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...

Accurate modeling of gas through shale-gas reservoirs characterized by nano-meter pores where the effects of various non- Darcy flow regimes and the adsorbed-layer are important is presented and demonstrated by several examples. Quantification of gas transport may be accomplished using the transport equation that is valid for all flow regimes. This equation though needs further modification when transport is through a media where the gas is adsorbed onto the pore wall. In the presence of adsorption, there is a pore pressure dependent loss of porosity and cross-sectional area to free gas transport. The apparent gas permeability correction is accomplished for various flow regimes using the Knudsen number by consideration of the reduction of the cross-sectional area to free gas transport in the presence of adsorption. We show that transport in the adsorbed layer may contribute significantly in the total gas transport in these nanopores. An effective transport model is presented to account for the impact of adsorption through two mechanisms. First, we modify the transport equation to account for the pore-pressure dependent-reduction in the volume available to free gas transport; second, we model transport through the adsorbed layer using Fick's law of diffusion. The coupled model is then compare to conventional transport models over a wide range of reservoir properties and conditions. As pore-pressure is reduced, adsorbed phase gas desorbs into free gas and apparent permeability increases. The difference in the estimated apparent permeability with and without the consideration of the adsorption volume can be a factor of two or more at initial reservoir conditions. Diffusion on the surface of organic pores can be a substantial transport mechanism in shales depending on the pore connectivity, pore pressure, and pore size distribution in the organic pores. The interpretation of production data will be compromised without considering the effects of adsorption on apparent permeability. This work implies that permeability measurements for shale gas reservoirs must be done with methane at in-situ pore pressures. Because these corrections are pore-pressure not effective pressure dependent, effective pressure is not a valid parameter to use in quantifying the pressure dependence of these transport equations.

Summary Distribution of alkanes and water in organic pores of shale, referred to as kerogen, is essential information required for the estimation of shale-reservoir oil and gas in place, adsorption of hydrocarbon, and fate of hydraulic-fracture water. A practical modeling approach is presented for the proper description of the kerogen pore systems with different mixed wettability, surface roughness, tortuous paths, and material disorder. Three kerogen models—activated kerogen, kerogen free of activated sites, and graphite-slit pore—with proper surface-oxidized functional groups and high-temperature and pressure maturation are constructed by simulation. Distribution of octane and water in the organic pores of these models is predicted by molecular dynamics (MD) simulation. The results from our studies underscore the need for accurate characterization of kerogen pore systems in terms of the pore morphology, level of surface activation, and pore size. The improved kerogen models constructed to structurally resemble real organic materials have the potential to enable a better understanding of the placement, distribution, and trapping mechanisms of hydraulic-fracture water in shales. We demonstrate that depending on the maturity of the kerogen within organic-rich shales, organic pore systems may have mixed-wet characteristics and may create opportunities for water entrapment. The differences in the uptake of water are shown to be a function of the existence of oxygenated functional groups. In addition, the adsorption characteristics of alkanes in pores characterized by surface roughness are shown to be significantly different from those observed in the graphite-slit pore model. Our results indicate that careful consideration of the pore morphology is merited when estimating hydrocarbons in place with the Langmuir monolayer-adsorption theory.

No abstract

Cop ThisThis revie offic repr