In petroleum engineering, imbibition is one of the most important elements for the hydraulic fracturing and water flooding processes, when extraneous fluids are introduced to the reservoir. However, in unconventional shale formations, osmosis has been often overlooked, but it can influence the imbibition process between the working fluid and the contacting formation rocks. The main objective of this study is to understand effects of fluid–rock interactions for osmosis-associated imbibition in unconventional formations. This paper summarizes previous studies on imbibition in unconventional formations, including shale, tight carbonate, and tight sandstone formations. Various key factors and their influence on the imbibition processes are discussed. Then, the causes and role of osmotic forces in fluid imbibition processes are summarized based on previous and recent field observations and laboratory measurements. Moreover, some numerical simulation approaches to model the osmosis-associated imbibition are summarized and compared. Finally, a discussion on the practical implications and field observations of osmosis-associated imbibition is included.

In shale gas formations, imbibition is significant since the tight pore structure causes a strong capillary suction pressure. After hydraulic fracturing, imbibition during the period of shut-in affects the water recovery of flowback. Although there have been many studies investigating imbibition in shale formations, few papers have studied the relationship between gas production and shut-in time under the influence of imbibition. This paper developed a numerical model to investigate the effect of imbibition on gas production to optimize the shut-in time after hydraulic fracturing. This numerical model is a 2-D two-phase (gas and water) imbibition model for simulating an imbibed fluid flow and its effect on permeability, flowback, and water recovery. The experimental and field data from the Woodford shale formation were matched by the model to properly configure and calibrate the model parameters. The experimental data consisted of the relationship between the imbibed fluid volume and permeability change, the relative permeability, and the capillary pressure for the Woodford shale samples. The Woodford field data included the gas production and flowback volume. The modeling results indicate that imbibition can be a beneficial factor for gas production, since it can increase rock permeability. However, the gas production would be reduced when excessive fluid is imbibed by the shale matrix. Therefore, the shut-in time after hydraulic fracturing, when the imbibition happens in shale, could be optimized to maximize the gas production.

Salt precipitation and pore clogging near CO₂ injection wells can reduce injectivity during geological storage in saline formations; yet, the combined effects of CO₂ phase state, flow rate, and humidity remain insufficiently resolved at the core scale. This study investigated CO₂-induced pore-structure alteration in brine-saturated artificial sandstone containing shale/clay interbeds and carbonate cementation. Eight CO₂ core-flooding experiments were conducted under controlled phase-state, flow-rate, and humidity conditions, and each core was imaged before and after displacement using X-ray CT. Pressure response, apparent flow resistance, CT-derived porosity change, and salt-enriched phase distribution were evaluated. CO₂ flooding caused substantial porosity loss in all tests. In the phase-state series, porosity reductions ranged from 40.75% to 50.21%, with the largest reduction under supercritical CO₂. In the flow-rate series, the largest porosity reduction was 56.52%, whereas the highest apparent flow resistance occurred at the lowest flow rate. The humidity comparison showed the strongest contrast: dry supercritical CO₂ reduced porosity by 46.45%, whereas wet supercritical CO₂ reduced it by only 15.68%. These results indicate that CO₂ humidity strongly controls pore-volume preservation and that humidified CO₂ can mitigate evaporation-driven salt-related injectivity impairment.

The Tarim Basin is one of the most important oil formations in China, and it is prospected to exceed 110 billion barrels. Recently, some fault areas were drilled to achieve high potential oil reservoirs in the Tarim Basin. However, during drilling, wellbore stability is difficult to ensure in the fault areas. Wellbore collapse and lost circulation may unexpectedly occur. Therefore, analysis of wellbore stability according to the formation characteristics of the fault zone is necessary. On the basis of the formation mechanism of the fault zone, the stratigraphic characteristics corresponding to the internal structure of different fault zones were analyzed in this work. As a result of the formation characteristics, the corresponding logging identification methods of the induced fracture zone and sliding crushing zone formed, and the differences in wellbore instability in different internal structures were compared. The formation characteristics and mechanical properties of the sliding crushing zone were characterized by XRD, SEM, linear expansion rate test, rolling recovery test, and other physical experiments. Logging calculations were also conducted to assess the phenomenon of collapse that often occurs in the sliding crushing zone, and the collapse mechanism was analyzed accordingly. In view of the leakage phenomenon in the induced fracture zone, the complex mechanism of the leakage was analyzed, and the traditional minimum principal stress model was modified to obtain the leakage pressure calculation model suitable for the fault zone. Finally, taking the F1 fault zone in Shunbei area as an example, the internal structure of the fault zone was divided by using the summarized logging identification method. The wellbore instability of the different internal structures was compared, and the newly established loss pressure model was applied in the SHBX1 well, thereby proving that the model has a good application effect. The study in this paper provided some mechanisms of wellbore instability based on formation property and rock mechanics in the fault area. In addition, a loss pressure model based on the special formation characteristics was proposed to guide drilling in the fault zone.