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<p>In recent years, tight oil has emerged as a significant and complex topic in the fields of oil exploration and development. Following hydraulic fracturing, wells are typically shut-in for a designated period to facilitate water uptake into shale formations, which has become the predominant method for developing tight oil resources. During this process, initial pressure—specifically the shut-in pressure post-fracturing—plays a crucial role in ensuring imbibition recovery and determining shut-in duration. This study focuses on the typical terrestrial tight oil found in China—the Chang 7 tight oil from the Ordos Basin. Through quantitative analysis of wettability and pore-throat structure, we elucidate the flow mechanisms of oil during "shut-in" processes under varying pressure differentials using experiments conducted with nuclear magnetic resonance (NMR). Furthermore, we establish a model to quantitatively analyze the relationship between shut-in time and pressure across different reservoir types. Significant variations in wettability were observed among distinct pore spaces. Water-wet pores predominantly occurred within both small and large pores, whereas oil-wet pores were mainly identified in medium-sized pores. During imbibition, fluids initially mobilize crude oil within macropores with an impressive recovery rate reaching up to 25%. This process subsequently transitions into spontaneous sorption dynamics as infiltration continues, leading to reduced recovery rates primarily associated with micropores. Additionally, our findings indicate that the impact of shut-in pressure on enhanced imbibition recovery varies across different reservoir types. When the reservoir physical properties are better (i.e. the micro-fractures are more developed in the reservoirs), higher shut-in pressures correlate with improved imbibition recovery; optimal pressures are determined to be approximately 45&#xa0;MPa ~ 55&#xa0;MPa, with corresponding ideal shut-in durations of around 20 ~ 30&#xa0;days. Conversely, the worse the reservoir physical properties are, we recommended to maintain maximum possible pressures to minimize shutdown periods while reducing ineffective downtime during well operations.</p>

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The effect of the displacement pressure on migration of fluid during the imbibition for tight oil reservoir

  • 期刊论文

  • 出版模式：

    开放获取

  • 发表日期：

    2025年7月3日

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  • Yubin Yang,
  • Xian Peng,
  • Wenlian Xiao,
  • Qihong Lei,
  • Tao Li,
  • Youan He,
  • Chun Zhang,
  • Jiahao Jiang,
  • Tao Qi,
  • Lingli Zheng,
  • Haoyu Chen

摘要

In recent years, tight oil has emerged as a significant and complex topic in the fields of oil exploration and development. Following hydraulic fracturing, wells are typically shut-in for a designated period to facilitate water uptake into shale formations, which has become the predominant method for developing tight oil resources. During this process, initial pressure—specifically the shut-in pressure post-fracturing—plays a crucial role in ensuring imbibition recovery and determining shut-in duration. This study focuses on the typical terrestrial tight oil found in China—the Chang 7 tight oil from the Ordos Basin. Through quantitative analysis of wettability and pore-throat structure, we elucidate the flow mechanisms of oil during "shut-in" processes under varying pressure differentials using experiments conducted with nuclear magnetic resonance (NMR). Furthermore, we establish a model to quantitatively analyze the relationship between shut-in time and pressure across different reservoir types. Significant variations in wettability were observed among distinct pore spaces. Water-wet pores predominantly occurred within both small and large pores, whereas oil-wet pores were mainly identified in medium-sized pores. During imbibition, fluids initially mobilize crude oil within macropores with an impressive recovery rate reaching up to 25%. This process subsequently transitions into spontaneous sorption dynamics as infiltration continues, leading to reduced recovery rates primarily associated with micropores. Additionally, our findings indicate that the impact of shut-in pressure on enhanced imbibition recovery varies across different reservoir types. When the reservoir physical properties are better (i.e. the micro-fractures are more developed in the reservoirs), higher shut-in pressures correlate with improved imbibition recovery; optimal pressures are determined to be approximately 45 MPa ~ 55 MPa, with corresponding ideal shut-in durations of around 20 ~ 30 days. Conversely, the worse the reservoir physical properties are, we recommended to maintain maximum possible pressures to minimize shutdown periods while reducing ineffective downtime during well operations.