Impact of micro- and macro-scale consistent flows on well performance in fractured shale gas reservoirs

Jia, Lei; Wang, Jingguo; Gao, Feng; Ju, Yang; Tang, Furong

doi:10.1016/j.jngse.2016.05.005

Cited by 22 publications

(7 citation statements)

References 44 publications

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“…It is suggested that the thickness of the boundary layer is associated with pore radius of porous media, the displacement gradient, and the fluid viscosity For instance, Cao et al proposed the following empirical model to estimate the boundary layer thickness ( h , μm):

h = ({, \begin{array}{c} r \cdot 0.25763 e^{- 0.261 r {(\nabla p)}^{- 0.419}} μ, (||, \nabla p) < 1 MPa / normalm \\ r \cdot 0.25763 e^{- 0.261 r} μ, (||, \nabla p) > 1 MPa / normalm \end{array})

where r is the pore radius (μm), ∇ p is the displacement pressure gradient (MPa/m), and μ is the fluid viscosity (mPa·s).…”

Section: Methodsmentioning

confidence: 97%

Investigation of the dynamic capillary pressure during displacement process in fractured tight rocks

Chen

et al. 2019

AIChE Journal

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This work investigates the dynamic capillary pressure during the displacement process in fractured tight rocks, through specially designed experiments on fractured and intact core samples. The dynamic capillarity coefficient of matrix and the multiphase flow behaviors are also obtained. Results have shown that the dynamic capillary pressure of the matrix becomes around 5-20% higher after the fracturing treatment. The lower and less variable values of dynamic capillarity coefficient of matrix illustrate a weakened dynamic effect and a more uniform displacement front. Moreover, time derivative of water saturation is increased significantly with fractures. Finally, oil relative permeability after fracturing is lower than its value of the intact core at high water saturations. A dynamic capillarity coefficient model for matrix, which includes the influence of fractures, is derived and verified with the average R 2 more than 0.95. This wok helps to understand and predict multiphase flow in fractured tight porous media.

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h = ({, \begin{array}{c} r \cdot 0.25763 e^{- 0.261 r {(\nabla p)}^{- 0.419}} μ, (||, \nabla p) < 1 MPa / normalm \\ r \cdot 0.25763 e^{- 0.261 r} μ, (||, \nabla p) > 1 MPa / normalm \end{array})

where r is the pore radius (μm), ∇ p is the displacement pressure gradient (MPa/m), and μ is the fluid viscosity (mPa·s).…”

Section: Methodsmentioning

confidence: 97%

Investigation of the dynamic capillary pressure during displacement process in fractured tight rocks

Chen

et al. 2019

AIChE Journal

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“…The commercial development of shale gas has been driven by three key advances in technology and science: (1) horizontal well plus multi-stage hydraulic fracturing [1][2][3][4][5][6], (2) the understanding of gas storage mechanisms [1], and (3) the understanding of multi-scale mechanisms of gas flows from shale matrix to hydraulic fracture [7][8][9][10]. A shale gas reservoir has free gas stored in matrix pores and natural fractures, and adsorbed gas on the organic matter [11,12].…”

Section: Introductionmentioning

confidence: 99%

A Multi-Parameter Optimization Model for the Evaluation of Shale Gas Recovery Enhancement

et al. 2018

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Although a multi-stage hydraulically fractured horizontal well in a shale reservoir initially produces gas at a high production rate, this production rate declines rapidly within a short period and the cumulative gas production is only a small fraction (20-30%) of the estimated gas in place. In order to maximize the gas recovery rate (GRR), this study proposes a multi-parameter optimization model for a typical multi-stage hydraulically fractured shale gas horizontal well. This is achieved by combining the response surface methodology (RSM) for the optimization of objective function with a fully coupled hydro-mechanical FEC-DPM for forward computation. The objective function is constructed with seven uncertain parameters ranging from matrix to hydraulic fracture. These parameters are optimized to achieve the GRR maximization in short-term and long-term gas productions, respectively. The key influential factors among these parameters are identified. It is established that the gas recovery rate can be enhanced by 10% in the short-term production and by 60% in the long-term production if the optimized parameters are used. Therefore, combining hydraulic fracturing with an auxiliary method to enhance the gas diffusion in matrix may be an effective alternative method for the economic development of shale gas.

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“…Combining (11), (12), and 14, the final effective diffusion coefficient for the whole matrix is given as…”

Section: Knudsen Numbermentioning

confidence: 99%

“…Usually, higher total injectedwater volume leads to larger effective fracture pore volume [9]. In most cases, these flowback data are ignored if singlephase flow is used for the prediction of shale gas production [10][11][12]. This ignorance of two-phase flowback makes the predicted gas production curve inconsistent with the actual field observation in the early period [13].…”

Section: Introductionmentioning

confidence: 99%

A Two-Phase Flowback Model for Multiscale Diffusion and Flow in Fractured Shale Gas Reservoirs

Wang

Gao

et al. 2018

Geofluids

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A shale gas reservoir is usually hydraulically fractured to enhance its gas production. When the injection of water-based fracturing fluid is stopped, a two-phase flowback is observed at the wellbore of the shale gas reservoir. So far, how this water production affects the long-term gas recovery of this fractured shale gas reservoir has not been clear. In this paper, a two-phase flowback model is developed with multiscale diffusion mechanisms. First, a fractured gas reservoir is divided into three zones: naturally fractured zone or matrix (zone 1), stimulated reservoir volume (SRV) or fractured zone (zone 2), and hydraulic fractures (zone 3). Second, a dual-porosity model is applied to zones 1 and 2, and the macroscale two-phase flow flowback is formulated in the fracture network in zones 2 and 3. Third, the gas exchange between fractures (fracture network) and matrix in zones 1 and 2 is described by a diffusion process. The interactions between microscale gas diffusion in matrix and macroscale flow in fracture network are incorporated in zones 1 and 2. This model is validated by two sets of field data. Finally, parametric study is conducted to explore key parameters which affect the short-term and long-term gas productions. It is found that the two-phase flowback and the flow consistency between matrix and fracture network have significant influences on cumulative gas production. The multiscale diffusion mechanisms in different zones should be carefully considered in the flowback model.

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Impact of micro- and macro-scale consistent flows on well performance in fractured shale gas reservoirs

Cited by 22 publications

References 44 publications

Investigation of the dynamic capillary pressure during displacement process in fractured tight rocks

Investigation of the dynamic capillary pressure during displacement process in fractured tight rocks

A Multi-Parameter Optimization Model for the Evaluation of Shale Gas Recovery Enhancement

A Two-Phase Flowback Model for Multiscale Diffusion and Flow in Fractured Shale Gas Reservoirs

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