Coupled Thermo-Hydro-Mechanical-Chemical Modeling of Water Leak-Off Process during Hydraulic Fracturing in Shale Gas Reservoirs

Wang, Fei; Zhang, Yichi; Zhang, Shicheng

doi:10.3390/en10121960

Cited by 12 publications

(12 citation statements)

References 59 publications

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“…The following fluid flow equations for water and gas in hydraulically fractured shale reservoirs are based on the above-mentioned physical model, which was developed by Wang et al 43 for fracturing fluid leakoff simulation. Here, flowback simulation is applied.…”

Section: Mathematical Modelmentioning

confidence: 99%

“…In eq 1, q l Ff stands for the fluid flux between F and f (g/cm 3 ·s), which can be calculated by the following equationwhere p l f stands for the fluid pressure in f (10 –1 MPa), α 1 stands for the shape factor between F and m (cm –2 ), and the calculation equation can be referred to a previous study. 43…”

Section: Mathematical Modelmentioning

confidence: 99%

“…Because of the limitation of the flowback models, the results from flowback data analysis cannot provide fracture network parameters. In this study, an integrated hydro-mechanical–chemical model (HMC) developed by Wang et al 43 is used to simulate fracturing fluid flowing back after the hydraulic fracturing treatment. Two field cases from the Longmaxi Formation, Southern Sichuan Basin, China, are investigated with the HMC model-based flowback history matching method.…”

Section: Introductionmentioning

confidence: 99%

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Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Liu

Yandong

et al. 2019

ACS Omega

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Fracture characterization is necessary to evaluate fracturing operations and forecast well performance. However, it is challenging to quantitatively characterize the complex fracture network in shale gas reservoirs because of the unknown density and reactivation of natural fractures. The flowback water transients can provide useful information about the complexity of the fracture network after the fracturing operations. In this paper, a mathematical model for modeling fracturing fluid flowback of hydraulically fractured shale gas wells is established. This proposed model characterizes the flow of water and gas in a hydraulic fracture-induced natural fracture–shale matrix system. Hydraulic, capillary, and osmotic convections; gas adsorption; and natural fracture closure are considered in this model. Flowback simulation of a hydraulically fractured shale gas well is conducted using the developed numerical simulator, and the water/gas transients between hydraulic fractures, natural fractures, and matrix are obtained. Finally, two field cases from the Longmaxi Formation, Southern Sichuan Basin, China, are used for comparison of the flowback data with the model results. The good match of the two water transients provides a group of fracture network parameters, that is, the effective length and conductivity of main hydraulic fractures and the density of induced natural fractures. The proposed model for describing the flowback process and its meaningful relationship with the fracture–network complexity provides an alternative approach for post-stimulation evaluation.

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Section: Mathematical Modelmentioning

confidence: 99%

Section: Mathematical Modelmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

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Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Liu

Yandong

et al. 2019

ACS Omega

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“…Horizontal well and multistage fracturing are the two key techniques for shale gas development, by creating complex fracture networks within tight formations [1][2][3][4][5]. Due to the fact that tens of thousands of cubic meters of fracturing fluid are pumped into the downholes of shale gas wells and injected into the matrix of shale reservoirs, geostatic stress can be changed due to the elastic response of the rock mass to hydraulic fracturing.…”

Section: Introductionmentioning

confidence: 99%

Mechanisms and Influence of Casing Shear Deformation near the Casing Shoe, Based on MFC Surveys during Multistage Fracturing in Shale Gas Wells in Canada

Liu

et al. 2019

Energies

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Casing shear deformation has become a serious problem in the development of shale gas fields, which is believed to be related to fault slipping caused by multistage fracturing, and the evaluation of the reduction of a casing’s inner diameter is key. Although many fault slipping models have been published, most of them have not taken the fluid-solid-heat coupling effect into account, and none of the models could be used to calculate the reduction of a casing’s inner diameter. In this paper, a new 3D finite element model was developed to simulate the progress of fault slipping, taking the fluid-solid-heat coupling effect during fracturing into account. For the purpose of increasing calculation accuracy, the elastoplastic constitutive relations of materials were considered, and the solid-shell elements technique was used. The reduction of the casing’s inner diameter along the axis was calculated and the calculation results were compared with the measurement results of multi-finger caliper (MFC) surveys. A sensitivity analysis was conducted, and the influences of slip distance, casing internal pressure, thickness of production and intermediate casing, and the mechanical parameters of cement sheath on the reduction of a casing’s inner diameter in the deformed segment were analyzed. The numerical analysis results showed that decreasing the slip distance, maintaining high pressure, decreasing the Poisson ratio of cement sheath, and increasing casing thickness were beneficial to protect the integrity of the casing. The numerical simulation results were verified by comparison to the shape of MFC measurement results, and had an accuracy up to 90.17%. Results from this study are expected to provide a better understanding of casing shear deformation, and a prediction method of a casing’s inner diameter after fault slipping in multistage fracturing wells.

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“…Tight reservoirs are those reservoirs that are characterized by a low-permeability (i.e., less than 0.5 mD), they are either carbonate or sandstone reservoirs [12,13]. Problems that are associated with tight gas production in drilling or hydraulic fracturing operations include aqueous phase trapping, natural fractures (fluid leak-off), folding and faulting (making the prediction of fracture pressure difficult), and fluid incompatibility with the formation [14]. Water blockage or aqueous phase trapping (APT) is a serious problem in tight formations among others [15][16][17].…”

Section: Introductionmentioning

confidence: 99%

Development of Chelating Agent-Based Polymeric Gel System for Hydraulic Fracturing

et al. 2018

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Hydraulic Fracturing is considered to be one of the most important stimulation methods. Hydraulic Fracturing is carried out by inducing fractures in the formation to create conductive pathways for the flow of hydrocarbon. The pathways are kept open either by using proppant or by etching the fracture surface using acids. A typical fracturing fluid usually consists of a gelling agent (polymers), cross-linkers, buffers, clay stabilizers, gel stabilizers, biocide, surfactants, and breakers mixed with fresh water. The numerous additives are used to prevent damage resulting from such operations, or better yet, enhancing it beyond just the aim of a fracturing operation. This study introduces a new smart fracturing fluid system that can be either used for proppant fracturing (high pH) or acid fracturing (low pH) operations in sandstone formations. The fluid system consists of glutamic acid diacetic acid (GLDA) that can replace several additives, such as cross-linker, breaker, biocide, and clay stabilizer. GLDA is also a surface-active fluid that will reduce the interfacial tension eliminating the water-blockage effect. GLDA is compatible and stable with sea water, which is advantageous over the typical fracturing fluid. It is also stable in high temperature reservoirs (up to 300 °F) and it is also environmentally friendly and readily biodegradable. The new fracturing fluid formulation can withstand up to 300 °F of formation temperature and is stable for about 6 h under high shearing rates (511 s−1). The new fracturing fluid formulation breaks on its own and the delay time or the breaking time can be controlled with the concentrations of the constituents of the fluid (GLDA or polymer). Coreflooding experiments were conducted using Scioto and Berea sandstone cores to evaluate the effectiveness of the developed fluid. The flooding experiments were in reasonable conformance with the rheological properties of the developed fluid regarding the thickening and breaking time, as well as yielding high return permeability.

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Coupled Thermo-Hydro-Mechanical-Chemical Modeling of Water Leak-Off Process during Hydraulic Fracturing in Shale Gas Reservoirs

Cited by 12 publications

References 59 publications

Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Fracture Characterization Using Flowback Water Transients from Hydraulically Fractured Shale Gas Wells

Mechanisms and Influence of Casing Shear Deformation near the Casing Shoe, Based on MFC Surveys during Multistage Fracturing in Shale Gas Wells in Canada

Development of Chelating Agent-Based Polymeric Gel System for Hydraulic Fracturing

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