The Experts below are selected from a list of 9747 Experts worldwide ranked by ideXlab platform
Viviane Sampaio Santiago Dos Santos - One of the best experts on this subject based on the ideXlab platform.
-
characterization of pore systems in seal rocks using nitrogen gas adsorption combined with mercury injection capillary pressure techniques
Marine and Petroleum Geology, 2013Co-Authors: Mayka Schmitt, Celso Peres Fernandes, Jose Neto, Fabiano G Wolf, Viviane Sampaio Santiago Dos SantosAbstract:Abstract Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the Intrinsic Permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N 2 GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N 2 GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area ( S o ). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N 2 GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The S o values measured by N 2 GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 A. The Intrinsic Permeability could also be predicted applying the measured parameters, S o , PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of Permeability values obtained were 4.09 × 10 −24 –4.96 × 10 −21 m 2 and 9.48 × 10 −27 –9.14 × 10 −22 m 2 , respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay Permeability (PDP) tests.
-
characterization of pore systems in seal rocks using nitrogen gas adsorption combined with mercury injection capillary pressure techniques
Marine and Petroleum Geology, 2013Co-Authors: Mayka Schmi, Celso Peres Fernandes, Jose Neto, Fabiano G Wolf, Viviane Sampaio Santiago Dos SantosAbstract:Abstract Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the Intrinsic Permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N 2 GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N 2 GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area ( S o ). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N 2 GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The S o values measured by N 2 GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 A. The Intrinsic Permeability could also be predicted applying the measured parameters, S o , PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of Permeability values obtained were 4.09 × 10 −24 –4.96 × 10 −21 m 2 and 9.48 × 10 −27 –9.14 × 10 −22 m 2 , respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay Permeability (PDP) tests.
Wenquan Tao - One of the best experts on this subject based on the ideXlab platform.
-
generalized lattice boltzmann model for flow through tight porous media with klinkenberg s effect
Physical Review E, 2015Co-Authors: Li Chen, Qinjun Kang, Wenzhen Fang, Jeffrey D Hyman, Hari S Viswanathan, Wenquan TaoAbstract:Gas slippage occurs when the mean free path of the gas molecules is in the order of the characteristic pore size of a porous medium. This phenomenon leads to Klinkenberg's effect where the measured Permeability of a gas (apparent Permeability) is higher than that of the liquid (Intrinsic Permeability). A generalized lattice Boltzmann model is proposed for flow through porous media that includes Klinkenberg's effect, which is based on the model of Guo et al. [Phys. Rev. E 65, 046308 (2002)]. The second-order Beskok and Karniadakis-Civan's correlation [A. Beskok and G. Karniadakis, Microscale Thermophys. Eng. 3, 43 (1999) and F. Civan, Transp. Porous Med. 82, 375 (2010)] is adopted to calculate the apparent Permeability based on Intrinsic Permeability and the Knudsen number. Fluid flow between two parallel plates filled with porous media is simulated to validate the model. Simulations performed in a heterogeneous porous medium with components of different porosity and Permeability indicate that Klinkenberg's effect plays a significant role on fluid flow in low-Permeability porous media, and it is more pronounced as the Knudsen number increases. Fluid flow in a shale matrix with and without fractures is also studied, and it is found that the fractures greatly enhance the fluid flow and Klinkenberg's effect leads to higher global Permeability of the shale matrix.
-
nanoscale simulation of shale transport properties using the lattice boltzmann method Permeability and diffusivity
Scientific Reports, 2015Co-Authors: Li Chen, Qinjun Kang, Hari S Viswanathan, Lei Zhang, Jun Yao, Wenquan TaoAbstract:Porous structures of shales are reconstructed using the markov chain monte carlo (MCMC) method based on scanning electron microscopy (SEM) images of shale samples from Sichuan Basin, China. Characterization analysis of the reconstructed shales is performed, including porosity, pore size distribution, specific surface area and pore connectivity. The lattice Boltzmann method (LBM) is adopted to simulate fluid flow and Knudsen diffusion within the reconstructed shales. Simulation results reveal that the tortuosity of the shales is much higher than that commonly employed in the Bruggeman equation, and such high tortuosity leads to extremely low Intrinsic Permeability. Correction of the Intrinsic Permeability is performed based on the dusty gas model (DGM) by considering the contribution of Knudsen diffusion to the total flow flux, resulting in apparent Permeability. The correction factor over a range of Knudsen number and pressure is estimated and compared with empirical correlations in the literature. For the wide pressure range investigated, the correction factor is always greater than 1, indicating Knudsen diffusion always plays a role on shale gas transport mechanisms in the reconstructed shales. Specifically, we found that most of the values of correction factor fall in the slip and transition regime, with no Darcy flow regime observed.
Bin Wang - One of the best experts on this subject based on the ideXlab platform.
-
influence of Intrinsic Permeability of reservoir rocks on gas recovery from hydrate deposits via a combined depressurization and thermal stimulation approach
Applied Energy, 2018Co-Authors: Jiafei Zhao, Zhen Fan, Bin Wang, Weixin PangAbstract:Abstract Reservoir Permeability is a crucial controlling factor for the successful exploitation of unconventional gas hydrate resources, which represent a vast natural gas reserve with substantial energy potential. Numerical simulations and analyses are essential tools for the prediction and evaluation of natural gas recovery from hydrate deposits. In this study, a two-dimensional axisymmetric model was developed and validated to investigate the effect of the Intrinsic Permeability of reservoir rocks on hydrate dissociation characteristics induced by a combined depressurization and thermal stimulation method. Simulation results indicate that the average gas production rate from hydrate deposits could be enhanced when thermal stimulation was additionally applied at the same production pressure, but the enhancement effect weakens as reservoir Permeability increases. Pressure reduction propagates slowly from gas production wells into cores with low-Permeability, and thermal stimulation dominates hydrate dissociation. However, depressurization can play a determining role for hydrate dissociation in high-Permeability cores which benefit to the propagation of pressure reduction. Increased Permeability promotes the characteristic shift from thermal-stimulation-governed radial hydrate dissociation to depressurization-determined uniform dissociation. To a certain extent, increased Permeability enhances gas generation, but there is a threshold beyond which this effect is no longer felt as excessive consumption of sensible heat restricts further hydrate dissociation. Although there are many uncertainties in the hydrate dissociation process in porous media, numerical simulation can provide useful information for evaluating the feasibility of methodology for gas recovery from gas hydrate reservoirs.
Fabiano G Wolf - One of the best experts on this subject based on the ideXlab platform.
-
characterization of pore systems in seal rocks using nitrogen gas adsorption combined with mercury injection capillary pressure techniques
Marine and Petroleum Geology, 2013Co-Authors: Mayka Schmitt, Celso Peres Fernandes, Jose Neto, Fabiano G Wolf, Viviane Sampaio Santiago Dos SantosAbstract:Abstract Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the Intrinsic Permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N 2 GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N 2 GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area ( S o ). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N 2 GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The S o values measured by N 2 GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 A. The Intrinsic Permeability could also be predicted applying the measured parameters, S o , PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of Permeability values obtained were 4.09 × 10 −24 –4.96 × 10 −21 m 2 and 9.48 × 10 −27 –9.14 × 10 −22 m 2 , respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay Permeability (PDP) tests.
-
characterization of pore systems in seal rocks using nitrogen gas adsorption combined with mercury injection capillary pressure techniques
Marine and Petroleum Geology, 2013Co-Authors: Mayka Schmi, Celso Peres Fernandes, Jose Neto, Fabiano G Wolf, Viviane Sampaio Santiago Dos SantosAbstract:Abstract Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the Intrinsic Permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N 2 GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N 2 GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area ( S o ). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N 2 GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The S o values measured by N 2 GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 A. The Intrinsic Permeability could also be predicted applying the measured parameters, S o , PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of Permeability values obtained were 4.09 × 10 −24 –4.96 × 10 −21 m 2 and 9.48 × 10 −27 –9.14 × 10 −22 m 2 , respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay Permeability (PDP) tests.
Jose Neto - One of the best experts on this subject based on the ideXlab platform.
-
characterization of pore systems in seal rocks using nitrogen gas adsorption combined with mercury injection capillary pressure techniques
Marine and Petroleum Geology, 2013Co-Authors: Mayka Schmitt, Celso Peres Fernandes, Jose Neto, Fabiano G Wolf, Viviane Sampaio Santiago Dos SantosAbstract:Abstract Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the Intrinsic Permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N 2 GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N 2 GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area ( S o ). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N 2 GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The S o values measured by N 2 GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 A. The Intrinsic Permeability could also be predicted applying the measured parameters, S o , PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of Permeability values obtained were 4.09 × 10 −24 –4.96 × 10 −21 m 2 and 9.48 × 10 −27 –9.14 × 10 −22 m 2 , respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay Permeability (PDP) tests.
-
characterization of pore systems in seal rocks using nitrogen gas adsorption combined with mercury injection capillary pressure techniques
Marine and Petroleum Geology, 2013Co-Authors: Mayka Schmi, Celso Peres Fernandes, Jose Neto, Fabiano G Wolf, Viviane Sampaio Santiago Dos SantosAbstract:Abstract Porous microstructure parameters of seal rock samples originating from different depths within Brazilian geological formations were correlated to empirical models which predict the Intrinsic Permeability. Mercury Injection Capillary Pressure (MICP) and Nitrogen Gas Adsorption (N 2 GA) were applied in combination as complementary techniques; MICP to obtain the porosity values and the size distribution of meso- and macropores, and N 2 GA associated with the Brunauer, Emmett and Teller (BET) theory to determine the specific surface area ( S o ). The Barret, Joyner and Hallenda (BJH) theory was applied to find the size distribution of the micro- and mesopores. The combination of the MICP and N 2 GA curves showed that the samples analyzed present a polymodal pore size distribution (PSD) and a total porosity ranging from 0.33 % to 10.44 %. The S o values measured by N 2 GA were higher than those calculated by MICP, due to the majority of the samples having a mean pore size of 20–1000 A. The Intrinsic Permeability could also be predicted applying the measured parameters, S o , PSD curves and total porosity in the Carman–Kozeny and Series–Parallel models. The ranges of Permeability values obtained were 4.09 × 10 −24 –4.96 × 10 −21 m 2 and 9.48 × 10 −27 –9.14 × 10 −22 m 2 , respectively. These results were compared with values reported in the related literature and those obtained for four samples submitted to pressure pulse decay Permeability (PDP) tests.
