No abstract

Using carbon dioxide as a displacing fluid to enhance shale gas recovery is a promising technique given its potential for significant contributions to both unconventional resource development and CO2 geological sequestration. The adsorption capacity of CO2 in nanoscale shale organic pores is the key issue to evaluate the feasibility of CO2-enhanced shale gas recovery technology. However, as a result of the complex organic component of the solid surface, the fluid–solid interaction between the confined fluid and the solid surface, and the intermolecular interaction between the confined fluids, the adsorption behavior of CO2 in the shale is not clear. In this work, shale organic nanopores with different geometries (slit pore and cylindrical pore) and different sizes (1, 2, and 4 nm) are constructed using molecular dynamics and Monte Carlo methods. Isothermal adsorption of CO2 and methane as single components and competitive adsorption of a CO2–methane binary mixture are simulated in a nanoscale methane/CO2/organic matter system. The density profile and distribution contour indicate that CO2 adsorption in shale organic mesopores does not occur via monolayer adsorption. Considering the inadaptability of the Langmuir model to analyze the CO2 adsorption curve, a modified Brunauer–Emmett–Teller (BET) model is applied to describe and fit the data for the CO2 and methane adsorption amount, with the parameters in the modified BET model used to characterize the adsorption capacity and affinity of the fluid. The maximum adsorption amount, characteristic pressure, and selectivity parameter of CO2, methane, and a binary mixture indicate that the adsorption capacity and affinity of CO2 are stronger than those of methane under reservoir pressure, which provides useful support for enhancing shale gas recovery by injecting CO2.

Tang W-Z and Li F-L (2020) Energy Conservation and Carbon Flux Distribution During Fermentation of CO or H 2 /CO 2 by Clostridium ljungdahlii.

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Moisture significantly affects the adsorption capability of gas shales for methane (CH4), the main component of shale gas. Primary moisture, i.e., the moisture that exists in in situ shale reservoirs, is therefore crucial to estimate and produce shale gas resource. Aiming to understand the influences of primary moisture on CH4 adsorption on shale samples, the occurrence of primary moisture in shales gathered from the Lower Silurian Longmaxi Formation located in southern Sichuan Basin of China was experimentally investigated. Additionally, the primary moisture dependence of CH4 adsorption equilibrium and thermodynamics of shales was investigated. Results indicate that the primary moisture contents of the four shale samples vary between 0.64 and 0.82% (mass percentage), positively correlated with the clay mineral content of shale samples. The adsorption equilibrium behavior regarding water vapor on shales well follows the modified Brunauer–Emmett–Teller (BET) equation. The water vapor is typically adsorbed onto the primary adsorption sites of shale samples, i.e., the oxygenic functional groups consisting of COOH, conjugated CO, and highly conjugated CO, and the secondary adsorption sites, i.e., the previously adsorbed water molecules and clay minerals. The pores with pore diameter less than 4 nm of shales are the main accommodation space for primary moisture. The adsorption equilibrium of CH4 on primary moisture-containing shales well obeys the Ono–Kondo lattice equation. On the basis of the modeling results, the primary moisture causes a remarkable reduction in maximum CH4 adsorption capacity of shale samples by 12.86–45.45%. Moreover, the primary moisture reduces the isosteric heat of CH4 adsorption on shale samples. In summary, the primary moisture in gas shales decreases the adsorption affinity between CH4 and shale samples. Therefore, focusing on the effects of primary moisture on CH4 adsorption on shales is vital to better estimate and produce shale gas resource.