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Coal seam water injection is an effective technique for dust reduction in coal mines. Imbibition is an important means of water transport in coal seams and is influenced by coal bedding. The spatial distribution of water in the seepage process was obtained, and the spontaneous seepage characteristics and water transport mechanisms of coals containing different layered angles were revealed by NMR. Results show that the bedding mainly serves as the water flow channels in the imbibition. When the angle increases, the imbibition rate of adsorption pores and seepage pores in the early stage decreases. The imbibition is firstly transported to the top quickly along the bedding flow channel, 1.5h for 0° bedding coal sample, 24h for 90°, when the water reached its apex, the curve no longer changed and imbibition proceeded slowly. With the increase of bedding angle, the imbibition equilibrium time increased from 3h to 30h, up to 9 times more, the maximum imbibition rate decreases significantly, reduced from 5.64 g/h to 1.13 g/h, the flow resistance increases, and the remaining capillary force after equilibrium increases from 0.007 Pa to 5.24 Pa. When the capillary force cannot overcome the flow resistance, the imbibition reaches equilibrium. [ABSTRACT FROM AUTHOR]

Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Understanding preferential flow in porous media holds substantial theoretical significance on the design and optimization of hydrocarbon exploitation in shale reservoir. Previous researches discussed the competition of imbibition front in layered porous media while the underlining mechanism for interfacial dynamics and induced displacement efficiency of multiphase flow remains ambiguous. In this paper, we investigate the spontaneous imbibition in dual permeable media and analyze the flux exchange between the neighboring porous zones with permeability contrast using dynamic pore network model. The impact of fluid viscosity ratio and permeability contrast on the spontaneous imbibition preference have been addressed, and finally a phase diagram for displacement efficiency has been obtained. The results reveal that the dual permeable structure enhances the invasion rate of wetting fluid in the low‐permeable zone and induces unstable displacement patterns, leading to reduction of the long‐term displacement efficiency. The interfacial pattern transition from stable displacement to unstable pattern in dual permeable media could be ascribed into the flux exchange between dual permeable zones, which shows a contrary impact on the fluid flow within the low‐permeable zone under favorable and unfavorable viscosity ratios. The permeability contrast in dual permeable media intensifies this impact during spontaneous imbibition. These results help us to understand the occurrence and mutual interaction of multiphase flow in layered porous media, and provide a theoretical guidance for the hydrocarbon exploitation in shale reservoir. Plain Language Summary: The shale oil reservoir has emerged as a crucial contributor to the global energy supply, primarily attributed to stimulation techniques such as hydraulic fracturing. The geological composition of shale rock encompasses stratified layers characterized by varying permeability, leading to diverse multiphase flow patterns at the pore scale during the shut‐in period. These intricate flow patterns significantly impact shale oil recovery during subsequent exploitations. However, a gap exists in comprehending the optimal design of injection conditions by controlling the multiphase flow pattern for a high‐efficiency exploitation strategy. The elucidation of multiphase displacement mechanisms within the complex porous structure featuring staggered layers are imperative. To address this gap, pore‐scale modeling and analysis were conducted to visualize spontaneous imbibition behaviors across varying fluid viscosity ratios and permeability contrasts. The findings indicate that the imbibition flux in low‐permeable zone is augmented by fluid flow in high‐permeable zone. Furthermore, an escalating permeability contrast intensifies the flux enhancement and reduce the displacement efficiency in dual permeable media by changing the displacement pattern from stable to unstable distribution. These outcomes serve as a theoretical foundation, providing insights for the selection and optimization of an effective exploitation strategy to enhance shale oil recovery under complex engineering conditions. Key Points: A dynamic pore network model for studying spontaneous imbibition in dual permeable media is presentedThe contrary effect of flux exchange on spontaneous imbibition within low‐permeable zone under various viscosity ratios is observedTransition of interface dynamics from stable to unstable pattern is induced by unfavorable viscosity ratio and large permeability contrast [ABSTRACT FROM AUTHOR]

To understand the effect of the spontaneous imbibition (SI) and waterflooding on oil recovery in the tight sandstone reservoirs, we selected three pairs of tight sandstone samples from the Ordos Basin in China to conduct the SI-plus-waterflooding and waterflooding-only experiments, and monitor the oil distribution and flow characteristics by using the low-field nuclear magnetic resonance (NMR) technology. One interesting observation was that oil extracted in the SI process mainly comes from macropores and micropores, which doesn't agree with the previous results wherein oil was produced from micropores, and oil was produced from the mesopores during the waterflooding after the SI process. The oil recovery factor of tight sandstone samples in the process of the SI-plus-waterflooding was more than 50%, and even more than 85%, which was greater than that in the waterflooding-only process. Moreover, we found that our tight sandstone samples behaved lower residual oil saturation, and wider oil-water two-phase co-flow region during the SI-plus-waterflooding process than that did during the waterflooding-only process. These differences in behavior appear to be linked to the fluid dynamic characteristics and capillary pressure acting on the flow fluid during the two processes. In summary, the SI-plus-waterflooding overcame the limitations related to waterflooding-only and further improved oil recovery factor in the tight sandstones. [ABSTRACT FROM AUTHOR]

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Copyright of Journal of Engineering Geology / Gongcheng Dizhi Xuebao is the property of Journal of Engineering Geology and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Copyright of Oilfield Chemistry is the property of Sichuan University, Oilfield Chemistry Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Spontaneous water imbibition into matrix blocks can be a significant oil recovery mechanism in fractured reservoirs. Many enhanced oil recovery methods, such as injection of modified salinity brine, are proposed for improving spontaneous imbibition efficacy. Many scaling equations are developed in the literature to predict spontaneous imbibition oil recovery. However, almost none of them included the impact of the diversity in ionic composition of injected and connate brines and the blending/interaction of a low salinity imbibing brine with a higher salinity connate brine. In this research, these two issues are included to propose new scaling equations for the scaling of spontaneous imbibition oil recovery by modified salinity imbibing brines. This study uses experimental data of the spontaneous imbibition of modified salinity brines into oil-saturated rock samples with different lithologies containing an irreducible high salinity connate brine. The collected tests from the literature were performed at high temperatures and on aged altered wettability cores. The results of 110 available spontaneous imbibition laboratory experiments (85, 12 and 13 tests on chalks, dolomites and sandstones, respectively) are gathered. This research initially shows the poor ability of three selected convenient scaling equations from the literature to scale imbibition recovery by modified salinity brine. Then, our newly proposed technique to find the scaling equation for spontaneous imbibition recovery by modified salinity brine, during the abovementioned conditions in limestones (Bassir et al. in J Pet Explor Prod Technol 13(1): 79–99, 2023. https://doi.org/10.1007/s13202-022-01537-7) is used in chalks, dolomites and sandstones to develop the three new scaling equations. Finally, a new general equation to scale imbibition recovery by modified salinity brine for all four lithologies is presented. Moreover, for each of the four datasets (chalk, dolomite, sandstone and all the four lithologies), the scaled data by the new equations is matched by two mathematical expressions based on the Aronofsky et al. model and the Fries and Dreyer model. These mathematical expressions can be used to develop transfer functions in reservoir simulators for a more accurate prediction of oil recovery by spontaneous imbibition of modified salinity brine in fractured reservoirs. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas & Oil is the property of Editorial Department of Natural Gas & Oil and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

This study investigates the impact of nanomaterials on different surfactant solutions. By measuring the parameters (including emulsification property, zeta potential, DLS, CA, IFT, etc.) of imbibition liquid system with nanoparticles and without nanoparticles, combining with imbibition experiments, the law and mechanism of improving the imbibition recovery of nanomaterials were obtained. The findings demonstrate that the nano-silica sol enhances the emulsification and dispersion of crude oil in the surfactant system, resulting in smaller and more uniform particle sizes for emulsified oil droplets. Non-ionic surfactant AEO-7 has the best effect under the synergistic action of nanomaterials. Zeta potential and DLS tests also showed that AEO-7 exhibits smaller particle sizes due to their insignificant electrostatic interaction with nanoparticles. Furthermore, the addition of nanomaterials enhances the hydrophilicity of core and reduces the interfacial tension. Under the synergistic action of nanoparticles, AEO-7 still showed the best enhanced core hydrophilicity (CA 0.61° after imbibition) and the lowest interfacial tension (0.1750 mN·m−1). In the imbibition experiment, the imbibition recovery of the system with nanomaterials is higher than that of the non-nanomaterials. The mixed system of AEO-7 and nano-silica sol ZZ-1 has the highest imbibition recovery (49.27%). Combined with the experiments above, it shows that nanomaterials have a good effect on enhancing the recovery rate of tight core, and the synergistic effect of non-ionic surfactant AEO-7 with nanomaterials is the best. Moreover, nanomaterials reduce adhesion work within the system while improving spontaneous imbibition recovery. These findings provide theoretical guidance for better understanding the mechanism behind nanomaterial-induced imbibition enhancement as well as improving tight oil's imbibition recovery. [ABSTRACT FROM AUTHOR]

Abstract Spontaneous water imbibition into matrix blocks can be a significant oil recovery mechanism in fractured reservoirs. Many enhanced oil recovery methods, such as injection of modified salinity brine, are proposed for improving spontaneous imbibition efficacy. Many scaling equations are developed in the literature to predict spontaneous imbibition oil recovery. However, almost none of them included the impact of the diversity in ionic composition of injected and connate brines and the blending/interaction of a low salinity imbibing brine with a higher salinity connate brine. In this research, these two issues are included to propose new scaling equations for the scaling of spontaneous imbibition oil recovery by modified salinity imbibing brines. This study uses experimental data of the spontaneous imbibition of modified salinity brines into oil-saturated rock samples with different lithologies containing an irreducible high salinity connate brine. The collected tests from the literature were performed at high temperatures and on aged altered wettability cores. The results of 110 available spontaneous imbibition laboratory experiments (85, 12 and 13 tests on chalks, dolomites and sandstones, respectively) are gathered. This research initially shows the poor ability of three selected convenient scaling equations from the literature to scale imbibition recovery by modified salinity brine. Then, our newly proposed technique to find the scaling equation for spontaneous imbibition recovery by modified salinity brine, during the abovementioned conditions in limestones (Bassir et al. in J Pet Explor Prod Technol 13(1): 79–99, 2023. https://doi.org/10.1007/s13202-022-01537-7 ) is used in chalks, dolomites and sandstones to develop the three new scaling equations. Finally, a new general equation to scale imbibition recovery by modified salinity brine for all four lithologies is presented. Moreover, for each of the four datasets (chalk, dolomite, sandstone and all the four lithologies), the scaled data by the new equations is matched by two mathematical expressions based on the Aronofsky et al. model and the Fries and Dreyer model. These mathematical expressions can be used to develop transfer functions in reservoir simulators for a more accurate prediction of oil recovery by spontaneous imbibition of modified salinity brine in fractured reservoirs.

Surfactant-assisted spontaneous imbibition is an important mechanism in enhanced oil recovery by capillary pressure in low permeability and tight oil reservoirs. Though many experiments have been conducted to study the mechanism of enhanced oil recovery by surfactant-assisted spontaneous imbibition, the effects of surfactant type, concentration, and temperature have not been well studied. Using tight sandstone outcrop core samples with similar permeability and porosity, this paper experimentally studies surfactant-assisted spontaneous imbibition using three different surfactant types, i.e., sodium dodecylbenzene sulfonate (SDBS), cocamidopropyl betaine (CAB), and C12–14 fatty alcohol glycoside (APG). In addition to the type of surfactant, the effect of the surfactant concentration and the temperature is also investigated. The study results show that the ultimate oil recovery of spontaneous imbibition with formation water and denoised water is about 10%. Surfactant can significantly improve the oil recovery of spontaneous imbibition by reducing the interfacial tension between oil and water, emulsifying crude oil and improving oil mobility. APG showed better performance compared to SDBS and CAB, with a maximum oil recovery factor of 36.19% achieved with formation water containing 0.05% APG surfactant. Lower concentrations (0.05% APG) in the formation water resulted in a higher oil recovery factor compared to 0.1% APG. Increasing temperature also improves oil recovery by reducing oil viscosity. This empirical study contributes to a better understanding of the mechanism of surfactant-assisted spontaneous imbibition and enhanced oil recovery in tight oil reservoirs. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition (SI) is an important mechanism for enhancing oil recovery in low-permeability reservoirs. Due to the strong heterogeneity, and the non-Darcy flow, the construction of SI model for lowpermeability reservoirs is extremely challenging. Commonly, traditional SI models based on single or averaged capillary tortuosity ignore the influence of heterogeneity of pore seepage channels and the threshold pressure (TP) on imbibition. Therefore, in this work, based on capillary model and fractal theory, a mathematical model of characterizing SI considering heterogeneity of pore seepage channels is established. On this basis, the threshold pressure was introduced to determine the pore radius at which the wetted phase can displace oil. The proposed new SI model was verified by imbibition experimental data. The study shows that for weakly heterogeneous cores with permeability of 0-1 mD, the traditional SI model can characterize the imbibition process relatively accurately, and the new imbibition model can increase the coefficient of determination by 1.05 times. However, traditional model has serious deviations in predicting the imbibition recovery for cores with permeability of 10e50 mD. The new SI model coupling with heterogeneity of pore seepage channels and threshold pressure effectively solves this problem, and the determination coefficient is increased from 0.344 to 0.922, which is increased by 2.68 times. For low-permeability reservoirs, the production of the oil in transitional pores (0.01-0.1 mm) and mesopores (0.1-1 mm) significantly affects the imbibition recovery, as the research shows that when the heterogeneity of pore seepage channels is ignored, the oil recovery in transitional pores and mesopores decreases by 7.54% and 4.26%, respectively. Sensitivity analysis shows that increasing interfacial tension, decreasing contact angle, oilewater viscosity ratio and threshold pressure will increase imbibition recovery. In addition, there are critical values for the influence of these factors on the imbibition recovery, which provides theoretical support for surfactant optimization. [ABSTRACT FROM AUTHOR]

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 fluidPore enlargement and reduction were observed due to calcite dissolution and precipitation during acid‐based capillary riseCalcite dissolution is the main reaction observed during the acidic imbibition and result in a more water‐wet matrix [ABSTRACT FROM AUTHOR]

The mechanisms of spontaneous imbibition to enhance oil recovery, including capillary force, electrochemical force, etc ・, are reviewed・ Imbibition mechanism models and influencing factors for shales of varying complexity are expounded. The factors which control spontaneous imbibition are summarized, including reservoir rock, fluid properties, temperature and pressure ・ The issues of spontaneous imbibition and the ways forward are noted, which provides a theoretical basis for improving EOR of shale oil in the future. [ABSTRACT FROM AUTHOR]

Copyright of China Surfactant Detergent & Cosmetics (2097-2806) is the property of China Surfactant Detergent & Cosmetics Editorial Office and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

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. [ABSTRACT FROM AUTHOR]

Slickwater fracturing fluids have gained widespread application in the development of tight oil reservoirs. After the fracturing process, the active components present in slickwater can directly induce spontaneous imbibition within the reservoir. Several variables influence the eventual recovery rate within this procedure, including slickwater composition, formation temperature, degree of reservoir fracture development, and the reservoir characteristics. Nonetheless, the underlying mechanisms governing these influences remain relatively understudied. In this investigation, using the Chang-7 block of the Changqing Oilfield as the study site, we employ EM-30 slickwater fracturing fluid to explore the effects of the drag-reducing agent concentration, imbibition temperature, core permeability, and core fracture development on spontaneous imbibition. An elevated drag-reducing agent concentration is observed to diminish the degree of medium and small pore utilization. Furthermore, higher temperatures and an augmented permeability enhance the fluid flow properties, thereby contributing to an increased utilization rate across all pore sizes. Reduced fracture development results in a lower fluid utilization across diverse pore types. This study deepens our understanding of the pivotal factors affecting spontaneous imbibition in tight reservoirs following fracturing. The findings act as theoretical, technical, and scientific foundations for optimizing fracturing strategies in tight oil reservoir transformations. [ABSTRACT FROM AUTHOR]

Copyright of Natural Gas Industry is the property of Natural Gas Industry Journal Agency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

The core pore structure of the target shale oil block was finely characterized using scanning electron microscopy， and a microscopic numerical model of the pore-scale core was constructed to elucidate the intrinsic mechanisms and the main controlling factors of spontaneous imbibition of fracturing fluid within the complex pore space of shale. On this basis， research was conducted on spontaneous imbibition within the fracture-matrix system. The Navier-Stokes （N-S） equations were coupled with the level-set method to track changes in the oil and water interface， thus clarifying the oil and water two-phase flow characteristics and evaluating the efficiency of spontaneous imbibition under the influence of the wettability， viscosity ratio of oil and water， and interfacial tension. The research results revealed that large and small intercommunicating pores in shale form intricate microscopic displacement units under capillary action. When the rock wettability presents a water-wet state， water preferentially infiltrates from the fracture into the smaller pores， expelling oil from larger pores into the fracture， and the produced range of crude oil within the matrix pores is wider， resulting in higher spontaneous imbibition efficiency. When the rock wettability turns oil-wet， crude oil within the small pores cannot be produced during spontaneous imbibition， while the water invades from larger pores， causing crude oil to be displaced from other large pores. This results in a lower spontaneous imbibition efficiency and a small range of crude oil produced in the matrix pores. The spontaneous imbibition in the initial phase is faster but gradually slows over time. Stronger water wettability of shale indicates a lower viscosity ratio of oil and water and higher interfacial tension， resulting in a wider range of crude oil produced within the matrix pores and a cumulative efficiency of spontaneous imbibition of more than 15%.

Nanoemulsion， as a kind of nanoscale colloidal dispersion system， has been widely applied in unconventional oil reservoir development due to its outstanding interfacial properties and enhanced oil recovery effects. Water-in-oil type nanoemulsion systems are prepared based on the low-energy emulsification method. The intrinsic relationships among the static adsorption， wettability alteration， and spontaneous imbibition of nanoemulsion are determined by laboratory experiments， elucidating the mechanism of imbibition and production enhancement of nanoemulsion in tight sandstone oil reservoirs. The laboratory results show that the average droplet size of nanoemulsion is less than 10 nm， which can meet the droplet size requirement of entering most of the pore throat of tight sandstone and can fully diffuse and migrate in the tight pore throat， thus expanding the imbibition range. The critical micelle mass fraction of the nanoemulsion is 0.015%， which can effectively reduce the oil-water interfacial tension to about 2 mN/m. The adsorption isotherm of the nanoemulsion conforms to the Langmuir adsorption model， and the wettability alteration mechanism is mainly adsorption. The nanoemulsion can dissolve the crude oil， further disperse the crude oil through emulsification， reduce the size of oil droplets in the emulsion， and weaken the Jamin effect when oil droplets pass through the pore throat， reducing seepage resistance. Core wettability will affect the spontaneous imbibition recovery， and the imbibition recovery will increase with the increase in core hydrophilicity. There are differences in the oil recovery at the pore scale in different wettability core spontaneous imbibition， and the addition of nanoemulsion can significantly improve the recovery of small pores in the oil-wet core. Meanwhile， increasing nanoemulsion concentration and boundary openness can improve the spontaneous imbibition recovery efficiency. This is mainly because tight sandstone imbibition is dominated by capillary force， increasing boundary openness can expand the contact area of nanoemulsion， and increasing nanoemulsion concentration can improve the wettability alteration and emulsification， thus improving the effect of spontaneous imbibition.

Flow and spontaneous imbibition phenomena in porous media are important for various industrial applications, including printing and medical lateral flow assays. Their quantitative characterization is important to better understand and select the appropriate raw materials. However, standard methods often require time-consuming tests, and/or expensive equipment. Different time scales must be considered, limiting the range of possible characterization tools. A novel experimental approach based on image analysis for characterizing spontaneous imbibition processes is presented. Hence, ultra-fast diffusion may be quantitatively characterized. Models are issued from the literature to consider physical phenomena at small (milliseconds) and medium range (seconds) of time scales. The obtained experimental data fit with theoretical results, providing valuable insights into the understanding of fluid flow behavior at different time scales. Furthermore, the identification of some physical properties for either the fluid, or the substrate, based on the theoretical models are possible, as the contact angle, which remains to be otherwise challenging. This study contributes to bridging the gap between spontaneous imbibition and capillary phenomena at different time scales, their modeling, and a characterization of material and/or fluid properties paving the way for enhanced understanding and control of fluid behavior in porous media. Different papers are considered to illustrate the method.

Cores from shale reservoirs in Subei Oilfield were taken as sample to study the effects of surfactants on the oil displacement efficiency and the main controlling factors of imbibition in shale reservoirs. The TOC analysis and scanning microscope technique （SEM） were used to characterize the pore structure of the core samples. Imbibition experiments under the influence of multiple factors were conducted using nuclear magnetic resonance （NMR） technology. Then the effects of factors were evaluated such as wettability， fractures， porosities， permeability， surfactant concentrations， and types on the imbibition efficiency of shale oil reservoirs， and the distribution characteristics and producing conditions of the oil in different pores were clarified during the imbibition process. The results showed that shale imbibition could be divided into three stages： early stage， middle stage， and late stage. The imbibition rate was high in the early stage， and the imbibition efficiency increased rapidly. The middle stage accounted for the longest period， and the imbibition rate slowed down in the late stage， with the imbibition efficiency tending to be stable. By comparing the effects of different factors on imbibition， it was found that a wetter core indicated more fractures and higher imbibition rate and efficiency. Moreover， a higher porosity and lower permeability led to higher imbibition efficiency. The imbibition efficiency showed an increasing trend with the concentration of surfactants decreasing. The NMR experimental results demonstrated that in the process of shale imbibition， the produced oil of micro-pores was more than that of macro-pores， and changing the imbibition conditions could improve the producing percentage of oil in various pores.

Flow and spontaneous imbibition phenomena in porous media are important for various industrial applications, including printing and medical lateral flow assays. Their quantitative characterization is important to better understand and select the appropriate raw materials. However, standard methods often require time-consuming tests, and/or expensive equipment. Different time scales must be considered, limiting the range of possible characterization tools. A novel experimental approach based on image analysis for characterizing spontaneous imbibition processes is presented. Hence, ultra-fast diffusion may be quantitatively characterized. Models are issued from the literature to consider physical phenomena at small (milliseconds) and medium range (seconds) of time scales. The obtained experimental data fit with theoretical results, providing valuable insights into the understanding of fluid flow behavior at different time scales. Furthermore, the identification of some physical properties for either the fluid, or the substrate, based on the theoretical models are possible, as the contact angle, which remains to be otherwise challenging. This study contributes to bridging the gap between spontaneous imbibition and capillary phenomena at different time scales, their modeling, and a characterization of material and/or fluid properties paving the way for enhanced understanding and control of fluid behavior in porous media. Different papers are considered to illustrate the method. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Recovery Efficiency is the property of Petroleum Geology & Recovery Efficiency and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Tight sandstone reservoir has the characteristics of low porosity, low permeability and strong reservoir heterogeneity, which leads to a rapid decline in single well production after hydraulic fracturing. Adding nano emulsion to fracturing fluid can not only realize the dual function of fracturing and imbibition oil displacement, but also effectively prolong the stable production time of oil wells. In order to improve the understanding of the interaction between nano emulsion and reservoir, this paper based on the basic physical property test and analysis of nano emulsion, macroscopic and microscopic spontaneous imbibition oil displacement experiments, the mechanism of imbibition displacement of nano emulsion in tight sandstone reservoirs and the influence of related factors is clarified. The results show that: ©The particle size of the three types of nano emulsions ranges from 11 to 16 nm, and they can enter the nanopore throats deep in the reservoir, and can achieve good injectivity in tight reservoirs. The anionic AES nano emulsion is superior to cationic ADT and nonionic AEO-9 nano emulsion in terms of injectability, oil-water interfacial tension and wetting modification effect in tight sandstone cores, and the optimal concentration is 0.30 wt%. ©Spontaneous imbibition oil displacement experiments show that the nano emulsion concentration is not the higher the better. Since the nano emulsion adsorption on the solid surface reaches a dynamic equilibrium, the excessive nano emulsion cannot further change the wettability of the solid surface, and the lower oil-water interfacial tension has the opposite effect on the imbibition displacement. ©The migration and gathering of emulsified oil droplets in solution mainly included five processes: Saturated oil core/Nano-surfactant fluid emulsion reaction, Aqueous/Emulsified oil droplets, Emulsified oil droplet gathering phase, Demulsifying and emulsifying oil droplets, Oil phase after demulsification. The generation of remaining oil in porous media is due to the non-uniform wetting modification in different regions. This study further improves the understanding of the mechanism of spontaneous imbibition of nano emulsion in tight sandstone reservoirs. [ABSTRACT FROM AUTHOR]

Low-salinity waterflooding (LSWF) process has gained much attention in recent years as a promising enhanced oil recovery (EOR) method because of its potential for a superior performance, especially through extensive laboratory studies. This study reviews a rigorous and systematic laboratory-to-field approach involving research, discovery and validation using experimental and simulation components. The impact of various ionic compositions on LSWF is evaluated including a fundamental understanding of water geochemistry and the likely geochemical reactions that would occur during the process. Roles of crude oil/brine/rock (COBR) interactions and resulting rock surface charges are investigated as well. In so doing, authors present findings of their studies to support their analysis. Both experimental and simulation components are treated as complementary to each other. Experimental components included reservoir-condition high-pressure high-temperature (HPHT) displacement tests in composite cores using brines of different salinities and specially designed ionic compositions; investigation of wettability alteration—presumably a key LSWF mechanism—in a unique and specifically designed HPHT imbibition cell; Zeta potentiometric studies using a Zeta potentiometer capable of more representative evaluation in brine-saturated whole cores rather than with pulverized samples. Simulation studies involved validation of likely geochemical reactions during LSWF; incorporating oil/brine/rock interactions, and then, linking laboratory data to data from a candidate reservoir to complement the process. Findings of the coreflooding experiments proved conclusively that LSWF with certain specific ionic composition yielded a higher oil recovery. HPHT imbibition tests yielded both visual and quantitative estimations and visual real-time monitoring of how the wettability alteration took place during LSWF and how it was impacted by the degree and magnitude of both temperature and pressure as the vivid variations in the contact angles were clearly captured. Using a whole reservoir core rather than pulverized samples, Zeta potentiometric studies enabled an investigation of the charging behavior at the rock-water interface at various salinities. A new method to estimate Zeta potential in high-salinity environment was developed and validated, and it conclusively proved that rock surface charge played a vital in the LSWF process. The simulation studies included incorporation of experimental data generated during the study, identification of a set of likely geochemical reactions during the process and complementary field data to study the LSWF performance under various conditions and constraints. A conceptual "laboratory-to-field" approach that can contribute to designing a more efficient LSWF process with optimized ionic chemistry has been proposed based on results and analysis from this study and characteristics of similar types of reservoir targeted. [ABSTRACT FROM AUTHOR]

Spontaneous imbibition is of great significance for the water injection development of tight sandstone reservoirs. Ideally, the oil displacement efficiency of spontaneous imbibition can reach over 50% . Currently, domestic and foreign scholars have not conducted systematic and in-depth research on the spontaneous static imbibition of tight reservoirs, and experimental models cannot truly and comprehensively reflect the influence of reservoir properties and fluids on spontaneous imbibition. In response to the above issues, natural and artificial cores of typical block tight reservoirs were designed and manufactured, and multi factor spontaneous static infiltration experiments were conducted on tight reservoirs. The effects of infiltration time, core length, core porosity, formation water mineralization degree, core permeability, initial water saturation, interfacial tension, and wettability on the efficiency and speed of infiltration and displacement of tight reservoirs were systematically studied, quantitative evaluation was conducted on the variation patterns of oil displacement effects by infiltration under different factors. The results indicate that the main factors affecting oil displacement by infiltration are wettability, porosity, permeability, and interfacial tension, followed by initial water saturation. The influence of core length and formation water salinity on oil displacement efficiency by infiltration is the weakest, with the least intensity. The research results provide experimental and theoretical basis for effective water injection development in tight reservoirs. [ABSTRACT FROM AUTHOR]

Surfactants are usually added to the fracturing fluids to enhance the imbibition between fractures and matrix, which is an important measure to improve oil recovery. The popular perspective believes that altering water-wet conditions and keeping a relatively high IFT value are the keys to achieving the imbibition process. Recently, both indoor experiments and oilfield practice have shown that the surfactant systems with ultra-low IFT can also achieve imbibition and effectively recover oil from the matrix. For the problem that the imbibition mechanism of ultra-low IFT system is still unclear, the wettability alteration system, ultra-low IFT system, and emulsification system are constructed, the characteristics of imbibition systems and imbibition recovery are clarified, the oil-water transport patterns and dominant mechanisms of wettability alteration system and ultra-low IFT system with excellent emulsification are revealed by using mathematical models. The results show that the applicability range of the wettability alteration system and ultra-low IFT system with excellent emulsification is different. The wettability alteration system has better imbibition effects under 0.1 mD, but the ultra-low IFT system with excellent emulsification performs better under 0.01 mD and 0.001 mD. The imbibition process of the wettability alteration system is a layer flow pattern dominated by capillary force, the rate at which the wetted phase fills the pores decreases rapidly with the decrease of permeability, and the imbibition recovery decreases significantly from about 45% to 18%. The micro-nano emulsions can be formed by the ultra-low IFT system with excellent emulsification, which has a special emulsification and diffusion mechanism. In the early stage, oil is mainly recovered by emulsification and diffusion, in the late stage, the layer flow pattern of IFT reduction and wettability alteration gradually works, and the imbibition recovery decreases from about 38% to 23%. The emulsification and diffusion mechanism of the ultra-low IFT system with excellent emulsification is suitable for the imbibition of tighter reservoirs, and has a broad application in fracturing and stimulation of tight reservoirs. [ABSTRACT FROM AUTHOR]

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This study used the diethylene triamine pentaacetic acid (DTPA)-seawater (SW) system to modify the sandstone rock wettability and enhance oil recovery. The investigation involved conducting wettability measurement, Zeta potential measurement, and spontaneous imbibition experiment. The introduction of 5% DTPA-SW solution resulted in a significant decrease in the rock-oil contact angle from 143° to 23°, along with a reduction in the Zeta potential from −2.29 mV to −13.06 mV, thereby altering the rock surface charge and shifting its wettability from an oil-wet state to a strongly water-wet state. The presence or absence of potential determining ions (Ca2+, Mg2+, SO42−) in the solution did not impact the effectiveness of DTPA in changing the rock wettability. However, by tripling the concentration of these ions in the solution, the performance of 5% DTPA-SW solution in changing wettability was impaired. Additionally, spontaneous imbibition tests demonstrated that the 5% DTPA-SW solution led to an increase in oil recovery up to 39.6%. Thus, the optimum mass fraction of DTPA for changing sandstone wettability was determined to be 5%.

Tight sandstone reservoir has the characteristics of low porosity, low permeability and strong reservoir heterogeneity, which leads to a rapid decline in single well production after hydraulic fracturing. Adding nano emulsion to fracturing fluid can not only realize the dual function of fracturing and imbibition oil displacement, but also effectively prolong the stable production time of oil wells. In order to improve the understanding of the interaction between nano emulsion and reservoir, this paper based on the basic physical property test and analysis of nano emulsion, macroscopic and microscopic spontaneous imbibition oil displacement experiments, the mechanism of imbibition displacement of nano emulsion in tight sandstone reservoirs and the influence of related factors is clarified. The results show that: ①The particle size of the three types of nano emulsions ranges from 11 to 16 nm, and they can enter the nanopore throats deep in the reservoir, and can achieve good injectivity in tight reservoirs. The anionic AES nano emulsion is superior to cationic ADT and nonionic AEO-9 nano emulsion in terms of injectability, oil-water interfacial tension and wetting modification effect in tight sandstone cores, and the optimal concentration is 0.30 wt%. ②Spontaneous imbibition oil displacement experiments show that the nano emulsion concentration is not the higher the better. Since the nano emulsion adsorption on the solid surface reaches a dynamic equilibrium, the excessive nano emulsion cannot further change the wettability of the solid surface, and the lower oil-water interfacial tension has the opposite effect on the imbibition displacement. ③The migration and gathering of emulsified oil droplets in solution mainly included five processes: Saturated oil core/Nano-surfactant fluid emulsion reaction, Aqueous/Emulsified oil droplets, Emulsified oil droplet gathering phase, Demulsifying and emulsifying oil droplets, Oil phase after demulsification. The generation of remaining oil in porous media is due to the non-uniform wetting modification in different regions. This study further improves the understanding of the mechanism of spontaneous imbibition of nano emulsion in tight sandstone reservoirs.

Abstract Nano-emulsions stabilized by nonionic surfactants have the characteristics of ultra-low interfacial tension (IFT) and altered wettability in ultra-low permeability reservoirs. Thus, in this work, a new nanoemulsion is proposed to enhance spontaneous imbibition recovery in ultra-low permeability reservoirs. The nanoemulsion is prepared using n-dodecane, Tween-20, and coconut oil acid diethanolamine n-amyl alcohol. The effects of temperature and salinity on particle size, IFT, and wettability alteration performance of the nanoemulsions were systematically studied. Experimental results show that the particle size of nanoemulsions increases with salinity, and the highest level is up to 100 nm, while an increase in temperature is beneficial to the formation of smaller nanoemulsions. The IFT of the nanoemulsion system can be reduced to an ultra-low level (10–3 mN/m) when the salinity is lower than 50,000 mg/L. As for the wettability alteration property of a nanoemulsion system, an increase in temperature can improve its performance, but variations in salinity seldom have any effects. At 56 °C and 30,000 mg/L salinity, the spontaneous imbibition recovery of 1.00 wt% nanoemulsion can reach 53.8% under the synergistic effect of three mechanisms: extremely small droplet size, excellent wettability alteration performance, and ultra-low IFT. These three mechanisms work together to significantly improve the displacement efficiency of ultra-low-permeability reservoirs. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing technology can improve the geologic structure of unconventional oil and gas reservoirs, yielding a complex fracture network resulting from the synergistic action of hydraulic and natural fractures. However, the impact of spontaneous imbibition associated with hydraulic fracture propagation on the reservoir matrix remains poorly understood. In this study, combining the Cahn-Hilliard phase field method with the Navier-Stokes equations, pore-scale modeling was employed to capture the evolution of the oil-water interface during dynamic spontaneous imbibition for hydraulic fracture propagation in a two-end open mode. This pore-scale modeling approach can effectively circumvent the challenges of conducting spontaneous imbibition experiments on specimens partitioned by hydraulic fractures. A direct correlation was established between the pressure difference curve and the morphology of discharged oil phase in the primary hydraulic fracture, providing valuable insights into the distribution of oil phase in spontaneous imbibition. Furthermore, it was shown that secondary hydraulic fracture propagation expands the longitudinal swept area and enhances the utilization of natural fractures in the transverse swept area during spontaneous imbibition. When secondary hydraulic fracture propagation results in the interconnection of upper and lower primary hydraulic fractures, competitive imbibition occurs in the matrix, leading to reduced oil recovery compared to the unconnected models. Our results shed light upon the spontaneous imbibition mechanism in porous media with hydraulic fracture propagation, contributing to the refinement and application of hydraulic fracturing techniques. [ABSTRACT FROM AUTHOR]

Shale oil can be extracted from shale by using interconnected pore networks. The migration of hydrocarbon molecules within the shale is controlled by pore connectivity. However, assessing the pore connectivity of shale oil reservoirs is uncommon. To characterize pore connectivity and clarify its controlling factors, this study used spontaneous imbibition (SI) combined with nuclear magnetic resonance (NMR) T2 and T1-T2 technologies on shale oil reservoirs selected from the Shahejie Formation in the Dongying Sag, Bohai Bay Basin. According to the findings, the SI processes of shales include fast-rising, slow-rising, and stable stages. The fast-rising stage denotes pore connectivity. The shales studied have poor connectivity, with lower imbibition slopes and connected porosity ratios, but large effective tortuosity. During the SI process, micropores have the highest imbibition saturation, followed by mesopores and macropores. Furthermore, n-dodecane ingested into micropores appears primarily as adsorbed, whereas n-dodecane appears primarily as free states in mesopores and macropores during the SI process. The pore connectivity of the shales under study is primarily controlled by inorganic minerals. Quartz and feldspar develop large and regular pores, resulting in better pore connectivity, whereas clay minerals and calcite with plenty of complex intragranular pores do not. Organic matter negatively influences pore connectivity because the dissolution of calcite by organic acid produced during hydrocarbon generation leads to a more complex and heterogeneous pore structure. This study sheds light on the pore connectivity and controlling factors of the shale oil reservoir and aids in the understanding of shale oil mobility. [ABSTRACT FROM AUTHOR]

Shale oil can be extracted from shale by using interconnected pore networks. The migration of hydrocarbon molecules within the shale is controlled by pore connectivity. However, assessing the pore connectivity of shale oil reservoirs is uncommon. To characterize pore connectivity and clarify its controlling factors, this study used spontaneous imbibition (SI) combined with nuclear magnetic resonance (NMR) T2 and T1-T2 technologies on shale oil reservoirs selected from the Shahejie Formation in the Dongying Sag, Bohai Bay Basin. According to the findings, the SI processes of shales include fast-rising, slow-rising, and stable stages. The fast-rising stage denotes pore connectivity. The shales studied have poor connectivity, with lower imbibition slopes and connected porosity ratios, but large effective tortuosity. During the SI process, micropores have the highest imbibition saturation, followed by mesopores and macropores. Furthermore, n-dodecane ingested into micropores appears primarily as adsorbed, whereas n-dodecane appears primarily as free states in mesopores and macropores during the SI process. The pore connectivity of the shales under study is primarily controlled by inorganic minerals. Quartz and feldspar develop large and regular pores, resulting in better pore connectivity, whereas clay minerals and calcite with plenty of complex intragranular pores do not. Organic matter negatively influences pore connectivity because the dissolution of calcite by organic acid produced during hydrocarbon generation leads to a more complex and heterogeneous pore structure. This study sheds light on the pore connectivity and controlling factors of the shale oil reservoir and aids in the understanding of shale oil mobility. [ABSTRACT FROM AUTHOR]

Surfactant-assisted spontaneous imbibition is an important mechanism in enhanced oil recovery by capillary pressure in low permeability and tight oil reservoirs. Though many experiments have been conducted to study the mechanism of enhanced oil recovery by surfactant-assisted spontaneous imbibition, the effects of surfactant type, concentration, and temperature have not been well studied. Using tight sandstone outcrop core samples with similar permeability and porosity, this paper experimentally studies surfactant-assisted spontaneous imbibition using three different surfactant types, i.e., sodium dodecylbenzene sulfonate (SDBS), cocamidopropyl betaine (CAB), and C12–14 fatty alcohol glycoside (APG). In addition to the type of surfactant, the effect of the surfactant concentration and the temperature is also investigated. The study results show that the ultimate oil recovery of spontaneous imbibition with formation water and denoised water is about 10%. Surfactant can significantly improve the oil recovery of spontaneous imbibition by reducing the interfacial tension between oil and water, emulsifying crude oil and improving oil mobility. APG showed better performance compared to SDBS and CAB, with a maximum oil recovery factor of 36.19% achieved with formation water containing 0.05% APG surfactant. Lower concentrations (0.05% APG) in the formation water resulted in a higher oil recovery factor compared to 0.1% APG. Increasing temperature also improves oil recovery by reducing oil viscosity. This empirical study contributes to a better understanding of the mechanism of surfactant-assisted spontaneous imbibition and enhanced oil recovery in tight oil reservoirs.

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 (

Nanoparticles as novel EOR agents are used to enhance the production of crude oil. This improvement is due to the improved surface activity at the crude oil–brine–rock interface and disjoining pressure. The aim of this study was to examine the role of the greenly synthesized nanocomposites (NCs) in EOR applications. For this purpose, Fe3O4/mineral–soil NCs were synthesized from the extract of Euodia hortensis plant and characterized using several analytical techniques. Nanofluids were prepared from dispersing the synthesized NCs in distilled water at different ranges of concentrations from 250 to 1000 ppm. The role of the developed nanofluids on the IFT reduction, wettability alteration and oil recovery was experimentally examined. Different IFT values of crude oil with the presence of nanofluids were estimated, and the minimum IFT of 3.69 mN/m was obtained with NF1000 solution formulated from mixing 1000 ppm within the distilled water, while the wettability was highly altered toward the strong water-wet system from 99.15 to 22° contact angle when dispersing 1000 ppm of NCs in water. In addition, NF1000 solution was enabled to improve oil recovery by 11.28% original oil recovery (OOIP) under the spontaneous imbibition process. [ABSTRACT FROM AUTHOR]

In the development of shale gas, the flowback rate of the fracturing fluid is usually low and quite unequal, which affects the recycling of fracturing fluid and becomes potential pollutants to water resources. Spontaneous imbibition has been considered as one of the main reasons for this phenomenon. To discover the mechanism and the factors controlling the spontaneous imbibition of fracturing fluid into shale reservoirs, laboratory experiments were carried out. The results showed that the amount of water imbibed in rock samples had a good linear relationship with the square root of time, and the imbibed amount in the samples containing smectite was much larger than those containing few- or no-smectite mineral at the same conditions. For example, the samples of the size of φ30 × 30 mm at 70 °C, the imbibed amounts was 3.7964% and 2.8159% for Type A and Type B rocks, which were much smaller than that of 9.5068% for Type C rock. In the case of smectite containing samples, imbibition model was divided into three stages, which was controlled by the capillary force from micro- and nano-scale pores inside the rock and simultaneous hydration-related swelling of the clay. In the case of few- or no-smectite containing samples, imbibition mainly depended on the capillary force. The sample size of rocks was the main variable controlling the imbibition rate, but not the amount. The temperature affected the imbibition rate and amount through controlling the hydration-related swelling of the clay. At the temperature of 50, 70 and 90 °C, the imbibition rates were 0.3140, 0.4328 and 0.7013 h−1/2 in the first stage, 0.1237, 0.1456 and 0.2581 h−1/2 in the second stage, and − 0.0544, − 0.2052 and − 0.3695 h−1/2 in the third stage; the maximum imbibition amounts were 10.4374%, 9.5068% and 9.3970%. The KCl solution inhibited the hydration-related swelling of the smectite. The hydration-related smectite swelling could be observed from the SEM images, and could also be confirmed by the cracks in the rocks. This study helps better analyze and understand the environmental behavior of fracturing fluid in formations, and promote the recycling of fracturing fluid in shale gas production. [ABSTRACT FROM AUTHOR]

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. [ABSTRACT FROM AUTHOR]

Copyright of Petroleum Geology & Oilfield Development in Daqing is the property of Editorial Department of Petroleum Geology & Oilfield Development in Daqing and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Based on the theory of Backly-Leverett water flooding, a one-dimensional low permeability imbibition mathematical model was established,considering the gravity, capillary force, viscous force and threshold pressure gradient, and simultaneously considering the different characteristics of the same direction imbibition resistance between before and after the leading edge of wetting phase breakthrough the outlet, When the calculated curve result of the imbibition rate and time is consistent with the experimental curve result of the imbibition in the same direction the mathematical model was utilized to obtain the values and the changes characteristic of the threshold pressure gradient in the imbibition process by adjusting the coefficient and the index of oil-water phase in the threshold pressure gradient equation. The results of the five groups experiments and calculations show that the mathematical model can effectively calculate the threshold pressure gradient of spontaneous imbibition. It can be seen that the establishment of the mathematical method is of great significance to further improve the theory of imbibition and enrich the calculation method of starting pressure gradient. [ABSTRACT FROM AUTHOR]

Adsorption of water by desaturated shale could be misinterpreted as osmotic swelling. If the saturation state of shale is not known, one should not presume that osmosis is responsible for water adsorption and resultant swelling. Such presumption may overlook the fact that spontaneous imbibition could be responsible for most water adsorption and apparent swelling in desaturated shale. This work examines mechanisms responsible for water adsorption by desaturated shale and proposes a superimposing technique that separate water adsorption by imbibition from that by chemical and diffusion osmosis. Also, this work investigates the impact of desaturation on physicochemical and mechanical properties of shale using gravimetric measurements, ASTM methods., X-ray diffraction and pore fluid's chemical composition analysis. Results show that water transport in desaturated shale is falsely attributed to osmotic swelling and that spontaneous imbibition is the main force driving water transport. In the absence of diffusion osmosis and hydraulic flow, amount of water adsorbed via spontaneous imbibition is 2–3 times higher than that adsorbed by chemical osmosis. For desaturated shale, results revealed that reduction in water activity is non- linearly proportional to desaturation (drying) time. Results also showed that compressive strength and Young's modulus increased non-linearly as moisture content decreased. [ABSTRACT FROM AUTHOR]

The phenomenon of spontaneous imbibition in porous media is of great importance in many scientific and technical fields, such as oil reservoirs and environmental engineering. In this paper, a combination of theoretical studies and numerical simulations has been used to investigate the two-phase spontaneous imbibition law in a single capillary tube. A mathematical model taking into account the dynamic contact angle was used to characterize two-phase spontaneous imbibition within a single capillary tube. The accuracy of the model was verified against the Lucas–Washburn model and relevant experimental data. The imbibition distance calculated by the mathematical model considering the dynamic contact angle correlates well with the experimental data. The results show that during the spontaneous imbibition process, the dynamic contact angle increases as the imbibition velocity increases. Moreover, a simulation of spontaneous imbibition in a single capillary tube based on the Navier–Stokes equation has been performed in order to investigate the effect of different two-phase viscosity ratios on the accuracy of the model. It was found that the larger the viscosity ratio of the two phases, the smaller the difference in the imbibition distance between the mathematical model considering the dynamic contact angle and the simulation results. Overall, our model reveals the effect of dynamic changes in contact angle on the spontaneous imbibition process and can accurately characterize the two-phase spontaneous imbibition process in porous media. Article Highlights: A capillary two-phase spontaneous imbibition model with dynamic contact angle is proposed. Quantitative comparison of dynamic and static contact angle models. Two-phase flow simulation in a single capillary with different two-phase viscosity ratios. [ABSTRACT FROM AUTHOR]