Numerical Investigation of the Effect of Partially Propped Fracture Closure on Gas Production in Fractured Shale Reservoirs

Nonuniform proppant distribution is fairly common in hydraulic fractures, and different closure behaviors of the propped and unpropped fractures have been observed in lots of physical experiments. However, the modeling of partially propped fracture closure is rarely performed, and its effect on gas production is not well understood as a result of previous studies. In this paper, a fully coupled fluid flow and geomechanics model is developed to simulate partially propped fracture closure, and to examine its effect on gas production in fractured shale reservoirs. Specifically, an efficient hybrid model, which consists of a single porosity model, a multiple porosity model and the embedded discrete fracture model (EDFM), is adopted to model the hydro-mechanical coupling process in fractured shale reservoirs. In flow equations, the Klinkenberg effect is considered in gas apparent permeability, and adsorption/desorption is treated as an additional source term. In the geomechanical domain, the closure behaviors of propped and unpropped fractures are described through two different constitutive models. Then, a stabilized extended finite element method (XFEM) iterative formulation, which is based on the polynomial pressure projection (PPP) technique, is developed to simulate a partially propped fracture closure with the consideration of displacement discontinuity at the fracture interfaces. After that, the sequential implicit method is applied to solve the coupled problem, in which the finite volume method (FVM) and stabilized XFEM are applied to discretize the flow and geomechanics equations, respectively. Finally, the proposed method is validated through some numerical examples, and then it is further used to study the effect of partially propped fracture closures on gas production in 3D fractured shale reservoir simulation models. This work will contribute to a better understanding of the dynamic behaviors of fractured shale reservoirs during gas production, and will provide more realistic production forecasts.

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Simultaneous Multifracture Treatments: Fully Coupled Fluid Flow and Fracture Mechanics for Horizontal Wells

SPE Journal ◽

10.2118/167626-pa ◽

2014 ◽

Vol 20 (02) ◽

pp. 337-346 ◽

Cited By ~ 154

Author(s):

Kan Wu ◽

Jon E. Olson

Keyword(s):

Fluid Flow ◽

Fracture Propagation ◽

Horizontal Wells ◽

Gas Production ◽

Propagation Model ◽

Displacement Discontinuity ◽

Hydraulic Fractures ◽

Multiple Fractures ◽

Frictional Pressure Drop ◽

Horizontal Wellbore

Summary Successfully creating multiple hydraulic fractures in horizontal wells is critical for unconventional gas production economically. Optimizing the stimulation of these wells will require models that can account for the simultaneous propagation of multiple, potentially nonplanar, fractures. In this paper, a novel fracture-propagation model (FPM) is described that can simulate multiple-hydraulic-fracture propagation from a horizontal wellbore. The model couples fracture deformation with fluid flow in the fractures and the horizontal wellbore. The displacement discontinuity method (DDM) is used to represent the mechanics of the fractures and their opening, including interaction effects between closely spaced fractures. Fluid flow in the fractures is determined by the lubrication theory. Frictional pressure drop in the wellbore and perforation zones is taken into account by applying Kirchoff's first and second laws. The fluid-flow rates and pressure compatibility are maintained between the wellbore and the multiple fractures with Newton's numerical method. The model generates physically realistic multiple-fracture geometries and nonplanar-fracture trajectories that are consistent with physical-laboratory results and inferences drawn from microseismic diagnostic interpretations. One can use the simulation results of the FPM for sensitivity analysis of in-situ and fracture treatment parameters for shale-gas stimulation design. They provide a physics-based complex fracture network that one can import into reservoir-simulation models for production analysis. Furthermore, the results from the model can highlight conditions under which restricted width occurs that could lead to proppant screenout.

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An Efficient Numerical Hybrid Model for Multiphase Flow in Deformable Fractured-Shale Reservoirs

SPE Journal ◽

10.2118/191122-pa ◽

2018 ◽

Vol 23 (04) ◽

pp. 1412-1437 ◽

Cited By ~ 15

Author(s):

Xia Yan ◽

ZhaoQin Huang ◽

Jun Yao ◽

Yang Li ◽

Dongyan Fan ◽

...

Keyword(s):

Hydraulic Fracturing ◽

Hybrid Model ◽

Hydraulic Fractures ◽

Fluid Exchange ◽

Flow Process ◽

Numerical Examples ◽

Fracturing Process ◽

The Matrix ◽

Shale Reservoirs ◽

Porosity Model

Summary After hydraulic fracturing, a shale reservoir usually has multiscale fractures and becomes more stress-sensitive. In this work, an adaptive hybrid model is proposed to simulate hydromechanical coupling processes in such fractured-shale reservoirs during the production period (i.e., the hydraulic-fracturing process is not considered and cannot be simulated). In our hybrid model, the single-porosity model is applied in the region outside the stimulated reservoir volume (SRV), and the matrix and natural/induced fractures in the SRV region are modeled using a double-porosity model that can accurately simulate the matrix/fracture fluid exchange during the entire transient period. Meanwhile, the fluid flow in hydraulic fractures is modeled explicitly with the embedded-discrete-fracture model (EDFM), and a stabilized extended-finite-element-method (XFEM) formulation using the polynomial-pressure-projection (PPP) technique is applied to simulate mechanical processes. The developed stabilized XFEM formulation can avoid the displacement oscillation on hydraulic-fracture interfaces. Then a modified fixed-stress sequential-implicit method is applied to solve the hybrid model, in which mixed-space discretization [i.e., finite-volume method (FVM) for flow process and stabilized XFEM for geomechanics] is used. The robustness of the proposed model is demonstrated through several numerical examples. In conclusion, several key factors for gas exploitation are investigated, such as adsorption, Klinkenberg effect, capillary pressure, and fracture deformation. In this study, all the numerical examples are 2D, and the gravity effect is neglected in these simulations. In addition, we assume there is no oil phase in the shale reservoirs, thus the gas/water two-phase model is used to simulate the flow in these reservoirs.

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Numerical Simulation Study on Seepage Theory of a Multi-Section Fractured Horizontal Well in Shale Gas Reservoirs Based on Multi-Scale Flow Mechanisms

Energies ◽

10.3390/en11092329 ◽

2018 ◽

Vol 11 (9) ◽

pp. 2329 ◽

Cited By ~ 6

Author(s):

Chao Tang ◽

Xiaofan Chen ◽

Zhimin Du ◽

Ping Yue ◽

Jiabao Wei

Keyword(s):

Shale Gas ◽

Large Scale ◽

Gas Diffusion ◽

Gas Production ◽

Hydraulic Fractures ◽

Klinkenberg Effect ◽

Stimulated Reservoir Volume ◽

Multi Scale ◽

Reservoir Volume ◽

Flow Mechanisms

Aimed at the multi-scale fractures for stimulated reservoir volume (SRV)-fractured horizontal wells in shale gas reservoirs, a mathematical model of unsteady seepage is established, which considers the characteristics of a dual media of matrix and natural fractures as well as flow in the large-scale hydraulic fractures, based on a discrete-fracture model. Multi-scale flow mechanisms, such as gas desorption, the Klinkenberg effect, and gas diffusion are taken into consideration. A three-dimensional numerical model based on the finite volume method is established, which includes the construction of spatial discretization, calculation of average pressure gradient, and variable at interface, etc. Some related processing techniques, such as boundedness processing upstream and downstream of grid flow, was used to limit non-physical oscillation at large-scale hydraulic fracture interfaces. The sequential solution is performed to solve the pressure equations of matrix, natural, and large-scale hydraulic fractures. The production dynamics and pressure distribution of a multi-section fractured horizontal well in a shale gas reservoir are calculated. Results indicate that, with the increase of the Langmuir volume, the average formation pressure decreases at a slow rate. Simultaneously, the initial gas production and the contribution ratio of the desorbed gas increase. With the decrease of the pore size of the matrix, gas diffusion and the Klinkenberg effect have a greater impact on shale gas production. By changing the fracture half-length and the number of fractured sections, we observe that the production process can not only pursue the long fractures or increase the number of fractured sections, but also should optimize the parameters such as the perforation position, cluster spacing, and fracturing sequence. The stimulated reservoir volume can effectively control the shale reservoir.

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History Matching and Forecast of Shale Gas Production Considering Hydraulic Fracture Closure

Energies ◽

10.3390/en12091634 ◽

2019 ◽

Vol 12 (9) ◽

pp. 1634 ◽

Cited By ~ 1

Author(s):

Juhyun Kim ◽

Youngjin Seo ◽

Jihoon Wang ◽

Youngsoo Lee

Keyword(s):

Shale Gas ◽

Hydraulic Fracture ◽

History Matching ◽

Gas Flow ◽

Fluid Pressure ◽

Gas Production ◽

Hydraulic Fractures ◽

Gas Reservoirs ◽

Shale Gas Reservoirs ◽

Fracture Closure

Most shale gas reservoirs have extremely low permeability. Predicting their fluid transport characteristics is extremely difficult due to complex flow mechanisms between hydraulic fractures and the adjacent rock matrix. Recently, studies adopting the dynamic modeling approach have been proposed to investigate the shape of the flow regime between induced and natural fractures. In this study, a production history matching was performed on a shale gas reservoir in Canada’s Horn River basin. Hypocenters and densities of the microseismic signals were used to identify the hydraulic fracture distributions and the stimulated reservoir volume. In addition, the fracture width decreased because of fluid pressure reduction during production, which was integrated with the dynamic permeability change of the hydraulic fractures. We also incorporated the geometric change of hydraulic fractures to the 3D reservoir simulation model and established a new shale gas modeling procedure. Results demonstrate that the accuracy of the predictions for shale gas flow improved. We believe that this technique will enrich the community’s understanding of fluid flows in shale gas reservoirs.

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A FRACTAL MODEL FOR GAS APPARENT PERMEABILITY IN MICROFRACTURES OF TIGHT/SHALE RESERVOIRS

Fractals ◽

10.1142/s0218348x17500360 ◽

2017 ◽

Vol 25 (03) ◽

pp. 1750036 ◽

Cited By ~ 11

Author(s):

SHIFANG WANG ◽

TAO WU ◽

XIUYING CAO ◽

QIUSHA ZHENG ◽

MIN AI

Keyword(s):

Fractal Dimension ◽

Flow Rate ◽

Molecular Diffusion ◽

Ambient Pressure ◽

Fractal Theory ◽

Fractal Model ◽

Gas Production ◽

Apparent Permeability ◽

Microstructural Parameters ◽

Shale Reservoirs

The investigation of gas transport in microfractures of tight/shale reservoirs can provide potential applications in predicting shale gas production rates. In this paper, analytical expressions for flow rate and apparent permeability are derived based on the fractal theory and the superposition of convection and molecular diffusion transfer. The proposed model relates the flow rate and apparent permeability to the microstructural parameters of tight/shale reservoirs, gas properties, the ambient pressure as well as temperature. The model predictions from the present model are compared with existing experimental data sets and are found to be consistent with existing experimental measurements. The effects of microstructural parameters of tight/shale reservoirs on apparent permeability are also investigated. The results show that apparent permeability increases with temperature, the pore area fractal dimension, the porosity as well as the maximum microfracture width and decreases with the tortuosity fractal dimension and the mean pressure.

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Gas Multiple Flow Mechanisms and Apparent Permeability Evaluation in Shale Reservoirs

Sustainability ◽

10.3390/su11072114 ◽

2019 ◽

Vol 11 (7) ◽

pp. 2114 ◽

Cited By ~ 6

Author(s):

Xuelei Feng ◽

Fengshan Ma ◽

Haijun Zhao ◽

Gang Liu ◽

Jie Guo

Keyword(s):

Pore Size ◽

Gas Flow ◽

Knudsen Diffusion ◽

Stress Sensitivity ◽

Gas Production ◽

Apparent Permeability ◽

Matrix Shrinkage ◽

Gas Seepage ◽

Flow Mechanisms ◽

Shale Reservoirs

Gas flow mechanisms and apparent permeability are important factors for predicating gas production in shale reservoirs. In this study, an apparent permeability model for describing gas multiple flow mechanisms in nanopores is developed and incorporated into the COMSOL solver. In addition, a dynamic permeability equation is proposed to analyze the effects of matrix shrinkage and stress sensitivity. The results indicate that pore size enlargement increases gas seepage capacity of a shale reservoir. Compared to conventional reservoirs, the ratio of apparent permeability to Darcy permeability is higher by about 1–2 orders of magnitude in small pores (1–10 nm) and at low pressures (0–5 MPa) due to multiple flow mechanisms. Flow mechanisms mainly include surface diffusion, Knudsen diffusion, and skip flow. Its weight is affected by pore size, reservoir pressure, and temperature, especially pore size ranging from 1 nm to 5 nm and reservoir pressures below 5 MPa. The combined effects of matrix shrinkage and stress sensitivity induce nanopores closure. Therefore, permeability declines about 1 order of magnitude compare to initial apparent permeability. The results also show that permeability should be adjusted during gas production to ensure a better accuracy.

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Numerical Investigation of Water Blockage in Secondary Fractures and Apparent Permeability Modeling in Shale Gas Production

Proceedings of the 7th Unconventional Resources Technology Conference ◽

10.15530/urtec-2019-592 ◽

2019 ◽

Author(s):

Chuanyao Zhong ◽

Juliana Y. Leung

Keyword(s):

Numerical Investigation ◽

Shale Gas ◽

Gas Production ◽

Apparent Permeability ◽

Permeability Modeling ◽

Secondary Fractures

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NANOSCALE PORE SIZE DISTRIBUTION EFFECTS ON GAS PRODUCTION FROM FRACTAL SHALE ROCKS

Fractals ◽

10.1142/s0218348x19501421 ◽

2019 ◽

Vol 27 (08) ◽

pp. 1950142

Author(s):

JINZE XU ◽

KELIU WU ◽

RAN LI ◽

ZANDONG LI ◽

JING LI ◽

...

Keyword(s):

Fractal Dimension ◽

Pore Size Distribution ◽

Pore Size ◽

Size Distribution ◽

Gas Transport ◽

Gas Production ◽

Lower Sensitivity ◽

Apparent Permeability ◽

Transport Efficiency ◽

Nanoscale Pore

Effect of nanoscale pore size distribution (PSD) on shale gas production is one of the challenges to be addressed by the industry. An improved approach to study multi-scale real gas transport in fractal shale rocks is proposed to bridge nanoscale PSD and gas filed production. This approach is well validated with field tests. Results indicate the gas production is underestimated without considering a nanoscale PSD. A PSD with a larger fractal dimension in pore size and variance yields a higher fraction of large pores; this leads to a better gas transport capacity; this is owing to a higher free gas transport ratio. A PSD with a smaller fractal dimension yields a lower cumulative gas production; this is because a smaller fractal dimension results in the reduction of gas transport efficiency. With an increase in the fractal dimension in pore size and variance, an apparent permeability-shifting effect is less obvious, and the sensitivity of this effect to a nanoscale PSD is also impaired. Higher fractal dimensions and variances result in higher cumulative gas production and a lower sensitivity of gas production to a nanoscale PSD, which is due to a better gas transport efficiency. The shale apparent permeability-shifting effect to nanoscale is more sensitive to a nanoscale PSD under a higher initial reservoir pressure, which makes gas production more sensitive to a nanoscale PSD. The findings of this study can help to better understand the influence of a nanoscale PSD on gas flow capacity and gas production.

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High-Resolution and Multimaterial Fracture Productivity Calculator for the Successful Design of Channel Fracturing Jobs

10.2118/206654-ms ◽

2021 ◽

Author(s):

Dimitry Chuprakov ◽

Ludmila Belyakova ◽

Ivan Glaznev ◽

Aleksandra Peshcherenko

Keyword(s):

High Resolution ◽

Effective Conductivity ◽

Productivity Index ◽

Hydraulic Fractures ◽

Total Production ◽

Fracture Conductivity ◽

Hindered Settling ◽

Accurate Evaluation ◽

Skin Factor ◽

Fracture Closure

Abstract We developed a high-resolution fracture productivity calculator to enable fast and accurate evaluation of hydraulic fractures modeled using a fine-scale 2D simulation of material placement. Using an example of channel fracturing treatments, we show how the productivity index, effective fracture conductivity, and skin factor are sensitive to variations in pumping schedule design and pulsing strategy. We perform fracturing simulations using an advanced high-resolution multiphysics model that includes coupled 2D hydrodynamics with geomechanics (pseudo-3D, or P3D, model), 2D transport of materials with tracking temperature exposure history, in-situ kinetics, and a hindered settling model, which includes the effect of fibers. For all simulated fracturing treatments, we accurately solve a problem of 3D planar fracture closure on heterogenous spatial distribution of solids, estimate 2D profiles of fracture width and stresses applied to proppants, and, as a result, obtain the complex and heterogenous shape of fracture conductivity with highly conductive cells owing to the presence of channels. Then, we also evaluate reservoir fluid inflows from a reservoir to fracture walls and further along a fracture to limited-size wellbore perforations. Solution of a productivity problem at the finest scale allows us to accurately evaluate key productivity characteristics: productivity index, dimensional and dimensionless effective conductivity, skin factor, and folds of increase, as well as the total production rate at any day and for any pressure drawdown in a well during well production life. We develop a workflow to understand how productivity of a fracture depends on variation of the pumping schedule and facilitate taking appropriate decisions about the best job design. The presented workflow gives insight into how new computationally efficient methods can enable fast, convenient, and accurate evaluation of the material placement design for maximum production with cost-saving channel fracturing technology.

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