Dynamic fluid states in organic-inorganic nanocomposite: Implications for shale gas recovery and CO2 sequestration

Huang, Liang; Zhou, Wen; Xu, Hao; Wang, Lu; Zou, Jie; Zhou, Qin

doi:10.1016/j.cej.2021.128423

Cited by 106 publications

(42 citation statements)

References 68 publications

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“…9 In contrast, some laboratory experiments suggest that the nanoconfined water fails to exceed conventional flow capacity. 10,11 Also, as for the nanopores with various material or pore sizes, the water transport efficiency varies, spanning 0.1-10 7 times that evaluated by traditional HP formula. 12 Hence, it is controversy to summarize that nanoconfined effect acts as positive or detrimental role affecting water transport performance.…”

Section: Introductionmentioning

confidence: 99%

Optimal nanocone geometry for water flow

Sun

Wang²,

Xiong

et al. 2021

AIChE Journal

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The pursuit, toward transport efficiency, is significantly necessary for energy conversion, water filtration. However, structure design, aiming at further enhancing nanoconfined water flow, is still lacking. With the motivation to bridge the knowledge gap, a simple yet practical model regarding the nanocone structure design is established. This research demonstrates that nanocone, with desirable opening angle and length, possesses the capacity to achieve the optimal flow behavior. Flow resistance occurring inside nanocones, and that at cone entrance, exit, are considered. Optimal nanocone geometry can be determined based on the minimization of total resistance. Results show that (a) suitable opening angle spans from 10 to 30 over a wide range of nanocone geometry; (b) evident decline tendency of the suitable opening angle toward the increasing surface wettability is captured; and (c) water transport capacity inside optimal nanocone is 4-50 times that within cylindrical nanopores. This article forms a theoretical framework for nanocone design.

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Section: Introductionmentioning

confidence: 99%

Optimal nanocone geometry for water flow

Sun

Wang²,

Xiong

et al. 2021

AIChE Journal

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“…As the concentration of elemental sulfur in the sour gas exceeds the critical dissolved concentration during the development of sour gas reservoirs, sulfur deposition may occur in the formation. The characteristics of sulfur dissolution, like hydrocarbon dissolution in organic matter (Huang et al, 2020;Huang et al, 2021), are crucial in the analysis of elemental sulfur deposition limit and deposition amount (Smith et al, 1970;Brunner and Woll, 1980;Brunner et al, 1988). Thus, many researchers have been devoted to the study on the elemental sulfur solubility in sour gas from experiment (Kennedy and Wieland, 1960;Roof, 1971;Swift and Manning, 1976;Brunner and Woll, 1980;Brunner et al, 1988;Davis et al, 1993;Gu et al, 1993;Sun and Chen, 2003;Zeng et al, 2005;Yang et al, 2009;Bian et al, 2010;Serin et al, 2010;Cloarec et al, 2012), thermodynamic model (Karan et al, 1998;Heidemann et al, 2001;Cézac et al, 2007;Cézac et al, 2008), semi empirical model (Chrastil, 1982;Eslamimanesh et al, 2011a;Hu et al, 2014;Guo and Wang, 2016), artificial intelligence algorithm (Mohammadi and Richon, 2008;Mehrpooya et al, 2010;Aminian, 2011;Bian et al, 2018;Fu et al, 2019;Bemani et al, 2020;Chen et al, 2020) and molecular simulation (Kadoura et al, 2013;Chen et al, 2019).…”

Section: Introductionmentioning

confidence: 99%

Experimental Study on the Elemental Sulfur Solubility in Sour Gas Mixtures

Zhang

Huang

et al. 2021

Front. Earth Sci.

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The investigation of elemental sulfur solubility plays critical roles on sour gas reservoir development. In this paper, the solubility of elemental sulfur was directly measured by static method with gas samples from well M1 of a sour gas reservoir in Sichuan Basin. The results show that the solubility of elemental sulfur ranges from 0.001 g/cm3 to 0.968 g/cm3 at 40–98.9 MPa and 15–49.8 MPa. The elemental sulfur solubility increases with increasing temperature and pressure, especially when the pressure is greater than 30 MPa. Moreover, the H2S content in sour gas mixtures is also an important factor affecting elemental sulfur solubility. The elemental sulfur solubility increases with increasing H2S content of the sour gas mixtures. The experimental data in this paper display a consistent trend with the reported experimental data. Based on the experimental results, the chrastil-type model, Robert’s model and Hu’s model were investigated and compared. The results show that the chrastil-type model by fitting experimental data in this paper has less error and higher accuracy in calculating elemental sulfur solubility in M gas reservoir. The chrastil-type models proposed in the literature, meanwhile, are only based on the regression of specific gas components and experimental conditions, which lead to a large error in the calculation of elemental sulfur solubility of sour gas samples in this research. The research results provide important basic data and technical support for the development of M gas reservoir.

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“…Unconventional natural gas resources are abundant in China (Yu et al 2021;Fu et al 2020;Huang et al 2021). Coalbed methane (CBM) reservoirs are widely distributed in major coal-bearing basins, which have great development potential.…”

Section: Introductionmentioning

confidence: 99%

Controlling factors towards co-production performance of coalbed methane and tight sandstone gas reservoirs

Huang

Wang²

2021

Arab J Geosci

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Multi-layer superposition of coal seams and tight sandstone layers is common in Chinese major coal-bearing basins, which possesses huge resource potential. Co-production of coalbed methane (CBM) and tight sandstone gas reservoirs is still in the stage of engineering test in China; the control factors towards the co-production performance remain to be clarified. Based on discussion on the key problems involved in co-production of coal seams and tight sandstone layers, the main control factors governing the co-production performance of CBM and tight sandstone gas are analyzed. Taking well X in Ordos Basin as an example, a co-production numerical model is established. The co-production characteristics of well X are analyzed. The optimization of co-production sequence and hydraulic fracturing parameters of tight sandstone formation is carried out. The results show that the early drainage in coal seams and the reasonable control of bottom-hole flowing pressure are the keys to achieve good development benefits. The co-production is mainly controlled by reservoir permeability, water saturation of sandstone formation, formation-desorption pressure difference of coal seam, reservoir pressure gradient, and surrounding rock properties. Under the optimized co-production sequence of perforating coal seam first and the tight sandstone layer, the tight sandstone layer has a low recovery degree, which may be targeted for later reservoir reconstruction. The recovery degree of tight sandstone layer can be improved by optimizing the hydraulic fracturing parameters such as the fracture halflength and the fracture conductivity. For well X, the fracture half-length and the fracture conductivity are optimized to be 150 m and 300 mD•m. The findings of this study can be applicable to evaluating the adaptability of geological conditions for multi-layer co-production in coal-bearing basins. Also, the findings can provide theoretical guides for the optimization of production sequence and hydraulic fracturing to improve the co-production benefits.

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Dynamic fluid states in organic-inorganic nanocomposite: Implications for shale gas recovery and CO2 sequestration

Cited by 106 publications

References 68 publications

Optimal nanocone geometry for water flow

Optimal nanocone geometry for water flow

Experimental Study on the Elemental Sulfur Solubility in Sour Gas Mixtures

Controlling factors towards co-production performance of coalbed methane and tight sandstone gas reservoirs

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