Adsorption and migration mechanisms of methane and carbon dioxide in gas shales at pore scale
Storage and production mechanisms in gas shales are controlled by pore-scale adsorption and diffusion, respectively. Using a series of experimental and numerical techniques these processes that occur at a molecular level are investigated for their impact on field-scale technologies. Type I adsorption isotherms were obtained for Lothian shale samples. Net sorption was found to contribute to the biggest errors in sorption characterization. Whilst the DR (Dubinin-Radushkevich) isotherm was found to provide the best fit, the Langmuir isotherm was thermodynamically consistent providing good fits to both adsorption and adsorption uptake, making it the best isotherm for shale reservoir characterization. Of three parameter isotherms, the Toth isotherm is preferred over the Sips isotherm given that it is more thermodynamically consistent. Using a series of numerical experiments, importance of adsorption and adsorption uptake on diffusion and gas production in shales are then investigated. Intrinsic permeability of shales decreased with increasing adsorption uptake. A dual porosity FEM (Finite Element Method) is solved to determine reserves. The decrease in effective diffusion with increasing adsorption was found to be quite significant and increasing amounts of sorbed gas in the reservoir counterintuitively results in decreased production for some reservoirs. However, it is possible to minimize this effect by good design of production technology. Smaller fracture spacing and higher fracture heights with very high fracture conductivity could be used to increase sorbed gas production from shale reservoirs. Effect of geochemistry and pore structure on adsorption in Bowland shales is investigated using a series of experimental techniques. Pore characteristics are investigated under the SEM (Scanning Electron Microscopy, and mineral phases are identified using EDS (Energy Dispersive Spectroscopy). This provided good agreement with the shale’s TOC (Total Organic Carbon) and XRD (X-Ray Diffraction) data. Using image analysis techniques, micropore volume was found to be predominantly located in the organic matter phase of gas shales. Clay minerals contribute to micropore volume, but to a lesser extent. Pore size distribution was analysed using N2 isotherms with BET (Braunner-Emmett-Teller), BJH (Barrett-Joyner-Halenda), and DFT (Density Functional Theory) techniques. Most Bowland shales exhibit a bimodal pore size distribution with peaks in the micropore and mesopore range corresponding to pores contributed by organic and clay minerals content, respectively. The BET theory corresponds to minimum energetic sorption in heterogeneous shales. For determination of pore size distribution, the DFT theory provides much better predictions compared to the BJH theory. High pressure adsorption and diffusion for methane and carbon dioxide in Bowland shales are determined using the manometric rig. A linear isotherm was obtained for sorption up to 60 bars. The second order kinetics based fit was found to better estimate diffusion than the first order based fit. Sorption and diffusion in shales was a strong function of organic matter, clay mineral content, surface area, and micropore volume. Carbon dioxide sequestration in shales is investigated using a series of experimental and numerical techniques. Shales provide excellent carbon dioxide sequestration capabilities adsorbing nearly 1.25 times carbon dioxide as methane in laboratory experiments. High pressure methane and carbon dioxide adsorption isotherms are used as input parameters in a reservoir simulation using FEM (Finite Element Method) in COMSOL. 10 years of production was simulated to deplete the reservoir, followed by 10 years of carbon dioxide injection for carbon sequestration. A rapid dissipation of pressure was observed in the reservoir after carbon dioxide injection with nearly 10% of the total gas stored due to sorption. Sorbed carbon dioxide was also very stable even under methane production. However, there was no benefit to methane production under Huff-and-Puff carbon dioxide injection technology, which was conducted in a 5 year cycle. This is because high adsorption uptakes are expected to decrease the shale intrinsic permeability consistent with previous results. Also, longer injection times are required to store a similar amount of carbon dioxide in the reservoir for the same reason. Adsorption characterization in methane was done at multiple temperatures to determine the temperature dependence and the heat of sorption. Governing equations of heat and mass balance are modified to include sorption and heat of sorption. These are solved using FEM in COMSOL. Thermal stimulation was found to provide strong benefits for methane production increasing ultimate recovery by 10%. Isosteric heat of sorption is an important parameter in the thermal stimulation of gas shales. Not including isosteric heat over predicted production by 13% compared to production with heat of sorption. Permeability, Langmuir volume, and Langmuir pressure are also significant parameters.