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

Abstract

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.

A fully coupled multiscale shale deformation-gas transport model for the evaluation of shale gas extraction

“…Many scholars adopt the continuum mechanics model to investigate the gas flow within shale reservoirs. Specifically, both the single porosity single permeability model [1] and dual porosity dual permeability model [2][3][4][5] are used to represent the gas flow within the shale matrix. For the single porosity model, it is assumed that the porous medium is made up of uniform pores with the same properties, which ignores the differences between big cracks and small pores.…”

Impact of Local Effects on the Evolution of Unconventional Rock Permeability

“…where σ = −σ kk /3 is the mean compressive stress. Combining Equations (1), (2), (7) and (8) yields the general Navier-type equations for the matrix and fracture, respectively…”

“…Many scholars established models to investigate the evolution of the permeability of different parts over the past few decades. The models were developed from a single porosity/permeability model [8] to dual porosity/permeability model [9][10][11][12]. For a single porosity model, the effects of effective stress variation and the matrix shrinkage/swelling were taken into consideration [13,14], which ignored the interactions between different range radius pores.…”

A Fully Coupled Model for the Simulation of Gas Flow in Multiscale Shale Reservoirs Combining Multiple Effects

“…Traditionally, single-porosity models [7,10], dual-porosity models [22,23], and triple-porosity models (dual fracture models) [24,25] are used to describe gas flow in shale reservoirs. However, single-porosity and dual-porosity models assume that the pore and fracture properties are uniform across the porous medium, while actual shale reservoirs include multiscale pores and fractures with different properties.…”

“…In addition to that, the validity of such correlation models using empirical coefficients has been questionable [13][14][15][16][17][18]. Chen et al [19] and Wu et al [5] proposed gas transport models for describing gas flow in different scale fractures while considering the effects of the fracture shape; Mi et al [20] established an apparent permeability model for describing gas flow in multiscale shale reservoirs without considering the effects of adsorption/desorption and stress-sensitivity; Wu et al [3] proposed an apparent permeability model for evaluating gas flow in nano-scale shale matrix by coupling the effects of adsorption/desorption and stress-sensitivity; Sun et al [4] revealed gas flow mechanisms in a shale matrix combined with the effects of surface diffusion and the thickness of the adsorbed gas layer; Zhang et al [21] found that shale reservoirs are highly stress-dependent, which significantly affects gas transport mechanisms; and Moghaddam et al [22] investigated the gas flow mechanisms in multiscale fractures in tight reservoirs while considering the coupled effects of adsorption/desorption and stress-sensitivity. Few previous studies have attempted to model all gas flow regimes in multiscale shale reservoirs while considering multiple effects as reservoir pressure changes [6].…”