Understanding gas transport mechanisms in shale gas reservoir: Pore network modelling approach

Song, Wenhui; Jun, Youngcook; Zhang, Kai; Yang, Yongfei; Sun, Hai

doi:10.46690/ager.2022.04.11

Cited by 15 publications

(4 citation statements)

References 6 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…The PNM is widely used to simulate the migration of multicomponent fluid and multiphase fluid in porous media. Song et al studied the multiphase and multicomponent fluid transport mechanisms of shale based on the multiscale PNM of shale by comprehensively considering factors, such as gas slippage, surface diffusion, restricted phase state, water phase wall slip, and viscosity change of the interface layer. ,− Chen et al established a coupling model considering the influence of wall mineral composition of shale on the confined phase transition of nanopores and studied the influence of wall properties on gas phase transition …”

Section: Multiscale Flow Simulationmentioning

confidence: 99%

Recent Advances in Multiscale Digital Rock Reconstruction, Flow Simulation, and Experiments during Shale Gas Production

Yang

Zhang

et al. 2023

Energy Fuels

Self Cite

View full text Add to dashboard Cite

The complex and multiscale nature of shale gas transport imposes new challenges to the already well-developed techniques for conventional reservoirs, especially digital core analysis. Multiscale complicated pore systems and distinctive properties limit most reconstruction methods not applicable. High-precision imaging experiments play a key role in the characterization of pore structures and mineral components. While the exhilarating breakthroughs in physical experimental methods and hybrid superposition methods have made significant achievements in shale digital rock reconstruction, rapidly evolving deep learning methods also present a promising option. Benefiting from the digital rock techniques, the pore-scale flow of shale gas can be directly simulated based on digital rock or indirectly modeled using the pore network model. It is precise and realistic to investigate the shale gas flow at the pore scale considering the desorption, surface diffusion, and slippage in nanopores. In this paper, we reviewed the recent advances in off-mentioned methods and processes and presented a hand for the research in this field.

show abstract

Section: Multiscale Flow Simulationmentioning

confidence: 99%

Recent Advances in Multiscale Digital Rock Reconstruction, Flow Simulation, and Experiments during Shale Gas Production

Yang

Zhang

et al. 2023

Energy Fuels

Self Cite

View full text Add to dashboard Cite

show abstract

“…The three-phase fluid transport phenomenon in shale has received increasing attention because of the current development of unconventional resources. − Elucidating the nanoscale compositional multiphase thermodynamic equilibrium and transport behavior is essential to predict the productivity of these resources. , The rock–fluid intermolecular interaction and multiphase interfacial curvature change are more pronounced in nanoporous shale than that in micron scale porous media. The current thermodynamic and transport models designed for micron scale porous media consequently fail to predict multiphase thermodynamic equilibrium and transport behavior in nanoporous shale.…”

Section: Introductionmentioning

confidence: 99%

Nanoscale Three-Phase Transport in a Shale Pore Network with Phase Change and Solid–Fluid Interaction

Song,

Yao,

Sun

et al. 2023

Energy Fuels

Self Cite

View full text Add to dashboard Cite

The complexities of three-phase transport in nanoporous shale are expressed in terms of strong solid–fluid intermolecular interaction and complex phase change in nanoscale confined pore space. In this study, we propose a general pore network-based three-phase thermodynamic equilibrium and transport model, which enables accurate prediction of multicomponent hydrocarbon–water transport properties in nanoporous shale at different temperatures and pressures. The multicomponent hydrocarbon–water molecule distribution in irregular pores is first determined based on the extended DLVO theory and free energy balance. A nanoscale phase equilibrium model is further developed considering the influence of water distribution on oil–gas–water interfacial curvature variation. The resultant three-phase distribution on the pore network is applied to calculate transport properties by considering the gas-phase Knudsen number change and liquid phase slippage dependent on pore shape and size. The multiphase multicomponent fluid transport properties at different phase saturations, pressures, temperatures, hydrocarbon compositions, and pore size conditions are discussed in detail. The study results reveal that the existence of water molecules causes lower oil saturation when phase change occurs than that under the multicomponent hydrocarbon-saturated condition and the gas phase notably loses its transport ability because of oil phase blockage.

show abstract

“…Based on previous studies, it can be known that the fluid in the reservoir rock mass can be categorized into movable and irreducible fluid according to the state of residence [21][22][23]. Among them, movable fluid refers to the fluid in the large pores that is weakly affected by the rock skeleton and can flow freely under a specific driving force.…”

Section: Introductionmentioning

confidence: 99%

Research on the Pore Evolution of Oil Shale under Different Thermal Treatment Temperatures Using NMR and FE-SEM Methods

Xi,

Li,

Lian

et al. 2023

Geofluids

View full text Add to dashboard Cite

Underground in situ pyrolysis for oil shale extraction is currently significant; the evolutions in microstructure, porosity, and permeability parameters are essential factors in evaluating the productivity of oil shale after pyrolysis. With the underground oil shale reservoir core, obtained from Jimsar Sag in the Junggar Basin in China, as the research object, the samples were subjected to the treatment at different high temperatures (400°C, 500°C, 600°C, and 700°C). The NMR and FE-SEM experiments on oil shale samples were conducted; the T 2 relaxation spectra, pore size distribution, and porosity and permeability variation were analyzed; and the relationships between movable fluid saturation and porosity and permeability were established, respectively. The results showed that when the thermal treatment temperature increased, the porosity and permeability of oil shale rose continuously but showed different laws. With the temperature being lower than 400°C, the porosity increased slowly, and the growth rate of porosity increased rapidly when the thermal treatment temperature was higher than 500°C. In the pyrolysis temperature range of 25°C~400°C, the growth rate of permeability was relatively slow. With the continuously enhancing temperature (500°C~600°C), the growth rate of permeability accelerated rapidly. When the temperature continued to rise (700°C), the increase of permeability began to slow down. There is a nonlinear correlation between porosity and movable fluid saturation and an approximately linear correlation between permeability and movable fluid saturation. The findings showed that 600°C was the suitable temperature for the pyrolysis of oil shale.

show abstract

Understanding gas transport mechanisms in shale gas reservoir: Pore network modelling approach

Cited by 15 publications

References 6 publications

Recent Advances in Multiscale Digital Rock Reconstruction, Flow Simulation, and Experiments during Shale Gas Production

Recent Advances in Multiscale Digital Rock Reconstruction, Flow Simulation, and Experiments during Shale Gas Production

Nanoscale Three-Phase Transport in a Shale Pore Network with Phase Change and Solid–Fluid Interaction

Research on the Pore Evolution of Oil Shale under Different Thermal Treatment Temperatures Using NMR and FE-SEM Methods

Contact Info

Product

Resources

About