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<p>Repeated hydraulic fracturing is essential for sustaining production in tight oil reservoirs due to rapid post-stimulation decline rates, yet optimizing its timing remains challenging. This study develops a two-phase (oil-water) flow model using finite difference methods to simulate fracture-porous media. The governing equations are solved with the IMPES approach to predict flow and production. Validated with Well X data, the model closely matches actual trends (3.1% deviation in reservoir pressure). Comparing initial and repeated fracturing geometries reveals key production mechanisms: high-permeability fractures increase from 14 to 21 (33% density rise), boosting oil output but accelerating pressure depletion and shortening steady flow periods. Early re-fracturing maximizes cumulative output: simulations show re-stimulation at four years extends production by 18% versus delayed interventions. Gradual pressure decline requires proactive planning to avoid productivity loss. Field validation confirms the model’s accuracy, with repeated fracturing boosting oil production by 26% over five years. Results highlight the need to balance fracture-network expansion with pressure maintenance. The proposed two-phase flow model offers a transferable methodology for optimizing re-stimulation schedules based on reservoir dynamics. This work enhances recovery strategies in heterogeneous tight oil systems by linking fracture evolution and flow behavior.</p>

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Optimization of refracturing timing in tight oil reservoirs based on an oil water two phase flow model

  • 期刊论文

  • 出版模式：

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  • 发表日期：

    2025年7月2日

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  • Qingan Zhou,
  • Rong Dai,
  • Liang Chen,
  • Chennan Wu,
  • Shunshe Luo

摘要

Repeated hydraulic fracturing is essential for sustaining production in tight oil reservoirs due to rapid post-stimulation decline rates, yet optimizing its timing remains challenging. This study develops a two-phase (oil-water) flow model using finite difference methods to simulate fracture-porous media. The governing equations are solved with the IMPES approach to predict flow and production. Validated with Well X data, the model closely matches actual trends (3.1% deviation in reservoir pressure). Comparing initial and repeated fracturing geometries reveals key production mechanisms: high-permeability fractures increase from 14 to 21 (33% density rise), boosting oil output but accelerating pressure depletion and shortening steady flow periods. Early re-fracturing maximizes cumulative output: simulations show re-stimulation at four years extends production by 18% versus delayed interventions. Gradual pressure decline requires proactive planning to avoid productivity loss. Field validation confirms the model’s accuracy, with repeated fracturing boosting oil production by 26% over five years. Results highlight the need to balance fracture-network expansion with pressure maintenance. The proposed two-phase flow model offers a transferable methodology for optimizing re-stimulation schedules based on reservoir dynamics. This work enhances recovery strategies in heterogeneous tight oil systems by linking fracture evolution and flow behavior.