Search Results (16)

The capillary force driving the water penetration process in the coal pore network is the key factor affecting the effect of coal seam water injection. The resistivity method can be used to determine the migration characteristics of water in coal. In order to study the relationship between the resistivity of gas-bearing coal and the migration of water in the process of imbibition, the self-generated imbibition tests of coal under different external water conditions were carried out by using the self-developed gas-bearing coal imbibition experimental platform and the dynamic response characteristics of coal resistivity with external water were obtained. The results show that the water injected into the coal body migrates from bottom to top under the driving of capillary force, and the resistivity of the wetted coal body shows a sudden decline, slow decline, and gradually stable stage change. Through the slice drying method, it is found that the moisture in the coal body is almost uniform after imbibition, and the resistivity method can be used to accurately and quantitatively characterize the moisture content of the coal body. In the axial direction, as water infiltrates layer by layer, the sudden change time of resistivity is delayed with the deepening of the layer. The resistivity of each layer first drops sharply then slows down and tends to stabilize. The stable value of resistivity increases gradually with the depth of the layer. In the radial direction, within the same plane, water first migrates to the centre of the coal body and then begins to spread outwards. The average mutation time and stable value of coal resistivity during spontaneous imbibition decrease with increasing water content. When the water content reaches 10%, the stable value of resistivity tends to be constant, and the relationship between the stable value of coal resistivity and water content conforms to an exponential function. Full article

Pore connectivity and ultimate imbibed porosity are two important parameters used to assess the shale oil reservoir property, the proper appraising of which could facilitate the efficient flow of oil from the matrix and an improvement in recovery efficiency. In previous studies, the uncertainty in sample dimensions and the extra-long stable time during imbibition experiments exploring pore connectivity and ultimate imbibed porosity showed a lack of discussion, which influenced the accuracy and efficiency of the SI experiments. In this study, SI experiments with shale samples of different thicknesses are carried out to acquire the two parameters in a short period of time. As a result, the pore connectivity of sample D86-5 from the Qingshankou Formation (Fm) in the Songliao Basin fluctuates with the increase in thicknesses, with an average of 0.265. The water penetrates sample D86-5 of all thicknesses, so the ultimate imbibed porosity fluctuates around 3.7%, and the stable time increases with thicknesses. The pore connectivity of sample Y172 from the Shahejie Fm in the Bohaiwan Basin fluctuates around an average of 0.026, which is much smaller than that of D86-5. The ultimate imbibed porosity of Y172 decreases with thicknesses because the penetration depth is so small that the pores cannot be fully accessed, and the stable time increases before becoming stable with fluctuations. The method is examined using the samples from the Liushagang Fm in the Beibuwan Basin measuring around 400 μm: the ultimate imbibed porosity of BW1-1 and BW1-3 is 5.8% and 18.1%, respectively, the pore connectivity of BW1-1, BW1-2, and BW1-3 is 0.086, 0.117, and 0.142, respectively, and the results can be obtained within a day. In comparison, the average pore connectivity of the 400 μm samples from Qingshankou, Shahejie, and Liushagang Fms is 0.324, 0.033, and 0.097, respectively, and the average ultimate imbibed porosity of these Fms is 3.7%, 3.1%, and 12.0%, respectively. Based on the above results, a quick method for measuring the two parameters with thin samples by spontaneous imbibition is established, providing a fast solution for the evaluation of the sweet spot. Full article

Shut-in after fracturing is generally adopted for wells in shale oil reservoirs, and imbibition occurring in matrix nanopores has been proven as an effective way to improve recovery. In this research, a molecular dynamics (MD) simulation was used to investigate the effects of wettability and pressure on nanopore imbibition during shut-in for a typical shale reservoir, Jimsar. The results indicate that the microscopic advancement mechanism of the imbibition front is the competitive adsorption between “interfacial water molecules” at the imbibition front and “adsorbed oil molecules” on the pore wall. The essence of spontaneous imbibition involves the adsorption and aggregation of water molecules onto the hydroxyl groups on the pore wall. The flow characteristics of shale oil suggest that the overall push of the injected water to the oil phase is the main reason for the displacement of adsorbed oil molecules. Thus, shale oil, especially the heavy hydrocarbon component in the adsorbed layer, tends to slip on the walls. However, the weak slip ability of heavy components on the wall surface is an important reason that restricts the displacement efficiency of shale oil during spontaneous imbibition. The effectiveness of spontaneous imbibition is strongly dependent on the hydrophilicity of the matrix pore’s wall. The better hydrophilicity of the matrix pore wall facilitates higher levels of adsorption and accumulation of water molecules on the pore wall and requires less time for “interfacial water molecules” to compete with adsorbed oil molecules. During the forced imbibition process, the pressure difference acts on both the bulk oil and the boundary adsorption oil, but mainly on the bulk oil, which leads to the occurrence of wetting hysteresis. Meanwhile, shale oil still existing in the pore always maintains a good, stratified adsorption structure. Because of the wetting hysteresis phenomenon, as the pressure difference increases, the imbibition effect gradually increases, but the actual capillary pressure gradually decreases and there is a loss in the imbibition velocity relative to the theoretical value. Simultaneously, the decline in hydrophilicity further weakens the synergistic effect on the imbibition of the pressure difference because of the more pronounced wetting hysteresis. Thus, selecting an appropriate well pressure enables cost savings and maximizes the utilization of the formation’s natural power for enhanced oil recovery (EOR). Full article

As conventional oil reservoirs are gradually being depleted, researchers worldwide are progressively shifting their focus towards the development and comprehensive study of tight oil reservoirs. Considering that hydraulic fracturing is one of the main approaches for developing tight sandstone reservoirs, it is of great significance to explore the mechanism of spontaneous imbibition and waterflooding behavior after hydraulic fracturing in tight oil reservoirs. This research delves into the analysis of tight sandstone core samples obtained from the Shahejie Formation in the Bohai Bay Basin. All core samples are used for a series of experiments, including spontaneous imbibition and water flooding experiments. An additional well-shut period experiment is designed to understand the impact and operational dynamics of well shut-in procedures in tight reservoir development. Utilizing nuclear magnetic resonance (NMR) technology, the pore sizes of a sample are divided into three types, namely, macropores (>100 ms), mesopores (10–100 ms), and micropores (<10 ms), to thoroughly assess the fluid distribution and changes in fluid signals during the spontaneous imbibition and water flooding stages. Experimental outcomes reveal that during the spontaneous imbibition stage, oil recovery ranges from 12.23% to 18.70%, predominantly depending on capillary forces. The final oil recovery initially rises and then falls as permeability decreases, while the contribution of micropores progressively grows as the share of mesopores and macropores deceases. With water flooding processes carried out after spontaneous imbibition, enhanced oil recovery is observed between 28.26% and 33.50% and is directly proportional to permeability. The well shut-in procedures can elevate the oil recovery to as high as 47.66% by optimizing energy balance. Full article

Gulong shale oil is found in a typical continental shale oil reservoir, which is different from marine shale oil reservoirs. The Gulong shale oil reservoir is a pure shale-type oil reservoir with abundantly developed nanoscale pores, making it extremely difficult to unlock fluids. Pressure drive does not easily achieve fluid unlock conditions; thus, it is necessary to utilize imbibition to unlock nanoscale pore fluids. In this study, experiments were conducted on oil displacement by high-speed centrifugal pressure and imbibition under different conditions, respectively, and simulations were used to evaluate the effects of pressure differential drive and imbibition efficiency on the utilization of crude oil following fracturing. Combined with the mixed wettability of the reservoir, the imbibition efficiency was analyzed, and the imbibition efficiency at different soaking stages was evaluated. When the fracturing pressure was higher than the matrix pore pressure, the imbibition efficiency was the most obvious, which was 27.9%. Spontaneous imbibition depending solely on capillary force had poor efficiency, at 16.8%. When the fracturing pressure was lower than the matrix pore pressure, the imbibition efficiency was the lowest, at only 1.3%. It is proposed that strengthening fracture pressure and promoting pressurized imbibition are the keys to improving shale oil development. Full article

This work focuses on the development of a novel high-temperature microemulsion for enhanced oil recovery in tight oil reservoirs. Microemulsions are a type of mixture that has properties of both liquids and solids; they have shown significant potential for improving oil recovery through spontaneous imbibition. Herein, a high-temperature-tolerant lower-phase microemulsion using a microemulsion dilution method was developed. The properties and morphological characteristics of the microemulsion were evaluated and proposed a mechanism for enhanced spontaneous imbibition oil recovery using imbibition tests and CT scanning technology. The results of the study showed that the optimum concentration of the microemulsion was 0.2 wt% and that it had good thermal stability, small droplet size, lower interfacial tension, good wettability alteration ability, and minimum adsorption loss. The imbibition and CT experiments demonstrated that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. The study concludes that the solubilization coefficient and self-driving force were defined and calculated to quantitatively analyze the imbibition mechanisms and the results showed that the reduction in oil/solid adhesion was due to the synergistic effect of IFT reduction and wettability alteration and the ability to increase the imbibition distance through a larger self-driving force. Full article

Spontaneous imbibition is a phenomenon of fluid displacement under the action of capillary force, which is of great significance to reservoir protection, enhanced oil recovery, flow-back optimization, and fracturing fluid selection in unconventional oil and gas reservoirs. Remarkable progress has been made in the imbibition research of oil and gas, and the overall research situation of research needs to be analyzed more systematically. This paper aims to provide a scientometric review of imbibition studies in unconventional reservoirs from 2010 to 2021. A total of 1810 papers are collected from the Web of Science Core Correction database based on selected keywords and paper types. Using CiteSpace software, a quantitative scientific analysis is carried out on the main aspects of national cooperation, institutional cooperation, scholarly cooperation, keyword co-occurrence, journal co-citation, article co-citation, and keyword clustering. The principal research countries, institutions, scholars, keywords, published journals, influential articles, and main research clusters are obtained, and the cooperation relationship is analyzed from the centrality and number of publications. At the end of the paper, the existing knowledge areas are discussed based on the analysis of scientometric results. This study constructs a comprehensive research knowledge map of imbibition, providing relevant research with a more valuable and in-depth understanding of the field. Full article

Polymers have been used as viscosifying agents in enhanced oil recovery applications for decades, but their influence on rock surface wettability is rarely discussed relative to its importance: wettability largely controls fluid flow in porous media and changes in wettability may significantly influence subsequent system performance. This paper presents a two-part systematic investigation of wettability alteration during polymer injection into oil-wet limestone. The first part of the paper determines wettability and wetting stability on the core scale. The well-established Amott–Harvey method is used, and five full cycles performed with repeated spontaneous imbibition and forced displacements. Wettability alterations are measured in a polymer/oil system, to determine polymer influence on wettability, and evaluated towards simpler brine/oil and glycerol/oil systems, to determine reproducibility and uncertainty related to the method and fluid/rock system. Polymer injection into oil-wet limestone core plugs is shown to repeatedly and reproducibly reverse the core wettability towards water-wet. Wettability changed both quicker and towards stronger water-wet conditions with polymer solution as the aqueous phase compared to brine and glycerol. The second part of the paper attempts to explain the observed behavior; by utilizing in situ imaging by Positron Emission Tomography, an emerging imaging technology within the geosciences. High resolution imaging provides insight into fluid flow dynamics during water and polymer injections, identifying uneven displacement fronts and significant polymer adsorption. Full article

Shale gas reservoirs are unconventional resources with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing have been extensively used for the exploitation of these unconventional resources. According to engineering practice, some shale gas wells with low flowback rate of fracturing fluids may obtain high yield which is different from the case of conventional sandstone reservoirs, and fracturing fluid absorbed into formation by spontaneous imbibition is an important mechanism of gas production. This paper integrates NMR into imbibition experiment to examine the effects of fractures, fluid salinity, and surfactant concentration on imbibition recovery and performance of shale core samples with different pore-throat sizes acquired from the Longmaxi Formation in Luzhou area, the Sichuan Basin. The research shows that the right peak of T₂ spectrum increases rapidly during the process of shale imbibition, the left peak increases rapidly at the initial stage and changes gently at the later stage, with the peak of the left peak shifting to the right. The result indicates that water first enters the fracture system quickly, then enters the small pores near the fracture wall due to the effect of the capillary force, and later gradually sucks into the deep and large pores. Both imbibition rate and capacity increase with increased fracture density, decreased solution salinity, and decreased surfactant concentration. After imbibition flowback, shale permeability generally increases by 8.70–17.88 times with the average of 13.83 times. There are also many microcracks occurring on the end face and surface of the core sample after water absorption, which may function as new flowing channels to further improve reservoir properties. This research demonstrates the imbibition characteristics of shale and several relevant affecting factors, providing crucial theory foundations for the development of shale gas reservoirs. Full article

At present, the imbibition behavior in tight rocks has been attracted increasing attention since spontaneous imbibition plays an important role in unconventional oil and gas development, such as increasing swept area and enhancing recovery rate. However, it is difficult to describe the imbibition behavior through imbibition experiment using tight rock core. To characterize the imbibition behavior, imbibition and drainage experiments were conducted among water, oil, and gas phases in a visible circular capillary tube. The whole imbibition process is monitored using a microfluidic platform equipped with a high frame rate camera. This study conducts two main imbibition experiments, namely liquid-displacing-air and water-displacing-oil experiments. The latter is a spontaneous imbibition that the lower-viscosity liquid displaces the higher-viscosity liquid. For the latter, the tendency of imbibition rate with time does not match with previous model. The experimental results indicate that it is unreasonable to take no account of the effect of accumulated liquid flowing out of the capillary tube on imbibition, especially in the imbibition experiments where the lower-viscosity liquid displaces the higher-viscosity liquid. A mathematical model is established by introducing an additional force to describe the imbibition behavior in capillary tube, and the model shows a good prediction effect on the tendency of imbibition rate with time. This study discovers and analyzes the effect of additional force on imbibition, and the analysis has significances to understand the imbibition behavior in tight rocks. Full article

The migration and accumulation of oil in tight sandstone reservoirs are mainly controlled by capillary force. Due to the small pore radius and complex pore structure of tight sandstone reservoirs, the capillary force is very sensitive to wettability, so wettability significantly affects oil migration and accumulation. However, the study of oil migration and accumulation in tight sandstone reservoirs often needs to combine multiple methods, the process is complex, and the research methods of wettability are not uniform, so the mechanism of wettability affecting oil migration and accumulation is not clear. Taking the tight sandstone of the Shahejie Formation in the Dongying sag, Bohai Bay Basin, as the research object, the wettability characteristics of a tight sandstone reservoir and their influence on oil migration and accumulation were analyzed by means of a pore permeability test, XRD analysis, micro-CT experiment, contact angle tests, spontaneous imbibition experiments, and physical simulation experiments on oil migration and accumulation. The results show that the reservoir is of the water-wet type, and its wettability is affected by the mineral composition. Wettability in turn affects the spontaneous imbibition characteristics by controlling the capillary force. Oil migration in tight sandstone reservoirs is characterized by non-Darcy flow, the oil is in the non-wetting phase and subject to capillary resistance. The key parameters to describe the oil migration and accumulation characteristics include the kickoff pressure gradient, the critical pressure gradient, and ultimate oil saturation. Wettability affects oil migration characteristics by controlling the capillary force. The more oil-wet the reservoir is, the more favourable it is to oil migration and oil accumulation and therefore the higher the reservoir’s ultimate oil saturation is. Full article

 Forced and spontaneous imbibition of water is performed to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar oils (n-heptane and Marcol-82) were used as a non-wetting phase, with viscosities between 0.4 and 32 cP and brine (1 M NaCl) for the wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was measured during forced imbibition. Five forced imbibition tests were performed using low or high injection rates, using low or high oil viscosity. Seventeen spontaneous imbibition experiments were performed at four different oil viscosities. By varying the oil viscosity, the injection rate and imbibition modes, capillary and advective forces were allowed to dominate, giving trends that could be captured with modeling. Full numerical simulations matched the experimental observations consistently. The findings of this study provide better understanding of pressure and recovery behavior in strongly water-wet systems. A strong positive capillary pressure and a favorable mobility ratio resulting from low water relative permeability were main features explaining the observations. Complete oil recovery was achieved at water breakthrough during forced imbibition for low and high oil viscosity and the recovery curves were identical when plotted against the injected volume. Analytical solutions for forced imbibition indicate that the pressure drop changes linearly with time when capillary pressure is negligible. Positive capillary forces assist water imbibition, reducing the pressure drop needed to inject water, but yielding a jump in pressure drop when the front reaches the outlet. At a high injection rate, capillary forces are repressed and the linear trend between the end points was clearer than at a low rate for the experimental data. Increasing the oil viscosity by a factor of 80 only increased the spontaneous imbibition time scale by five, consistent with low water mobility constraining the imbibition rate. The time scale was predicted to be more sensitive to changes in water viscosity. At a higher oil-to-water mobility ratio, a higher part of the total recovery follows the square root of time. Our findings indicate that piston-like displacement of oil by water is a reasonable approximation for forced and spontaneous imbibition, unless the oil has a much higher viscosity than the water.  Full article

Tight matrix has relatively low permeability and porosity, with abundant micro/nano pores. The capillary force in these pores are relatively strong, making the wetting liquid easier to be imbibed in the matrix. This process is called spontaneous imbibition. The complexity of pore structure is identified as one of the key factors influencing the imbibition process, but the detailed mechanism is not clear. Thus, in this work, a method is proposed to evaluate the influence of pore structure on imbibition process. Pore structure has fractal properties in a specific scale. By using the fractal theory, an imbibition model is provided to analyze the influence of microscopic structures on spontaneous imbibition, considering the pore size distribution and pore connectivity. Also, based on this model, the influencing factors on dimensionless imbibition and diffusion rate are discussed. Results show that the pore structure has more branches, larger and shorter sub-throats has higher chance to gain a high imbibition rate. Finally, a 3D imbibition parameter cube is constructed to determine the parameter combinations in favor of strong water diffusion potential. By utilizing the analysis method based on the fractal theory, we can effectively evaluate the imbibition potential. It is helpful to provide a guidance to evaluate the water imbibition to gas production. Full article

The determination of microscopic residual gas distribution is beneficial for exploiting reservoirs to their maximum potential. In this work, both forced and spontaneous imbibition (waterflooding) experiments were performed on a high-pressure displacement experimental setup, which was integrated with nuclear magnetic resonance (NMR) to reveal the impacts of capillary number (Ca) and initial water saturation (S_wi) on the residual gas distribution over four magnitudes of injection rates (Q = 0.001, 0.01, 0.1 and 1 mL/min), expressed as Ca (logCa = −8.68, −7.68, −6.68 and −5.68), and three different S_wi (S_wi = 0%, 39.34% and 62.98%). The NMR amplitude is dependent on pore volumes while the NMR transverse relaxation time (T₂) spectrum reflects the characteristics of pore size distribution, which is determined based on a mercury injection (MI) experiment. Using this method, the residual gas distribution was quantified by comparing the T₂ spectrum of the sample measured after imbibition with the sample fully saturated by brine before imbibition. The results showed that capillary trapping efficiency increased with increasing S_wi, and above 90% of residual gas existed in pores larger than 1 μm in the spontaneous imbibition experiments. The residual gas was trapped in pores by different capillary trapping mechanisms under different Ca, leading to the difference of residual gas distribution. The flow channels were mainly composed of micropores (pore radius, r < 1 μm) and mesopores (r = 1–10 μm) at logCa = −8.68 and −7.68, while of mesopores and macropores (r > 10 μm) at logCa = −5.68. At both S_wi= 0% and 39.34%, residual gas distribution in macropores significantly decreased while that in micropores slightly increased with logCa increasing to −6.68 and −5.68, respectively. Full article

Spontaneous imbibition of water into tight oil reservoirs is considered an effective way to improve tight oil recovery. We have combined testing techniques such as nuclear magnetic resonance, mercury injection capillary pressure, and magnetic resonance imaging to reveal the distribution characteristics of oil and water during the spontaneous imbibition process of tight sandstone reservoir. The experimental results were used to describe the dynamic process of oil–water distribution at the microscopic scale. The water phase is absorbed into the core sample by micropores and mesopores under capillary forces that dry away the original oil phase into the hydraulically connected macropores. The oil phase entering the macropores will drive away the oil in place and expel the original oil from the macropores. The results of magnetic resonance imaging clearly show that the remaining oil accumulates in the central region of the core because a large amount of water is absorbed in the late stage of spontaneous imbibition, and the water in the pores gradually connects to form a “water shield” that blocks the flow of the oil phase. We propose the spontaneous imbibition pathway, which can effectively explain the internal mechanisms controlling the spontaneous imbibition rate. The surface of the core tends to form many spontaneous imbibition pathways, so the rate of spontaneous imbibition is fast. The deep core does not easily form many spontaneous imbibition pathways, so the rate of spontaneous imbibition is slow. This paper reveals the pore characteristics and distribution of oil and water during the spontaneous imbibition process, which is of significance for the efficient development of tight oil. Full article