Carbon Dioxide Storage Capacity of Organic-Rich Shales
- Seung Mo Kang (The University of Oklahoma) | Ebrahim Fathi (The University of Oklahoma) | Ray J. Ambrose (The University of Oklahoma) | I. Yucel Akkutlu (The University of Oklahoma) | Richard F. Sigal (The University of Oklahoma)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- December 2011
- Document Type
- Journal Paper
- 842 - 855
- 2011. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.4 Enhanced Recovery, 5.5.8 History Matching, 5.1.1 Exploration, Development, Structural Geology, 1.2.2 Geomechanics, 5.8.3 Coal Seam Gas
- shale gas, sequestration, diffusion, adsorption, kerogen
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This paper presents an experimental study on the ability of organic-rich-shale core samples to store carbon dioxide (CO2). 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 CO2 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 CO2--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 CO2 molecules is different, which leads to enhanced adsorption of CO2. Hence, affinity of shale to CO2 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 mechanisms: pore and surface diffusion.
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