The Experts below are selected from a list of 234 Experts worldwide ranked by ideXlab platform

J J K Daemen - One of the best experts on this subject based on the ideXlab platform.

  • determination of the maximum allowable gas Pressure for an underground gas storage salt cavern a case study of jintan china
    Journal of rock mechanics and geotechnical engineering, 2019
    Co-Authors: Tongtao Wang, Chunhe Yang, Jianjun Li, Gang Jing, Qingqing Zhang, J J K Daemen
    Abstract:

    Abstract Increasing the allowable gas Pressure of underground gas storage (UGS) is one of the most effective methods to increase its working gas capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture Breakdown Pressure. Based on the test results, the maximum allowable gas Pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable gas Pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating gas penetration failure and gas seepage are proposed. Results show that the maximum allowable gas Pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum gas Pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum gas Pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable gas Pressure are reliable.

  • Determination of the maximum allowable gas Pressure for an underground gas storage salt cavern – A case study of Jintan, China
    Elsevier, 2019
    Co-Authors: Tongtao Wang, Chunhe Yang, Gang Jing, Qingqing Zhang, J J K Daemen
    Abstract:

    Increasing the allowable gas Pressure of underground gas storage (UGS) is one of the most effective methods to increase its working gas capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture Breakdown Pressure. Based on the test results, the maximum allowable gas Pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable gas Pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating gas penetration failure and gas seepage are proposed. Results show that the maximum allowable gas Pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum gas Pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum gas Pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable gas Pressure are reliable. Keywords: Underground gas storage (UGS) salt cavern, In situ stress testing, Maximum gas Pressure, Gas penetration failure, Microseismic monitorin

Jian Zhou - One of the best experts on this subject based on the ideXlab platform.

  • influence of grain size heterogeneity and in situ stress on the hydraulic fracturing process by pfc2d modeling
    Energies, 2018
    Co-Authors: Jian Zhou, Luqing Zhang
    Abstract:

    A modified fluid-mechanically coupled algorithm in PFC2D was adopted in this article to study the influence of grain size heterogeneity and in-situ stress on hydraulic fracturing behavior. Simulated results showed that the in-situ stress and grain size heterogeneity significantly affect the initiation, growth, and spatial distribution of the hydraulic fractures: (1) the initiation and Breakdown Pressure are gradually reduced with the increase of the grain size heterogeneity; (2) with increased in-situ stress, the initiation and Breakdown Pressure increase, and the reduction effect of grain size heterogeneity on the Breakdown Pressure becomes more obvious; (3) in grain size homogeneous rock, the initiation Pressure decreases with increasing in-situ stress ratio, however, the initiation Pressure of grain size heterogeneous rock is almost unaffected by the in-situ stress ratio; (4) The in-situ stress ratio and grain size heterogeneity affect the spatial distribution of hydraulic fractures simultaneously. When the in-situ stress ratio is larger than 1, the hydraulic fractures propagate substantially along the direction of the maximum principal stress. When the in-situ stress ratio is 1, the initiation position and extension direction of hydraulic fractures are random and complex fracture networks can easily develop in a grain size homogeneous model.

  • numerical investigation of fluid driven near borehole fracture propagation in laminated reservoir rock using pfc2d
    Journal of Natural Gas Science and Engineering, 2016
    Co-Authors: Jian Zhou, Luqing Zhang, Zhejun Pan, Zhenhua Han
    Abstract:

    Abstract Hydraulic fracturing is a useful tool for enhancing permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration using high-Pressure injection of a fracturing fluid into tight reservoir rocks. Mechanisms of fluid injection-induced fracture initiation and propagation should be well understood to take full advantage of hydraulic fracturing. In this paper, hydraulic fracturing modeling work was developed using discrete particle modeling based on two-dimensional particle flow code (PFC2D). Firstly, the developed model is validated against the analytical solutions of the Breakdown Pressure for the hydraulic fracturing process under varied in-situ stress conditions. Secondly, the model is tested using the microscopic parameters optimized from laboratory Uniaxial Compressive Test for laminated reservoir rock. Lastly, a series of hydraulic fracturing simulation work was performed to study the influence of weak layers, in-situ stress ratio, fluid injection rate and fluid viscosity on the borehole Pressure history, the geometry of hydraulic fractures and the pore-Pressure field. It is found that the hydraulic fracture propagation in laminated reservoir is controlled by both in situ stress state and strength anisotropy of the reservoir rock. With fluid injection rate increasing, higher Breakdown Pressure is required for fracture propagation and complex fracture geometry will develop. Furthermore, low viscosity fluid can more easily penetrate from the borehole into the surrounding rock, causing a reduction of the effective stress and leading to a lower Breakdown Pressure. Moreover, the geometry of the fractures is found to be sensitive to the fluid viscosity, and the major fractures propagate more easily along the maximum principle stress direction.

  • numerical modeling and investigation of fluid driven fracture propagation in reservoirs based on a modified fluid mechanically coupled model in two dimensional particle flow code
    Energies, 2016
    Co-Authors: Jian Zhou, Luqing Zhang, Anika Braun, Zhenhua Han
    Abstract:

    Hydraulic fracturing is a useful tool for enhancing rock mass permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration by the high-Pressure injection of a fracturing fluid into tight reservoir rocks. Although significant advances have been made in hydraulic fracturing theory, experiments, and numerical modeling, when it comes to the complexity of geological conditions knowledge is still limited. Mechanisms of fluid injection-induced fracture initiation and propagation should be better understood to take full advantage of hydraulic fracturing. This paper presents the development and application of discrete particle modeling based on two-dimensional particle flow code (PFC 2D ). Firstly, it is shown that the modeled value of the Breakdown Pressure for the hydraulic fracturing process is approximately equal to analytically calculated values under varied in situ stress conditions. Furthermore, a series of simulations for hydraulic fracturing in competent rock was performed to examine the influence of the in situ stress ratio, fluid injection rate, and fluid viscosity on the borehole Pressure history, the geometry of hydraulic fractures, and the pore-Pressure field, respectively. It was found that the hydraulic fractures in an isotropic medium always propagate parallel to the orientation of the maximum principal stress. When a high fluid injection rate is used, higher Breakdown Pressure is needed for fracture propagation and complex geometries of fractures can develop. When a low viscosity fluid is used, fluid can more easily penetrate from the borehole into the surrounding rock, which causes a reduction of the effective stress and leads to a lower Breakdown Pressure. Moreover, the geometry of the fractures is not particularly sensitive to the fluid viscosity in the approximate isotropic model.

Luqing Zhang - One of the best experts on this subject based on the ideXlab platform.

  • influence of grain size heterogeneity and in situ stress on the hydraulic fracturing process by pfc2d modeling
    Energies, 2018
    Co-Authors: Jian Zhou, Luqing Zhang
    Abstract:

    A modified fluid-mechanically coupled algorithm in PFC2D was adopted in this article to study the influence of grain size heterogeneity and in-situ stress on hydraulic fracturing behavior. Simulated results showed that the in-situ stress and grain size heterogeneity significantly affect the initiation, growth, and spatial distribution of the hydraulic fractures: (1) the initiation and Breakdown Pressure are gradually reduced with the increase of the grain size heterogeneity; (2) with increased in-situ stress, the initiation and Breakdown Pressure increase, and the reduction effect of grain size heterogeneity on the Breakdown Pressure becomes more obvious; (3) in grain size homogeneous rock, the initiation Pressure decreases with increasing in-situ stress ratio, however, the initiation Pressure of grain size heterogeneous rock is almost unaffected by the in-situ stress ratio; (4) The in-situ stress ratio and grain size heterogeneity affect the spatial distribution of hydraulic fractures simultaneously. When the in-situ stress ratio is larger than 1, the hydraulic fractures propagate substantially along the direction of the maximum principal stress. When the in-situ stress ratio is 1, the initiation position and extension direction of hydraulic fractures are random and complex fracture networks can easily develop in a grain size homogeneous model.

  • numerical investigation of fluid driven near borehole fracture propagation in laminated reservoir rock using pfc2d
    Journal of Natural Gas Science and Engineering, 2016
    Co-Authors: Jian Zhou, Luqing Zhang, Zhejun Pan, Zhenhua Han
    Abstract:

    Abstract Hydraulic fracturing is a useful tool for enhancing permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration using high-Pressure injection of a fracturing fluid into tight reservoir rocks. Mechanisms of fluid injection-induced fracture initiation and propagation should be well understood to take full advantage of hydraulic fracturing. In this paper, hydraulic fracturing modeling work was developed using discrete particle modeling based on two-dimensional particle flow code (PFC2D). Firstly, the developed model is validated against the analytical solutions of the Breakdown Pressure for the hydraulic fracturing process under varied in-situ stress conditions. Secondly, the model is tested using the microscopic parameters optimized from laboratory Uniaxial Compressive Test for laminated reservoir rock. Lastly, a series of hydraulic fracturing simulation work was performed to study the influence of weak layers, in-situ stress ratio, fluid injection rate and fluid viscosity on the borehole Pressure history, the geometry of hydraulic fractures and the pore-Pressure field. It is found that the hydraulic fracture propagation in laminated reservoir is controlled by both in situ stress state and strength anisotropy of the reservoir rock. With fluid injection rate increasing, higher Breakdown Pressure is required for fracture propagation and complex fracture geometry will develop. Furthermore, low viscosity fluid can more easily penetrate from the borehole into the surrounding rock, causing a reduction of the effective stress and leading to a lower Breakdown Pressure. Moreover, the geometry of the fractures is found to be sensitive to the fluid viscosity, and the major fractures propagate more easily along the maximum principle stress direction.

  • numerical modeling and investigation of fluid driven fracture propagation in reservoirs based on a modified fluid mechanically coupled model in two dimensional particle flow code
    Energies, 2016
    Co-Authors: Jian Zhou, Luqing Zhang, Anika Braun, Zhenhua Han
    Abstract:

    Hydraulic fracturing is a useful tool for enhancing rock mass permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration by the high-Pressure injection of a fracturing fluid into tight reservoir rocks. Although significant advances have been made in hydraulic fracturing theory, experiments, and numerical modeling, when it comes to the complexity of geological conditions knowledge is still limited. Mechanisms of fluid injection-induced fracture initiation and propagation should be better understood to take full advantage of hydraulic fracturing. This paper presents the development and application of discrete particle modeling based on two-dimensional particle flow code (PFC 2D ). Firstly, it is shown that the modeled value of the Breakdown Pressure for the hydraulic fracturing process is approximately equal to analytically calculated values under varied in situ stress conditions. Furthermore, a series of simulations for hydraulic fracturing in competent rock was performed to examine the influence of the in situ stress ratio, fluid injection rate, and fluid viscosity on the borehole Pressure history, the geometry of hydraulic fractures, and the pore-Pressure field, respectively. It was found that the hydraulic fractures in an isotropic medium always propagate parallel to the orientation of the maximum principal stress. When a high fluid injection rate is used, higher Breakdown Pressure is needed for fracture propagation and complex geometries of fractures can develop. When a low viscosity fluid is used, fluid can more easily penetrate from the borehole into the surrounding rock, which causes a reduction of the effective stress and leads to a lower Breakdown Pressure. Moreover, the geometry of the fractures is not particularly sensitive to the fluid viscosity in the approximate isotropic model.

Tongtao Wang - One of the best experts on this subject based on the ideXlab platform.

  • determination of the maximum allowable gas Pressure for an underground gas storage salt cavern a case study of jintan china
    Journal of rock mechanics and geotechnical engineering, 2019
    Co-Authors: Tongtao Wang, Chunhe Yang, Jianjun Li, Gang Jing, Qingqing Zhang, J J K Daemen
    Abstract:

    Abstract Increasing the allowable gas Pressure of underground gas storage (UGS) is one of the most effective methods to increase its working gas capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture Breakdown Pressure. Based on the test results, the maximum allowable gas Pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable gas Pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating gas penetration failure and gas seepage are proposed. Results show that the maximum allowable gas Pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum gas Pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum gas Pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable gas Pressure are reliable.

  • Determination of the maximum allowable gas Pressure for an underground gas storage salt cavern – A case study of Jintan, China
    Elsevier, 2019
    Co-Authors: Tongtao Wang, Chunhe Yang, Gang Jing, Qingqing Zhang, J J K Daemen
    Abstract:

    Increasing the allowable gas Pressure of underground gas storage (UGS) is one of the most effective methods to increase its working gas capacity. In this context, hydraulic fracturing tests are implemented on the target formation for the UGS construction of Jintan salt caverns, China, in order to obtain the minimum principal in situ stress and the fracture Breakdown Pressure. Based on the test results, the maximum allowable gas Pressure of the Jintan UGS salt cavern is calibrated. To determine the maximum allowable gas Pressure, KING-1 and KING-2 caverns are used as examples. A three-dimensional (3D) geomechanical model is established based on the sonar data of the two caverns with respect to the features of the target formation. New criteria for evaluating gas penetration failure and gas seepage are proposed. Results show that the maximum allowable gas Pressure of the Jintan UGS salt cavern can be increased from 17 MPa to 18 MPa (i.e. a gradient of about 18 kPa/m at the casing shoe depth). Based on numerical results, a field test with increasing maximum gas Pressure to 18 MPa has been carried out in KING-1 cavern. Microseismic monitoring has been conducted during the test to evaluate the safety of the rock mass around the cavern. Field monitoring data show that KING-1 cavern is safe globally when the maximum gas Pressure is increased from 17 MPa to 18 MPa. This shows that the geomechanical model and criteria proposed in this context for evaluating the maximum allowable gas Pressure are reliable. Keywords: Underground gas storage (UGS) salt cavern, In situ stress testing, Maximum gas Pressure, Gas penetration failure, Microseismic monitorin

Zhenhua Han - One of the best experts on this subject based on the ideXlab platform.

  • numerical investigation of fluid driven near borehole fracture propagation in laminated reservoir rock using pfc2d
    Journal of Natural Gas Science and Engineering, 2016
    Co-Authors: Jian Zhou, Luqing Zhang, Zhejun Pan, Zhenhua Han
    Abstract:

    Abstract Hydraulic fracturing is a useful tool for enhancing permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration using high-Pressure injection of a fracturing fluid into tight reservoir rocks. Mechanisms of fluid injection-induced fracture initiation and propagation should be well understood to take full advantage of hydraulic fracturing. In this paper, hydraulic fracturing modeling work was developed using discrete particle modeling based on two-dimensional particle flow code (PFC2D). Firstly, the developed model is validated against the analytical solutions of the Breakdown Pressure for the hydraulic fracturing process under varied in-situ stress conditions. Secondly, the model is tested using the microscopic parameters optimized from laboratory Uniaxial Compressive Test for laminated reservoir rock. Lastly, a series of hydraulic fracturing simulation work was performed to study the influence of weak layers, in-situ stress ratio, fluid injection rate and fluid viscosity on the borehole Pressure history, the geometry of hydraulic fractures and the pore-Pressure field. It is found that the hydraulic fracture propagation in laminated reservoir is controlled by both in situ stress state and strength anisotropy of the reservoir rock. With fluid injection rate increasing, higher Breakdown Pressure is required for fracture propagation and complex fracture geometry will develop. Furthermore, low viscosity fluid can more easily penetrate from the borehole into the surrounding rock, causing a reduction of the effective stress and leading to a lower Breakdown Pressure. Moreover, the geometry of the fractures is found to be sensitive to the fluid viscosity, and the major fractures propagate more easily along the maximum principle stress direction.

  • numerical modeling and investigation of fluid driven fracture propagation in reservoirs based on a modified fluid mechanically coupled model in two dimensional particle flow code
    Energies, 2016
    Co-Authors: Jian Zhou, Luqing Zhang, Anika Braun, Zhenhua Han
    Abstract:

    Hydraulic fracturing is a useful tool for enhancing rock mass permeability for shale gas development, enhanced geothermal systems, and geological carbon sequestration by the high-Pressure injection of a fracturing fluid into tight reservoir rocks. Although significant advances have been made in hydraulic fracturing theory, experiments, and numerical modeling, when it comes to the complexity of geological conditions knowledge is still limited. Mechanisms of fluid injection-induced fracture initiation and propagation should be better understood to take full advantage of hydraulic fracturing. This paper presents the development and application of discrete particle modeling based on two-dimensional particle flow code (PFC 2D ). Firstly, it is shown that the modeled value of the Breakdown Pressure for the hydraulic fracturing process is approximately equal to analytically calculated values under varied in situ stress conditions. Furthermore, a series of simulations for hydraulic fracturing in competent rock was performed to examine the influence of the in situ stress ratio, fluid injection rate, and fluid viscosity on the borehole Pressure history, the geometry of hydraulic fractures, and the pore-Pressure field, respectively. It was found that the hydraulic fractures in an isotropic medium always propagate parallel to the orientation of the maximum principal stress. When a high fluid injection rate is used, higher Breakdown Pressure is needed for fracture propagation and complex geometries of fractures can develop. When a low viscosity fluid is used, fluid can more easily penetrate from the borehole into the surrounding rock, which causes a reduction of the effective stress and leads to a lower Breakdown Pressure. Moreover, the geometry of the fractures is not particularly sensitive to the fluid viscosity in the approximate isotropic model.