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David A. Dicarlo - One of the best experts on this subject based on the ideXlab platform.
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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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an extended jbn method of determining unsteady state two Phase Relative Permeability
Water Resources Research, 2016Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:Relative Permeability is the reduction of Permeability of porous media when subjected to multi-Phase flow and a key parameter in subsurface hydrology. The JBN method [Welge, 1952; Johnson et al., 1959] is a well-known method of obtaining Relative Permeability, which measures the overall pressure drop and the effluent Phase ratio versus time during two-Phase displacements. By assuming no capillary pressure or gravity, the JBN method obtains the Relative permeabilities to both Phases at the core outlet. Since data across a range of saturations are acquired in a Relatively short time, this method is widely used. This work extends the JBN method by having (1) section-wise pressure drop measurements between the core inlet, four pressure taps on the core and the outlet, (2) local saturation measurements, and (3) local Phase fluxes. With these data, the extended JBN method can determine Relative permeabilities to both Phases at each pressure tap of the core (not just at the core outlet). The JBN extension is shown using a data set where CO2 invades a brine-filled core. From this it is found that the advantages of the extended JBN method over the regular JBN method are: (1) four times more data are obtained, and (2) data are more accurate because the capillary end effect is experimentally avoided. Avoiding the end effect results in tripling the saturation range, and obtaining Relative permeabilities that are consistent with steady-state measurements and roughly 40% higher than those from the regular JBN method. This article is protected by copyright. All rights reserved.
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The effect of saturation path on three‐Phase Relative Permeability
Water Resources Research, 2015Co-Authors: Amir Kianinejad, Xiongyu Chen, David A. DicarloAbstract:Simulation and fluid flow prediction of many petroleum enhanced oil recovery methods as well as environmental processes such as carbon dioxide (CO2) geological storage or underground water resources remediation requires accurate modeling and determination of Relative Permeability under different saturation histories. Based on this critical need, several three-Phase Relative Permeability models were developed to predict Relative Permeability; however, for practical purposes most of them require a variety of parameters introducing undesired complexity to the models. In this work, we attempt to find out if there is a simpler way to express this functionality. To do so, we experimentally measure three-Phase, water/oil/gas, Relative Permeability in a 1-m long water-wet sand pack, under several saturation flow paths to cover the entire three-Phase saturation space. We obtain the in-situ saturations along the sand pack using a CT scanner and then determine the Relative permeabilities of liquid Phases directly from the measured in-situ saturations using an unsteady-state method. The measured data shows that at a specific saturation, the oil Relative Permeability varies significantly (up to 2 orders of magnitude), depending on the path through saturation space. The three-Phase Relative Permeability data are modeled using standard Relative Permeability models, Corey-type and Saturation Weighted Interpolation (SWI). Our measured data suggest that three-Phase oil Relative Permeability in water-wet media is only a function of its own saturation if the residual oil saturation is treated as a function of two saturations. We determine that residual saturation is the key parameter in modeling three-Phase Relative Permeability (effect of saturation history). This article is protected by copyright. All rights reserved.
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the effect of saturation path on three Phase Relative Permeability
Water Resources Research, 2015Co-Authors: Amir Kianinejad, Xiongyu Chen, David A. DicarloAbstract:Simulation and fluid flow prediction of many petroleum enhanced oil recovery methods as well as environmental processes such as carbon dioxide (CO2) geological storage or underground water resources remediation requires accurate modeling and determination of Relative Permeability under different saturation histories. Based on this critical need, several three-Phase Relative Permeability models were developed to predict Relative Permeability; however, for practical purposes most of them require a variety of parameters introducing undesired complexity to the models. In this work, we attempt to find out if there is a simpler way to express this functionality. To do so, we experimentally measure three-Phase, water/oil/gas, Relative Permeability in a 1-m long water-wet sand pack, under several saturation flow paths to cover the entire three-Phase saturation space. We obtain the in-situ saturations along the sand pack using a CT scanner and then determine the Relative permeabilities of liquid Phases directly from the measured in-situ saturations using an unsteady-state method. The measured data shows that at a specific saturation, the oil Relative Permeability varies significantly (up to 2 orders of magnitude), depending on the path through saturation space. The three-Phase Relative Permeability data are modeled using standard Relative Permeability models, Corey-type and Saturation Weighted Interpolation (SWI). Our measured data suggest that three-Phase oil Relative Permeability in water-wet media is only a function of its own saturation if the residual oil saturation is treated as a function of two saturations. We determine that residual saturation is the key parameter in modeling three-Phase Relative Permeability (effect of saturation history). This article is protected by copyright. All rights reserved.
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The effect of wettability on three-Phase Relative Permeability
Transport in Porous Media, 2000Co-Authors: David A. Dicarlo, Akshay Sahni, M.j. BluntAbstract:We study three-Phase flow in water-wet, oil-wet, and fractionally-wet sandpacks. We use CT scanning to measure directly the oil and water Relative permeabilites for three-Phase gravity drainage. In an analogue experiment, we measure pressure gradients in the gas Phase to determine the gas Relative Permeability. Thus we find all three Relative permeabilities as a function of saturation. We find that the gas Relative Permeability is approximately half as much in a oil-wet medium than in an water-wet medium at the same gas saturation. The water Relative Permeability in the water-wet medium and the oil Relative Permeability in the oil-wet medium are similar. In the water-wet medium the oil Relative Permeability scales as kro ∼ So4 for So > Sor, where Sor is the waterflood residual oil saturation. With octane as the oil Phase, kro ∼ So2 for So < Sor, while with decane as the oil Phase, kro falls sharply for So < Sor. The water Relative Permeability in the oil-wet medium resembles the oil Relative Permeability in the water-wet medium for a non-spreading oil such as decane. These observations can be explained in terms of wetting, spreading, and the pore scale configurations of fluid.
Fangming Jiang - One of the best experts on this subject based on the ideXlab platform.
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Impact of PTFE content and distribution on liquid–gas flow in PEMFC carbon paper gas distribution layer: 3D lattice Boltzmann simulations
International Journal of Hydrogen Energy, 2016Co-Authors: Wang Chen, Fangming JiangAbstract:Abstract A 3D multiPhase lattice Boltzmann model (LBM) was established and employed to study the impact of polytetrafluoroethylene (PTFE) content and distribution on the liquid–gas transport in proton exchange membrane fuel cell (PEMFC) carbon-paper gas distribution layer (GDL). In the computer-generated carbon paper GDL, part of the fibers’ surface was randomly specified as PTFE to achieve a desired PTFE content and distribution. For non-uniform PTFE distribution cases, a GDL sub-region neighboring to gas channel (GC) was set to have higher PTFE content. PTFE content and distribution show important influence on the liquid–gas flow and on the relationship of Relative Permeability versus Phase saturation. The GDL sub-region of more PTFE acts like a capillary barrier and raises the liquid saturation level in the rest part of GDL. The simulated liquid saturation level in GDL diminishes with the increase of PTFE content in GDL. The liquid Phase Relative Permeability is larger in the GDL of lower PTFE content if the (overall) liquid saturation is lower than a threshold value, whereas it becomes smaller if the liquid saturation is higher than this threshold value. The liquid Phase Relative Permeability in the GDL with non-uniform PTFE distribution is reduced when the liquid saturation in GDL is lower than a certain value, but when the liquid saturation is higher than this value, it is larger compared with that in the GDL with uniform PTFE distribution. The gas Phase Relative Permeability in the GDL of lower PTFE content is larger than tat in the GDL of higher PTFE content and the non-uniform distribution of PTFE in GDL slightly reduces the gas Phase Relative Permeability value.
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impact of ptfe content and distribution on liquid gas flow in pemfc carbon paper gas distribution layer 3d lattice boltzmann simulations
International Journal of Hydrogen Energy, 2016Co-Authors: Wang Che, Fangming JiangAbstract:Abstract A 3D multiPhase lattice Boltzmann model (LBM) was established and employed to study the impact of polytetrafluoroethylene (PTFE) content and distribution on the liquid–gas transport in proton exchange membrane fuel cell (PEMFC) carbon-paper gas distribution layer (GDL). In the computer-generated carbon paper GDL, part of the fibers’ surface was randomly specified as PTFE to achieve a desired PTFE content and distribution. For non-uniform PTFE distribution cases, a GDL sub-region neighboring to gas channel (GC) was set to have higher PTFE content. PTFE content and distribution show important influence on the liquid–gas flow and on the relationship of Relative Permeability versus Phase saturation. The GDL sub-region of more PTFE acts like a capillary barrier and raises the liquid saturation level in the rest part of GDL. The simulated liquid saturation level in GDL diminishes with the increase of PTFE content in GDL. The liquid Phase Relative Permeability is larger in the GDL of lower PTFE content if the (overall) liquid saturation is lower than a threshold value, whereas it becomes smaller if the liquid saturation is higher than this threshold value. The liquid Phase Relative Permeability in the GDL with non-uniform PTFE distribution is reduced when the liquid saturation in GDL is lower than a certain value, but when the liquid saturation is higher than this value, it is larger compared with that in the GDL with uniform PTFE distribution. The gas Phase Relative Permeability in the GDL of lower PTFE content is larger than tat in the GDL of higher PTFE content and the non-uniform distribution of PTFE in GDL slightly reduces the gas Phase Relative Permeability value.
Mehran Sohrabi - One of the best experts on this subject based on the ideXlab platform.
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An Improved Approach to Estimate Three-Phase Relative Permeability Functions for Heavy-Oil Displacement Involving Instability and Compositional Effects
Energies, 2017Co-Authors: Pedram Mahzari, Usman Taura, Alexander J. Cooke, Mehran SohrabiAbstract:Simultaneous three-Phase flow of gas, oil and water is a common phenomenon in enhanced oil recovery techniques such as water-alternating-gas (WAG) injection. Reliable reservoir simulations are required to predict the performance of these injections before field application. However, heavy oil displacement by gas or water can lead to viscous fingering due to the unfavorable mobility ratio between heavy oil and the displacing fluid. In addition, the injection of partially dissolvable gases such as CO2 can result in compositional effects, which can bring about a significant reduction of oil viscosity and hence can cause variations of the mobility ratio. Estimations of three-Phase Relative Permeability under such conditions are extremely complex, and using conventional techniques for the estimation can lead to erroneous results. We used the results of four coreflood experiments, carried out on a core, to estimate two-Phase and three-Phase Relative Permeability. A new history matching methodology for laboratory experiments was used that takes into account the instability and the compositional effects in the estimation processes. The results demonstrate that a simultaneous CO2 and water injection (CO2-simultaneous water and gas (SWAG)) can be adequately matched using the Relative permeabilities of a secondary gas/liquid and a tertiary oil/water. In heavy oil WAG injection, the injected water follows the CO2 path due its lower resistance as a result of the CO2 dissolution in the oil and the resultant reduction of the oil viscosity. This is contrary to WAG injection in conventional oils, where gas and water open up separate saturations paths. It is also important to include capillary pressure (Pc), even in high permeable porous media, as we observed that the inclusion of capillary pressure dampened the propagation of the viscous fingers and hence helped the front to become stabilized, leading to a more realistic simulated sweep efficiency.
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Modeling of Cyclic Hysteresis of Three-Phase Relative Permeability During Water-Alternating-Gas Injection
SPE Journal, 2014Co-Authors: Hamidreza Shahverdi, Mehran SohrabiAbstract:Summary MultiPhase flow takes place in many petroleum reservoirs—in particular, mature fields and reservoirs under fluid [e.g., gas, water-alternating-gas (WAG)] injection. The numerical simulation of such reservoirs requires knowledge of flow functions (i.e., Relative Permeability and capillary pressure). Because experimental measurement of fluid permeabilities (in particular) under three-Phase-flow conditions is very time-consuming and difficult, many correlations and models were developed and these are widely used instead of measured data. In this study, we have used the results of a comprehensive set of WAG-injection coreflood experiments performed under different wettability conditions and core-Permeability values to obtain Relative permeabilites of oil, water, and gas under reservoir pressure and temperature. Three-Phase Relative Permeability of each Phase was obtained by history matching the measured production and differential pressure obtained in the laboratory. The results of the experiments revealed significant cyclic hysteresis effects in gas and oil Relative Permeability. We proposed new formulations and methodology for the modeling of cyclic hysteresis of three-Phase Relative Permeability during WAG injection. This technique is a direct method that uses measured three-Phase kr data obtained from the first cycle of WAG injection to predict the Relative Permeability of the subsequent cycles. The integrity of this technique was validated against the three-Phase kr data obtained from our WAG experiments. We also assess the validity of the WAG-injection hysteresis model available in reservoir simulators against our three-Phase Relative Permeability data to evaluate its performance.
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An Improved Three-Phase Relative Permeability and Hysteresis Model for the Simulation of a Water-Alternating-Gas Injection
SPE Journal, 2013Co-Authors: Hamidreza Shahverdi, Mehran SohrabiAbstract:Summary Water-alternating-gas (WAG) injection in waterflooded reservoirs can increase oil recovery and extend the life of these reservoirs. Reliable reservoir simulations are needed to predict the performance of WAG injection before field implementation. This requires accurate sets of Relative Permeability (kr) and capillary pressure (Pc) functions for each fluid Phase, in a three-Phase-flow regime. The WAG process also involves another major complication, hysteresis, which is caused by flow reversal happening during WAG injection. Hysteresis is one of the most important phenomena manipulating the performance of WAG injection, and hence, it has to be carefully accounted for. In this study, we have benefited from the results of a series of coreflood experiments that we have been performing since 1997 as a part of the Characterization of Three-Phase Flow and WAG Injection JIP (joint industry project) at Heriot-Watt University. In particular, we focus on a WAG experiment carried out on a water-wet core to obtain three-Phase Relative Permeability values for oil, water, and gas. The Relative permeabilities exhibit significant and irreversible hysteresis for oil, water, and gas. The observed hysteresis, which is a result of the cyclic injection of water and gas during WAG injection, is not predicted by the existing hysteresis models. We present a new three-Phase Relative Permeability model coupled with hysteresis effects for the modeling of the observed cycle-dependent Relative permeabilities taking place during WAG injection. The approach has been successfully tested and verified with measured three-Phase Relative Permeability values obtained from a WAG experiment. In line with our laboratory observations, the new model predicts the reduction of the gas Relative Permeability during consecutive water-and-gas-injection cycles as well as the increase in oil Relative Permeability happening in consecutive water-injection cycles.
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Three-Phase Relative Permeability and hysteresis effect during WAG process in mixed wet and low IFT systems
Journal of Petroleum Science and Engineering, 2011Co-Authors: Hamidreza Shahverdi, Mehran Sohrabi, Mobeen Fatemi, Mahmoud JamiolahmadyAbstract:Abstract There is significant uncertainty associated with the selection of three-Phase Relative Permeability in particular for the numerical simulations of water-alternating-gas (WAG) injection. Generally, three-Phase Relative permeabilities are calculated from empirical correlations, which are based on two-Phase Relative permeabilities. Water alternating gas injection involves drainage and imbibition processes taking place sequentially. Therefore, accurate prediction of the Relative Permeability ( k r ) functions and their hysteresis effects applicable to WAG are extremely complex. The problem of 3-Phase k r selection becomes even more difficult for three-Phase systems involving mixed-wet rocks and low gas–oil IFT (interfacial tension) fluids (nearly-miscible fluids). We use the results of coreflood experiments carried out on two different cores (one water-wet and one mixed-wet) using a low IFT gas–oil system to generate two-Phase and three-Phase Relative Permeability data by using an in-house three-Phase coreflood simulator. The results show that water and gas three-Phase k r values depend on two independent saturations, contrary to the inherent assumption in most of the existing empirical k r models. Three-Phase water, oil and gas k r values were all significantly lower than their corresponding two-Phase values. This reduction in k r was more profound for the gas where the three-Phase k rg was an order of magnitude lower than its corresponding two-Phase k rg . Using the laboratory derived three-Phase k r data, the performance of some of the existing three-Phase k r models was evaluated by comparing the results of the WAG experiments with predictions made by a commercial reservoir simulator. In general, considerable discrepancies between the measured and the predicted k r values were observed. Some models performed better than others but no single model was capable of matching all experimental results adequately.
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a new algorithm for estimating three Phase Relative Permeability from unsteady state core experiments
Transport in Porous Media, 2011Co-Authors: Hamidreza Shahverdi, Mehran Sohrabi, Mahmoud JamiolahmadyAbstract:We present a new history matching method based on a Genetic Algorithm to estimate three-Phase k r (Relative Permeability) from unsteady-state coreflood experiments. In this method, Relative permeabilities (k r) are represented by quadratic B-Spline functions. Adjustable coefficients in k r functions are changed in an iterative process to minimize an objective function. The objective function is defined as the difference between the measures and simulated values of the pressure drop across the core and fluids recovery during the experiment. One of the main features of this approach is that water and gas Relative permeabilities (k rw and k rg) are assumed to be functions of two independent saturations as opposed to most of the existing empirical k r models in which k rw and k rg are assumed to be only dependent of their own saturations. Another important aspect of this algorithm is that it considers inequality constrains to ensure that physically acceptable k r curves are maintained throughout the iterative optimization process. A three-Phase coreflood simulator has been developed based on this methodology that generates best k r values by matching experimental data. The integrity of the developed software was first successfully verified by using two sets of experimental three-Phase k r data published in the literature. Then, the results of some three-Phase coreflood experiments carried out in our laboratory were used to obtain three-Phase k r curves by this approach.
Xiongyu Chen - One of the best experts on this subject based on the ideXlab platform.
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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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an extended jbn method of determining unsteady state two Phase Relative Permeability
Water Resources Research, 2016Co-Authors: Xiongyu Chen, Amir Kianinejad, David A. DicarloAbstract:Relative Permeability is the reduction of Permeability of porous media when subjected to multi-Phase flow and a key parameter in subsurface hydrology. The JBN method [Welge, 1952; Johnson et al., 1959] is a well-known method of obtaining Relative Permeability, which measures the overall pressure drop and the effluent Phase ratio versus time during two-Phase displacements. By assuming no capillary pressure or gravity, the JBN method obtains the Relative permeabilities to both Phases at the core outlet. Since data across a range of saturations are acquired in a Relatively short time, this method is widely used. This work extends the JBN method by having (1) section-wise pressure drop measurements between the core inlet, four pressure taps on the core and the outlet, (2) local saturation measurements, and (3) local Phase fluxes. With these data, the extended JBN method can determine Relative permeabilities to both Phases at each pressure tap of the core (not just at the core outlet). The JBN extension is shown using a data set where CO2 invades a brine-filled core. From this it is found that the advantages of the extended JBN method over the regular JBN method are: (1) four times more data are obtained, and (2) data are more accurate because the capillary end effect is experimentally avoided. Avoiding the end effect results in tripling the saturation range, and obtaining Relative permeabilities that are consistent with steady-state measurements and roughly 40% higher than those from the regular JBN method. This article is protected by copyright. All rights reserved.
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The effect of saturation path on three‐Phase Relative Permeability
Water Resources Research, 2015Co-Authors: Amir Kianinejad, Xiongyu Chen, David A. DicarloAbstract:Simulation and fluid flow prediction of many petroleum enhanced oil recovery methods as well as environmental processes such as carbon dioxide (CO2) geological storage or underground water resources remediation requires accurate modeling and determination of Relative Permeability under different saturation histories. Based on this critical need, several three-Phase Relative Permeability models were developed to predict Relative Permeability; however, for practical purposes most of them require a variety of parameters introducing undesired complexity to the models. In this work, we attempt to find out if there is a simpler way to express this functionality. To do so, we experimentally measure three-Phase, water/oil/gas, Relative Permeability in a 1-m long water-wet sand pack, under several saturation flow paths to cover the entire three-Phase saturation space. We obtain the in-situ saturations along the sand pack using a CT scanner and then determine the Relative permeabilities of liquid Phases directly from the measured in-situ saturations using an unsteady-state method. The measured data shows that at a specific saturation, the oil Relative Permeability varies significantly (up to 2 orders of magnitude), depending on the path through saturation space. The three-Phase Relative Permeability data are modeled using standard Relative Permeability models, Corey-type and Saturation Weighted Interpolation (SWI). Our measured data suggest that three-Phase oil Relative Permeability in water-wet media is only a function of its own saturation if the residual oil saturation is treated as a function of two saturations. We determine that residual saturation is the key parameter in modeling three-Phase Relative Permeability (effect of saturation history). This article is protected by copyright. All rights reserved.
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the effect of saturation path on three Phase Relative Permeability
Water Resources Research, 2015Co-Authors: Amir Kianinejad, Xiongyu Chen, David A. DicarloAbstract:Simulation and fluid flow prediction of many petroleum enhanced oil recovery methods as well as environmental processes such as carbon dioxide (CO2) geological storage or underground water resources remediation requires accurate modeling and determination of Relative Permeability under different saturation histories. Based on this critical need, several three-Phase Relative Permeability models were developed to predict Relative Permeability; however, for practical purposes most of them require a variety of parameters introducing undesired complexity to the models. In this work, we attempt to find out if there is a simpler way to express this functionality. To do so, we experimentally measure three-Phase, water/oil/gas, Relative Permeability in a 1-m long water-wet sand pack, under several saturation flow paths to cover the entire three-Phase saturation space. We obtain the in-situ saturations along the sand pack using a CT scanner and then determine the Relative permeabilities of liquid Phases directly from the measured in-situ saturations using an unsteady-state method. The measured data shows that at a specific saturation, the oil Relative Permeability varies significantly (up to 2 orders of magnitude), depending on the path through saturation space. The three-Phase Relative Permeability data are modeled using standard Relative Permeability models, Corey-type and Saturation Weighted Interpolation (SWI). Our measured data suggest that three-Phase oil Relative Permeability in water-wet media is only a function of its own saturation if the residual oil saturation is treated as a function of two saturations. We determine that residual saturation is the key parameter in modeling three-Phase Relative Permeability (effect of saturation history). This article is protected by copyright. All rights reserved.
M.j. Blunt - One of the best experts on this subject based on the ideXlab platform.
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An Empirical Model for Three-Phase Relative Permeability
SPE Journal, 2000Co-Authors: M.j. BluntAbstract:Summary We present an empirical model for three-Phase Relative Permeability. We allow for changes in hydrocarbon composition, different saturation paths, and the trapping of oil, water, and gas. The model is based on saturation-weighted interpolation between the two-Phase Relative permeabilities. By writing the Relative permeabilities as unique functions of a flowing saturation, the model predicts the behavior for any sequence of saturation changes and accounts for trapping. Layer drainage allows the oil Relative Permeability to be extrapolated to low saturation. The formulation for water-wet media, including layer drainage and trapping, is tested against experimental three-Phase data. Introduction The flow of three Phases—oil, water, and gas—occurs in a variety of circumstances in oil and gas reservoirs, and during nonaqueous Phase migration and cleanup in the unsaturated zone. To understand the fluid movement, estimates of three-Phase Relative permeabilities are needed. While two-Phase Relative permeabilities (oil/water, gas/oil, and gas/water) are often time consuming to obtain, there are only two principal displacement paths: the saturation of one Phase may either increase or decrease. In contrast, the measurement of three-Phase Relative Permeability poses a particular challenge. In addition to the measurement of saturations, pressure drops, and fluxes in three flowing Phases, there are an infinite number of different displacement paths. This is because any three-Phase displacement involves the variation of two independent saturations. Thus, it is impractical to measure Relative Permeability for all possible three-Phase displacements that may occur in a reservoir—including, for instance, solution gas drive, gas injection, and waterflooding with different initial oil and gas saturations. Empirical models predict the three-Phase Relative Permeability kro as a function of the oil Relative Permeability in the presence of water only, kro(w) and the oil Relative Permeability in the presence of gas (and normally irreducible or connate water), kro(g) Since the pore occupancy in three-Phase flow is not necessarily represented by the two-Phase experiments, there is no guarantee that an empirical model, however sophisticated, will be able to predict the three-Phase Relative Permeability accurately. Stone1,2 proposed two empirical models of three-Phase Relative Permeability that are widely used in the oil industry. These models have become a benchmark against which experimental measurements, and other models, are compared. However, several reviews of the literature have shown that Stone's models occasionally fail to predict three-Phase Relative Permeability accurately.3–5 In recent years our fundamental physical understanding of three-Phase flow at the pore level has increased significantly. Micromodel experiments and theoretical analysis have elucidated the microscopic three-Phase displacement mechanisms.6–11 These studies have been used to develop pore network models that predict Relative Permeability directly from a knowledge of the pore structure and the displacement physics.12–15 Two-Phase Relative Permeability has been successfully predicted for sandstones16,17 and three-Phase network models have been able to match the generic features of experimental measurements.13 Recently, promising progress has been made in predicting three-Phase Relative Permeability from pore-scale models.18 However, empirical models are still widely used since an accurate description of the pore geometry and wettability is not always available. Many of the currently used empirical models suffer from three major limitations. First, they were developed for water-wet media but are applied to reservoir rocks, which are rarely water-wet. Although Stone 1,2 discussed extensions to oil-wet media, we will show that some of the assumptions made in this analysis are sometimes incorrect. Second, the models fail to account for the trapping of oil and gas for any displacement sequence. Larsen and Skauge19 extended Stone's Model I to allow for gas trapping during repeated water alternating gas (WAG) cycles. Jerauld20 presented a model for Prudhoe Bay Relative Permeability that accounted for oil and gas trapping. We will use a modification of these approaches. Third, the functional form of the Relative Permeability at low oil saturation, often the regime of greatest interest for enhanced oil recovery projects and contaminant cleanup, disagrees with recent experimental results. We will develop a model that overcomes the limitations listed above. It is based on saturation-weighted averages of the two-Phase Relative permeabilities, which was first suggested by Baker.3 Saturation-weighted interpolation is applied to all three Phases, as used by Hustad and Hansen.21 We will include gas and oil trapping based on the work of Land22 and Carlson,23 which enables three-Phase Relative Permeability to be estimated for any saturation path. We will also introduce a model for oil layer drainage that allows the oil Relative Permeability to be extrapolated to low saturation. The model is extended to ensure smooth changes in Relative Permeability with changing oil and gas composition, and to give the correct limits to the oil and gas Relative permeabilities for miscible flow. A similar method for compositional consistency has been proposed by Fayers et al.,24 although we use a different method for considering trapping. The model is then successfully tested against the three-Phase data of Oak et al.25,26 Stone's Models I and II Stone1,2 proposed two empirical three-Phase Relative Permeability models. He assumed that the water and gas Relative permeabilities are functions only of their own saturations. The Stone I model 1 assumes that the water and gas block the flow of the oil Phase, and that the degree of blocking is computed from the two-Phase Relative permeabilities. The version of the Stone I model normally used in simulators was proposed by Aziz and Settari27 and includes a normalization to ensure that the model reduces smoothly to the two-Phase data when Sg=0, or S w=Swi: k r o = S o e k r o ( w ) k r o ( g ) k r o ( w i ) ( 1 − S w e ) ( 1 − S g e ) , ( 1 ) where S o e = S o − S o m 1 − S w i − S o m , ( 2 ) S w e = S w − S w i 1 − S w i − S o m , ( 3 ) S g e = S g 1 − S w i − S o m . ( 4 )
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Three-Phase Relative Permeability of Water-Wet, Oil-Wet, and Mixed-Wet Sandpacks
SPE Journal, 2000Co-Authors: D.a. Dicarlo, Sahni Akshay, M.j. BluntAbstract:Summary We study three-Phase flow in water-wet, oil-wet, mixed-wet, and fractionally wet sandpacks. We make the mixed-wet pack by invading a water-filled water-wet pack with crude oil and aging it for a week. This process mimics wettability changes in reservoir settings, leading to a realistic arrangement of wettability at the pore scale. We characterize the wettability of each sand pack by measuring the capillary pressure curves. We obtain the oil and water Relative permeabilites during three-Phase gravity drainage, by measuring the saturation in situ using computerized tomography scanning. In an analog experiment, we measure pressure gradients in the gas Phase to obtain the gas Relative Permeability. Thus we determine all three Relative permeabilities as a function of saturation for each wettability. We find that under uniform wetting, the Relative permeabilities of the most-wetting Phase (water in a water-wet pack, oil in an oil-wet pack) are similar. However, the Relative permeabilities of the intermediate-wet Phase (oil in a water-wet pack, water in a oil-wet pack) are very different at low saturations, with spreading oils showing a characteristic layer drainage regime. The mixed-wet pack also shows the layer drainage regime. We also find that the gas Relative Permeability is smaller in an oil-wet medium than in a water-wet medium. We explain the observations in terms of wetting, spreading, and the pore scale configurations of fluid. Introduction A knowledge of three-Phase (water, oil, and gas) flow in porous media is essential for predicting enhanced oil recovery and the migration of nonaqueous Phase pollutants. In oil reservoirs, three-Phase flow will occur during gas injection, gas cap expansion, and thermal flooding among other processes. In two-Phase flow, one Phase will wet the porous medium more than the other Phase. This wetting Phase occupies the smaller pores, crevices, and corners while the nonwetting Phase occupies the larger pores with the exact arrangement determined by the capillary pressure. Regardless of which pair of fluids is used (gas/water, oil/water, gas/oil) positioning of the fluids is likely to be similar at the same saturations. In contrast, for three-Phase flow there will be an intermediate-wetting Phase which will be positioned uniquely in the porous medium, and will affect macroscopic properties such as Relative Permeability and residual saturation. We measure three-Phase Relative permeabilities during the gravity driven displacement of oil and water by gas, which is called gravity drainage. This is an important three-Phase process that occurs during gas cap expansion in an oil reservoir and when nonaqueous Phase pollutants migrate through an unsaturated soil. Gravity drainage is also Relatively easy to study experimentally and its analysis avoids consideration of hysteresis effects, which can be very significant in three-Phase flow.1,2 Several authors3–5 have shown that low oil saturations can be reached during three-Phase displacements. Most experiments have been performed on uniformly water-wet media (see Ref. 6 for a review). Oak et al.7 studied three-Phase Relative permeabilities in an intermediate-wet Berea sandstone. Vizika and Lombard8 studied three-Phase drainage for water-wet, oil-wet, and fractionally wet systems. Jerauld9 developed a model for three-Phase Relative Permeability based on two-Phase measurements for Prudhoe Bay, which is a mixed-wet reservoir. Sahni et al.10 used computerized tomography (CT) scanning to measure oil and water Relative Permeability in water-wet media and studied the effect of the spreading coefficient. Zhou and Blunt11 performed three-Phase gravity drainage in fractionally wet sandpacks. They measured the saturation distribution at the end of drainage and interpreted the results in terms of the pore scale arrangement of fluid. DiCarlo et al.12 measured three-Phase Relative permeabilities for oil-wet and fractionally wet packs. The fractionally wet media studied in the literature were composed of mixtures of oil-wet and water-wet grains. While this is a convenient way of varying the wettability, it does not necessarily represent the real distribution of wettability in a natural setting. An alternative approach is to mimic a physical sequence of wettability changes in the laboratory, which leads to a medium whose pore-scale pattern of wettability represents reservoir rocks. This is achieved by flooding a water-wet water-filled pack with a crude oil and then aging it for several days. This induces a wettability change on the sand surfaces that have come into contact with the oil (see, for example, Ref. 13). Smaller pores that are water filled and the corners of the pore space will remain water-wet. We will call such systems mixed wet. In this article we extend the work of Sahni et al.10 and of DiCarlo et al.12 to mixed-wet media. The description of the experiments follows that of DiCarlo et al.12 and, for the sake of completeness, we present all our results in water-wet, oil-wet, fractionally wet, and mixed-wet media. We characterize the wettability by measuring two-Phase (water/oil) capillary pressure curves. We measure the gas Relative Permeability using an analog experiment in which we directly measure the gas saturation and pressure gradient. Thus we obtain all three permeabilities for three-Phase gravity drainage, in water-wet, oil-wet, mixed-wet, and fractionally wet sandpacks. We explain the results in terms of the pore-scale fluid arrangements. Materials and Methods We chose sandpacks as our porous media because they are easy to characterize and they can be easily sectioned for destructive saturation measurements. We used clean industrial sand (No. 60, Corona Industrial Sand Co., Corona, CA) which was initially water- wet. The sand was put through a size 120 sieve to remove any fine particles. We made 15 kg of the sand oil-wet by soaking initially dry sand in a mixture of 20% crude oil (Thums Inc., Long Beach, CA) and 80% iso-octane for 24 hours.14 This oil-wet sand was then rinsed with iso-octane and air dried. The fractionally wet sand was a 50-50 mixture of the oil and water-wet sands.
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The effect of wettability on three-Phase Relative Permeability
Transport in Porous Media, 2000Co-Authors: David A. Dicarlo, Akshay Sahni, M.j. BluntAbstract:We study three-Phase flow in water-wet, oil-wet, and fractionally-wet sandpacks. We use CT scanning to measure directly the oil and water Relative permeabilites for three-Phase gravity drainage. In an analogue experiment, we measure pressure gradients in the gas Phase to determine the gas Relative Permeability. Thus we find all three Relative permeabilities as a function of saturation. We find that the gas Relative Permeability is approximately half as much in a oil-wet medium than in an water-wet medium at the same gas saturation. The water Relative Permeability in the water-wet medium and the oil Relative Permeability in the oil-wet medium are similar. In the water-wet medium the oil Relative Permeability scales as kro ∼ So4 for So > Sor, where Sor is the waterflood residual oil saturation. With octane as the oil Phase, kro ∼ So2 for So < Sor, while with decane as the oil Phase, kro falls sharply for So < Sor. The water Relative Permeability in the oil-wet medium resembles the oil Relative Permeability in the water-wet medium for a non-spreading oil such as decane. These observations can be explained in terms of wetting, spreading, and the pore scale configurations of fluid.
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Empirical model for three-Phase Relative Permeability
Journal of Petroleum Technology, 1999Co-Authors: M.j. BluntAbstract:A new empirical model has been developed to estimate three-Phase Relative Permeability. A literature review indicates that use of a model based on saturation-weighted interpolation of two-Phase Relative permeabilities provides more accurate data. ○ Saturation-weighted interpolation is extended to account for oil and gas trapping and allow oil-layer drainage. ○ Compositional consistency is introduced to account for miscible and near-miscible flows. ○ From a single set of two-Phase oil/water, gas/water, and gas/oil measurements, three-Phase Relative permeabilities can be predicted for any saturation path, reservoir wettability, and hydrocarbon composition.
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An Empirical Model for Three-Phase Relative Permeability
SPE Annual Technical Conference and Exhibition, 1999Co-Authors: M.j. BluntAbstract:We present an empirical model for three-Phase Relative Permeability that overcomes the limitations of current formulations, such as Stone’s methods. 1,2 We provide a selfconsistent treatment of wettability, changes in hydrocarbon composition, different saturation paths, and the trapping of oil, water and gas. The theoretical development is motivated by a review of recent three-Phase experiments. The model is based on saturation-weighted interpolation between the two-Phase values. 3 To account for the effects of wettability we apply saturation-weighting to all three Phases. By writing the Relative permeabilities as unique functions of a flowing saturation, the model predicts the behavior for any sequence of saturation changes and accounts for trapping. Layer drainage, which allows oil Relative permeabilities to be extrapolated to low saturation, is included for water-wet media. The model ensures smooth changes in Relative Permeability with changes in hydrocarbon composition and tends to the appropriate limits as the gas and oil become miscible. The model is tested against the data of Oak and co-workers. 4,5 We show that it is necessary to include layer drainage and oil trapping to predict three-Phase oil Relative Permeability at low oil saturation accurately.