Methane and CO₂ Adsorption Capacities of Kerogen in the Eagle Ford Shale from Molecular Simulation

ConspectusOver the past decade, the United States has become a world leader in natural gas production, thanks in part to a large-fold increase in recovery from unconventional resources, i.e., shale rock and tight oil reservoirs. In an attempt to help mitigate climate change, these depleted formations are being considered for their long-term CO₂ storage potential. Because of the variability in mineral and structural composition from one formation to the next (even within the same region), it is imperative to understand the adsorption behavior of CH₄ and CO₂ in the context of specific conditions and pore surface chemistry, i.e., relative total organic content (TOC), clay, and surface functionality.This study examines two Eagle Ford shale samples, both recovered from shale that was extracted at depths of approximately 3800 m and having low clay content (i.e., less than 5%) and similar mineral compositions but distinct TOCs (i.e., 2% and 5%, respectively). Experimentally validated models of kerogen were used to the estimate CH₄ and CO₂ adsorption capacities. The pore size distributions modeled were derived from low-pressure adsorption isotherm data using CO₂ and N₂ as probe gases for micropores and mesopores, respectively. Given the presence of water in these natural systems, the role of surface chemistry on modeled kerogen pore surfaces was investigated. Several functional groups associated with surface-dissociated water were considered. Pressure conditions from 10 to 50 bar were investigated using grand canonical Monte Carlo simulations along with typical outgassing temperatures used in many shale characterization and adsorption studies (i.e., 60 and 250 °C). Both CO₂ and N₂ were used as probe gases to determine the total pore volume available for gas adsorption spanning pore diameters ranging from 0.3 to 30 nm. The impacts of surface chemistry, outgassing temperature, and the inclusion of nanopores with diameters of less than 1.5 nm were determined for applications of CH₄ and CO₂ storage from samples of the gas-producing region of the Eagle Ford Shale. At 50 bar and temperatures of 60 and 250 °C, CH₄ adsorption increased across all surface chemistries considered by 60% and 2-fold, respectively. In the case of CO₂, the surface chemistry played a role at both 10 and 50 bar. For instance, at temperatures of 60 and 250 °C, CO₂ adsorption increased across all surface chemistries by 6-fold and just over 2-fold, respectively. It was also found that at both 10 and 50 bar, if too low an outgassing temperature is used, this may lead to a 2-fold underestimation of gas in place. Finally, neglecting to include pores with diameters of less than 1.5 nm has the potential to underestimate pore volume by up to 28%. Taking into consideration these aspects of kerogen and shale characterization in general will lead to improvements in estimating the CH₄ and CO₂ storage potential of gas shales

Selection of Shale Preparation Protocol and Outgas Procedures for Applications in Low-Pressure Analysis

The low-pressure gas adsorption (LPGA) method for estimation of pore capacities, pore size distributions, and total surface area using adsorption–desorption isotherms is selected as an effective technique in pore characterization. A recent application of this method is to understand the complex and heterogeneous nature of shales across the globe. The LPGA experiments were conducted on shale samples from Barnett and Eagle Ford formations in the United States using CO₂ for micropores of 0.3–1.5 nm in diameter and N₂ and Ar as the adsorbates to focus on micropores from 1.5 to 2.0 nm and the lower range of mesopores above 2.0–27 nm in diameter. It was hypothesized that a significant error in estimations could occur due to inconsistencies in the shale outgas temperatures. It was observed that lower pore capacities result from lower outgas temperatures, and higher pore capacities result from increasing outgas temperatures. It is hypothesized that lower outgas temperatures fail to completely eliminate adsorbed moisture and adsorbed low-molecular weight hydrocarbon species from shale pores, which leaves the pores partially filled and as such result in lower values of pore capacity. By increasing the outgassing temperature, the adsorbed species in the pores are completely removed, yielding higher pore capacities. The cutoff temperature of 250 °C during outgassing for regeneration of “clean” shale pores was arrived at by analyzing the LPGA results of samples without any outgassing and samples outgassed at 60, 110, and 250 °C. The 250 °C maximum outgas temperature is intended to maximize the results of LPGA while minimizing structural changes to shales. Mass stabilization as shown by thermogravimetric analysis and magnetic suspension balance measurements support the assertion that the shale is not fundamentally altered by processes such as kerogen cracking until a temperature higher than 250 °C is reached. The kerogen had approximately 3.0% weight loss at 110 °C, with an additional 1.3% loss between 110 and 250 °C. Likewise, the desorption experiments carried out on clay at 110 °C were approximately 1.3%, with an additional 0.5% loss between 110 and 250 °C. On the basis of the interpretation of pore size distributions using the LPGA method, it was concluded that accurate shale characterization is achieved when the analysis is limited to results from relative pressures (<i>P</i>/<i>P</i>_o) less than or equal to 0.90. At higher relative pressures, the sizes of the adsorbate-occupied pores cannot be distinguished