Summary Using focused-ion-beam (FIB)/scanning-electron-microscope (SEM) imaging technology, a series of 2D and 3D submicroscale investigations revealed a finely dispersed porous organic (kerogen) material embedded within an inorganic matrix. The organic material has pores and capillaries having characteristic lengths typically less than 100 nm. A significant portion of total gas in place appears to be associated with interconnected large nanopores within the organic material. Thermodynamics (phase behavior) of fluids in these pores is quite different; gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a different density profile. This raises serious questions related to gas-in-place calculations: Under reservoir conditions, what fraction of the pore volume of the organic material can be considered available as free gas, and what fraction is taken up by the adsorbed phase? How accurately is the shale-gas storage capacity estimated using the conventional volumetric methods? And finally, do average densities exist for the free and the adsorbed phases? We combine the Langmuir adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the pore space taken up by the sorbed phase. The method yields a total-gas-in-place prediction. Molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature predict density profiles across the pores and show that (a) the adsorbed methane forms a 0.38-nm monolayer phase and (b) the adsorbed-phase density is 1.8–2.5 times larger than that of bulk methane. These findings could be a more important consideration with larger hydrocarbons and suggest that a significant adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, calculations show a 10–25% decrease in total gas-storage capacity compared with that using the conventional approach. The role of sorbed gas is more important than previously thought. The new methodology is recommended for estimating shale gas in place.

This paper presents an experimental study on the ability of organic-rich-shale core samples to store carbon dioxide (CO 2). An apparatus has been built for precise measurements of gas pressure and volumes at constant temperature. A new analytical methodology is developed allowing interpretation of the pressure/volume data in terms of measurements of total porosity and Langmuir parameters of core plugs. The method considers pore-volume compressibility and sorption effects and allows small gas-leakage adjustments at high pressures. Total gas-storage capacity for pure CO 2 is measured at supercritical conditions as a function of pore pressure under constant reservoir-confining pressure. It is shown that, although widely known as an impermeable sedimentary rock with low porosity, organic shale has the ability to store significant amount of gas permanently because of trapping of the gas in an adsorbed state within its finely dispersed organic matter (i.e., kerogen). The latter is a nanoporous material with mainly micropores (< 2 nm) and mesopores (2-50 nm). Storage in organic-rich shale has added advantages because the organic matter acts as a molecular sieve, allowing CO 2-with linear molecular geometry-to reside in small pores that the other naturally occurring gases cannot access. In addition, the molecular-interaction energy between the organics and CO 2 molecules is different, which leads to enhanced adsorption of CO 2. Hence, affinity of shale to CO 2 is partly because of steric and thermodynamic effects similar to those of coals that are being considered for enhanced coalbed-methane recovery. Mass-transport paths and the mechanisms of gas uptake are unlike those of coals, however. Once at the fracture/matrix interface, the injected gas faces a geomechanically strong porous medium with a dual (organic/inorganic) pore system and, therefore, has choices of path for its flow and transport into the matrix: the gas molecules (1) dissolve into the organic material and diffuse through a nanopore network and (2) enter the inorganic material and flow through a network of irregularly shaped voids. Although gas could reach the organic pores deep in the shale formation following both paths, the application of the continua approximation requires that the gas-flow system be near or beyond the percolation threshold for a consistent theoretical framework. Here, using gas permeation experiments and history matching pressure-pulse decay, we show that a large portion of the injected gas reaches the organic pores through the inorganic matrix. This is consistent with scanning-electron-microscope (SEM) images that do not show connectivity of the organic material on scales larger than tens of microns. It indicates an in-series coupling of the dual continua in shale. The inorganic matrix permeability, therefore, is predicted to be less, typically on the order of 10 nd. More importantly, although transport in the inorganic matrix is viscous (Darcy) flow, transport in the organic pores is not due to flow but mainly to molecular transport...

On the basis of micro-and mesoscale investigations, a new mathematical formulation is introduced in detail to investigate multiscale gas-transport phenomena in organic-rich-shale core samples. The formulation includes dual-porosity continua, where shale permeability is associated with inorganic matrix with relatively large irregularly shaped pores and fractures, whereas molecular phenomena (diffusive transport and nonlinear sorption) are associated with the kerogen pores. Kerogen is considered a nanoporous organic material finely dispersed within the inorganic matrix. The formulation is used to model and history match gaspermeation measurements in the laboratory using shale core plugs under confining stress. The results indicate significance of molecular transport and strong transient effects caused by gas/solid interactions within the kerogen. In the second part of the paper, we present a novel multiscale perturbation approach to quantify the overall impact of local porosity fluctuations associated with a spatially nonuniform kerogen distribution on the adsorption and transport in shale gas reservoirs. Adopting weak-noise and meanfield approximation, the approach applies a stochastic upscaling technique to the mathematical formulation developed in the first part for the laboratory. It allows us to investigate local kerogenheterogeneity effects in spectral (Fourier-Laplace) domain and to obtain an upscaled "macroscopic" model, which consists of the local heterogeneity effects in the real time-space domain. The new upscaled formulation is compared numerically with the previous homogeneous case using finite-difference approximations to initial/boundary value problems simulating the matrix gas release. We show that macrotransport and macrokinetics effects of kerogen heterogeneity are nontrivial and affect cumulative gas recovery. The work is important and timely for development of newgeneration shale-gas reservoir-flow simulators, and it can be used in the laboratory for organic-rich gas-shale characterization.

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Using FIB/SEM imaging technology, a series of 2-D and 3-D submicro-scale investigations are performed on the types of porous constituents inherent to gas shale. A finely-dispersed porous organic (kerogen) material is observed imbedded within an inorganic matrix. The latter may contain larger-size pores of varying geometries although it is the organic material that makes up the majority of gas pore volume, with pores and capillaries having characteristic lengths typically less than 100 nanometers. A significant portion of total gas in-place appears to be associated with inter-connected large nano-pores within the organic material.This observation has several implications on reservoir engineering of gas shales. Primarily, thermodynamics (phase behavior) of fluids in these pores are known to be quite different. Most importantly, gas residing in a small pore or capillary is rarefied under the influence of organic pore walls and shows a density profile across the pore with damped-oscillations. This raises the following serious questions related to gas-in-place calculations: under reservoir conditions, what fraction of the pore volume of the organic material can be considered available for the free gas phase and what fraction is taken up by the adsorbed phase? If a significant fraction of the organic pore volume is taken up by the adsorbed phase, how accurately is the shale gas storage capacity estimated using the conventional volumetric methods? And, finally, do average densities exist for the free and the adsorbed phases and how large would a typical density contrast be in an organic pore for an accurate gas reserve calculation?In order to answer these questions we combine the Langmuir equilibrium adsorption isotherm with the volumetrics for free gas and formulate a new gas-in-place equation accounting for the organic pore space taken up by the sorbed phase. The method yields a total gas-in-place prediction based on a corrected free gas pore volume that is obtained using an average adsorbed gas density. Next, we address the fundamental-level questions related to phase transition in organic matter using equilibrium molecular dynamics simulations involving methane in small carbon slit-pores of varying size and temperature. We predict methane density profiles across the pores and show that (i) an average total thickness for an adsorbed methane layer is typically 0.7 nm, which is roughly equivalent to 4% of a 100 nm diameter pore volume, and (ii) the adsorbed phase density is 1.8-2.0 times larger than that of the bulk methane, i.e., in the absence of pore wall effects. These findings suggest that a significant level of adjustment is necessary in volume calculations, especially for gas shales high in total organic content. Finally, using typical values for the parameters, we perform a series of calculations using the new volumetric method and show a 10-25% decrease in total gas storage capacity compared to that using the conventional approach. This additionally could have a larger impact in shales where the sorbed gas pha...