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Brij B Maini - One of the best experts on this subject based on the ideXlab platform.
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effect of temperature on Relative Permeability role of viscosity ratio
Fuel, 2020Co-Authors: Sajjad Esmaeili, Thomas G Harding, Jafar Modaresghazani, Hemanta K Sarma, Brij B MainiAbstract:Abstract Although there are many studies regarding the effect of temperature on Relative Permeability, there is no consensus on this issue. Here we examine the role of oil/water viscosity ratio in making the measured oil/water Relative Permeability dependent on temperature. Two-phase oil/water Relative Permeability was carefully measured over a wide range of temperature between 23 °C and 210 °C using a poly-alpha-olefin (PAO) oil and deionized water in a clean unconsolidated sand-pack at confining pressure of 800 psi. A sophisticated experimental setup that is capable of measuring the pressure drop and monitoring the temperature in four different length segments of the sand-pack was used. Both the Johnson, Bossler and Neumann (JBN) method and the history match approach were employed to obtain the Relative Permeability from the results of isothermal oil displacement tests. Furthermore, high-temperature and high-pressure interfacial tension (IFT) and contact angle measurements were also carried out. The results show that the two-phase oil/water Relative Permeability, in this ultra-clean system, is practically insensitive to the temperature, even though the oil/water viscosity ratio changes by two orders of magnitude. The slight variation in oil endpoint Relative Permeability and irreducible water saturation, especially at ambient condition, was attributed to the uncertainty in the oil viscosity measurement and reproducibility of the sand packing procedure. The IFT of this system declined from 41.1 mN/m at 23.5 °C to 20.9 mN/m at 185.2 °C and contact angle decreased from 80.7° at 23.5 °C to 56.9° at 150 °C. Changes of this level do not significantly affect the oil displacement behavior.
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two phase bitumen water Relative Permeability at different temperatures and sagd pressure experimental study
Fuel, 2020Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract The heavy oil or bitumen trapped in subterranean formations in Canada and North America can be effectively produced and recovered using thermal enhanced oil recovery (TEOR) techniques, especially steam assisted gravity drainage (SAGD) processes. Heating the formation to a high temperature greatly reduces the oil viscosity, which increases the oil mobility in the reservoir. In the SAGD process, the steam injected through a long horizontal well creates a steam saturated zone, called steam chamber, around the well that gradually expands laterally and vertically within the reservoir. The edge of the growing steam chamber is where the oil is displaced by the steam. There is a large temperature gradient in the oil drainage zone with steam temperature at the edge of the steam chamber and close to the original reservoir temperature on the other side of the drainage zone. The fluid flow behavior, which is controlled by Relative Permeability, can be sensitive to the temperature in this transition zone. The objective of this study was to investigate the impact of temperature on two-phase bitumen/water Relative Permeability of sand over a wide range of temperature from 70 to 220 °C. In the present study, isothermal displacement experiments were conducted with an advanced experimental rig under the confining pressure of 1400 psi using Athabasca bitumen, deionized water, and clean silica sand at six different temperatures. All experiments were repeated to ensure that the results are repeatable and reliable. The JBN (Johnson, Bossler and Neumann) method was used to obtain the two-phase Relative Permeability. The effect of temperature on Relative Permeability for the bitumen system was found to be substantial and should be accounted for in simulation of SAGD processes. The endpoint water Relative Permeability can increase by two orders of magnitude in going from the reservoir temperature to the steam temperature. The endpoint oil Relative Permeability also increases, albeit more modestly and the residual oil saturation decreases. Besides the Relative Permeability tests, contact angle and IFT measurements at high-temperature, high-pressure conditions were conducted to evaluate the fluid-fluid and rock-fluid interactions and examine any changes in wettability. According to the contact angle results, the wettability of system was water-wet and shifted toward strongly water-wet at higher temperatures. In addition, the IFT displayed a decreasing trend with temperature and reached the minimum value of 18 mN/m in the temperature range of 125–155 °C.
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correlations for effect of temperature on oil water Relative Permeability in clastic reservoirs
Fuel, 2019Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract For more than half a century, a large number of scholars have endeavored to delineate the effects of temperature on two-phase Relative Permeability curves using different oils and porous media. However, we still cannot predict how the Relative Permeability will change with temperature in a specific rock-fluid system. In fact, even a cursory review of the literature on the effect of temperature on oil/water Relative Permeability will show that a bewildering array of conflicting results have been reported. These inconsistent results are partly due to the likelihood that the effect of temperature is different in different rock-fluid systems and partly due to differences in the measurements techniques that can introduce varying experimental artifacts. The main objective of this study was to see whether some of the contradictions in the reported results would be resolved by examining the effects of temperature on Relative Permeability separately in different classes of rock-fluid systems. Another objective was to develop empirical correlations for estimating the value of oil/water Relative Permeability in different systems at higher temperatures. Reported results from a large number of experimental studies of the effect of temperature on Relative Permeability were collected to generate a large dataset of oil/water Relative Permeability curves. This dataset was partitioned into four parts representing four different classes of rock-fluid systems, namely: 1) light oil in unconsolidated sand, 2) heavy oil in unconsolidated sand, 3) light oil in consolidated sandstone and 4) heavy oil in consolidated sandstone. The effect of temperature on irreducible water saturation, residual oil saturation, the endpoint Relative Permeability to oil and water and the generalized Corey saturation exponents of oil and water were analyzed separately for each rock-fluid system. It was found that, although the scatter in reported data is large, some discernable differences are present in the effect of temperature in different rock fluid types. Separate correlations, in the form of generalized Corey saturation exponent model with temperature dependent parameters, were developed for oil/water Relative Permeability in different rock-fluid systems.
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a data driven model for predicting the effect of temperature on oil water Relative Permeability
Fuel, 2019Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract Several empirical models have been proposed by scholars to capture the temperature’s impact on Relative Permeability for a specific rock/fluid system, often using very limited dataset of measured Relative Permeability values, which makes these models inapplicable to a wider range of rock-fluid characteristics. The current study presents a new data-driven model to predict the two-phase oil/water Relative Permeability over a wide range of temperature in unconsolidated sand and sandstone formations. We found that the carbonate rock systems have different characteristics and the reported high temperature Relative Permeability data for them is limited, which prevented us from including them alongside the sand systems. For developing the model, the Least Square Support Vector Machine (LSSVM) in the form of a supervised learning approach was implemented, in which the coupled simulated annealing optimization technique was employed for calculation of LSSVM hyper-parameters. To gather a comprehensive dataset for constructing the model, 626 experimental oil Relative Permeability and 547 experimental water Relative Permeability data points were obtained from the open literature. To identify the doubtful data points (the outliers) the method of Leverage Value Statistics was applied. The temperature (ranging from 21 to 200 °C), water saturation, oil viscosity (ranging from 0.42 to 1190 cP), water viscosity (ranging from 0.136 to 1.1 cP), and the absolute Permeability (ranging from 152 to 95,000 mD) were used as the independent variables in the model. The statistical analysis of the obtained LSSVM for prediction of Relative Permeability demonstrated that the coefficient of determination, root mean square error, and average absolute error were 0.9987, 0.0111, and 5.36% for oil Relative Permeability and 0.9991, 0.0056, and 8.40% for water Relative Permeability. The comparison of statistical parameters of this model with other reported Relative Permeability models showed that this model is more reliable for estimating the oil and water Relative Permeability including its dependence on temperature and therefore it can be used for reservoir simulation studies, when experimentally measured data are not available.
Sajjad Esmaeili - One of the best experts on this subject based on the ideXlab platform.
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effect of temperature on Relative Permeability role of viscosity ratio
Fuel, 2020Co-Authors: Sajjad Esmaeili, Thomas G Harding, Jafar Modaresghazani, Hemanta K Sarma, Brij B MainiAbstract:Abstract Although there are many studies regarding the effect of temperature on Relative Permeability, there is no consensus on this issue. Here we examine the role of oil/water viscosity ratio in making the measured oil/water Relative Permeability dependent on temperature. Two-phase oil/water Relative Permeability was carefully measured over a wide range of temperature between 23 °C and 210 °C using a poly-alpha-olefin (PAO) oil and deionized water in a clean unconsolidated sand-pack at confining pressure of 800 psi. A sophisticated experimental setup that is capable of measuring the pressure drop and monitoring the temperature in four different length segments of the sand-pack was used. Both the Johnson, Bossler and Neumann (JBN) method and the history match approach were employed to obtain the Relative Permeability from the results of isothermal oil displacement tests. Furthermore, high-temperature and high-pressure interfacial tension (IFT) and contact angle measurements were also carried out. The results show that the two-phase oil/water Relative Permeability, in this ultra-clean system, is practically insensitive to the temperature, even though the oil/water viscosity ratio changes by two orders of magnitude. The slight variation in oil endpoint Relative Permeability and irreducible water saturation, especially at ambient condition, was attributed to the uncertainty in the oil viscosity measurement and reproducibility of the sand packing procedure. The IFT of this system declined from 41.1 mN/m at 23.5 °C to 20.9 mN/m at 185.2 °C and contact angle decreased from 80.7° at 23.5 °C to 56.9° at 150 °C. Changes of this level do not significantly affect the oil displacement behavior.
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two phase bitumen water Relative Permeability at different temperatures and sagd pressure experimental study
Fuel, 2020Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract The heavy oil or bitumen trapped in subterranean formations in Canada and North America can be effectively produced and recovered using thermal enhanced oil recovery (TEOR) techniques, especially steam assisted gravity drainage (SAGD) processes. Heating the formation to a high temperature greatly reduces the oil viscosity, which increases the oil mobility in the reservoir. In the SAGD process, the steam injected through a long horizontal well creates a steam saturated zone, called steam chamber, around the well that gradually expands laterally and vertically within the reservoir. The edge of the growing steam chamber is where the oil is displaced by the steam. There is a large temperature gradient in the oil drainage zone with steam temperature at the edge of the steam chamber and close to the original reservoir temperature on the other side of the drainage zone. The fluid flow behavior, which is controlled by Relative Permeability, can be sensitive to the temperature in this transition zone. The objective of this study was to investigate the impact of temperature on two-phase bitumen/water Relative Permeability of sand over a wide range of temperature from 70 to 220 °C. In the present study, isothermal displacement experiments were conducted with an advanced experimental rig under the confining pressure of 1400 psi using Athabasca bitumen, deionized water, and clean silica sand at six different temperatures. All experiments were repeated to ensure that the results are repeatable and reliable. The JBN (Johnson, Bossler and Neumann) method was used to obtain the two-phase Relative Permeability. The effect of temperature on Relative Permeability for the bitumen system was found to be substantial and should be accounted for in simulation of SAGD processes. The endpoint water Relative Permeability can increase by two orders of magnitude in going from the reservoir temperature to the steam temperature. The endpoint oil Relative Permeability also increases, albeit more modestly and the residual oil saturation decreases. Besides the Relative Permeability tests, contact angle and IFT measurements at high-temperature, high-pressure conditions were conducted to evaluate the fluid-fluid and rock-fluid interactions and examine any changes in wettability. According to the contact angle results, the wettability of system was water-wet and shifted toward strongly water-wet at higher temperatures. In addition, the IFT displayed a decreasing trend with temperature and reached the minimum value of 18 mN/m in the temperature range of 125–155 °C.
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correlations for effect of temperature on oil water Relative Permeability in clastic reservoirs
Fuel, 2019Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract For more than half a century, a large number of scholars have endeavored to delineate the effects of temperature on two-phase Relative Permeability curves using different oils and porous media. However, we still cannot predict how the Relative Permeability will change with temperature in a specific rock-fluid system. In fact, even a cursory review of the literature on the effect of temperature on oil/water Relative Permeability will show that a bewildering array of conflicting results have been reported. These inconsistent results are partly due to the likelihood that the effect of temperature is different in different rock-fluid systems and partly due to differences in the measurements techniques that can introduce varying experimental artifacts. The main objective of this study was to see whether some of the contradictions in the reported results would be resolved by examining the effects of temperature on Relative Permeability separately in different classes of rock-fluid systems. Another objective was to develop empirical correlations for estimating the value of oil/water Relative Permeability in different systems at higher temperatures. Reported results from a large number of experimental studies of the effect of temperature on Relative Permeability were collected to generate a large dataset of oil/water Relative Permeability curves. This dataset was partitioned into four parts representing four different classes of rock-fluid systems, namely: 1) light oil in unconsolidated sand, 2) heavy oil in unconsolidated sand, 3) light oil in consolidated sandstone and 4) heavy oil in consolidated sandstone. The effect of temperature on irreducible water saturation, residual oil saturation, the endpoint Relative Permeability to oil and water and the generalized Corey saturation exponents of oil and water were analyzed separately for each rock-fluid system. It was found that, although the scatter in reported data is large, some discernable differences are present in the effect of temperature in different rock fluid types. Separate correlations, in the form of generalized Corey saturation exponent model with temperature dependent parameters, were developed for oil/water Relative Permeability in different rock-fluid systems.
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a data driven model for predicting the effect of temperature on oil water Relative Permeability
Fuel, 2019Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract Several empirical models have been proposed by scholars to capture the temperature’s impact on Relative Permeability for a specific rock/fluid system, often using very limited dataset of measured Relative Permeability values, which makes these models inapplicable to a wider range of rock-fluid characteristics. The current study presents a new data-driven model to predict the two-phase oil/water Relative Permeability over a wide range of temperature in unconsolidated sand and sandstone formations. We found that the carbonate rock systems have different characteristics and the reported high temperature Relative Permeability data for them is limited, which prevented us from including them alongside the sand systems. For developing the model, the Least Square Support Vector Machine (LSSVM) in the form of a supervised learning approach was implemented, in which the coupled simulated annealing optimization technique was employed for calculation of LSSVM hyper-parameters. To gather a comprehensive dataset for constructing the model, 626 experimental oil Relative Permeability and 547 experimental water Relative Permeability data points were obtained from the open literature. To identify the doubtful data points (the outliers) the method of Leverage Value Statistics was applied. The temperature (ranging from 21 to 200 °C), water saturation, oil viscosity (ranging from 0.42 to 1190 cP), water viscosity (ranging from 0.136 to 1.1 cP), and the absolute Permeability (ranging from 152 to 95,000 mD) were used as the independent variables in the model. The statistical analysis of the obtained LSSVM for prediction of Relative Permeability demonstrated that the coefficient of determination, root mean square error, and average absolute error were 0.9987, 0.0111, and 5.36% for oil Relative Permeability and 0.9991, 0.0056, and 8.40% for water Relative Permeability. The comparison of statistical parameters of this model with other reported Relative Permeability models showed that this model is more reliable for estimating the oil and water Relative Permeability including its dependence on temperature and therefore it can be used for reservoir simulation studies, when experimentally measured data are not available.
Zhe Yuan - One of the best experts on this subject based on the ideXlab platform.
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experimental studies on effects of temperature on oil and water Relative Permeability in heavy oil reservoirs
Scientific Reports, 2018Co-Authors: Yadong Qin, Pengcheng Liu, Fajun Zhao, Zhe YuanAbstract:A heavy-oil sample derived from a block of Venezuelan oil was used to investigate effects of temperature on Relative Permeability to oil and water. Measurements of Relative Permeability were based on one-dimensional core-flow simulated systems using an unsteady-state technique at different temperatures, and then impact rules of temperature dependency were discussed. Both water and heavy oil in cores were reconfigured under the consideration of actual reservoir conditions. Study results suggest that Relative Permeability is high to oil phase and is very low to water phase, and fluid flow capability is extremely imbalanced between oil and water. As temperature increases, irreducible water saturation linearly increases, residual oil saturation performs a nonlinear decrease, and water saturation exhibits a nonlinear increase at equal-Permeability points. The water-wettability of rocks is heightened and overall Relative Permeability curves shift to the right with increasing temperature; furthermore, two-phase flow area becomes wider and both oil and water Relative Permeability increases apparently, but the increase ratio of water is less than that of oil.
Farshid Torabi - One of the best experts on this subject based on the ideXlab platform.
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predicting heavy oil water Relative Permeability using modified corey based correlations
Fuel, 2016Co-Authors: Farshid Torabi, Nader Mosavat, Ostap ZarivnyyAbstract:Abstract In this study, the effect of various parameters such as operating temperature, crude oil viscosity, injection flow rate, and operating pressure on heavy oil/water Relative Permeability were investigated followed by proposing new correlations for calculating heavy oil/water Relative Permeability. The experimental results obtained in this study showed that both water and oil Relative permeabilities are significantly temperature dependent and they increase when temperature increases. It was also found that Relative Permeability to oil and water increase with decrease in oil viscosity. Additionally, tests results indicated that increase in injection flow rate results in higher oil Relative Permeability and lower water Relative Permeability. Unsteady state core flooding experiments carried out at various operating pressures showed that the Relative Permeability to oil in heavy oil/water system is independent of operating pressure. The heavy oil/water Relative Permeability data obtained in this study was used to develop new heavy oil/water Relative Permeability correlations by modifying the original Corey’s correlations. The comparative evaluation of the new correlations with the original Corey’s correlations indicated significant improvement in both heavy oil and water Relative Permeability estimation. Statistical analysis of the results showed that the new correlations facilitate reliable calculation of heavy oil/water Relative Permeability values by decreasing the root mean square magnitude from 0.167 and 0.178 to 0.004 and 0.061 for water and oil Relative Permeability, respectively. In addition, the accuracy of newly developed correlations was tested against five sets of experimental data obtained from literature. Results of this comparison also showed that heavy oil/water Relative Permeability predicted by new correlations is in better agreement with experimental data compared to those predicted by Corey’s model.
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Experimental investigation of temperature effect on three-phase Relative Permeability isoperms in heavy oil systems
Fuel, 2014Co-Authors: Manoochehr Akhlaghinia, Farshid Torabi, Christine W. ChanAbstract:Abstract This study reports effect of temperature on the estimated Relative Permeability isoperms for a fluid system of heavy oil, water, and CO 2 . An experimental/numerical technique was utilized to estimate Relative Permeability isoperms for a three-phase fluid system. Two-phase displacement tests were separately carried out in order to measure residual saturations. Three-phase displacements were conducted in the form of CO 2 injection into a consolidated Berea core saturated with heavy oil and water at temperatures 28, 40, and 52 °C. A three-phase one-dimensional numerical simulator (able to use three-phase Relative Permeability data in explicit form) was developed to simulate the displacement experiments. The procedure was validated using steady state experiment as well as sensitivity analysis. The results of this study demonstrate that limited three-phase flow zone exists for heavy oil fluid systems due to high values of residual oil saturation. Different curvatures are observed for each of the phases. These curvatures are more complicated for oil and water than in the gas phase. Although temperature is found to change the position of the three-phase flow zone in ternary diagrams, however, no significant change in the size of the three-phase flow zone is observed. The effect of an increase in temperature on the Relative Permeability isoperms is very different in each phase. This process decreases the Relative Permeability of oil. In an opposite way, the Relative Permeability of the gas phase increases at elevated temperatures. When it comes to water, reversal behavior is observed as it increases from 28 °C to 40 °C and, then, decreases as temperature further rises to 52 °C.
Thomas G Harding - One of the best experts on this subject based on the ideXlab platform.
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effect of temperature on Relative Permeability role of viscosity ratio
Fuel, 2020Co-Authors: Sajjad Esmaeili, Thomas G Harding, Jafar Modaresghazani, Hemanta K Sarma, Brij B MainiAbstract:Abstract Although there are many studies regarding the effect of temperature on Relative Permeability, there is no consensus on this issue. Here we examine the role of oil/water viscosity ratio in making the measured oil/water Relative Permeability dependent on temperature. Two-phase oil/water Relative Permeability was carefully measured over a wide range of temperature between 23 °C and 210 °C using a poly-alpha-olefin (PAO) oil and deionized water in a clean unconsolidated sand-pack at confining pressure of 800 psi. A sophisticated experimental setup that is capable of measuring the pressure drop and monitoring the temperature in four different length segments of the sand-pack was used. Both the Johnson, Bossler and Neumann (JBN) method and the history match approach were employed to obtain the Relative Permeability from the results of isothermal oil displacement tests. Furthermore, high-temperature and high-pressure interfacial tension (IFT) and contact angle measurements were also carried out. The results show that the two-phase oil/water Relative Permeability, in this ultra-clean system, is practically insensitive to the temperature, even though the oil/water viscosity ratio changes by two orders of magnitude. The slight variation in oil endpoint Relative Permeability and irreducible water saturation, especially at ambient condition, was attributed to the uncertainty in the oil viscosity measurement and reproducibility of the sand packing procedure. The IFT of this system declined from 41.1 mN/m at 23.5 °C to 20.9 mN/m at 185.2 °C and contact angle decreased from 80.7° at 23.5 °C to 56.9° at 150 °C. Changes of this level do not significantly affect the oil displacement behavior.
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two phase bitumen water Relative Permeability at different temperatures and sagd pressure experimental study
Fuel, 2020Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract The heavy oil or bitumen trapped in subterranean formations in Canada and North America can be effectively produced and recovered using thermal enhanced oil recovery (TEOR) techniques, especially steam assisted gravity drainage (SAGD) processes. Heating the formation to a high temperature greatly reduces the oil viscosity, which increases the oil mobility in the reservoir. In the SAGD process, the steam injected through a long horizontal well creates a steam saturated zone, called steam chamber, around the well that gradually expands laterally and vertically within the reservoir. The edge of the growing steam chamber is where the oil is displaced by the steam. There is a large temperature gradient in the oil drainage zone with steam temperature at the edge of the steam chamber and close to the original reservoir temperature on the other side of the drainage zone. The fluid flow behavior, which is controlled by Relative Permeability, can be sensitive to the temperature in this transition zone. The objective of this study was to investigate the impact of temperature on two-phase bitumen/water Relative Permeability of sand over a wide range of temperature from 70 to 220 °C. In the present study, isothermal displacement experiments were conducted with an advanced experimental rig under the confining pressure of 1400 psi using Athabasca bitumen, deionized water, and clean silica sand at six different temperatures. All experiments were repeated to ensure that the results are repeatable and reliable. The JBN (Johnson, Bossler and Neumann) method was used to obtain the two-phase Relative Permeability. The effect of temperature on Relative Permeability for the bitumen system was found to be substantial and should be accounted for in simulation of SAGD processes. The endpoint water Relative Permeability can increase by two orders of magnitude in going from the reservoir temperature to the steam temperature. The endpoint oil Relative Permeability also increases, albeit more modestly and the residual oil saturation decreases. Besides the Relative Permeability tests, contact angle and IFT measurements at high-temperature, high-pressure conditions were conducted to evaluate the fluid-fluid and rock-fluid interactions and examine any changes in wettability. According to the contact angle results, the wettability of system was water-wet and shifted toward strongly water-wet at higher temperatures. In addition, the IFT displayed a decreasing trend with temperature and reached the minimum value of 18 mN/m in the temperature range of 125–155 °C.
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correlations for effect of temperature on oil water Relative Permeability in clastic reservoirs
Fuel, 2019Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract For more than half a century, a large number of scholars have endeavored to delineate the effects of temperature on two-phase Relative Permeability curves using different oils and porous media. However, we still cannot predict how the Relative Permeability will change with temperature in a specific rock-fluid system. In fact, even a cursory review of the literature on the effect of temperature on oil/water Relative Permeability will show that a bewildering array of conflicting results have been reported. These inconsistent results are partly due to the likelihood that the effect of temperature is different in different rock-fluid systems and partly due to differences in the measurements techniques that can introduce varying experimental artifacts. The main objective of this study was to see whether some of the contradictions in the reported results would be resolved by examining the effects of temperature on Relative Permeability separately in different classes of rock-fluid systems. Another objective was to develop empirical correlations for estimating the value of oil/water Relative Permeability in different systems at higher temperatures. Reported results from a large number of experimental studies of the effect of temperature on Relative Permeability were collected to generate a large dataset of oil/water Relative Permeability curves. This dataset was partitioned into four parts representing four different classes of rock-fluid systems, namely: 1) light oil in unconsolidated sand, 2) heavy oil in unconsolidated sand, 3) light oil in consolidated sandstone and 4) heavy oil in consolidated sandstone. The effect of temperature on irreducible water saturation, residual oil saturation, the endpoint Relative Permeability to oil and water and the generalized Corey saturation exponents of oil and water were analyzed separately for each rock-fluid system. It was found that, although the scatter in reported data is large, some discernable differences are present in the effect of temperature in different rock fluid types. Separate correlations, in the form of generalized Corey saturation exponent model with temperature dependent parameters, were developed for oil/water Relative Permeability in different rock-fluid systems.
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a data driven model for predicting the effect of temperature on oil water Relative Permeability
Fuel, 2019Co-Authors: Sajjad Esmaeili, Hemanta Sarma, Thomas G Harding, Brij B MainiAbstract:Abstract Several empirical models have been proposed by scholars to capture the temperature’s impact on Relative Permeability for a specific rock/fluid system, often using very limited dataset of measured Relative Permeability values, which makes these models inapplicable to a wider range of rock-fluid characteristics. The current study presents a new data-driven model to predict the two-phase oil/water Relative Permeability over a wide range of temperature in unconsolidated sand and sandstone formations. We found that the carbonate rock systems have different characteristics and the reported high temperature Relative Permeability data for them is limited, which prevented us from including them alongside the sand systems. For developing the model, the Least Square Support Vector Machine (LSSVM) in the form of a supervised learning approach was implemented, in which the coupled simulated annealing optimization technique was employed for calculation of LSSVM hyper-parameters. To gather a comprehensive dataset for constructing the model, 626 experimental oil Relative Permeability and 547 experimental water Relative Permeability data points were obtained from the open literature. To identify the doubtful data points (the outliers) the method of Leverage Value Statistics was applied. The temperature (ranging from 21 to 200 °C), water saturation, oil viscosity (ranging from 0.42 to 1190 cP), water viscosity (ranging from 0.136 to 1.1 cP), and the absolute Permeability (ranging from 152 to 95,000 mD) were used as the independent variables in the model. The statistical analysis of the obtained LSSVM for prediction of Relative Permeability demonstrated that the coefficient of determination, root mean square error, and average absolute error were 0.9987, 0.0111, and 5.36% for oil Relative Permeability and 0.9991, 0.0056, and 8.40% for water Relative Permeability. The comparison of statistical parameters of this model with other reported Relative Permeability models showed that this model is more reliable for estimating the oil and water Relative Permeability including its dependence on temperature and therefore it can be used for reservoir simulation studies, when experimentally measured data are not available.