@Article{ee.2025.073788,
AUTHOR = {Sheng Lei, Guanglong Sheng, Hui Zhao},
TITLE = {A New Integrated Numerical Simulation Method for Fracturing-Shut-in-Production of Shale Oil},
JOURNAL = {Energy Engineering},
VOLUME = {},
YEAR = {},
NUMBER = {},
PAGES = {{pages}},
URL = {http://www.techscience.com/energy/online/detail/25343},
ISSN = {1546-0118},
ABSTRACT = {Multi-stage fractured horizontal wells are among the most prevalent technologies in contemporary shale oil development. This article provides a comprehensive overview of several prevalent issues by examining pertinent simulation methods applicable to existing fractured horizontal wells. First, traditional methods primarily concentrate on individual stages of fracturing, shut-in, and production. These stages are relatively isolated and lack continuity. Second, the effects of reservoir stimulation vary under different operational conditions. The conventional dual (or multiple) porosity model is overly idealized, while analytical (or semi-analytical) models often struggle to accurately represent actual fracture geometries and internal fracture-grid characteristics, which limits their ability to effectively describe heterogeneous stimulation effects. In response to these challenges, this paper enhances the single-stage research model employed in traditional approaches by conducting an integrated analysis and establishing a comprehensive flow simulation model that encompasses the entire cycle of fracturing, shut-in, and production stages. Additionally, we introduce the concept of zonal composite flow to partition the reservoir into multiple regions based on specific physical domain partitioning principles; distinct physical property distributions are assigned to each flow region. Furthermore, we improve upon the overall well-fracturing methodology found in traditional techniques by rigorously adhering to actual construction processes. This allows for simulations of common operating conditions such as single-stage fracturing, single multi-stage fracturing events, and pauses in construction between adjacent stages. Finally, utilizing this enhanced method enables us to define evaluation indicators including effective pressure rise ratio (EPER), maximum pressure, and average pressure. We conduct a comparative analysis regarding how factors such as the number of fracturing stages, volume of fracturing fluid injection, and duration of shut-in time influence reservoir energy distribution. The research results show that for the model set up in this article, when the number of fractures is 20, the stimulated regions between fractures exactly overlap, resulting in an EPER of 20.09%, and the best transformation effect is achieved at this time. Additionally, it is determined that the ideal injection volume is 1400 m<sup>3</sup> per unit thickness. The most effective duration for well shutdown is identified as 30 days; however, it should be noted that for varying scenarios, the best solution must be derived based on specific operational conditions.},
DOI = {10.32604/ee.2025.073788}
}