• Energy Research

AbstractLimestone pore structure strongly influences dissolution and associated reactive transport. These effects are critical in limestone diagenesis and but also in engineering operations such as carbon capture and storage (CCS). However, detailed studies on how CO2‐enriched (acidic) brine changes this pore structure at relevant reservoir storage conditions are very limited. Thus, to provide further quantitative information and more fundamental understanding about these key processes, we studied the dissolution patterns of a homogeneous, a fractured, and a vuggy limestone when flooded with CO2‐saturated brine at representative storage conditions. The pore structured of these limestones showed drastically different responses to the acidic brine flood. As such, preferential channels surrounded by branched channels were formed in the homogeneous sample, while fractures became the main flow path in the fractured sample. In contrast, only one dominant channel formed in the vuggy sample, which resulted in a sharp permeability increase. These dissolution patterns reflect the associated Damköhler number, which significantly lower in the homogeneous, representing uniform dissolution. However, after injecting sufficient reactive fluid (1,000 PV), this uniform dissolution pattern transformed into a single preferential channel growth. Moreover, we conclude that increasing complexity of the pore geometry leads to more nonuniform dissolution. These dissolution patterns indicate the effect of initial pore structure on preferential channel growth and reaction transport. Our work provides key fundamental data for further quantifying limestone dissolution patterns in CCS, indicating that the CO2 injection may cause the reactivation of geological faults and damage around wellbore, thus aids in the implementation of industrial‐scale CCS.

AbstractLimestone pore structure strongly influences dissolution and associated reactive transport. These effects are critical in limestone diagenesis and but also in engineering operations such as carbon capture and storage (CCS). However, detailed studies on how CO2‐enriched (acidic) brine changes this pore structure at relevant reservoir storage conditions are very limited. Thus, to provide further quantitative information and more fundamental understanding about these key processes, we studied the dissolution patterns of a homogeneous, a fractured, and a vuggy limestone when flooded with CO2‐saturated brine at representative storage conditions. The pore structured of these limestones showed drastically different responses to the acidic brine flood. As such, preferential channels surrounded by branched channels were formed in the homogeneous sample, while fractures became the main flow path in the fractured sample. In contrast, only one dominant channel formed in the vuggy sample, which resulted in a sharp permeability increase. These dissolution patterns reflect the associated Damköhler number, which significantly lower in the homogeneous, representing uniform dissolution. However, after injecting sufficient reactive fluid (1,000 PV), this uniform dissolution pattern transformed into a single preferential channel growth. Moreover, we conclude that increasing complexity of the pore geometry leads to more nonuniform dissolution. These dissolution patterns indicate the effect of initial pore structure on preferential channel growth and reaction transport. Our work provides key fundamental data for further quantifying limestone dissolution patterns in CCS, indicating that the CO2 injection may cause the reactivation of geological faults and damage around wellbore, thus aids in the implementation of industrial‐scale CCS.

Abstract Coal and shale are strong heterogeneous anisotropic media involving nanoscale pore size and variance of microstructure. The complexity of methane adsorption is expressed both in diverse chemical properties and confined pore structures. In this study, Grand canonical Monte Carlo simulations were carried out to assess the influence of pore structure on methane adsorption at temperature 318 K, 333 K and pressure up to 20 MPa. The pore radii of physical carbon-based model range from 0.55 nm to 1.15 nm at the step of 0.1 nm. Simulated results indicate that the excess adsorption isotherms and maximum excess adsorption density are notably different for different pore structures. The triangle pore exhibits largest value of maximum excess adsorption density followed by the slit pore, circle pore and square pore. The maximum excess adsorption density is larger than 6 × 103 mol/m3 at simulated temperatures for triangle pore with pore radius less than 1 nm. The excess adsorption amount first increases with the increase of pressure and then decreases when the pressure is larger than 7.5 MPa for slit pore and 5 MPa for the circle pore, triangle pore and square pore. The excess adsorption amount for circle pore and square pore drops down to negative value when the pressure is larger than 12.5 MPa while the excess adsorption amount stays above zero across simulated pressure for the slit pore and triangle pore. The adsorption isotherms of micro-porous carbons were obtained by superposition of simulated adsorption isotherms based on the pore size distribution and were compared with coal samples experimental data gathered from the same temperature. The experimental isotherm is more close to slit pore excess isotherm and predicted excess isotherms based on circle pore and square pore under-estimate excess adsorption capacity.

Abstract Coal and shale are strong heterogeneous anisotropic media involving nanoscale pore size and variance of microstructure. The complexity of methane adsorption is expressed both in diverse chemical properties and confined pore structures. In this study, Grand canonical Monte Carlo simulations were carried out to assess the influence of pore structure on methane adsorption at temperature 318 K, 333 K and pressure up to 20 MPa. The pore radii of physical carbon-based model range from 0.55 nm to 1.15 nm at the step of 0.1 nm. Simulated results indicate that the excess adsorption isotherms and maximum excess adsorption density are notably different for different pore structures. The triangle pore exhibits largest value of maximum excess adsorption density followed by the slit pore, circle pore and square pore. The maximum excess adsorption density is larger than 6 × 103 mol/m3 at simulated temperatures for triangle pore with pore radius less than 1 nm. The excess adsorption amount first increases with the increase of pressure and then decreases when the pressure is larger than 7.5 MPa for slit pore and 5 MPa for the circle pore, triangle pore and square pore. The excess adsorption amount for circle pore and square pore drops down to negative value when the pressure is larger than 12.5 MPa while the excess adsorption amount stays above zero across simulated pressure for the slit pore and triangle pore. The adsorption isotherms of micro-porous carbons were obtained by superposition of simulated adsorption isotherms based on the pore size distribution and were compared with coal samples experimental data gathered from the same temperature. The experimental isotherm is more close to slit pore excess isotherm and predicted excess isotherms based on circle pore and square pore under-estimate excess adsorption capacity.

Abstract This paper presents a new upscaling method to derive the core-scale apparent gas permeability from an improved pore-scale permeability model and experimental data, with more rigorous incorporation of varying gas storage/transport mechanisms in nano/micro pores. First, in use of SEM images of a gas-rich shale field example in Sichuan Basin from our lab, pore network models of inorganic-matter (IOM) and organic-matter (OM) are characterized by using a digital-core technique. Next, an improved pore-scale real gas apparent permeability is modeled rigorously for both IOM/OM, respectively, with 1) bulk gas transport, gas adsorption, surface diffusion, pore-size confined phase behavior, and stress-dependent rock properties and 2) an additional reduction in inorganic pore sizes by water film adhered on pore surfaces. Core-scale permeability is then derived by assembling the permeabilities of stochastically distributed IOM/OM patches with different pore network models properties using the Monte Carlo sampling method. The new core-scale permeability model is validated by pulse-decay permeability experiment. Moreover, the representative elementary volume (REV) size is determined by analyzing the relative standard deviation of apparent gas permeability in cases with different sample sizes. The contributions of different gas transport mechanisms are discussed, and the impacts of stress-dependence for several field examples (i.e., Sichuan, Pierre and Barnett Basins) and water film with varying relative humidity (RH) on core-scale apparent permeability are analyzed. This work provides an effective approach to determine the core-scale shale permeability by directly using pore-scale experimental data, which is a common challenge in the unconventional resources.

Abstract This paper presents a new upscaling method to derive the core-scale apparent gas permeability from an improved pore-scale permeability model and experimental data, with more rigorous incorporation of varying gas storage/transport mechanisms in nano/micro pores. First, in use of SEM images of a gas-rich shale field example in Sichuan Basin from our lab, pore network models of inorganic-matter (IOM) and organic-matter (OM) are characterized by using a digital-core technique. Next, an improved pore-scale real gas apparent permeability is modeled rigorously for both IOM/OM, respectively, with 1) bulk gas transport, gas adsorption, surface diffusion, pore-size confined phase behavior, and stress-dependent rock properties and 2) an additional reduction in inorganic pore sizes by water film adhered on pore surfaces. Core-scale permeability is then derived by assembling the permeabilities of stochastically distributed IOM/OM patches with different pore network models properties using the Monte Carlo sampling method. The new core-scale permeability model is validated by pulse-decay permeability experiment. Moreover, the representative elementary volume (REV) size is determined by analyzing the relative standard deviation of apparent gas permeability in cases with different sample sizes. The contributions of different gas transport mechanisms are discussed, and the impacts of stress-dependence for several field examples (i.e., Sichuan, Pierre and Barnett Basins) and water film with varying relative humidity (RH) on core-scale apparent permeability are analyzed. This work provides an effective approach to determine the core-scale shale permeability by directly using pore-scale experimental data, which is a common challenge in the unconventional resources.

Abstract The heterogeneities of shale are manifested in the complex pore spatial configurations and the wide distribution of pore sizes. The recent advances of high-resolution imaging techniques such as Scanning Electron Microscope (SEM) and Focussed Ion Beam Scanning Electron Microscopes (FIB-SEM) enable accurate characterization of shale pore structure in the limited imaging area. Due to the nature of multiscale pore size, image-based petrophysical properties are highly dependent on the selection of image resolution. Fractal theory proves to be an effective approach to characterize pore structure as well as calculate fluid transport properties. In this study, the image-based fractal characteristic of shale pore structure at multiscale resolutions is investigated and its impact on the accurate prediction of gas permeability is analyzed. The fractal dimensions of pore phase in 100 SEM images at resolutions ranging from 15.5 nm to 420 nm are calculated by the box counting method and Sierpinski carpets analytical solution. The real gas permeability model in consideration of second order slip is derived based on the fractal theory. Two groups of gas permeabilities at different resolutions are estimated respectively based on the fractal dimensions obtained from the box counting method and Sierpinski carpets analytical solution. The results found that fractal dimensions obtained from the box counting method at different resolutions are more close to the exact fractal dimension compared with that obtained from the Sierpinski carpets analytical solution at low resolutions and gas permeabilities calculated at different resolutions based on the box counting estimated fractal dimensions are more close to the exact gas permeability. The image resolution for accurate calculation of shale pore structure properties and gas permeability should be less than 50 nm based on our analysis results.

Abstract The heterogeneities of shale are manifested in the complex pore spatial configurations and the wide distribution of pore sizes. The recent advances of high-resolution imaging techniques such as Scanning Electron Microscope (SEM) and Focussed Ion Beam Scanning Electron Microscopes (FIB-SEM) enable accurate characterization of shale pore structure in the limited imaging area. Due to the nature of multiscale pore size, image-based petrophysical properties are highly dependent on the selection of image resolution. Fractal theory proves to be an effective approach to characterize pore structure as well as calculate fluid transport properties. In this study, the image-based fractal characteristic of shale pore structure at multiscale resolutions is investigated and its impact on the accurate prediction of gas permeability is analyzed. The fractal dimensions of pore phase in 100 SEM images at resolutions ranging from 15.5 nm to 420 nm are calculated by the box counting method and Sierpinski carpets analytical solution. The real gas permeability model in consideration of second order slip is derived based on the fractal theory. Two groups of gas permeabilities at different resolutions are estimated respectively based on the fractal dimensions obtained from the box counting method and Sierpinski carpets analytical solution. The results found that fractal dimensions obtained from the box counting method at different resolutions are more close to the exact fractal dimension compared with that obtained from the Sierpinski carpets analytical solution at low resolutions and gas permeabilities calculated at different resolutions based on the box counting estimated fractal dimensions are more close to the exact gas permeability. The image resolution for accurate calculation of shale pore structure properties and gas permeability should be less than 50 nm based on our analysis results.