Experimental study on production characteristics and enhanced oil recovery during imbibition and huff-n-puff injection in shale reservoir

Shale reservoir wettability is a critical parameter governing the occurrence, migration and recovery efficiency of oil and gas. This paper systematically reviews the recent advances in shale wettability assessment methods and their influencing factors. These factors are evaluated by various methods, each offering distinct advantages and limitations. The contact angle method provides rapid macroscopic wettability assessment but is constrained by the properties of mineral and fluid. Spontaneous imbibition effectively characterizes macroscopic wettability but is time-consuming owing to the inherently low porosity and permeability of shale formations. Nuclear magnetic resonance enables the dynamic monitoring of fluid distribution across multi-scale pores, whereas it is constrained by high technical complexity and cost. Numerical simulations investigate wettability from the perspectives of interfacial mechanics and at the molecular scale, while their parameterization and accuracy still depend on experimental validation. The spatial distribution of hydrophilic minerals alongside oleophilic organic matter leads to mixed-wettability states. Increased total organic carbon content enhances the oil-wetting propensity, while higher maturity further promotes the development of hydrophobic organic pores. Elevated temperature generally strengthens the water-wet characteristics, whereas increased pressure induces a preference for oil-wetting. High salinity fluids, particularly those containing divalent cations, asphaltenes and aromatic compounds, enhance oil affinity. Macroscopic wetting behavior is ultimately determined by the connectivity and relative abundance of organic versus inorganic pores. Future studies should integrate multidisciplinary approaches combining advanced experimental characterization with computational modeling to enhance dynamic wettability prediction under real reservoir conditions. Document Type: Invited review Cited as: Jia, B., Yang, Y., Li, C., Wei, J., Rabatuly, M., Wang, L. A comprehensive review of shale wettability characterization: Mechanisms, measurements and inffuencing factors. Capillarity, 2025, 17(2): 38-53. https://doi.org/10.46690/capi.2025.11.01

Summary: Microscopic assessment of oil distribution and imbibition mechanisms within shale formations lays the groundwork for future development strategies. In this regard, the Songliao Basin’s continental shale oil holds immense exploration and development potential. In this study, we focus on shale samples extracted from the first member of the Qingshankou Formation (Q1) within the Songliao Basin. These samples were subjected to a comprehensive analysis, encompassing mercury injection capillary pressure (MICP), porosity, and permeability measurements and detailed monitoring processes. The experimental protocol involved multiple injection cycles, commencing with spontaneous oil imbibition, followed by a series of differential pressurized oil saturation stages (eight pressurization steps ranging from 0.2 MPa to 10 MPa). Subsequently, forced imbibition using slickwater under varying pressures was used, and the process was meticulously monitored via gravimetric and nuclear magnetic resonance (NMR) measurements to deduce relative fractions within distinct pores across the entire experimental process. Notably, the results unveiled that, during oil saturation through spontaneous imbibition, the interbedd-type shale core samples exhibit more efficient oil saturation compared with the organic-rich dark massive type. In the former, clay interlayers predominate in absorbing oil, while the latter showcases preferential saturation of mesopores and macropores. Following the differential pressurized oil saturation phase, clay interlayers continued to play a significant role in both sample types, accounting for 54.2% and 57.0% of the interbed-type and massive shale’s oil intake, respectively. Furthermore, a quantification of the slickwater imbibition recovery originating from pores of varying sizes under distinct pressures revealed that clay interlayers and micropores are the primary contributors to imbibition recovery in both sample types. Collectively, the experimental findings corroborate that shale oil can be displaced from nanopores to larger matrix pores and bedding fractures through imbibition, offering valuable insights for enhancing oil recovery operations in practical field scenarios.

This study focuses on the influence of proppant parameters on the long-term conductivity of hydraulic fractures. Embedment of proppants in fracture walls and proppant crushing was studied using FCMS-V fracture conductivity system, field emission scanning electron microscope, polarization microscope and the screening analysis. The correlations between the conductivity, grain size, grain-size composition, proppant concentration and placement technique, closure pressure of fractures and proppant embedment were revealed. Embedment and crushing of proppant grains of different size under different fracture closure pressures were discussed. The recommendations on proppant placement during hydraulic fracturing were given as a case study of coalbed methane production in YC site of Ordos Basin in China.

The influence of different reservoir spaces in shale reservoirs on imbibition recovery is a hot spot for improving shale oil recovery. However, the research on the influence of different chemical reagents on the recovery factor of different scale pores is limited, and the influence mechanism of shale imbibition recovery factor under the action of different media has not been systematically studied. Therefore, this study takes the Gulong shale oil reservoir as the research object, carries out imbibition experiments combined with nuclear magnetic resonance testing under different injection fluid conditions, quantifies the contribution of shale pores of different scales to imbibition recovery under different injection media conditions, and analyzes the influence of injection media types on imbibition recovery. The results show that the average contribution rate of different types of pores was in the order of interlayer clay (47.6%) > mesoscale pores (32.7%) > small pores (17.3%) > large pores (2.6%). The total imbibition recovery of shale with millimeter-scale sandy laminae was ranked as alkali solution (61.50%) > acid solution (60.92%) >GJ surfactant (39.79%)> distilled water (32.92%)>guanidine gum (30.38%) , and the total imbibition recovery of laminated shale was ranked as GJ surfactant (39.1%) > slick water (38.0%) > guanidine gum (34.7%) > distilled water (29.2%). Document Type: Original article Cited as: Wei, J., Wang, A., Wang, R., Yang, Y., Zhao, X., Zhou, X. Contribution of different shale storage spaces to recovery rate and mechanism of oil mobilization during imbibition. Capillarity, 2025, 15(1): 12-24. https://doi.org/10.46690/capi.2025.04.03