Impact of moisture on estimating gas in place for shales: characterisation and simulation studies on kerogens

Moisture in shale can affect the gas in place (GIP) estimated from the sum of free and adsorbed gas, which are also affected by the residual oil. Four shales (two China shales (SH1, SH2), and two UK shales (BS3, GH4)) were selected to reveal these impacts by illustrating their influence on the porosity and methane adsorption capacity. Kerogen (K1, K2, and GHK3, isolated from shales SH1, SH2, and GH4), the primary contributor to adsorbed gas, was selected as the target of laboratory characterisation and molecular simulation studies. Shales and their kerogens have been investigated, both dry and moisture equilibrated at 95% relative humidity (R.H.). Their methane adsorption capacities are obtained from high-pressure adsorption, and pore textures characterised primarily by low-pressure gas (N2, CO2) sorption. Type II kerogen micropore-scale models (matrix and slits (0.5, 1.0, 1.5, and 2.0 nm)) have been constructed for the molecular simulations. Results from Grand Canonical Monte Carlo (GCMC) and molecular dynamic (MD) simulations are compared with the experimental results. Isolated kerogens account for 59-83% and 42-67% of the methane adsorption capacities for the shales dry and at 95% R.H., respectively. However, the isolated kerogens could adsorb more methane than the organic matter in the shales. More than 50% of methane equilibrium adsorption quantity (Qm), surface area (SA), and nanopore volume (<100 nm) of the kerogens and shales are reduced at 95% R.H.. The low-pressure gas sorption results suggest water can block most micropores less than 1.3 nm, and vastly reduce accessible pores for gas transport. The greater proportional losses in SA and pore volume compared to the Qm is probably due to ice forming at -196 °C in the low-pressure N2 analysis. Failure to consider moisture overestimates the total GIP by 32-38% for shales (SH1 and SH2) investigated. As well as maturation, oil from contaminant drilling mud fluids can also be present in shales. The oils extracted in low yield from the overmature shales (SH1 and SH2, <0.5 wt.% TOC) arise from oil-based drilling mud, while the much higher yields from the lower maturity UK shales (BS3 and GH4, 1.1-2.5 wt.% TOC) is mainly oil generated by maturation. After extraction, minimal changes (<5%) in total nanopore volume (<100 nm) were observed for the dry over mature shales, but significant increases (95 and 176%) were observed for the dry lower maturity shales. More than 60% of the extracted oil resides in micro and mesopores, and removal could unblock the micropore necks and enlarge the accessible meso and macropore volume. The Qm increased after oil extraction for both the dry and wet shales, especially for lower maturity shales. Henry’s Law was used to show that there were no significant amounts of dissolved methane in oils for the dry shales. Extracting oil from shales prior to determining the porosity and methane adsorption capacity can lead to the GIP being over-estimated for moisture equilibrated shales, particularly for oil-window shales where an overestimation of 22% was obtained for the shale investigated here. The micropore volume (Vmicro) and Qm of dry K1, K2, and GHK3 (10-75 mm3/g TOC, and 21.3-75.8 mg/g TOC) are comparable with dry overmature (KIID) simulated kerogens (19-261 mm3/g TOC, and 36.5-148 mg/g TOC). The higher values from the simulation are observed as all the pores in GCMC are accessible. Both experiment and simulation suggest Type I(a) isotherms are attributable to small micropores, while Type I (b) isotherms arise from larger micropores. The increase of moisture leads to the decrease of Qm and Vmicro. When the moisture content of KIID (matrix and slits) is 4-24wt.%TOC, kerogen simulated models have the same Qm (61-75%), and Vmicro (88-93%) reductions as wet 95%R.H. isolated kerogens, suggesting up to 56% of the moisture is in the micropore of K1, K2, and GHK3. The relative coordination number (C_r) from the MD simulation indicates water has a stronger affinity than methane for the same functional groups. The preferred function groups for methane only exist at extremely low pressure, and the affinity becomes much weaker at higher pressures with no significant differences among the functional groups considered. Compared with the sorption sites around functional groups, micropores are regarded as the key control for methane adsorption kerogens, as a positive correlation between Vmicro and Qm is observed with R2>0.96. In contrast, certain functional groups, such as carboxyl (COOH) are the preferred sorption sites for water via the solid H-bonds. The selected functional groups provide initial sorption sites for water, with the water cluster size controlled by micropore volume. Water reduces the methane adsorption capacity of kerogen presenting as ‘rapid’, ‘gentle’, and ‘slow’ stages with increased moisture content in simulation. The ‘rapid’ reduction is due to water adsorbed in ultra-micropores (