Studying the effects of pore structure on spontaneous imbibition (SI) is of great significance for optimizing coal seam water injection measurements. To investigate the influence of reservoir microscopic pores on imbibition, we studied pore structure in selected coal samples using Mercury intrusion porosimetry (MIP) and nuclear magnetic resonance (NMR), along with multifractal analysis. SI experiments were conducted on coal cores to investigate the dynamic imbibition process and quantitatively analyze imbibition at different time intervals, as well as the factors influencing imbibition. The results show that the adsorption pores primarily function as water storage spaces, while the seepage pores have dual functionality in both water conduction and storage during imbibition. Water is imbibed more quickly in seepage pores than in adsorption pores, as the effective driving force is lower in adsorption pores due to the high frictional resistance caused by strong pore heterogeneity. Due to the strong microscopic heterogeneity of coal, the imbibition process is predominantly governed by its microscopic properties. The imbibition rate of coal is mainly controlled by the pore connectivity (H), development degree of seepage pores (Dmax), concentration degree of pore size distribution (PSD) (D(1)) and uniformity of PSD (D(2)), but less effected by the adsorption pores (Dmin) and PSD heterogeneity (ΔD). The imbibition capacity is mainly affected by wettability (θ), while it is relatively weakly influenced by pore-related parameters. Considering the heterogeneity of the pore network in coals, a new model for SI was proposed, which shows better fitting performance compared to conventional models. This study can help enhance the comprehension of the underlying mechanism of SI and contribute to its practical implementation.
Summary The flowback rate of a hydraulic fracturing fluid is related to coalbed methane (CBM) production in gas wells. The deep (>2000 m) CBM reservoir in the Ordos Basin has an extremely high salinity (>200 000 mg/L), which results in a very low flowback rate of fracturing fluid. The mechanism underlying the extremely low flowback rate of the fracturing fluid remains unclear. This study experimentally simulated two patterns of osmotic pressure variation that exist at a hydraulic fracturing site: the processes of injection of a low-salinity fracturing fluid into a high-salinity reservoir and a high-salinity fracturing fluid into a low-salinity reservoir. Low-field nuclear magnetic resonance (NMR) technology was used to monitor dynamic fluid migration and fluid distribution in the coals. Results showed that osmotic pressure is a driving force for spontaneous imbibition when the salinity of the fracturing fluid is lower than that of the reservoir water, and more fluid enters the coal as the osmotic pressure increases. This causes the displacement of the high-salinity fluid already present in the micropores by the low-salinity fracturing fluid. In high-salinity deep coal seams, both osmotic pressure and capillary forces cause the spontaneous imbibition of the fracturing fluid from fractures into pores, promoting CH4 desorption, alleviating the water-blocking effect, and enhancing the filtration loss of the fracturing fluid. In contrast, the injection of a high-salinity fluid into the reservoir with a low-salinity brine (LSB) creates an osmotic pressure difference that prevents fluid imbibition. In shallow, low-salinity coal seams, the injection of high-salinity fracturing fluids can result in high flowback rates. Therefore, these two injection schemes are significant for an understanding of the role of osmotic pressure in deep CBM extraction and serve as valuable guides for optimizing the selection of the fracturing fluid and improving its effective flowback.
The injection of CO2 into coalbed methane (CBM) reservoirs to enhance methane recovery has a second desirable benefit in simultaneously sequestering CO2. However, the real-time dynamic evolution of native adsorbed and rejected non-adsorbed methane during the process of CO2-enhanced coalbed methane (CO2-ECBM) production remains poorly constrained as a result of the nonlinear and hysteretic response of both CO2–CH4 interactions (part 1) and CO2–H2O wettability (part 2) of the coal under recreated reservoir conditions. In part 1, we apply calibrated nuclear magnetic resonance (NMR) to explore mechanisms of methane desorption and CO2 replacement during multiple cycles of CO2-ECBM flooding under recreated in situ conditions. Results for contrasting sub-bituminous coal and anthracite indicate that the adsorbed methane sweep efficiency is improved by ∼16–26% with a single injection of CO2 over mere in situ desorption. Furthermore, CO2–CH4 displacement rates evolve during each CO2 injection cycle, first declining rapidly and then stabilizing with a long desorptive tail. Importantly, the cumulative methane sweep efficiency increases monotonically with successive cycles of CO2 injection, albeit at a reducing incremental efficiency, identifying the utility of cyclic CO2-ECBM as an effective method in both CO2 sequestration and enhanced gas recovery. Observed ratios of CO2 sorption capacities to CH4 recovery are 5.0 and 2.2 for sub-bituminous coal and anthracite, respectively, demonstrating an elevated potential for CO2 sequestration in sub-bituminous coals and more favorable CO2-ECBM recovery in anthracite, per unit mass of CO2 injected.
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