Numerical investigation of gas flow rate in shale gas reservoirs with nanoporous media

Song, Haoran; Yu, Mao-Hong; Zhu, Weiyao; Wu, Pengjie; Lou, Yu; Wang, Yuhe; Killough, John

doi:10.1016/j.ijheatmasstransfer.2014.09.039

Cited by 55 publications

(15 citation statements)

References 37 publications

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“…The widespread application of nanoporous materials in several fields, such as chromatography, membrane separation, catalysis, etc., has lead to a growing interest in the accurate description of the thermodynamic behavior of fluids confined in nanopores [1][2][3][4][5][6]. The pressure of a nanoconfined fluid is one of the most important thermodynamic properties which is needed for an accurate description of the flow rate, diffusion coefficient, and the swelling of the nanoporous material [7][8][9][10]. Various approaches for calculating the pressure of a fluid in a nanopore have been proposed [1,[11][12][13].…”

Section: Introductionmentioning

confidence: 99%

Gibbs Ensemble Monte Carlo Simulation of Fluids in Confinement: Relation between the Differential and Integral Pressures

et al. 2020

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The accurate description of the behavior of fluids in nanoporous materials is of great importance for numerous industrial applications. Recently, a new approach was reported to calculate the pressure of nanoconfined fluids. In this approach, two different pressures are defined to take into account the smallness of the system: the so-called differential and the integral pressures. Here, the effect of several factors contributing to the confinement of fluids in nanopores are investigated using the definitions of the differential and integral pressures. Monte Carlo (MC) simulations are performed in a variation of the Gibbs ensemble to study the effect of the pore geometry, fluid-wall interactions, and differential pressure of the bulk fluid phase. It is shown that the differential and integral pressure are different for small pores and become equal as the pore size increases. The ratio of the driving forces for mass transport in the bulk and in the confined fluid is also studied. It is found that, for small pore sizes (i.e., < 5 σ fluid ), the ratio of the two driving forces considerably deviates from 1.

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Section: Introductionmentioning

confidence: 99%

Gibbs Ensemble Monte Carlo Simulation of Fluids in Confinement: Relation between the Differential and Integral Pressures

et al. 2020

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“…The flow patterns of a controlled area in the tight gas reservoir can be categorized into unidirectional flow in the middle area and radial flow in the rest of the area [23]. The sketch of a vertical well for tight gas production is shown in Figure 1.…”

Section: Physical Description For Vertical Fractured Wellmentioning

confidence: 99%

Analytical modeling of coupled flow and geomechanics for vertical fractured well in tight gas reservoirs

et al. 2017

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Abstract:The mathematical model of coupled flow and geomechanics for a vertical fractured well in tight gas reservoirs was established. The analytical modeling of unidirectional flow and radial flow was achieved by Laplace transforms and integral transforms. The results show that uncoupled flow would lead to an overestimate in performance of a vertical fractured well, especially in the later stage. The production rate decreases with elastic modulus because porosity and permeability decrease accordingly. Drawdown pressure should be optimized to lower the impact of coupled flow and geomechanics as a result of permeability decreasing. Production rate increases with fracture half-length significantly in the initial stage and becomes stable gradually. This study could provide a theoretical basis for effective development of tight gas reservoirs.

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“…Pore diameters in these reservoirs are mostly between 0.1 and 100 nm (Song et al 2015). Considering this range of pore size, the flow conduit length scale is comparable to molecular mean free path.…”

Section: Introductionmentioning

confidence: 96%

“…Under this condition, the Navier-Stokes assumptions are no longer valid; hence it cannot be used to predict the fluid flow behaviour. Many researchers have tried to model gas flow in the unconventional reservoirs by assuming different flow regimes such as slip flow, transient flow and free-molecular flow (Javadpour et al 2007;Freeman et al 2011;Song et al 2015;Javadpour 2009;Deng et al 2014;Florence et al 2007).…”

Section: Introductionmentioning

confidence: 99%

Numerical Simulation of Gas Production From Tight, Ultratight and Shale Gas Reservoirs: Flow Regimes and Geomechanical Effects

Moghaddam¹,

Aghabozorgi

Foroozesh³

2015

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Production from unconventional gas resources (UGRs) has received great attentions because of their large reserves as well as technical advances in developing these reservoirs. The fluid flow in ultralow permeability porous media cannot be considered in the range of conventional Darcy flow as it undergoes a transition from a Darcy regime to slip flow and free molecule flow regimes. Understanding fluid flow inside the matrix and how the matrix permeability evolves over depletion are among the major challenges to unconventional gas reservoirs characterization. Considering different flow regimes in UGRs and time dependent permeability during the production of reservoir, the applicability of the availabe numerical simulatior to predict the production from unconventional reservoirs is questionable.In this paper, a numerical approach is proposed for simulation of gas production of UGRs including geomechanical effect, slippage effect and non-Darcy flow. In this simulation, gas production is calculated using a pseudo-pressure integral for well inflow performance and material-balance for reservoir depletion. The numerical approach has been verified by comparing with the results of fine-grid compositional simulation for a typical conventional gas reservoir. The pseudo pressure-integral has been extended to include the geomechanical effect and time dependent matrix permeability. The flow regime is distinguished by Knudsen number for each regions of the reservoir during the reservoir depletion.According to the numerical results, the matrix permeability changes depending on the flow regime determined by Knudsen dimensionless number. Slip flow and Knudsen diffusion which are dependent on net pore pressure can play important roles in the gas production. Higher-than-expected matrix permeability becomes more highlighted when the permeability of the matrix decreases and dimensionless Knudsen number is higher than 0.1. This higher permeability enhances the gas production. On the other side, the matrix permeability decrease as the net overburden stress increases during the production life of the reservoirs. This decrease in matrix permeability clearly decreases the rate of gas production.The presented numerical simulation evaluates the significance of different flow regimes, time dependent permeability and geomechnical effect in production from UGRs. It also offers a rapid and simple tool for prediction of gas deliverability of UGRs well.

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Numerical investigation of gas flow rate in shale gas reservoirs with nanoporous media

Cited by 55 publications

References 37 publications

Gibbs Ensemble Monte Carlo Simulation of Fluids in Confinement: Relation between the Differential and Integral Pressures

Gibbs Ensemble Monte Carlo Simulation of Fluids in Confinement: Relation between the Differential and Integral Pressures

Analytical modeling of coupled flow and geomechanics for vertical fractured well in tight gas reservoirs

Numerical Simulation of Gas Production From Tight, Ultratight and Shale Gas Reservoirs: Flow Regimes and Geomechanical Effects

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