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Capillary rise experiments are conducted in a set of calcareous and siliceous rocks with varying mineralogy and petrophysical properties to understand the coupled impact of reactivity and spontaneous imbibition. A capillary rise experiment is performed in each sample: first with deionized water, then with a dilute acidic solution, and finally again with deionized water, and the capillary rise profile for each is recorded. Pre- and post-acid petrophysical properties such as porosity, permeability, pore size distribution, and contact angle are measured for each sample. The mineral makeup of the rocks significantly influences how the acidic fluids penetrate the samples. The primary reactions are the dissolution of Ca- and Mg-rich minerals which alter the pore network. The higher acid strength results in higher capillary rise in calcareous rocks and results in an increase in the average pore size. The same pH acid results in lower capillary rise in the siliceous rocks, and a general decrease in the average pore size is observed. Changes in contact angle indicate increased water affinity in carbonate and reduced affinity in sandstone. The link between capillary interactions and fluid reactivity is often overlooked in fluid flow studies, and this research sheds light on the importance of reactivity during spontaneous imbibition, offering insights into dissolution and precipitation processes during capillary flow.

CO 2 injection is a prominent measurement to enhance the recovery of shale reservoirs. The imbibition of fracturing fluid + CO 2 additive is considered important for promoting the enhancement and stabilization of shale oil production to ensure energy supply. The imbibition experiments of fracturing fluid + CO 2 additive were carried out in shale reservoirs with a nuclear magnetic resonance (NMR) test. The imbibition displacement characteristics at different pore scales of shale were quantitatively evaluated. The variability of the imbibition effects in shale reservoirs was clarified in terms of shale type, fracturing fluid type, and CO 2 additive (pressure). This finding indicates that the effectiveness of the fracturing fluid + CO 2 additive imbibition on shale reservoirs is stronger, and the imbibition displacement efficiency ranges from 33.38 % to 41.56 %. The imbibition contribution rate is considerably higher for small pores than for large pores, and the difference between them is more than 10%. Therefore, the imbibition of fracturing fluid + CO 2 additive mainly extracted crude oil from the small pores of shale reservoirs. CNI nano variable-viscous slippery water is more effective for imbibition displacement in laminar type shale. For laminated type shale, EM30 + + guanidine gum mixed water has a better imbibition effect than CNI nano variable-viscous slippery water. Under 16 MPa CO 2 + fracturing fluid (miscible states), the imbibition displacement efficiency of the shale is significantly enhanced. The imbibition displacement degree at different pore scales is also increased. For different types of shale reservoirs, the imbibition displacement degree at different pore scales would be improved by methods, including the optimization of the fracturing fluid or the change of imbibition conditions. This study presents a theoretical underpinning for the high-efficiency exploitation in shale reservoirs.

The flowback rate of fracturing fluid in shale reservoirs is often notably low, primarily due to the spontaneous imbibition of the water-based fracturing fluid. Despite their significance, the factors influencing spontaneous imbibition in shale reservoirs remain insufficiently understood. Moreover, whether spontaneous imbibition is ultimately beneficial or detrimental to shale reservoirs is still a subject of debate. This study investigates the spontaneous imbibition process in shale, the factors (the bedding, contact area, porosity, initial water saturation, and fluid type) affecting it, and its impact on shale porosity and permeability. The results reveal that the spontaneous imbibition process can be categorized into three distinct stages: the rapid imbibition stage, the transitional stage, and the stable stage. It is observed that bedding significantly influences the imbibition rate, and the imbibition rate in the parallel bedding direction is greater than that in the vertical bedding direction. The imbibition capacity increases with larger contact area and higher porosity, while it decreases with higher initial water saturation. Furthermore, the imbibition capacity varies with the type of fluid, following this order: distilled water > 5% KCl solution > kerosene. The maximum imbibed volume per unit pore volume of shale in distilled water is twice that in kerosene. Lastly, spontaneous imbibition is found to enhance the porosity and permeability of shale. After three instances of imbibition, the porosity of the matrix and fractured sample increased by 0.85% and 1.68%, and the permeability increased by 0.636 mD and 0.829 mD, respectively.

Reactive transport in porous media exhibits multifaceted interactions that are dependent on the matrix and fluid properties, and which ultimately alter these properties. A set of calcareous rock samples with unique mineralogy and varying petrophysical properties are selected for this study. A capillary rise experiment is performed in each sample, first with deionized water and then with a dilute, pH 2, HCl solution. Pre‐ and post‐acid petrophysical properties such as porosity, permeability, pore size distribution, and contact angle are measured for each sample along with the capillary rise profile. The latter is tracked by applying image analysis on video recording. The rock mineralogy significantly affects the acidic fluid intrusion into the rock samples. Calcite dissolution is the main reaction that results in the opening of the pore space. This is more prominent in all the carbonate samples where a higher proportion of calcite minerals is present. A higher capillary rise is consistently observed compared to the neutral fluid along with an increase in porosity and the mean pore size. The contact angle also undergoes changes making the carbonate matrix from oil‐wet to neutral‐wet. Coupling capillary interactions with fluid reactivity is often neglected in fluid transport phenomena. This study offers new insights into the relative importance of reactivity at the timescale of spontaneous imbibition. This is important in understanding dissolution and precipitation processes during capillary flow. Plain Language Summary In the field of geochemistry, the coupled processes of reactivity and capillary interaction are influenced by the properties of rocks and fluids. However, during capillary rise with reactive fluid, the rocks can initiate a cycle wherein reactivity continuously changes the properties of the rocks thereby affecting the fluid height which results in a different in comparison to unreactive fluids. To comprehend the underlying mechanisms of this phenomenon, a series of capillary rise experiments were conducted in three different carbonate rocks: first with DI water and then with a dilute acidic solution. Rock and fluid properties were measured before and after the reactive capillary rise. A higher fluid height was observed in acidic fluids, indicating that these fluids altered the pore structure and surface chemistry of the rocks. The reactivity promoted both pore enlargement and reduction due to calcite dissolution and precipitation. These processes also altered the surface chemistry of calcites, making them more water wet. Despite the small length scale and short duration of this study, the results show the importance of reactivity during capillary phenomenon. This understanding is crucial for grasping how reactive contaminants can move through the vadose zone. Key Points Acidic imbibition (pH 2) in calcareous rocks results in higher capillary rise compared to neutral fluid Pore enlargement and reduction were observed due to calcite dissolution and precipitation during acid‐based capillary rise Calcite dissolution is the main reaction observed during the acidic imbibition and result in a more water‐wet matrix

Through new core wettability simulation technology and the single-sided unidirectional imbibition experimental method, the influence of core wettability on oil imbibition characteristics was studied by using artificial cores with wettability index in the range of −0.9~0.95. Results show that for the cores with permeability from ultra-low to medium–high, the imbibition time shows a monotonically decreasing law with the increase in the wettability index. In the weak water-wet range, the imbibition time increases significantly with the weakening of water-wet. Oil imbibition rate goes up with the increase in wettability index. In the strong water-wet range, the imbibition rate will change significantly with wettability. In the water-wet zone, there is a positive correlation between imbibition oil limit recovery and wettability index, according to which a power exponent model of them is established. The imbibition–displacement ratio, which characterizes the contribution rate of oil recovery by imbibition to that by waterflooding, is also positively correlated with the wettability index. In addition, imbibition–displacement ratios of extra-low permeability cores are very close to that of medium–high permeability cores. According to the analysis of the research results, compared with the strongly water-wet oil layer, the weakly water-wet oil layer with a wettability index of 0–0.5 has a greater contribution to oil recovery by using the enhanced imbibition method.

Unconventional tight/shale gas reservoirs have gained significant attention in the energy sector. The importance of temperature and pressure in shale imbibition lies in their profound influence on the kinetics, rate, and ultimate amount of water uptake, which directly impacts the efficiency of gas production. Given the importance of imbibition in influencing initial production, existing studies have primarily focused on shallow and mid‐deep shale samples under limited pressure and temperature conditions, while the imbibition characteristics of shale formations deeper than 3500 m have not been thoroughly investigated. To this end, we apply low‐field nuclear magnetic resonance (NMR) Carr–Purcell–Meiboom–Gill (CPMG) measurements to investigate the characteristics of water imbibition in shale under various pressure and temperature conditions. Very limited imbibition quantity was observed under spontaneous imbibition, while pressure significantly increased the imbibition amount by approximately eightfold at 30 MPa. Raising the temperature from room condition to 60°C significantly accelerated the imbibition rate, reducing the equilibrium time to 1 h. Samples with higher clay mineral content were found to exhibit greater imbibition amounts and faster imbibition rates.

Priming of seed is intended to reduce the time to germination through activation of pre-germinative processes. Seed priming is controlled hydration followed by a drying (dehydration) process. The physiological processes during hydration (imbibition) were studied in detail in tomato. In contrast, gibberellic acid changes during the dehydration phase were not studied in detail. We hypothesize that there would be a change in the GA concentration during the dehydration phase of the seed priming process, which may influence the vigour characteristics of the resultant seedling. The objective of the study was to understand the influence dehydration phase of seed priming on GA biosynthesis and its subsequent effect on seed germination and seedling traits of tomato. First, the hydroprimed and unprimed seeds were re-imbibed for 3 h, 6 h, 9 h, and 12 h to initiate the germination process, and the GA concentration and seedling vigour associated parameters were recorded. In the second experiment, the imbibed seeds were dehydrated for 3 h, 6 h, 9 h, and 12 h, then re-imbibed for 3 h, 6 h, 9 h, and 12 h to understand the effect of dehydration on the GA concentration and its associated traits. Results revealed that hydroprimed seeds had a higher GA concentration and seedling vigour than unprimed seeds. The seeds that are completely dehydrated for 12 h had the highest GA and seed vigour parameters. Therefore, increased vigour of hydroprimed seeds is due to the higher levels of GA accumulated during the dehydration phase of seed priming, which can improve seed germination and seedling vigour of tomato.

After multi-stage volume hydraulic fracturing in a shale oil reservoir, massive amounts of water can be imbibed into the matrix pores. One of the key imbibition characteristics of a shale reservoir is the imbibition water and its height distribution. Based on high pressure mercury injection (HPMI) experiments and nuclear magnetic resonance (NMR) analyses, this study quantitatively evaluated the pore-size distribution of Chang 7 continental shale oil reservoirs in Yanchang Formation, Ordos Basin. The pores could be divided into three types as micropores (≤0.1 μm), mesopores (0.1–1.0 μm), and macropores (>1.0 μm), while the volume of micropores and mesopores accounted for more than 90%. This demonstrated that there were strong heterogeneity and micro–nano characteristics. According to the spontaneous imbibition (SI) experiments, the cumulative proportion of imbibition water content was the largest in micropores, exceeding 43%, followed by mesopores around 30%, and that of macropores was the lowest, and basically less than 20%. The negative values of stage water content in the macropore or mesopore indicated that these pores became a water supply channel for other dominant imbibition pores. Additionally, combining the fractal theory with the NMR T2 spectrum, the relative imbibition water and actual height were calculated in different pores, while the height distribution varied with cores and shale oil. The shorter the core, the higher was the relative height, while the radius of macropores filled with imbibition water was reduced. This indicates that the height distribution was affected by the pore structure, oil viscosity, and core length.

Black nanosheets (BN, with a specific chemical composition of molybdenum disulfide) have been widely studied for low-permeability reservoir development due to their unique nanoscale dimensions and lamellar structure. Our prior research demonstrated that cationically modified BN combined with low-salinity water (LSW) significantly enhances oil displacement. This study compared the imbibition adaptability of the composite system under both ambient-pressure and pressurized conditions, while combining nuclear magnetic resonance (NMR) techniques to analyze related imbibition mechanisms and reservoir permeability adaptability. Results showed that the modified BN-LSW composited system achieved an imbibition recovery efficiency of 43.92% under ambient pressure. The mechanism was capillary force-dominated, preferentially displacing oil from small pores by improving core wettability and emulsification. Under pressurized conditions, the driving force became dominant, further increasing recovery efficiency to 56.52%, with the system displacing oil from both large and small pores. Additionally, the system showed optimal adaptability in cores with 0.05 × 10−3 μm2 permeability. Imbibition efficiency declined at higher/lower permeabilities due to weakened capillary forces or nanoparticle aggregation-induced clogging. This study confirmed that the modified BN-LSW composite system enhanced imbibition stability and recovery efficiency, and combined with nuclear magnetic resonance (NMR) technology, its mechanism was revealed at the microscale. This provided theoretical and technical support for the efficient development of low-permeability reservoirs, with significant engineering value.

This study explores the impact of salinity on fluid replacement during imbibition-driven oil recovery through a series of core self-imbibition experiments. By integrating key parameters such as interfacial tension, contact angle, and oil displacement efficiency, we systematically examine how variations in salinity level, ion type, and ion concentration affect the imbibition process. The results demonstrate that the salinity of the injected fluid exerts a strong influence on the rate and extent of oil recovery. Compared with high-salinity conditions, low-salinity injection, particularly below 5000 mg·L−1, induces pronounced fluctuations in the replacement rate, achieving the highest recovery at approximately 1000 mg·L−1. The interplay between interfacial tension and displacement efficiency is jointly governed by both ion type and concentration. Moreover, changes in ionic composition can alter rock wettability from oil-wet toward water-wet states, thereby enhancing imbibition efficiency. Among the tested ions, Mg2+ and SO42− at low concentrations were found to be especially effective in promoting oil displacement.