The Experts below are selected from a list of 360 Experts worldwide ranked by ideXlab platform
Virendra M Puri - One of the best experts on this subject based on the ideXlab platform.
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a fully coupled geomechanics and fluid flow model for proppant pack failure and Fracture conductivity damage analysis
Journal of Natural Gas Science and Engineering, 2016Co-Authors: John Yilin Wang, Virendra M PuriAbstract:Abstract One reason for observed reductions in the conductivity of hydraulic Fractures is failure of the proppant pack. Proppant deformation, crushing, or embedment can decrease the Fracture Width and conductivity. In this paper, the continuity and momentum balance equations were fully coupled to simulate the transient phenomena involving fluid flow through a deformable porous proppant pack. Porous media displacement, water pressure, and gas pressure were derived as primary unknowns. The governing equation was discretized using the finite element method and solved numerically. In this model, the proppant pack and formation rocks were treated as two different types of continuous porous media (Biot type). Proppant deformation, crushing, and embedment could be identified through the geomechanical model, while the damage effects on gas/oil production would be studied through the fluid-flow model. Analysis of proppant deformation and crushing was based on the proppant pack stress–strain behavior. The displacement of the Fracture-formation interface represented both the deformation of proppant and rock solids around Fracture surface. Mohr–Coulomb failure was used as the criterion for proppant crushing. Effects of proppant damage were evaluated on proppant pack porosity and permeability. The model can be applied generally in hydraulically Fractured reservoirs with proper inputs. In this paper, we used a Fractured tight sand gas reservoir as a study case. The pressure distribution as well as proppant pack deformation are illustrated in the paper. Proppant pack mechanical behavior was found to be sensitive to the fluid flow pressure. Proppant near the wellbore has a higher likelihood of being crushed.
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A fully coupled geomechanics and fluid flow model for proppant pack failure and Fracture conductivity damage analysis
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Jiahang Han, John Yilin Wang, Virendra M PuriAbstract:Abstract One reason for observed reductions in the conductivity of hydraulic Fractures is failure of the proppant pack. Proppant deformation, crushing, or embedment can decrease the Fracture Width and conductivity. In this paper, the continuity and momentum balance equations were fully coupled to simulate the transient phenomena involving fluid flow through a deformable porous proppant pack. Porous media displacement, water pressure, and gas pressure were derived as primary unknowns. The governing equation was discretized using the finite element method and solved numerically. In this model, the proppant pack and formation rocks were treated as two different types of continuous porous media (Biot type). Proppant deformation, crushing, and embedment could be identified through the geomechanical model, while the damage effects on gas/oil production would be studied through the fluid-flow model. Analysis of proppant deformation and crushing was based on the proppant pack stress–strain behavior. The displacement of the Fracture-formation interface represented both the deformation of proppant and rock solids around Fracture surface. Mohr–Coulomb failure was used as the criterion for proppant crushing. Effects of proppant damage were evaluated on proppant pack porosity and permeability. The model can be applied generally in hydraulically Fractured reservoirs with proper inputs. In this paper, we used a Fractured tight sand gas reservoir as a study case. The pressure distribution as well as proppant pack deformation are illustrated in the paper. Proppant pack mechanical behavior was found to be sensitive to the fluid flow pressure. Proppant near the wellbore has a higher likelihood of being crushed.
John Yilin Wang - One of the best experts on this subject based on the ideXlab platform.
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a fully coupled geomechanics and fluid flow model for proppant pack failure and Fracture conductivity damage analysis
Journal of Natural Gas Science and Engineering, 2016Co-Authors: John Yilin Wang, Virendra M PuriAbstract:Abstract One reason for observed reductions in the conductivity of hydraulic Fractures is failure of the proppant pack. Proppant deformation, crushing, or embedment can decrease the Fracture Width and conductivity. In this paper, the continuity and momentum balance equations were fully coupled to simulate the transient phenomena involving fluid flow through a deformable porous proppant pack. Porous media displacement, water pressure, and gas pressure were derived as primary unknowns. The governing equation was discretized using the finite element method and solved numerically. In this model, the proppant pack and formation rocks were treated as two different types of continuous porous media (Biot type). Proppant deformation, crushing, and embedment could be identified through the geomechanical model, while the damage effects on gas/oil production would be studied through the fluid-flow model. Analysis of proppant deformation and crushing was based on the proppant pack stress–strain behavior. The displacement of the Fracture-formation interface represented both the deformation of proppant and rock solids around Fracture surface. Mohr–Coulomb failure was used as the criterion for proppant crushing. Effects of proppant damage were evaluated on proppant pack porosity and permeability. The model can be applied generally in hydraulically Fractured reservoirs with proper inputs. In this paper, we used a Fractured tight sand gas reservoir as a study case. The pressure distribution as well as proppant pack deformation are illustrated in the paper. Proppant pack mechanical behavior was found to be sensitive to the fluid flow pressure. Proppant near the wellbore has a higher likelihood of being crushed.
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A fully coupled geomechanics and fluid flow model for proppant pack failure and Fracture conductivity damage analysis
Journal of Natural Gas Science and Engineering, 2016Co-Authors: Jiahang Han, John Yilin Wang, Virendra M PuriAbstract:Abstract One reason for observed reductions in the conductivity of hydraulic Fractures is failure of the proppant pack. Proppant deformation, crushing, or embedment can decrease the Fracture Width and conductivity. In this paper, the continuity and momentum balance equations were fully coupled to simulate the transient phenomena involving fluid flow through a deformable porous proppant pack. Porous media displacement, water pressure, and gas pressure were derived as primary unknowns. The governing equation was discretized using the finite element method and solved numerically. In this model, the proppant pack and formation rocks were treated as two different types of continuous porous media (Biot type). Proppant deformation, crushing, and embedment could be identified through the geomechanical model, while the damage effects on gas/oil production would be studied through the fluid-flow model. Analysis of proppant deformation and crushing was based on the proppant pack stress–strain behavior. The displacement of the Fracture-formation interface represented both the deformation of proppant and rock solids around Fracture surface. Mohr–Coulomb failure was used as the criterion for proppant crushing. Effects of proppant damage were evaluated on proppant pack porosity and permeability. The model can be applied generally in hydraulically Fractured reservoirs with proper inputs. In this paper, we used a Fractured tight sand gas reservoir as a study case. The pressure distribution as well as proppant pack deformation are illustrated in the paper. Proppant pack mechanical behavior was found to be sensitive to the fluid flow pressure. Proppant near the wellbore has a higher likelihood of being crushed.
Xiang Ding - One of the best experts on this subject based on the ideXlab platform.
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modelling of time dependent proppant embedment and its influence on tight gas production
Journal of Natural Gas Science and Engineering, 2020Co-Authors: Xiang Ding, Fan Zhang, Guangqing ZhangAbstract:Abstract Hydraulic fracturing is typically used to exploit underground gas/oil resources. However, most commercial Fracture-design programs and reservoir simulators neglect proppant embedment issues when calculating hydraulic the Fracture Width, and the majority of previous studies regarding proppant embedment treat the reservoir rocks as time-independent materials–elastic or elastoplastic. In this study, the time dependent deformation of tight reservoir rocks is validated through laboratory experiments, and the fractional Maxwell model is utilized to characterize the viscoelastic deformation of tight sandstones. Combining the fractional rheological model with the Hertz contact theory, an analytical model of Fracture Width, which considers the time-dependent embedment depth of proppants, is established. Utilizing this analytical model of Fracture Width, numerical simulations are conducted to study the viscoelastic deformation of tight sandstones on the long-term accumulative production of tight gas. Numerical simulations of a fifteen-year cumulative production tight gas well indicate the long-term gas production, which considers the creep characteristics of a tight sandstone reservoir, experiences a 40 % reduction when compared to the production of a linear elastic reservoir. Therefore, consideration of the viscoelastic characteristics of reservoir rocks to predict the long-term oil/gas production is extremely significant.
A P Peirce - One of the best experts on this subject based on the ideXlab platform.
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Asymptotic Analysis of an Elasticity Equation for a Finger-Like Hydraulic Fracture
2016Co-Authors: A P Peirce, J. I. AdachiAbstract:Abstract We derive a novel integral equation relating the fluid pressure in a finger-like hydraulic Fracture to the Fracture Width. By means of an asymptotic analysis in the small height to length ratio limit we are able to establish the action of the integral operator for receiving points that lie within three distinct regions: (1) an outer expansion region in which the dimensionless pressure is shown to be equal to the dimensionless Width plus a small correction term that involves the second derivative of the Width, which accounts for the nonlocal effects of the integral operator. The leading order term in this expansion is the classic local elasticity equation in the PKN model that is widely used in the oil and gas industry; (2) an inner expansion region close to the Fracture tip within which the action of the elastic integral operator is shown to be the same as that of a finite Hilbert transform associated with a state of plane strain. This result will enable pressure singularities and stress intensity factors to be incorporated into analytic models of these finger-like Fractures in order to model the effect of material toughness; (3) an intermediate region within which the action of the Fredholm integral operator of the first kind is reduced to a second kind operator in which the integral term appears as a small perturbation which is associated with a convergent Neumann series. These results are important fo
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modeling multi scale processes in hydraulic Fracture propagation using the implicit level set algorithm
Computer Methods in Applied Mechanics and Engineering, 2015Co-Authors: A P PeirceAbstract:Abstract In this paper we describe an implicit level set algorithm (ILSA) (Peirce and Detournay, 2008) suitable for modeling multi-scale behavior in planar hydraulic Fractures propagating in three dimensional elastic media. This multi-scale behavior is typically encountered when multiple physical processes compete to determine the location of the Fracture free boundary. Instead of having to match the mesh size to the finest active length scale, or having to re-mesh as the dominant length scales change in space and time, the novel ILSA scheme is able to represent the required multi-scale behavior on a relatively coarse rectangular mesh. This is achieved by using the local front velocity to construct, for each point of a set of control points, a mapping that adaptively identifies the dominant length scale at which the appropriate multi-scale universal asymptotic solution needs to be sampled. Finer-scale behavior is captured in a weak sense by integrating the universal asymptotic solution for the Fracture Width over partially filled tip elements and using these integrals to set the average values of the Widths in all tip elements. The ILSA solution shows good agreement with a multi-scale reference solution comprising a radial solution that transitions from viscosity to toughness dominated propagation regimes. The ILSA scheme is also used to model blade-like hydraulic Fractures that break through stress barriers located symmetrically with respect to the injection point. For the zero toughness case, the ILSA solution shows close agreement to experimental results. The multi-scale ILSA scheme is also used to provide results when the material toughness K I c is non-zero. In this case different parts of the Fracture-free-boundary can be propagating in different regimes. It is hoped that the multi-scale ILSA solutions presented here will form a set of reference results that can be used to benchmark simulators that use a propagation criterion based on only one dissipative process (either toughness or viscosity). The multi-scale ILSA solutions at larger times (for which plane strain conditions develop in vertical cross sections) are compared with and show close agreement to plane strain exact solutions for height-growth and the Fracture Width in vertical cross sections. This comparison provides some measure of the accuracy of the multi-scale ILSA scheme. The multi-scale ILSA solutions are also used to identify the regimes of applicability of pseudo 3D (P3D) approximate solutions. These ILSA solutions can also be used to design improved P3D models.
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an implicit level set method for modeling hydraulically driven Fractures
Computer Methods in Applied Mechanics and Engineering, 2008Co-Authors: A P Peirce, Emmanuel M DetournayAbstract:We describe a novel implicit level set algorithm to locate the free boundary for a propagating hydraulic Fracture. A number of characteristics of the governing equations for hydraulic Fractures and their coupling present considerable challenges for numerical modeling, namely: the degenerate lubrication equation; the hypersingular elastic integral equation; the indeterminate form of the velocity of the unknown Fracture front, which precludes the implementation of established front evolution strategies that require an explicit velocity field; and the computationally prohibitive cost of resolving all the length scales. An implicit algorithm is also necessary for the efficient solution of the stiff evolution equations that involve fully populated matrices associated with the coupled non-local elasticity and degenerate lubrication equations. The implicit level set algorithm that we propose exploits the local tip asymptotic behavior, applicable at the computational length scale, in order to locate the free boundary. Local inversion of this tip asymptotic relation yields the boundary values for the Eikonal equation, whose solution gives the Fracture front location as well as the front velocity field. The efficacy of the algorithm is tested by comparing the level set solution to analytic solutions for hydraulic Fractures propagating in a number of distinct regimes. The level set algorithm is shown to resolve the free boundary problem with first order accuracy. Further it captures the field variables, such as the Fracture Width, with the first order accuracy that is consistent with the piecewise constant discretization that is used.
Guangqing Zhang - One of the best experts on this subject based on the ideXlab platform.
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modelling of time dependent proppant embedment and its influence on tight gas production
Journal of Natural Gas Science and Engineering, 2020Co-Authors: Xiang Ding, Fan Zhang, Guangqing ZhangAbstract:Abstract Hydraulic fracturing is typically used to exploit underground gas/oil resources. However, most commercial Fracture-design programs and reservoir simulators neglect proppant embedment issues when calculating hydraulic the Fracture Width, and the majority of previous studies regarding proppant embedment treat the reservoir rocks as time-independent materials–elastic or elastoplastic. In this study, the time dependent deformation of tight reservoir rocks is validated through laboratory experiments, and the fractional Maxwell model is utilized to characterize the viscoelastic deformation of tight sandstones. Combining the fractional rheological model with the Hertz contact theory, an analytical model of Fracture Width, which considers the time-dependent embedment depth of proppants, is established. Utilizing this analytical model of Fracture Width, numerical simulations are conducted to study the viscoelastic deformation of tight sandstones on the long-term accumulative production of tight gas. Numerical simulations of a fifteen-year cumulative production tight gas well indicate the long-term gas production, which considers the creep characteristics of a tight sandstone reservoir, experiences a 40 % reduction when compared to the production of a linear elastic reservoir. Therefore, consideration of the viscoelastic characteristics of reservoir rocks to predict the long-term oil/gas production is extremely significant.
