Characteristics of Imbibition, Displacement, and Fluid Seepage in High Clay Content Shale Condensate Gas Reservoir in the Fuxing Area

QIAO Runwei; ZHANG Shicheng; LI Fengxia; WANG Fei; LI Ning

doi:10.11911/syztjs.2023121

Volume 52 Issue 1

Jan. 2024

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Petroleum Drilling Techniques > 2024 > 52(1): 96-106. > DOI: 10.11911/syztjs.2023121

QIAO Runwei, ZHANG Shicheng, LI Fengxia, et al. Characteristics of imbibition, displacement, and fluid seepage in high clay content shale condensate gas reservoir in the Fuxing Area [J]. Petroleum Drilling Techniques，2024, 52(1)：96-106. DOI: 10.11911/syztjs.2023121

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Characteristics of Imbibition, Displacement, and Fluid Seepage in High Clay Content Shale Condensate Gas Reservoir in the Fuxing Area

1.
College of Petroleum Engineering, China University of Petroleum(Beijing), Beijing, 102249, China
2.
Sinopec Petroleum Exploration and Production Research Institute, Beijing, 102206, China

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Received Date: May 22, 2023
Revised Date: January 14, 2024
Available Online: February 05, 2024

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Abstract

Abstract

The Lianggaoshan Formation in the Fuxing Area is a high clay content shale condensate gas reservoir, which is subject to retrograde condensation and liquid locking during well soaking and flowback after volumetric fracturing, which affects the production performance. In order to accurately understand the characteristics of imbibition, displacement and fluid seepage in high clay content shale condensate gas reservoir, and the timing of switching soaking to displacement was optimized, the experiments of gas and water imbibition, flowback and three-phase imbibition and displacement were carried out by selecting the reservoir core. Nuclear magnetic resonance and constant pressure displacement were both used to quantify the water lock damage characteristics of fracturing fluid and the flowable characteristics of condensate oil during the imbibition and displacement process. A liquid lock damage characterization method was established, and reservoir-scale water lock characteristics during well soaking were simulated. The results show that the imbibition recovery of the core in the shale reservoirs during the fracturing imbibition stage is between 50.22% and 57.14%; the lower salinity of the imbibition fluid indicates a lower flowback rate and higher water lock damage rate. The oil lock damage rate is lower than the water lock damage rate. When irreducible water exists, the critical flowable saturation of condensate oil can be reduced by about 20%. With the mitigation of water lock damage near fractures after well soaking as the goal, the recommended well soaking time is 20 to 30 days. The research results provide a theoretical basis for the efficient development of high clay content shale condensate gas reservoir in the Fuxing Area.
- clay,
- shale,
- condenstate gas reservoir,
- imbibition,
- fracturing fluid,
- fluid seepage characteristics,
- well socking time,
- Fuxing Area

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