The Experts below are selected from a list of 120 Experts worldwide ranked by ideXlab platform
Jishun Qin - One of the best experts on this subject based on the ideXlab platform.
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phase behavior of c3h8 co2 heavy oil systems in the presence of aqueous phase under reservoir conditions
Fuel, 2017Co-Authors: Haishui Han, Daoyong Yang, Xiaolei Liu, Jishun QinAbstract:Abstract Phase behaviors including phase boundaries, volumes, and compositions of reservoir fluids during solvent(s)-assisted heavy oil recovery processes have been experimentally and theoretically determined in the presence of an aqueous phase. More specifically, a water-rich aqueous phase (A), an oil-rich liquid phase (L), and a solvents-rich vapor phase (V) can coexist under certain reservoir conditions. The phase boundary between AL and ALV on a pressure–temperature phase diagram, i.e., three-phase Bubblepoint pressure, has been measured for C 3 H 8 –CO 2 –water–heavy oil systems at temperature ranging from 298.15 K to 383.15 K. The phase volumes of A + L and V at thermodynamic equilibrium state have been determined at temperatures of 321.55 K and 344.95 K, respectively. Moreover, the fluids in both L and V phases are sampled in an isobaric manner to perform the compositional analyses by using gas chromatography (GC) method. Meanwhile, two heavy oil samples are theoretically characterized as the multiple pseudocomponents. The Peng–Robinson equation of state (PR EOS) together with two recently developed alpha functions for water and non-water component(s) is applied as the primary thermodynamic model. A previously developed binary interaction parameter (BIP) correlation for CO 2 –water pair is combined with the van der Waals’ mixing rule to improve the phase behavior prediction for water-contained system. A volume translation method proposed by Peneloux et al. (1982) is then incorporated to correct the calculated phase volume. Without tuning any parameters, the developed water-associated and water-free mathematical models are found to be able to accurately reproduce the measured phase boundaries in the presence and absence of the aqueous phase, respectively. The three-phase Bubblepoint pressure is found to be reduced in the presence of water. More accurate prediction can be achieved by considering the effect of aqueous phase. Finally, the GC analyses and flash calculations demonstrate that CO 2 is more easily to be vaporized than alkane solvent (i.e., C 3 H 8 ) when phase splitting occurs for a C 3 H 8 –CO 2 –water–heavy oil system.
E. Shirif - One of the best experts on this subject based on the ideXlab platform.
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PREDICTION OF Bubblepoint SOLUTION GAS/OIL RATIO IN THE ABSENCE OF A PVT ANALYSIS
Brazilian Journal of Petroleum and Gas, 2011Co-Authors: S. Elmabrouk, E. ShirifAbstract:Several published correlations used to estimate the Bubblepoint pressure and the Bubblepoint oil formation volume factor of reservoir oils require that the value of the Bubblepoint solution gas/oil ratio be one of the input variables. Consequently, engineers resort to an additional correlation in order to estimate this value. The majority of the published Bubblepoint solution gas/oil ratio correlations are functions of Bubblepoint pressure and gas gravity, which can be obtained either experimentally (pressure-volumetemperature, PVT analysis) or estimated from the existing correlations. Thus, it is difficult to apply the correlations in the absence of a PVT analysis. In this study, a multiple regression analysis technique was applied to develop two novel correlations to estimate the Bubblepoint solution gas/oil ratio and stocktank vent gas/oil ratio in the absence of a PVT analysis. The developed correlations can be directly applied by using readily available field data, thus, forgoing the requirement of additional correlations or a PVT analysis. The Bubblepoint solution gas/oil ratio correlation is related to the separator gas-oil ratio, to the separator pressure, and to the stock-tank oil specific gravity. However, separator pressure and temperature with the stock-tank oil specific gravity were the only independent variables used in stocktank vent gas/oil ratio correlation. Another additional and important application of the proposed stocktank vent gas/oil ratio correlation was to estimate the stock-tank vent gas flow rate.
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prediction of Bubblepoint solution gas oil ratio in the absence of a pvt analysis
Brazilian Journal of Petroleum and Gas, 2011Co-Authors: S. Elmabrouk, E. ShirifAbstract:Several published correlations used to estimate the Bubblepoint pressure and the Bubblepoint oil formation volume factor of reservoir oils require that the value of the Bubblepoint solution gas/oil ratio be one of the input variables. Consequently, engineers resort to an additional correlation in order to estimate this value. The majority of the published Bubblepoint solution gas/oil ratio correlations are functions of Bubblepoint pressure and gas gravity, which can be obtained either experimentally (pressure-volumetemperature, PVT analysis) or estimated from the existing correlations. Thus, it is difficult to apply the correlations in the absence of a PVT analysis. In this study, a multiple regression analysis technique was applied to develop two novel correlations to estimate the Bubblepoint solution gas/oil ratio and stocktank vent gas/oil ratio in the absence of a PVT analysis. The developed correlations can be directly applied by using readily available field data, thus, forgoing the requirement of additional correlations or a PVT analysis. The Bubblepoint solution gas/oil ratio correlation is related to the separator gas-oil ratio, to the separator pressure, and to the stock-tank oil specific gravity. However, separator pressure and temperature with the stock-tank oil specific gravity were the only independent variables used in stocktank vent gas/oil ratio correlation. Another additional and important application of the proposed stocktank vent gas/oil ratio correlation was to estimate the stock-tank vent gas flow rate.
J M Del Rio - One of the best experts on this subject based on the ideXlab platform.
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estimation of the sara composition of crude oils from Bubblepoint pressure data
Energy & Fuels, 2016Co-Authors: D Reyesgonzalez, Edgar Ramirezjaramillo, O Manero, C Liragaleana, J M Del RioAbstract:A statistical correlation to provide reasonable estimates of crude oiĺs SARA compositions (saturates, aromatics, resins, asphaltenes) from Bubblepoint pressure and light-ends compositional data is presented. In developing the correlation, we collected experimental SARA compositions of 341 crude oils of different origin. The most-probable SARA compositions are then obtained by seeking the maximum probability according to its oil type, in line with the measured values of Bubblepoint pressures. Results show that the proposed method is simple and provides reasonable values of SARA compositions of an oil in cases in which only the light-ends compositions and a few Bubblepoint pressures are available.
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Estimation of the SARA Composition of Crude Oils from Bubblepoint Pressure Data
2016Co-Authors: D. Reyes-gonzalez, O Manero, E. Ramirez-jaramillo, C. Lira-galeana, J M Del RioAbstract:A statistical correlation to provide reasonable estimates of crude oiĺs SARA compositions (saturates, aromatics, resins, asphaltenes) from Bubblepoint pressure and light-ends compositional data is presented. In developing the correlation, we collected experimental SARA compositions of 341 crude oils of different origin. The most-probable SARA compositions are then obtained by seeking the maximum probability according to its oil type, in line with the measured values of Bubblepoint pressures. Results show that the proposed method is simple and provides reasonable values of SARA compositions of an oil in cases in which only the light-ends compositions and a few Bubblepoint pressures are available
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equations to predict precipitation onset and Bubblepoint pressures of asphaltenic reservoir fluids
Aiche Journal, 2009Co-Authors: J M Del Rio, E Ramirezjaramillo, C LiragaleanaAbstract:A set of algebraic equations to predict upper onset-of-precipitation and bubble-point pressures of asphaltene-containing reservoir fluids in wide temperature ranges are proposed. In developing the equations, laboratory data of 11 Mexican and 12 more live oils have been analyzed, and a correlation of these data with temperature has been found. A modified least-squares regression method has been used to develop two versions of the proposed equations. In one version, a single pressure/temperature data point is required to predict the entire onset/bubble-point curves at any temperature. For oils with no experimental precipitation data available at all, a second version of the proposed expressions employs standard chromatographic data of the reservoir fluid to provide a reasonable prediction. The average absolute deviations in calculated onset and bubble-point pressures by the proposed equations are 2.53 and 0.45MPa by the one-point correlations, respectively, and 3.96 and 1.62 MPa by the compositionally-based correlations, respectively. The developed expressions are simple and can be used to provide reasonable predictions of upper onset and bubble-point pressures of asphaltenic live oils in cases where laboratory data are scarce. © 2009 American Institute of Chemical Engineers AIChE J, 2009
Haishui Han - One of the best experts on this subject based on the ideXlab platform.
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phase behavior of c3h8 co2 heavy oil systems in the presence of aqueous phase under reservoir conditions
Fuel, 2017Co-Authors: Haishui Han, Daoyong Yang, Xiaolei Liu, Jishun QinAbstract:Abstract Phase behaviors including phase boundaries, volumes, and compositions of reservoir fluids during solvent(s)-assisted heavy oil recovery processes have been experimentally and theoretically determined in the presence of an aqueous phase. More specifically, a water-rich aqueous phase (A), an oil-rich liquid phase (L), and a solvents-rich vapor phase (V) can coexist under certain reservoir conditions. The phase boundary between AL and ALV on a pressure–temperature phase diagram, i.e., three-phase Bubblepoint pressure, has been measured for C 3 H 8 –CO 2 –water–heavy oil systems at temperature ranging from 298.15 K to 383.15 K. The phase volumes of A + L and V at thermodynamic equilibrium state have been determined at temperatures of 321.55 K and 344.95 K, respectively. Moreover, the fluids in both L and V phases are sampled in an isobaric manner to perform the compositional analyses by using gas chromatography (GC) method. Meanwhile, two heavy oil samples are theoretically characterized as the multiple pseudocomponents. The Peng–Robinson equation of state (PR EOS) together with two recently developed alpha functions for water and non-water component(s) is applied as the primary thermodynamic model. A previously developed binary interaction parameter (BIP) correlation for CO 2 –water pair is combined with the van der Waals’ mixing rule to improve the phase behavior prediction for water-contained system. A volume translation method proposed by Peneloux et al. (1982) is then incorporated to correct the calculated phase volume. Without tuning any parameters, the developed water-associated and water-free mathematical models are found to be able to accurately reproduce the measured phase boundaries in the presence and absence of the aqueous phase, respectively. The three-phase Bubblepoint pressure is found to be reduced in the presence of water. More accurate prediction can be achieved by considering the effect of aqueous phase. Finally, the GC analyses and flash calculations demonstrate that CO 2 is more easily to be vaporized than alkane solvent (i.e., C 3 H 8 ) when phase splitting occurs for a C 3 H 8 –CO 2 –water–heavy oil system.
Weiyu Fan - One of the best experts on this subject based on the ideXlab platform.
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co2 huff and puff for heavy oil recovery after primary production
Greenhouse Gases-Science and Technology, 2016Co-Authors: Weiyu FanAbstract:In this study, micromodel tests were performed to investigate the microscopic flow behavior during primary production and the subsequent CO2 huff and puff. A series of 12 tests was conducted in sandpacks to evaluate the effects of the injection and production parameters on the displacement efficiency of the CO2 huff and puff. The micromodel tests and sandpack tests showed that the flow characteristics of CO2 huff-and-puff process was significantly affected by the pressure of converting the solution gas drive to the subsequent CO2 huff and puff. A foamy oil flow could be more easily formed in the production period of the CO2 huff and puff with a higher conversion pressure. Foamy oil can reduce the mobility of gas and provide tremendous energy to the system, thereby improving the performance of the CO2 huff and puff. The sandpack flood results show that the oil recovery of the solution gas drive decreased as the conversion pressure increased, whereas the oil recovery of the CO2 huff and puff increased as the conversion pressure increased. The highest total oil recovery was obtained at the pseudo-Bubblepoint pressure. The oil recovery of the CO2 huff and puff increased as the CO2 injection pressure and pressure decline rate increased. The oil recovery of CO2 huff and puff increased with the soaking time, and it exhibits a significant change when the soaking time ranges from 10 h to 24 h; above this value, the increase become slight. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd
