Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production
In this work, a triple-porosity, two-phase flow model was established to fill the knowledge gap of previous models focusing on gas production characteristics while ignoring the impacts of water injection. The proposed model considers the water flow in the fracture systems and clay minerals and the g...
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| Main Authors: | , , , , , , |
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| Format: | Article |
| Language: | English |
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Wiley
2021-01-01
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| Series: | Geofluids |
| Online Access: | http://dx.doi.org/10.1155/2021/2637217 |
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| author | Ershe Xu Lingjie Yu Ming Fan Tianyu Chen Zhejun Pan Yuling Tan Guanglei Cui |
| author_facet | Ershe Xu Lingjie Yu Ming Fan Tianyu Chen Zhejun Pan Yuling Tan Guanglei Cui |
| author_sort | Ershe Xu |
| collection | DOAJ |
| description | In this work, a triple-porosity, two-phase flow model was established to fill the knowledge gap of previous models focusing on gas production characteristics while ignoring the impacts of water injection. The proposed model considers the water flow in the fracture systems and clay minerals and the gas flow in the organic matter, inorganic pore, and fracture systems. The proposed model is solved using a finite element approach with COMSOL Multiphysics (Version 5.6) and verified with field data. Then, the evolutions of the intrinsic and relative permeabilities during water injection and gas production are examined. Furthermore, the impacts of water injection time and pressure are investigated. Good verification results are obtained; the goodness-of-fit value is 0.92, indicating that the proposed model can replicate both the water stimulation and the gas production stages. The relative gas permeability declines during water injection but recovers in the gas depletion stage. Furthermore, the intrinsic permeability increases during the water injection stage but decreases during the gas production stage. A higher water injection pressure and longer injection time would enlarge the intrinsic permeability, thus improving flow capacity. However, it would reduce gas relative permeability, thereby hindering gas flow. The shale gas production characteristic is controlled by the two abovementioned competing mechanisms. There exists a perfect combination of water injection pressure and injection time for achieving the maximum profitability of a shale gas well. This work can give a better understanding of the two-phase flow process in shale reservoirs and shed light on the field application of hydraulic fracturing. |
| format | Article |
| id | doaj-art-f91baf1f3a22444f8cde0e0a6626b804 |
| institution | Kabale University |
| issn | 1468-8123 |
| language | English |
| publishDate | 2021-01-01 |
| publisher | Wiley |
| record_format | Article |
| series | Geofluids |
| spelling | doaj-art-f91baf1f3a22444f8cde0e0a6626b8042025-02-03T05:59:58ZengWileyGeofluids1468-81232021-01-01202110.1155/2021/2637217Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas ProductionErshe Xu0Lingjie Yu1Ming Fan2Tianyu Chen3Zhejun Pan4Yuling Tan5Guanglei Cui6Wuxi Research Institute of Petroleum GeologyWuxi Research Institute of Petroleum GeologyWuxi Research Institute of Petroleum GeologyKey Laboratory of Ministry of Education on Safe Mining of Deep Metal MinesKey Laboratory of Continental Shale Hydrocarbon Accumulation and Efficient DevelopmentDepartment of Engineering MechanicsKey Laboratory of Ministry of Education on Safe Mining of Deep Metal MinesIn this work, a triple-porosity, two-phase flow model was established to fill the knowledge gap of previous models focusing on gas production characteristics while ignoring the impacts of water injection. The proposed model considers the water flow in the fracture systems and clay minerals and the gas flow in the organic matter, inorganic pore, and fracture systems. The proposed model is solved using a finite element approach with COMSOL Multiphysics (Version 5.6) and verified with field data. Then, the evolutions of the intrinsic and relative permeabilities during water injection and gas production are examined. Furthermore, the impacts of water injection time and pressure are investigated. Good verification results are obtained; the goodness-of-fit value is 0.92, indicating that the proposed model can replicate both the water stimulation and the gas production stages. The relative gas permeability declines during water injection but recovers in the gas depletion stage. Furthermore, the intrinsic permeability increases during the water injection stage but decreases during the gas production stage. A higher water injection pressure and longer injection time would enlarge the intrinsic permeability, thus improving flow capacity. However, it would reduce gas relative permeability, thereby hindering gas flow. The shale gas production characteristic is controlled by the two abovementioned competing mechanisms. There exists a perfect combination of water injection pressure and injection time for achieving the maximum profitability of a shale gas well. This work can give a better understanding of the two-phase flow process in shale reservoirs and shed light on the field application of hydraulic fracturing.http://dx.doi.org/10.1155/2021/2637217 |
| spellingShingle | Ershe Xu Lingjie Yu Ming Fan Tianyu Chen Zhejun Pan Yuling Tan Guanglei Cui Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production Geofluids |
| title | Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production |
| title_full | Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production |
| title_fullStr | Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production |
| title_full_unstemmed | Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production |
| title_short | Two-Phase Flow Model for Numerical Investigation of Impact of Water Retention on Shale Gas Production |
| title_sort | two phase flow model for numerical investigation of impact of water retention on shale gas production |
| url | http://dx.doi.org/10.1155/2021/2637217 |
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