The Experts below are selected from a list of 210 Experts worldwide ranked by ideXlab platform
David A. Dicarlo - One of the best experts on this subject based on the ideXlab platform.
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steady state supercritical co2 and brine relative permeability in Berea Sandstone at different temperature and pressure conditions
Water Resources Research, 2017Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:We measure steady-state two-phase supercritical CO2-brine relative permeabilities in a 61-cm-long Berea Sandstone Core at three different conditions (40°C and 12.41 MPa, 40°C and 8.27 MPa, and 60°C and 12.41 MPa) under primary drainage. We use pressure taps to obtain pressure drops of individual sections of the Core, and X-ray Computed Tomography (CT) to obtain in situ saturation profiles, which together help to mitigate the capillary end effect. We include previously measured relative permeabilities at 20°C and 10.34 MPa, and compare all the data using both an eye-test and a statistical test. We find no appreciable temperature and pressure dependence of CO2 relative permeability within 20-60°C and 8.27-12.41 MPa. We find slight changes in the brine relative permeability between supercritical CO2 conditions (40-60°C and 8.27-12.41 MPa) and the liquid CO2 condition (20°C and 10.34 MPa). The temperature and pressure independence of CO2 relative permeability has been previously recognized and reassured in this work using a capillary-effect-free method. This allows one to use a single CO2 relative permeability curve in modeling two-phase CO2 flow within 20-60°C and 8.27-12.41 MPa.
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measurements of co2 brine relative permeability in Berea Sandstone using pressure taps and a long Core
Greenhouse Gases-Science and Technology, 2017Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:We measured CO 2 ‐brine relative permeability by performing five steady‐state primary drainage experiments in a 116 mD Berea Sandstone Core at 20°C and 10.34 MPa. We used a long (60.8 cm) Core and four pressure taps to study and minimize end effects that can plague CO 2 ‐brine relative permeability measurements, and we obtained in situ saturation profiles using a medical X‐ray Computed Tomography (CT) scanner. We found that entrance and exit effects propagated ∼5 cm into the Core, but the center sections of the Core had uniform saturation. From the saturations and pressure drops, we obtained both CO 2 and brine relative permeability in the center sections. We also obtained CO 2 relative permeability at the entrance section where the brine saturation was lower and not uniform. The 15‐cm long exit section of the Core had non‐uniform saturation and a measured pressure drop that was on the order of the capillary pressure and hence was unreliable for calculating relative permeability. We found that the CO 2 and brine relative permeabilities determined in five experiments were consistent with each other and followed two simple Corey‐type models that are similar to those seen in oil‐brine relative permeability measurements. We discuss why end effects are much greater in the CO 2 ‐brine system than in oil‐brine systems, and how this is a possible explanation of the low CO 2 relative permeabilities recently reported for the CO 2 ‐brine systems. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd.
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Supercritical CO2 - Brine Primary Drainages (40-60C, 8-12 MPa)
2017Co-Authors: Xiongyu Chen, Shuang Gao, Amir Kianinejad, David A. DicarloAbstract:This project includes porosity images and steady-state water saturation images at 8 different positions (distance from inlet are 4, 12, 20, 28, 37, 44, 52 and 59 cm) along a 60-cm long Berea Sandstone Core (45 mD) during three primary drainage experiments conducted at 40C & 12 MPa, 40C & 8.3 MPa, and 60C & 12 MPa. The drainage experiment starts with injecting 1:1 volume ratio of CO2 and brine. After steady state is reached, the water fractional flow (fw) is lowered. This is repeated until 100% CO2 injection. Each drainage experiment has three steps with fw of 0.5, 0.1 and 0.
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a new unsteady state method of determining two phase relative permeability illustrated by co 2 brine primary drainage in Berea Sandstone
Advances in Water Resources, 2016Co-Authors: Xiongyu Chen, David A. DicarloAbstract:Abstract This study presents a new unsteady-state method for measuring two-phase relative permeability by obtaining local values of the three key parameters (saturation, pressure drop, and phase flux) versus time during a displacement. These three parameters can be substituted to two-phase Darcy Buckingham equation to directly determine relative permeability. To obtain the first two, we use a medical X-ray Computed Tomography (CT) scanner to monitor saturation in time and space, and six differential pressure transducers to measure the overall pressure drop and the pressure drops of five individual sections (divided by four pressure taps on the Core) continuously. At each scanning time, the local phase flux is obtained by spatially integrating the saturation profile and converting this to the flux using a fractional flow framework. One advantage of this local method over most previous methods is that the capillary end effect is experimentally avoided; this improvement is crucial for experiments using low viscosity fluids such as supercritical and gas phases. To illustrate the new method, we conduct five CO 2 -brine primary drainage experiments in a 60.8 cm long and 116 mD Berea Sandstone Core at 20 °C and 1500 psi. In return, we obtain hundreds of unsteady-state CO 2 and brine relative permeability data points that are consistent with steady-state relative permeability data from the same experiments. Due to the large amount of relative permeability data obtained by the new unsteady-state method, the uncertainties of the exponents in the Corey-type fits decrease by up to 90% compared with the steady-state method.
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direct measurement of relative permeability in rocks from unsteady state saturation profiles
Advances in Water Resources, 2016Co-Authors: Amir Kianinejad, Xiongyu Chen, David A. DicarloAbstract:Abstract We develop a method to measure liquid relative permeability in rocks directly from transient in situ saturation profiles during gravity drainage experiments. Previously, similar methods have been used for sandpacks; here, this method is extended to rocks by applying a slight overpressure of gas at the inlet. Relative permeabilities are obtained in a 60 cm long vertical Berea Sandstone Core during gravity drainage, directly from the measured unsteady-state in situ saturations along the Core at different times. It is shown that for obtaining relative permeability using this method, if certain criteria are met, the capillary pressure of the rock can be neglected. However, it is essential to use a correct gas pressure gradient along the Core. This involves incorporating the pressure drop at the outlet of the Core due to capillary discontinuity effects. The method developed in this work obtains relative permeabilities in unsteady-state fashion over a wide range of saturations quickly and accurately.
Xiongyu Chen - One of the best experts on this subject based on the ideXlab platform.
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steady state supercritical co2 and brine relative permeability in Berea Sandstone at different temperature and pressure conditions
Water Resources Research, 2017Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:We measure steady-state two-phase supercritical CO2-brine relative permeabilities in a 61-cm-long Berea Sandstone Core at three different conditions (40°C and 12.41 MPa, 40°C and 8.27 MPa, and 60°C and 12.41 MPa) under primary drainage. We use pressure taps to obtain pressure drops of individual sections of the Core, and X-ray Computed Tomography (CT) to obtain in situ saturation profiles, which together help to mitigate the capillary end effect. We include previously measured relative permeabilities at 20°C and 10.34 MPa, and compare all the data using both an eye-test and a statistical test. We find no appreciable temperature and pressure dependence of CO2 relative permeability within 20-60°C and 8.27-12.41 MPa. We find slight changes in the brine relative permeability between supercritical CO2 conditions (40-60°C and 8.27-12.41 MPa) and the liquid CO2 condition (20°C and 10.34 MPa). The temperature and pressure independence of CO2 relative permeability has been previously recognized and reassured in this work using a capillary-effect-free method. This allows one to use a single CO2 relative permeability curve in modeling two-phase CO2 flow within 20-60°C and 8.27-12.41 MPa.
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measurements of co2 brine relative permeability in Berea Sandstone using pressure taps and a long Core
Greenhouse Gases-Science and Technology, 2017Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:We measured CO 2 ‐brine relative permeability by performing five steady‐state primary drainage experiments in a 116 mD Berea Sandstone Core at 20°C and 10.34 MPa. We used a long (60.8 cm) Core and four pressure taps to study and minimize end effects that can plague CO 2 ‐brine relative permeability measurements, and we obtained in situ saturation profiles using a medical X‐ray Computed Tomography (CT) scanner. We found that entrance and exit effects propagated ∼5 cm into the Core, but the center sections of the Core had uniform saturation. From the saturations and pressure drops, we obtained both CO 2 and brine relative permeability in the center sections. We also obtained CO 2 relative permeability at the entrance section where the brine saturation was lower and not uniform. The 15‐cm long exit section of the Core had non‐uniform saturation and a measured pressure drop that was on the order of the capillary pressure and hence was unreliable for calculating relative permeability. We found that the CO 2 and brine relative permeabilities determined in five experiments were consistent with each other and followed two simple Corey‐type models that are similar to those seen in oil‐brine relative permeability measurements. We discuss why end effects are much greater in the CO 2 ‐brine system than in oil‐brine systems, and how this is a possible explanation of the low CO 2 relative permeabilities recently reported for the CO 2 ‐brine systems. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd.
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Supercritical CO2 - Brine Primary Drainages (40-60C, 8-12 MPa)
2017Co-Authors: Xiongyu Chen, Shuang Gao, Amir Kianinejad, David A. DicarloAbstract:This project includes porosity images and steady-state water saturation images at 8 different positions (distance from inlet are 4, 12, 20, 28, 37, 44, 52 and 59 cm) along a 60-cm long Berea Sandstone Core (45 mD) during three primary drainage experiments conducted at 40C & 12 MPa, 40C & 8.3 MPa, and 60C & 12 MPa. The drainage experiment starts with injecting 1:1 volume ratio of CO2 and brine. After steady state is reached, the water fractional flow (fw) is lowered. This is repeated until 100% CO2 injection. Each drainage experiment has three steps with fw of 0.5, 0.1 and 0.
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a new unsteady state method of determining two phase relative permeability illustrated by co 2 brine primary drainage in Berea Sandstone
Advances in Water Resources, 2016Co-Authors: Xiongyu Chen, David A. DicarloAbstract:Abstract This study presents a new unsteady-state method for measuring two-phase relative permeability by obtaining local values of the three key parameters (saturation, pressure drop, and phase flux) versus time during a displacement. These three parameters can be substituted to two-phase Darcy Buckingham equation to directly determine relative permeability. To obtain the first two, we use a medical X-ray Computed Tomography (CT) scanner to monitor saturation in time and space, and six differential pressure transducers to measure the overall pressure drop and the pressure drops of five individual sections (divided by four pressure taps on the Core) continuously. At each scanning time, the local phase flux is obtained by spatially integrating the saturation profile and converting this to the flux using a fractional flow framework. One advantage of this local method over most previous methods is that the capillary end effect is experimentally avoided; this improvement is crucial for experiments using low viscosity fluids such as supercritical and gas phases. To illustrate the new method, we conduct five CO 2 -brine primary drainage experiments in a 60.8 cm long and 116 mD Berea Sandstone Core at 20 °C and 1500 psi. In return, we obtain hundreds of unsteady-state CO 2 and brine relative permeability data points that are consistent with steady-state relative permeability data from the same experiments. Due to the large amount of relative permeability data obtained by the new unsteady-state method, the uncertainties of the exponents in the Corey-type fits decrease by up to 90% compared with the steady-state method.
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direct measurement of relative permeability in rocks from unsteady state saturation profiles
Advances in Water Resources, 2016Co-Authors: Amir Kianinejad, Xiongyu Chen, David A. DicarloAbstract:Abstract We develop a method to measure liquid relative permeability in rocks directly from transient in situ saturation profiles during gravity drainage experiments. Previously, similar methods have been used for sandpacks; here, this method is extended to rocks by applying a slight overpressure of gas at the inlet. Relative permeabilities are obtained in a 60 cm long vertical Berea Sandstone Core during gravity drainage, directly from the measured unsteady-state in situ saturations along the Core at different times. It is shown that for obtaining relative permeability using this method, if certain criteria are met, the capillary pressure of the rock can be neglected. However, it is essential to use a correct gas pressure gradient along the Core. This involves incorporating the pressure drop at the outlet of the Core due to capillary discontinuity effects. The method developed in this work obtains relative permeabilities in unsteady-state fashion over a wide range of saturations quickly and accurately.
Xiaochun Li - One of the best experts on this subject based on the ideXlab platform.
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improved vinegar wellington calibration for estimation of fluid saturation and porosity from ct images for a Core flooding test under geologic carbon storage conditions
Micron, 2019Co-Authors: Xiuxiu Miao, Yan Wang, Liwei Zhang, Xiaochun LiAbstract:Abstract X-ray computed tomography (CT) of fluid flow in formation rocks is an important characterization technique in geologic carbon sequestration research to provide insight into the migration and capillary trapping of CO2 under reservoir conditions. An improved calibration method adapted from traditional Vinegar & Wellington calibration is proposed to map the 3D pore and fluid distributions from the CT images of CO2/brine displacement flooding. Similar to Vinegar & Wellington calibration, the proposed method adopts the linear scaling law of CT number transformation to mass density. However, different from Vinegar & Wellington calibration that uses a 100% brine-saturated Core image and a 100% CO2-saturated Core image as references to calculate CO2 and brine saturations at all time steps, the proposed method uses the CT numbers of CO2 and brine to calculate the incremental of CO2 and brine saturations from time step i to time step i +1. The method is intended for cases in which the two 100% brine saturation and 100% CO2 saturation images can not be successfully obtained. Overall, the improved calibration proposed by this study presents more reasonable results of CO2 and brine distribution in a Berea Sandstone Core, as compared to traditional Vinegar & Wellington calibration. The reconstructed porosity image agrees with the laminated structure of the Berea Sandstone Core, and the average porosity evaluated over the entire Core (0.176) is comparable to the physical porosity (0.165). Furthermore, the reconstructed saturation images using the improved calibration reveal a flat piston-like flooding front from a homogeneous longitudinal-section of the 3D orthogonal view and preferential fingerings from another non-homogeneous longitudinal-section, which are not present in the reconstructed saturation images using traditional Vinegar & Wellington calibration. Concerns and causes with respect to the uncertainty of linear CT number calibration are also explained, and approaches to alleviate the uncertainty are suggested.
Shidong Li - One of the best experts on this subject based on the ideXlab platform.
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the impact of nanoparticle adsorption on transport and wettability alteration in water wet Berea Sandstone an experimental study
Frontiers in Physics, 2019Co-Authors: Shidong Li, Ole Torsæter, Nanji J Hadia, Ludger P StubbsAbstract:Wettability alteration was proposed as one of the enhanced oil recovery (EOR) mechanisms for nanoparticle fluid (nanofluid) flooding. The effect of nanoparticle adsorption on wettability alteration was investigated by wettability index measurement of Berea Sandstone Core injected with nanofluids and by contact angle measurement of a glass surface treated with nanofluids. Nanoparticle adsorption was studied by single phase Coreflooding with nanofluids in Berea Sandstone. The adsorption isotherm and the impact of adsorption on the effective permeability were investigated by measuring the effluent nanoparticle concentration and differential pressure across the Core. Results showed that hydrophilic nanoparticles (e.g. fumed silica) made the Core slightly more water wet, and hydrophobic nanoparticles (e.g. silane modified fumed silica) delayed spontaneous imbibition but could not alter the original wettability. It was found that hydrophilic nanoparticles treatment reduced contact angle between oil and water by about 10 to 20 degree for a glass surface. Results also showed that different types of nanoparticle have different adsorption and desorption behavior and different ability to impair the permeability of Berea Sandstones Cores.
Amir Kianinejad - One of the best experts on this subject based on the ideXlab platform.
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steady state supercritical co2 and brine relative permeability in Berea Sandstone at different temperature and pressure conditions
Water Resources Research, 2017Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:We measure steady-state two-phase supercritical CO2-brine relative permeabilities in a 61-cm-long Berea Sandstone Core at three different conditions (40°C and 12.41 MPa, 40°C and 8.27 MPa, and 60°C and 12.41 MPa) under primary drainage. We use pressure taps to obtain pressure drops of individual sections of the Core, and X-ray Computed Tomography (CT) to obtain in situ saturation profiles, which together help to mitigate the capillary end effect. We include previously measured relative permeabilities at 20°C and 10.34 MPa, and compare all the data using both an eye-test and a statistical test. We find no appreciable temperature and pressure dependence of CO2 relative permeability within 20-60°C and 8.27-12.41 MPa. We find slight changes in the brine relative permeability between supercritical CO2 conditions (40-60°C and 8.27-12.41 MPa) and the liquid CO2 condition (20°C and 10.34 MPa). The temperature and pressure independence of CO2 relative permeability has been previously recognized and reassured in this work using a capillary-effect-free method. This allows one to use a single CO2 relative permeability curve in modeling two-phase CO2 flow within 20-60°C and 8.27-12.41 MPa.
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measurements of co2 brine relative permeability in Berea Sandstone using pressure taps and a long Core
Greenhouse Gases-Science and Technology, 2017Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:We measured CO 2 ‐brine relative permeability by performing five steady‐state primary drainage experiments in a 116 mD Berea Sandstone Core at 20°C and 10.34 MPa. We used a long (60.8 cm) Core and four pressure taps to study and minimize end effects that can plague CO 2 ‐brine relative permeability measurements, and we obtained in situ saturation profiles using a medical X‐ray Computed Tomography (CT) scanner. We found that entrance and exit effects propagated ∼5 cm into the Core, but the center sections of the Core had uniform saturation. From the saturations and pressure drops, we obtained both CO 2 and brine relative permeability in the center sections. We also obtained CO 2 relative permeability at the entrance section where the brine saturation was lower and not uniform. The 15‐cm long exit section of the Core had non‐uniform saturation and a measured pressure drop that was on the order of the capillary pressure and hence was unreliable for calculating relative permeability. We found that the CO 2 and brine relative permeabilities determined in five experiments were consistent with each other and followed two simple Corey‐type models that are similar to those seen in oil‐brine relative permeability measurements. We discuss why end effects are much greater in the CO 2 ‐brine system than in oil‐brine systems, and how this is a possible explanation of the low CO 2 relative permeabilities recently reported for the CO 2 ‐brine systems. © 2016 Society of Chemical Industry and John Wiley & Sons, Ltd.
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Supercritical CO2 - Brine Primary Drainages (40-60C, 8-12 MPa)
2017Co-Authors: Xiongyu Chen, Shuang Gao, Amir Kianinejad, David A. DicarloAbstract:This project includes porosity images and steady-state water saturation images at 8 different positions (distance from inlet are 4, 12, 20, 28, 37, 44, 52 and 59 cm) along a 60-cm long Berea Sandstone Core (45 mD) during three primary drainage experiments conducted at 40C & 12 MPa, 40C & 8.3 MPa, and 60C & 12 MPa. The drainage experiment starts with injecting 1:1 volume ratio of CO2 and brine. After steady state is reached, the water fractional flow (fw) is lowered. This is repeated until 100% CO2 injection. Each drainage experiment has three steps with fw of 0.5, 0.1 and 0.
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direct measurement of relative permeability in rocks from unsteady state saturation profiles
Advances in Water Resources, 2016Co-Authors: Amir Kianinejad, Xiongyu Chen, David A. DicarloAbstract:Abstract We develop a method to measure liquid relative permeability in rocks directly from transient in situ saturation profiles during gravity drainage experiments. Previously, similar methods have been used for sandpacks; here, this method is extended to rocks by applying a slight overpressure of gas at the inlet. Relative permeabilities are obtained in a 60 cm long vertical Berea Sandstone Core during gravity drainage, directly from the measured unsteady-state in situ saturations along the Core at different times. It is shown that for obtaining relative permeability using this method, if certain criteria are met, the capillary pressure of the rock can be neglected. However, it is essential to use a correct gas pressure gradient along the Core. This involves incorporating the pressure drop at the outlet of the Core due to capillary discontinuity effects. The method developed in this work obtains relative permeabilities in unsteady-state fashion over a wide range of saturations quickly and accurately.
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Three-Phase Oil Relative Permeability in Water-Wet Media: A Comprehensive Study
Transport in Porous Media, 2016Co-Authors: Amir Kianinejad, David A. DicarloAbstract:We report experimental three-phase oil relative permeability in two water-wet media (a sandpack and a Berea Sandstone Core) along different saturation paths. Three oils with different viscosities, compositions, and spreading coefficients were used in the measurements. The data show that oil relative permeability can vary significantly along different saturation paths. Most importantly, we find that despite the significant (orders of magnitude) variation of oil relative permeability along different saturation paths, the oil relative permeability in each medium can be collapsed into a single relative permeability curve, once they are plotted as a function of mobile oil saturation. However, this collapsed curve varies depending on the porous media. We show that the same behavior occurs in the relative permeability data published over the past 50 years. These observations indicate that the key factor in differences between oil permeabilities in the same porous media is changes in the residual oil saturation. We examine the performance of most commonly used relative permeability models, i.e., Corey, Saturation-Weighted Interpolation (SWI), and Stone against our data. Given the importance of residual oil saturation, we fit the experimental data along different saturation paths by treating the residual oil saturation in these models as the fitting parameter while keeping the other parameters constant. We find that the Corey and SWI models fit the data very well while the Stone model performs poorly at low saturations. We find that residual oil saturation is a nonlinear function of gas/water saturation as opposed to linear relationship previously suggested by others.