Understanding the occurrence state and microscopic distribution of bound water, as well as the factors governing bound water saturation and its impact on natural gas flow within nano-scaled pore networks, holds significant importance for reservoir evaluation, productivity prediction, and production. However, the complexity of pore structure poses a challenge in quantitatively characterizing these aspects, and currently, no effective method exists to achieve this characterization. This study takes the Bashijiqike tight sandstone of the Kuqa Depression of the Tarim Basin as an example; by integrating physical property test, XRD, microscopic observation with casting thin section and SEM, HPMI, NMR, and NMR-supervised gas-charging experiment, proposed a novel bound water occurrence model to depict the microscopic distribution of bound water in nano-scaled pore space. Furthermore, the impact of bound water on gas-flowing behaviors was thoroughly examined and the complex relationships between bound water saturation and reservoir macroscopic and microscopic parameters were explored. In addition, based on the grey relational analysis, the critical controlling factor on bound water saturation were screened out. The bound water in the pore space of tight sandstone comprises two components: capillary-bound water within small pores (<rcutoff) and restricted (by pore/throat < rcutoff) large pores, layered water-film within large pores (>rcutoff). The water-film within large pores is non-uniform, non-isothick, and low in content. During gas charing to reservoirs, the water-film thickness decreased gradually as the charging force increased, with a minimum thickness ranging from 0.10 to 3.72 nm. Water-film accounted for 1.75% to 22.96% of the total bound water content, with an average of 7.28%. In contrast to previous studies, we found that water-film had a negligible impact on the minimum pore/throat radius for gas charging, with only an increase of 0.7 nm. However, it significantly altered the physical characteristics, reducing gas permeability from 46.11% to 97.84%, with an average reduction of 78.37%. Furthermore, a water-film effectively eradicated the slip effect, leading to the prevalence of Darcy and diffusion flow as the primary mechanisms for gas seepage. At low pressure, diffusion flow prevails, whereas Darcy flow dominates at high pressure. I/S-mixed layer and illite exert the most significant influence on bound water saturation. 

A novel bound water occurrence model for tight sandstone

The adsorption characteristic of methane in water-bearing shale is essential for the accurate estimation of shale gas reserves. The sorption mechanisms of moisture and methane in shale remain poorly understood. In this work, moisture equilibrium measurements in shales were conducted to study moisture absorption characteristics. The governing factors for moisture absorption were determined, and the suitability of moisture absorption models was evaluated. An innovative water saturation apparatus and an improved methane adsorption system were built to measure methane adsorption in high water-bearing shales. The suitability of the Langmuir model in describing methane adsorption in water-bearing shale was studied. A predictive model for methane adsorption in water-bearing shale was developed based on improved BP neural network algorithm, which was further utilized to determine the primary governing factors for methane adsorption. The results revealed that the equilibrated moisture content in shale presents a three-stage and S-type ascending trend with increasing relative humidity. The methane adsorption amount shows a slide-type downward trend with the increase of water content. The Peleg model demonstrates the superior performance in describing the hygroscopic isotherms, and the Langmuir model performs poorly in characterizing methane adsorption in shales with high water contents. The controlling factors for the ultimate moisture content mainly include specific surface area, average pore diameter, carbonate and pyrite content. The methane adsorption in water-bearing shale is mainly governed by water content and specific surface area. The results of this work enrich the understanding of the adsorption mechanisms of shale gas and provide a solid basis for the assessment of shale gas reserves. 

Measurement and modeling of moisture equilibrium and methane adsorption in shales from the southern Sichuan Basin

A clear understanding of nanoconfined gas flow behavior in shale gas reservoirs is beneficial for its efficient development. Nanopores in the shale gas reservoirs are characterized by complex surface chemistry and composition, as well as affinity, while their impact on methane flow has not been investigated comprehensively before. In light of current research status, this article proposes a simple yet robust theoretical model, incorporating bulk-gas flow flux and surface diffusion of adsorption gas. In particular, wettability effect, indicating the influences of the shifted critical properties and adsorption thickness, is captured as well. In this article, gas physical attributes, such as gas compressibility factor and gas viscosity, are modified under the nanoconfinement effect and wettability effect, and also the variation of effective pore size, induced by surface wettability, is considered. Notably, wettability effect in this article is described by using a macroscopic form, surface contact angle, facilitating the model applicability. In addition, both the bulk-gas flow model and surface-diffusion model, developed in this research, are able to achieve excellent agreements compared with the existed documents, clarifying the reliability of the proposed model. Meanwhile, key role of wettability effect on nanoconfined gas flow behavior, especially for surface diffusion of adsorption gas, is demonstrated. Results show that (a) the gas flux in small nanopores may exceed that in large nanopores, due to the predominant role of surface diffusion, while pore size is less than 10 nm; (b) the absence of real gas effect will lead to inaccurate characterization of nanoconfined gas flow capacity, and the magnitude can reach 7% for pore size of 5 nm and will enlarge with further pore size shrinkage; (c) wettability effect governs the total gas flux when pore size is less than 10 nm, while its impact will be greatly mitigated when pore size is greater than 50 nm. This article provides a comprehensive investigation to shed light on surface wettability on gas flow behavior through nanopores.

/pdf/nanoconfined-gas-flow-behavior-in-organic-shale-wettability-2h9qkqw3.pdf

Nanoconfined Gas Flow Behavior in Organic Shale: Wettability Effect

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Nanoconfined Gas Flow Behavior in Organic Shale: Wettability Effect