This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 134583, ’Carbon Dioxide Storage Capacity of Organic-Rich Shales,’ by S.M. Kang, SPE, E. Fathi, SPE, R.J. Ambrose, SPE, I.Y. Akkutlu, SPE, and R.F. Sigal, SPE, University of Oklahoma, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has been peer reviewed for SPE Journal.
An experimental study was performed on the ability of Barnett-shale core samples to store carbon dioxide (CO2). A new analytical methodology was developed that allows interpreting pressure/volume data in terms of measurements in 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. Organic shale has the ability to store significant amounts of gas permanently by trapping the gas in an adsorbed state within its finely dispersed organic matter (i.e., kerogen).
A primary consideration in subsurface sequestration of anthropogenic CO2 is knowledge of gas storability of the geological formations. At first thought, a high-pore-volume formation would seem to be a good candidate for the purpose. However, not all high-porosity formations are suitable for permanent storage of the gas. Some formations lack a physical mechanism for trapping gas. In the absence of a trapping mechanism, a free-gas cap is created in the formation artificially, which may not warrant long-term storage of the injected gas. Needed trapping is associated with fluid/fluid or fluid/solid interactions in porous media such as dissolution, physical adsorption, or some homogeneous and heterogeneous reactions.
Depleted oil reservoirs, for example, could be considered acceptable targets. These reservoirs can trap CO2 that is not dissolved in reservoir brine to the extent that their seals for hydrocarbons also form a capillary seal for CO2. A second trapping mechanism is absorption of the injected gas by the immobile residual oil. This can be accomplished through multiple-contact (dynamic) miscibility, which involves simultaneous phase-change and mass-transport phenomena. Saline aquifers, on the other hand, allow aqueous-phase precipitation reactions as well as absorption by the formation water. The dissolved gas promotes density-driven natural convection of water and the related hydrodynamic instabilities. However, the injected gas could be transported and dispersed over large distances, leading to uncertainties concerning its fate. Coalbeds and naturally occurring gas-hydrate reservoirs have been proposed as economically feasible choices because the injected CO2 could be sequestered in sorbed states (adsorbed on microporous coal material surfaces and absorbed into organic macromolecular openings in coal and in water) and could aid enhanced recovery of natural gas by an in-situ molecular-swapping mechanism that promotes release and displacement of methane as a free gas. Introduction of greenhouse gases into these formations, however, is a difficult field operation with a significant or complete loss in well injectivity.