Investigation of multi-scale gas transport behavior in organic-rich shale

Chen, Mingjun; Kang, Yili; Li, Xiangchen; Wang, Weihong; Yang, Bin; Liu, Hua

doi:10.1016/j.jngse.2016.03.061

Cited by 33 publications

(10 citation statements)

References 41 publications

Supporting

Mentioning

Contrasting

Unclassified

Order By: Relevance

“…Also, it should be noted that when the r H decreases to a very small value, such as 2 nm shown in Figure 14, the permeability improves directly as the reservoir pressure decreases. Since the major peak of the matrix samples is 3-4 nm, 41 the modeling results show that the transport capability of shale matrix nanopores has an obvious tendency of increase in the mid-late production period, which is directly related to contribution of each gas transport mechanism during the decline of pore pressure and increase in formation effective stress that would be discussed in detail in the rest of section 5. Meanwhile, the modeling results are in line with the sensitivity of pore size and pressure for methane gas transport studied by the molecular dynamics simulation of shale matrix pores with a few nanometers.…”

Section: Resultsmentioning

confidence: 94%

Shale gas transport behavior considering dynamic changes in effective flow channels

Chen

Kang

Zhang

et al. 2019

Energy Science & Engineering

Self Cite

View full text Add to dashboard Cite

Shale gas transport is influenced by the changes in effective flow channels during production due to an effective stress sensitivity and a sorption layer effect. In this work, shale samples’ core analyses, methane adsorption experiments, and effective stress sensitivity experiments were conducted at in situ conditions. Then, a mathematical modeling was applied to quantitatively determine the real shale gas flow behavior considering the changes in effective flow channels during production. The results show that (1) the gas transport capability in matrix has an obvious tendency of increase in the mid‐late production period; (2) the decline of permeability of inorganic pores/fractures tends to be gentler during production, especially for the smaller flow channels; (3) surface diffusion is dominant in shale matrix throughout production; (4) the contribution of Knudsen diffusion to total gas flux cannot be neglected in flow channels with hydraulic radius of tens of nanometers in the early production period or of tens and hundreds of nanometers in the mid‐late production period; and (5) viscous flow generally dominates the total gas flux in flow channels with hydraulic radius more than 10 nm in the early production period or more than 100 nm in the mid‐late production period. This work is beneficial for an accurate evaluation of shale gas transport during production.

show abstract

Section: Resultsmentioning

confidence: 94%

Shale gas transport behavior considering dynamic changes in effective flow channels

Chen

Kang

Zhang

et al. 2019

Energy Science & Engineering

Self Cite

View full text Add to dashboard Cite

show abstract

“…Based on previous study [5,23,24], the pores in the shale are generally divided into inorganic and organic nanopores according to the existence of organic matter or kerogen. Specially, for the organic nanopores which are formed in the kerogen, the pores can be characterized by cylindrical tubes [23][24][25]. For the inorganic pores which are formed in the clay minerals [5,6], the pores can be characterized by silts [26,27].…”

Section: Gas Transport Mechanisms In Shale Inorganic and Organic Nanomentioning

confidence: 99%

Study on Two Component Gas Transport in Nanopores for Enhanced Shale Gas Recovery by Using Carbon Dioxide Injection

Guo

Wang

et al. 2020

Energies

View full text Add to dashboard Cite

Injecting carbon dioxide to enhance shale gas recovery (CO2-EGR) is a useful technique that has raised great research interests. Clear understanding of the two-component gas transport mechanisms in shale nanopores is the foundation for the efficient development of shale gas reservoir (SGR) and also the long-term geological storage of CO2. Although extensive studies on single-component gas transport and corresponding models in shale nanopores have been carried out in recent years, limited studies have been conducted on two-component or even multi-component gas transport models in shale nanopores. In this work, the shale nanopores were classified into inorganic and organic nanopores. The corresponding models for two-component gas transport were constructed. Mechanisms including Knudsen diffusion, slip flow, viscous flow, and molecular diffusion are considered in the inorganic pores. In the organic pores, due to existence of adsorption gas, surface diffusion is further considered besides the aforementioned mechanisms. Effects of pressure, temperature, fraction of organic nanopores, and gas concentration were analyzed. Results show that gas apparent permeability is negatively correlated with pressure, and positively correlated with temperature and organic nanopore fraction. As the concentration of CH4 decreases, the apparent permeability of CH4 increases continuously, while the apparent permeability of CO2 decreases. The permeability ratio of CH4 in the total permeability is negatively correlated with pressure and gas concentration ratio. Additionally, the contribution of transport mechanisms to the total gas apparent permeability has been analyzed. It is found that the surface diffusion contributes up to 5.68% to gas apparent permeability under high pressure. The contribution of molecular diffusion can reach up to 88.83% in mesopores under low pressure. Under high pressure and macropores, it contributes less than 1.41%. For all situations, the contribution of viscous flow is more than 46.36%, and its contribution can reach up to 86.07%. Results of this study not only can improve the understanding of two-component gas transport in nanochannels, but also can lay the foundation for more reliable reservoir simulation of CO2-EGR.

show abstract

“…A shale gas reservoir is characterized by multiscale flow channels. Especially after hydraulic fracturing, there are three main types of flow channels, including matrixes, natural fractures, and artificial fractures. − The APT damage caused by the retained fracturing fluid should also be influenced by such multiscale characteristics. From the perspective of the pore fracture structure, the larger the size of the flow channel, the shallower the invasion depth of the aqueous phase.…”

Section: Introductionmentioning

confidence: 99%

Impact of Aqueous Phase Trapping on Mass Transfer in Shales with Multiscale Channels

et al. 2020

Self Cite

View full text Add to dashboard Cite

Large amounts of fracturing fluid retained in a shale reservoir could not only restrict gas production through aqueous phase trapping (APT) but also cause potential contamination of groundwater. In this work, experiments modeling in situ aqueous imbibition and flowback were conducted to quantitatively investigate the APT behavior in shales, including matrix, natural fracture, and artificial fracture. Results show that the forward imbibition process is slower than the reverse imbibition process. The aqueous phase tends to be imbibed through parallel bedding. Permeability reduction rates of matrix, natural fracture, and artificial fracture cores after imbibition could reach 100, 85, and 70%, respectively. Meanwhile, it is demonstrated that the aqueous flowback efficiency depends upon flowback timing, pressure difference, initial permeability, and bedding direction. The flowback efficiencies of matrix, natural fracture, and artificial fracture cores could be less than 7%, less than 30%, and less than 15%, respectively. Additionally, the permeability recovery rates of those could be less than 19%, less than 39%, and less than 67%, respectively. Finally, shale APT mechanisms are analyzed from both geological and engineering aspects. The quantitative investigation of shale APT is conducive to economically and environmentally developing shale gas reservoirs.

show abstract

Investigation of multi-scale gas transport behavior in organic-rich shale

Cited by 33 publications

References 41 publications

Shale gas transport behavior considering dynamic changes in effective flow channels

Shale gas transport behavior considering dynamic changes in effective flow channels

Study on Two Component Gas Transport in Nanopores for Enhanced Shale Gas Recovery by Using Carbon Dioxide Injection

Impact of Aqueous Phase Trapping on Mass Transfer in Shales with Multiscale Channels

Contact Info

Product

Resources

About