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.
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
CO, and highly conjugated CO, 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.
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