions were observed at propane contents below 20 wt%. A second liquid phase appeared to have formed at higher propane contents. The saturation pressures, where only a single dense phase formed, ranged from 600 to 1,600 kPa and these were fitted with a modification to Raoult's law. Viscosities less than 210 mPa.s were obtained at a propane content of 15.6 wt%. All of the viscosity data of the liquid phase were predicted from the propane and bitumen viscosities using the Lobe mixing rule. Introduction The worldwide original oil-in-place (OOIP) of heavy oil and bitumen is estimated to be approximately 6 trillion barrels. A major part of these resources are in Canada (~36%) and Venezuela (~27%). In Canada, steam-based methods are often employed to improve heavy oil recovery. However, the industry is starting to seek alternatives to these methods because they are energy intensive and are drawing heavily on the available water supply. Solvent-based recovery methods are a potential alternative capable of providing high recovery factors without substantial water requirements. One option is the vapour extraction method (VAPEX), which is a solvent-based analogue of the Steam-Assisted Gravity Drainage (SAGD) process. VAPEX is implemented with a pair of horizontal wells: a production well at the bottom of the reservoir and a solvent injection well located directly above the production well, as shown in Figure 1. The vapourized solvent is injected through the injection well and a chamber of solvent vapour forms around the well. At the walls of the chamber, the solvent diffuses into a surface layer of the heavy oil and dramatically reduces its viscosity. The diluted oil layer is then mobile enough to drain down, under the influence of gravity, into the production well. VAPEX performance depends on the viscosity and density of the liquid phase that forms at the edge of the solvent chamber. In order to design and optimize VAPEX and other solvent-based processes, it is critical to be able to determine the diffusivity of the solvent in the heavy oil, identify the phases that form in the solvent and heavy oil mixtures at various temperatures and pressures, and determine the density and viscosity of the liquid phase. Other solvent-based processes (steam and solvent injection for heavy oil recovery and solvent extraction of oil sands) require similar data. Most research on VAPEX has focused on physical model experiments with light alkane solvents; particularly mixtures of methane and propane. However, mixtures of carbon dioxide and propane may be a more viable option. Currently, carbon dioxide is expensive, but costs are expected to decrease if environmental incentives to sequester carbon dioxide are introduced. Carbon dioxide may also be a better VAPEX solvent than methane because it is more soluble in heavy oil and reduces the viscosity more.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Facilities Design, Construction and Operation > Unconventional Production Facilities > Oil sand/shale/bitumen (1.00)
Abstract The motion and shape of a liquid drop through another continuous liquid phase (conveying phase) in a vertical Hele- Shaw cell with different two different apertures were investigated experimentally. Two different liquid-liquid systems were tested. In all cases, the continuous phase was more viscous and wetted the bounding walls. In the capillarity-dominated region, the irregular shape of the discontinuous phase changed with time and distance, with much lower velocity than that of the conveying phase. In contrast to gas-liquid systems, the velocity of these stabilized elongated drops was 2.5 to almost 5 times higher than that of conveying liquid. Despite the similarities between flow in vertical and horizontal Hele-Shaw cell, the velocity of droplets in vertical fracture is different from that of horizontal fracture. A new correlation is derived from dimensionless analysis and the experimental data to predict the elongated drop velocity as a function of the dimensionless parameters governing the system. Introduction Two-phase flow in micro-fractures is fundamental to many different fields of advanced science and technology, such as chemical process engineering, bioengineering, medical and genetic engineering as well as petroleum engineering. For instance understanding the flow of two-phase fluids in near parallel gaps through fractured rocks has a significant effect on design of different recovery methods for naturally fractured reservoir. The flow pattern of two-phase immiscible flow in a fracture depends on the flow rates of the phases, the geometry, aperture, and roughness of the fracture, the flow properties of the phases, and interfacial tension between the phases. The flow patterns in a fracture are different from that in macro size rectangular ducts or pipes due to the small aperture, which can enhance capillary effects. The flow structure in the fracture affects the flow and transport through the surrounding porous matrix blocks. The slug flow pattern in a fracture, which occurs over a wide range of parameters, is frequently encountered in oil-wet fractured reservoirs during the immiscible displacement of viscous oil. It also occurs in natural gas reservoirs during displacement of water during gas production. In the case of a smooth-walled fracture, the slug shape can be regular elongated drops (or bubbles) flowing through the conveying phase. The elongated drops (or bubbles) can have a rounded leading edge and occupy a considerable portion of the gap with length of several times to several hundred times that of the gap. The behavior of single elongated drops (or bubbles) through a continuous liquid phase problem is as rich and complex as the viscous fingering problem6. The conditions corresponding to a swarm of the elongated drops can be inferred by considering the behavior of a single drop (bubble) and their conglomeration. The interaction of many drops or bubbles across the flow cross section can also be inferred from single drop or bubble dynamics. A firm understanding of the behavior of drop or bubble flow in a single fracture is prerequisite to build predictive models for flow in complex fracture systems.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
Abstract The VAPEX (vapor extraction) is an oil recovery process, in which heavy oil or bitumen is mobilized by injection of a low molecular weight hydrocarbon solvent and is drained by gravity to a horizontal production well. It has attracted considerable attention because of its potential applicability to problematic reservoirs and the chance of in situ upgrading of the oil during the process. Oil drainage rate under Vapex is controlled by the viscosity of solvent diluted oil and can be affected substantially by deasphalting. In situ de-asphalting can be advantageous since it reduces the oil viscosity and leads to production of upgraded oil. However, the precipitated asphaltenes can also plug the pores of the formation and cause severe damage to the permeability. The objective of the current work was to determine whether the beneficial effects of asphaltene precipitation will outweigh any formation damage. The effects of in situ precipitation and deposition of asphaltenes on the rate of oil drainage and the quality of the produced oil under different operating conditions were experimentally evaluated. The experiments were conducted in a physical model packed with realistic permeability sand and propane was used as the solvent. The quality of the produced oil samples was evaluated through the SARA technique and viscosity measurements. To reduce the formation damage problem and resulting production restrictions from the deposition of precipitated asphaltenes, injection of a mixture of an asphaltene dissolving liquid solvent (toluene) and vaporized solvent (propane) was tested. Periodical cleaning of the production well with toluene injection was also evaluated. The performance of butane was compared with that of propane to see how the solvent affectsasphaltene deposition. The experimental results show that the oil produced at higher injection pressures was substantially upgraded but the viscosity reduction by asphaltene precipitation did not lead to higher rates of production. The effect of viscosity reduction was negated by the accompanying damage to formation permeability. Injection of toluene with propane was successful in increasing the rate of production and the extent of upgrading was encouraging. The huff and puff injection of toluene into the production well, to remove damage from the near well zone, was not successful. It led to production of oil with higher asphaltene content and there was no improvement in the rate of oil drainage compared to lower pressure operation with minimal asphaltene precipitation Introduction The heavy oil and bitumen reservoirs of Canada are one of the largest hydrocarbon resources in the world. The estimated original oil-in-place of the Canadian formations is more than 400 billion m3 which is almost twice of the total conventional oil reserves of the Middle East1. Being highly viscous and immobile in their original state, heavy oil and bitumen cannot be effectively recovered through primary and secondary recovery methods. To recover oil from the heavy oil and bitumen deposits, EOR (Enhanced Oil Recovery) methods which mostly act through viscosity reduction by means of heating or dilution, have been implemented. CSS (Cyclic Steam Stimulation), ISC (In-Situ Combustion), SAGD (Steam Assisted Gravity Drainage) and solvent injection based techniques are examples of these methods.
- North America > United States > Texas (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- (3 more...)
Abstract The design and optimization of solvent based processes to recover heavy oil are hampered by limited data and modeling capability for mixtures of heavy oils and solvents. Phase boundaries, compositions, and physical properties such as viscosity and density are required. Here, mixtures of propane and CO with Athabasca bitumen are considered. Saturation pressures were measured in a PVT cell and the density and viscosity of the saturated liquid phase were determined at temperatures between 0 and 90 °C and pressures up to 5 MPa. Data are reported for CO-bitumen, propane-bitumen and three propane-CO-bitumen mixtures. Vapour-liquid and some liquidliquid and vapour-liquid-liquid phase boundaries were determined. Regions where multiple liquid phase formation is likely were identified. A simple analytical methodology for determining the vapour-liquid phase boundary for each mixture was developed. Introduction In Canada, steam based methods are often employed to improve heavy oil recovery. However, the industry is seeking alternatives to these methods because they are energy intensive and are drawing heavily on the available water supply. Solvent based recovery methods are a potential alternative capable of providing high recovery factors without high waterrequirements. One option is the vapor extraction method(Vapex), which is a solvent-based analogue of the steam assisted gravity drainage (SAGD) process. Vapex is implemented with a pair of horizontal wells: a production well at the bottom of the reservoir and a solvent injection well located directly above the production well. The vaporized solvent is injected through the injector and a chamber of solvent vapour forms around the well. At the walls of the chamber, the solvent diffuses into a surface layer of the heavy oil and dramatically reduces its viscosity. The diluted oil layer is then mobile enough to drain down, under the influence of gravity, into the production well. VAPEX performance depends on the viscosity and density of the liquid phase that forms at the edge of the solvent chamber. In order to design and optimize VAPEX and other solvent based processes, it is critical to be able to: determine the diffusivity of the solvent in the heavy oil; identify the phases that form in the solvent and heavy oil mixtures at various temperatures and pressures; determine the density and viscosity of the liquid phase. Other solvent-based processes (steam and solvent injection for heavy oil recovery and solvent extraction of oil sands) require similar data. Most research on Vapex has focused on physical model experiments with light alkane solvents, particularly mixtures of methane and propane . However, mixtures of carbon dioxide and propane may be a more viable option. Currently, carbon dioxide is expensive but costs are expected to decrease if environmental incentives to sequester carbon dioxide are introduced. Carbon dioxide may also be a better Vapex solvent than methane because it is more soluble in heavy oil and reduces the viscosity more . However, at typical heavy oil reservoir conditions , propane and butane have higher solubility and provide greater viscosity reduction than carbon dioxide.
- North America > Canada (0.68)
- North America > United States > New York (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)