Abstract
Production simulation is an important method to evaluate the stimulation effect of refracturing. Therefore, a production simulation model based on coupled fluid flow and geomechanics in triple continuum including kerogen, an inorganic matrix, and a fracture network is proposed considering the multiscale flow characteristics of shale gas, the induced stress of fracture opening, and the pore elastic effect. The complex transport mechanisms due to multiple physics, including gas adsorption/desorption, slip flow, Knudsen diffusion, surface diffusion, stress sensitivity, and adsorption layer are fully considered in this model. The apparent permeability is used to describe the multiple physics occurring in the matrix. The model is validated using actual production data of a horizontal shale gas well and applied to predict the production and production increase percentage (PIP) after refracturing. A sensitivity analysis is performed to study the effects of the refracturing pattern, fracture conductivity, width of stimulated reservoir volume (SRV), SRV length of new and initial fractures, and refracturing time on production and the PIP. In addition, the effects of multiple physics on the matrix permeability and production, and the geomechanical effects of matrix and fracture on production are also studied. The research shows that the refracturing design parameters have an important influence on the PIP. The geomechanical effect is an important cause of production loss, while slippage and diffusion effects in matrix can offset the production loss.
Highlights
After initial fracturing of the shale gas well, monitoring results of production logging show that the local fracturing stage produces no gas and about one third of perforation cluster produces no gas or contributes little to gas production [1, 2]
We will perform a sensitivity analysis to study the effects of refracturing scenarios, fracture conductivity, stimulated reservoir volume (SRV) width, SRV length, and the refracturing time on the gas production and the production increase percentage (PIP) based on the initial fracturing production data
Considering the slippage effect in Case#3 can compensate the permeability loss caused by the stresssensitive effect, and the apparent permeability increases further when the Knudsen diffusion is taken into consideration
Summary
After initial fracturing of the shale gas well, monitoring results of production logging show that the local fracturing stage produces no gas and about one third of perforation cluster produces no gas or contributes little to gas production [1, 2]. The multiscale flow characteristic of shale gas and the complex transport mechanism in different scale media (kerogen, inorganic matrix, and fracture) and coupling fluid flow and geomechanics are not fully considered in the abovementioned mathematical models. Peng et al [56] presented a coupled fluid flow and geomechanical deformation model considering multiscale shale gas flow In this mathematical model, continuity equations of kerogen, inorganic matrix, and fracture system are established, respectively, and the correlations between the permeability, porosity, and volume strain are derived, respectively. Based on the theory of pore elasticity, Peng et al [59] proposed an apparent permeability model considering the adsorption strain and presented a coupled gas flow and geomechanical model to study the evolution process of apparent shale gas permeability under different stress boundary conditions. This study and research results provide vital theoretical and engineering significance for understanding shale gas complex flow mechanisms, refracturing design, and production evaluation
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