Imbibition Experiments Research Articles

Liquid Permeability Determination from Vacuum Imbibition in Tight/Shale Core Plugs

Liquid permeability is a key petrophysical parameter that quantifies the ability of a liquid to flow through porous rock/soil and can be used in determining the efficiency of many subsurface processes, including enhanced hydrocarbon recovery, groundwater transport, carbon dioxide geostorage, underground hydrogen storage, etc. However, it is time-consuming (usually >16–240 h) and challenging to measure the liquid permeability for tight/shale rocks, particularly when the permeability is 100 nD or lower. The objective of this study is to develop a rapid and simple approach to determine liquid (brine or oil) permeability in tight siltstones/shales. Specifically, the developed method is based on the combination of one-dimensional (1D) vacuum imbibition experiments in tight/shale core plugs and a modified Lucas–Washburn model. For our proof-of-concept study, the results have demonstrated that (1) only 44–116 h are required to determine the liquid permeability (98–608 nD) for the analyzed samples from the Montney and Yanchang Formations; and (2) the acquired brine permeability was 28.3–28.5% lower than the slip-corrected nitrogen (N2) permeability derived from the pulse-decay permeability tests. This is the first attempt to determine the absolute permeability of a liquid according to a 1D vacuum imbibition experiment and theory. This study provides a promising technique for the fast characterization of ultratight formation permeability of around 100 nD.

Percolation transitions of spontaneous imbibition in fractional-wet porous media

Percolation transition is an important scientific question for characterizing complex two-phase flow phenomena in fractional-wet porous media composed of different wetting grains. Recent studies have shown significant transitions of fluid distribution and pressure system in fractional-wet porous media by changing wettability proportion. However, very few studies have systematically investigated controlling factors of percolation transition in spontaneous imbibition. Additionally, there is a lack of comprehensive knowledge and experimental observations about imbibition recovery and dynamic imbibition phenomena (including imbibition time, imbibition rate, and induction time) in fractional-wet porous media. In this study, these knowledge gaps are filled through a series of water imbibition experiments for fractional-wet artificial porous media with different water-wet proportions, three pore diameters, and two wettability heterogeneities. The results show that pore diameter and wettability heterogeneity are influential factors for percolation transition. Decreasing water-wet proportion results in the emergence of induction time, as well as the absences of transition and late imbibition stage, small pore radius enhances these negative impacts. Under strong wettability heterogeneity, relationship of water-wet proportion and imbibition recovery follows the classical percolation theory containing two percolation transitions. Small pore diameter retards percolation transitions, and weakens fluid displacements of the transition stage and late stage in the partial imbibition. Moreover, effects of water-wet proportion on dynamic imbibition phenomena exhibit exponential relationship resulted from transition of pathway type. Additionally, through decreasing wettability heterogeneity, three percolation transitions and an optimal imbibition ability are achieved, thus hydrophilization of hydrophobic pore is advantageous for water imbibition. These intriguing findings can broaden current knowledge about spontaneous imbibition in fractional-wet porous media.

Modeling bimodal capillary bundle two-phase flow in the shale matrix for predicting water saturation distribution

In gas field development, the distribution of water saturation is one of the most effective estimated two-phase flow law methods for the shale matrix. Water saturation has been widely studied; however, few studies exist to show that water saturation distribution is related to pore diameter distribution of shale matrix. Furthermore, based on experimental observations, imbibition and gas-driven water flow nuclear magnetic resonance experiments also show the phenomenon. Therefore, the objective of this work is to build a bimodal capillary bundle two-phase flow model to investigate the relation of water saturation with pore diameter distribution of shale matrix. Firstly, this work combines the bimodal pore size distribution with the truncated Gaussian distribution theory to present the shale matrix pore. Moreover, we develope a shale core imbibition model and a gas-driven water flow model to predict the distribution of the water saturation distribution during the two-phase flow, by using the gas-water two-phase seepage theory. Shale imbibition and gas-driven water flow experiments are carried out on shale samples from the underground Longmaxi Formation. The relative error of distribution curve of water saturation predicted by model and experiments has been calculated. At the initial stage of imbibition the shale matrix core is not completely dried model values do not match the measured values, but, the relative error is stable at 1–2% at the late stage of imbibition. The average relative error is 2.13% in gas-driven water flow process. As a result, the shale imbibition model and the displacement model can accurately characterize the two-phase (gas-water) flow process, providing a theoretical support to study the two-phase flow in the shale matrix.

Investigation of the effect of diethylene triamine pentaacetic acid chelating agent as an enhanced oil recovery fluid on wettability alteration of sandstone rocks

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%.

Experimental Mechanism for Enhancing Oil Recovery by Spontaneous Imbibition with Surfactants in a Tight Sandstone Oil Reservoir

This study aims to investigate the mechanism behind surfactant enhanced oil recovery under reservoir conditions through experiments on spontaneous imbibition with surfactants. The tight sandstone samples are characterized using cast thin section (CTS), high-pressure mercury intrusion (HPMI), and nuclear magnetic resonance (NMR) to determine their clay mineral composition, pore size distribution, and fluid distribution. Spontaneous imbibition experiments are then conducted using formation water and surfactant solutions as imbibition liquids, with three different types of surfactants─dodecylbenzene sulfonate (DBS), sodium dodecyl sulfate (SDS), and ammonium bromide─at two different concentrations, each to examine the effect of surfactant type. Additionally, the interfacial tension (IFT) between crude oil and different imbibition solutions is measured, and the contact angles of an oil droplet on the core surface in air, formation water, distilled water, and surfactant solution are determined. Finally, the effects of IFT, rock wettability, formation water salinity, and core permeability on final oil recovery by spontaneous imbibition are analyzed. The results indicate that surfactant-assisted spontaneous imbibition primarily operates through IFT reduction, wettability alteration, and emulsification of crude oil. However, ultralow IFT may lead to low ultimate oil recovery. To increase the ultimate oil recovery of spontaneous imbibition, reducing the salinity of the surfactant solution and creating microfractures can be effective strategies.

Static and dynamic adsorption of supramolecular surfactant for oil recovery in high temperature and salinity conditions

AbstractThe adsorption of a supramolecular surfactant formed by the non‐covalent interactions among sodium (E)‐dodec‐2‐ene‐1‐sulfonate, sodium 3‐hydroxydodecane‐1‐sulfonate and 3‐[(3‐dodecanoylamidopropyl)dimethylazaniumyl]‐2‐hydroxypropane‐1‐sulfonate onto limestone under static and dynamic conditions in the presence of seawater and connate water is presented. In the static test at 70°C and atmospheric pressure, the adsorption capacity of the saturated monolayer was 8.65 mg/g for seawater and 4.05 mg/g for connate water. This behavior was associated with the increase of the critical micellar concentration from 217 ppm in seawater to 672 ppm in connate water, which is related to the capacity of the supramolecular surfactant to form complexes at high salinity and hardness. The dynamic experiment was carried out at 130°C with a pressure of 16,500 kPa, a flow rate of 90 mL/h and a dose of 2000 ppm of the surfactant. An adsorption of 0.230 mg/g was found in seawater, while a value of 0.109 mg/g was obtained in connate water, consistent with the static experiment. In addition, spontaneous imbibition experiments for connate and connate water with 2000 ppm of surfactant showed an increase in the oil recovery factor from 3% to 17% in the presence of surfactant at 100°C. It was observed that the rock changed from oil‐wettable to water‐wettable, indicating that the supramolecular complex retains its capability to form the monolayer on the rock surface. In contrast to the ionic and cationic conventional surfactants, the experimental evidence indicates that the surfactant preserves its properties under the extreme conditions found in mature Mexican carbonate reservoirs.

Experimental Study on the Distribution and Height of Spontaneous Imbibition Water of Chang 7 Continental Shale Oil

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.

Impacts of mineralogy and pore structure on spontaneous imbibition in tight glutenite reservoirs

Spontaneous imbibition plays a critical role in the two-phase flow in hydraulic fractures of tight reservoirs. Although massive contributions have been devoted to addressing this issue, very few studies focus on tight glutenite reservoirs, which is an important member of tight reservoirs. As a result, the imbibition mechanism and its influencing factors are still unclear, several key factors fail to be captured, and in-depth analyses are lacking in spontaneous imbibition for tight glutenite reservoirs. In light of the current knowledge gaps, this study conducted a series of water imbibition experiments, combined with X-ray diffraction tests, thin section and scanning electron microscopy observations, high-pressure mercury intrusion experiments, and corrected contact angle experiments to reveal the impacts of rock mineralogy and pore structure on spontaneous imbibition, and significance levels of main influential factors were determined by grey relation analysis. Results show that: 1) the hydrophilic mineral that exceeds 94% provides a strong driving force for water imbibition. Intergranular pore and gravel boost imbibition recovery through enhancing imbibition and drainage ability, respectively. However, intergranular dissolved pore is unfavorable for water imbibition due to extremely rough surface and small radius. Medium-size sand also has a negative impact because of incremental flow tortuosity and pore coordination number reduction; 2) A large percentage of micropore and macropore can significantly enhance imbibition rate and recovery. Three fractal characteristics in micropore, identified for the first time, complicates water imbibition process in tight glutenites. A critical total fractal dimension of micropore is observed, above which the negative influence magnitude of complex pore structure on spontaneous imbibition gradually decreases; 3) Water imbibition sequence and diversities of imbibition phenomena are significantly affected by the combination of multi-fractal dimensions and heterogeneous distributions of pore volume in different fractal regions. The superposition of smallest fractal dimension and the largest pore volume leads to the best imbibition recovery in the transition stage of imbibition, which is an extremely time-consuming process; 4) Upon grey relation analysis, oil drainage ability is the most critical factor for water imbibition in tight glutenites. These observations deepen our understanding of the distinctive imbibition mechanisms in tight glutenite reservoirs.

Hydration of Transitional Shale and Evolution of Physical Properties Constrained by Concurrent NMR and Acoustic Observations

Hydration state is a key factor affecting the pore structure and mechanical properties of shale that directly impacts the migration and then production of geofluids. We quantify the impact of the hydration state on physical properties through spontaneous imbibition experiments constrained by concurrent nuclear magnetic resonance (NMR) and acoustic observations as diagnostics of response. The long-duration experiments (24 days) are on samples from the Permian Shanxi Formation of the Ordos Basin, complemented by measurements of composition and physical properties. These shales primarily comprise quartz and clay minerals with intraparticle pores present within the clay minerals. The NMR T2 spectra indicate that mesopores (2–50 nm) comprise ∼80% of the total pore space. The imbibition rate decreases by a factor of 3 from 0.08 g/h to a stable rate of 0.03 g/h from the 1st to the 24th hour. This is accompanied by a 10% decrease in the deformation modulus from 44 to 40.3 GPa over 24 days. The reduction in the modulus is consistent with observations of the shedding and spalling of hydrophilic quartz particles from the unconstrained surface and the generation of fractures. Reduction in the imbibition rate is consistent with the swelling followed by squeezing of clay minerals and the corresponding reduction in pore diameters in the confined core of the sample, together with the reduction in saturation gradients with the progress of imbibition. Understanding the mechanisms and effects of hydration on the pore structure and mechanical properties is important in understanding the shale hydration process and defining diagnostic (acoustic and NMR) signatures that may be used in reservoir surveillance.

Influence of rock permeability and surface conditioning on carbonate wettability: A link between contact angle and Amott-index

The wettability of crude oil/brine/rock system is of great importance in determining oil recovery during water displacement processes. The wetting behavior of rocks has traditionally been assessed via a range of experimental techniques such as the Amott tests and contact angle measurements. While the Amott wettability is known to be influenced by a range of factors, still the impact of rock permeability, rocks surface/saturation condition and initial water saturation remains unclear. Furthermore, a link between Amott wettability and contact angle is missing which is vital to characterize macroscopic vs. core scale wettability. Therefore, in this study, we investigated the effect of permeability, rocks surface/saturation condition and initial water saturation on Amott tests and contact angle measurements using Indiana limestone. We further attempt to experimentally explore the relationship between the contact angle and Amott-Harvey wettability index (IAH) for different rocks. We demonstrated that, in addition to surface texture (roughness) and surface chemistry (heterogeneity), rock surface wetting behavior depends also on the rock permeability and surface/saturation condition (Dry,Sw=1,Sor,SwirrandSo=1). Moreover, a comparison of the observed values for the Amott and contact angles, showed that only when the rock has moderate to high permeability (up to 15.17 mD) will the Amott index corresponds to the wetting state estimated using contact angle method. The influence of several factors on wettability via IAH and contact angle is evident. While permeability demonstrated a positive correlation with wettability, Sor exhibited a negative correlation. For water-wet rocks, contact angle showed weak positive correlation with IAH, while negative correlations were observed in the case of intermediate- and oil-wet rocks. In addition, exceptions were found in the correlations; unlike the IAH, contact angle is weakly correlated with both Sor and Swi obtained from the imbibition experiments. Lastly, spontaneous imbibition time becomes slower and tends to underestimate IAH as rock permeability decreases. The findings from this study will thus broaden the understanding of the interplay of different petrophysical parameters and the relationship between different wetting indices.

The Dormancy Types and Germination Characteristics of the Seeds of Berberis koreana Palibin, an Endemic Species of Korea

Berberis koreana Palibin is an endemic plant native to Korea. In this study, we aimed to study the seed germination of this species using a water imbibition experiment, gibberellic acid (GA3) treatment (0, 10, 100, or 1000 mg·L−1), cold stratification (0, 2, 4, 8, or 12 weeks at 4 °C), move-along experiment, and phenology studies. In the water imbibition experiment, the weight of the seeds increased by more than 120% in 24 h. An analysis of the internal and external morphological characteristics of the seed revealed that the embryo was already fully grown from the fruit and did not grow thereafter. The final germination percentages for the cold stratification at 0, 2, 4, 8, and 12 weeks at 4 °C were 12 ± 3.65, 32 ± 9.09, 59 ± 1.00, 59 ± 9.59, and 71 ± 1.91%, respectively. In the move-along experiment and phenology studies, a longer low-temperature treatment period resulted in a higher germination percentage. However, the GA3 treatment had little effect on the seed germination. Our results indicate that B. koreana exhibits an intermediate physiological seed dormancy.

High-Throughput Nanoliter Sampling and Direct Analysis of Biological Fluids Using Droplet Imbibition Mass Spectrometry.

A high-throughput droplet imbibition mass spectrometry (MS) experiment is reported for the first time that allows direct analysis of ultra-small volumes of complex mixtures. In this experiment, an array of optimized tips of glass capillaries containing the analyte solution is sampled by rapidly moving charged microdroplets, which picks up (i.e., imbibes) the analyte and transfers it to a proximal mass spectrometer. The advantages associated with this droplet imbibition experiment include (1) ultra-small sample consumption (1.3 nL/min), which reduces the matrix effect in complex mixture analysis, and (2) high surface activity, which eliminates ion suppression effects caused by competition for the space charge on the droplet surface. Collectively, the enhanced surface effect and small flow rates dramatically increase the sensitivity of the droplet imbibition MS approach. This was experimentally shown by constructing calibration curves for cocaine analysis in human raw urine and whole blood, achieving 2 and 7 pg/mL limits of detection, respectively. The high-throughput feature was demonstrated by analyzing five structurally different compounds in 20 s intervals. With the measured flow rate of 1.3 nL/min on a 5 μm glass tip size, the results described in the current study showcase droplet imbibition MS to be a powerful and high-throughput alternative for conventional nano-electrospray ionization (flow rate <100 nL/min), which is the most efficient method for transferring small sample volumes to mass spectrometers.

Proppant embedment in rough fractures considering shale hydration

Shale reservoirs are significantly hydrated owing to the presence of large amounts of clay minerals. However, the mechanical properties of the hydration layer on the rock surface decline, resulting in severe proppant embedding. In this study, we established a mathematical model of proppant embedding based on the rock surface indentation experiment and Hertz contact theory, carried out shale spontaneous imbibition experiments to develop a mathematical model for the hydration depth, and built a proppant embedded mathematical model of rough fractures considering the elastic–elastoplastic–plastic whole-stage. We analyzed the proppant embedding laws by considering the hydration layer under closing stress. Our observations were as follows: the surface mechanical properties of hydrated shale decreased by 35.7% after 15 days of hydration intrusion; spontaneous imbibition water absorption in horizontal bedding was greater than that in the vertical bedding; the degree of proppant embedding increased with the increase in shale hydration time. As the closing stress increased, the degree of proppant embedding in the slick water liquid shale became significantly weaker than that in the distilled water liquid shale. This research provided a theoretical basis for shale reservoir fracturing design and fracture effectiveness analysis after fracturing.

Effect of pressure pulse stimulation on imbibition displacement within a tight sandstone reservoir with local variations in porosity

The pressure pulse technique has been suggested as a potential method to enhance oil recovery from tight oil reservoirs. To investigate the variations in the pore structure of tight sandstone samples from the Triassic Yanchang Formation in the Ordos Basin (China), a combination of casting thin sections, high-pressure mercury intrusion, and nuclear magnetic resonance was employed. Imbibition experiments combined with the imposed pressure pulse were performed to quantitively examine the effects of the primary parameter relevant to pressure pulse on displacement efficiency and oil recovery contribution of the various pore systems. By testing the effect of different pulse pressures, it was investigated which mechanisms controlled the oil recovery. It was thus found that a series of four pulses could enhance the oil recovery significantly, and that the pressure should be 2 MPa，4 MPa and 6 MPa for the three investigated types of reservoirs, respectively. In these cases, their corresponding pulse times are 48 h, 96 h, and 144 h, respectively. The oil displacement efficiency increases with the increasing pressure and pulse cycles; however, the amplitude in oil recovery gradually diminishes. It was also found that an increasing pulse pressure is favorable for mobilizing oil that is trapped in pore spaces, especially for the low-permeability samples, despite the longer pulse time. Employing the pressure pulse method could markedly improve the imbibition oil recovery, and the simultaneous pulse pressure with imbibition leads to a higher oil recovery than the approach that adopts the pulse pressure after imbibition experiments. The main cause is that the former method facilitates oil recovery, particularly from intermediate-sized pores in relatively porous media. Furthermore, there is a significant difference in oil displacement within the various pore systems for the various types of reservoirs. The developed microfractures greatly contribute to oil recovery during the early imbibition stage, and the pressure pulse method appears most suitable to tight reservoirs with a relatively uniform pore size distribution and a higher proportion of medium-large pores.

EOR mechanism of fracture oil displacement agent for ultra-low permeability reservoir

Due to the low permeability, small pore throat, and poor pore connectivity of ultra-low permeability reservoirs, fracturing was required to improve the flow environment of oil in the reservoir during its development. The combination of fracturing and oil displacement could reduce the complexity of the development of ultra-low permeability reservoirs. It was feasible to synthesize new surfactants to prepare fracturing oil displacement agents, but the research and development of new surfactants were difficult and costly. This paper aimed to experimentally investigate the imbibition displacement mechanism of fracturing flooding by combining the surfactant of chemical flooding with the fracturing fluid. With the conditions of the ultra-low permeability reservoir in block Y of Changqing Oilfield, the mechanism of remaining oil start-up and fractured oil displacement agent enhanced oil recovery in the ultra-low permeability reservoir was studied by microfluidic model experiment and NMR experiment. A mixture of fracture oil displacement agents was obtained by mixing heavy alkyl benzene sulfonate surfactant, a nonionic surfactant, and a betaine-type amphoteric surfactant. HAS-6C, HAS-5E, and HAS-5G were selected for their interfacial tension reaching 10−3 mN/m. Oil–water​ interfacial tension of HAS-5E was the lowest, which can be reduced to 10−4 mN/m. The ability to alter the wettability of HAS-6C was the most significant, which could make the contact angle go down to 64.5°. The multi-round dynamic and static imbibition experiments showed that the combination of selected surfactant and slickwater can greatly improve the imbibition recovery, of which HAS-6C could enhance oil recovery by 17%. The HAS-5E system with the lowest interfacial tension had the best effect of starting clustered residual oil, and the clustered residual oil saturation was reduced by 48.8%. The HAS-6C system with stronger wettability had the best effect of starting throat-like residual oil, and the throat-like residual saturation was reduced by 10.8%.

Microscopic pore structure and connectivity of lacustrine shale of the Shahejie Formation, Zhanhua Sag, Bohai Bay Basin

As an emerging source of global energy supply, shale reservoirs have extremely low porosity and permeability which are often associated with their highly heterogeneous and poorly connected pores. This is due to peculiar pore structure system and morphology of the shale reservoirs. The focus of this study is to evaluate the pore structure, connectivity and heterogeneities of lacustrine shale reservoirs of the Shahejie Formation within the Bohai Bay Basin using a combination of three methods. These are low temperature gas adsorption experiment (for pore morphology and structure), spontaneous imbibition experiments (for pore connectivity) and nuclear magnetic resonance (NMR) to characterize the structure and fluid saturation of the entire shale sample. The results showed that, high clay content blocked the pore throat and caused significant reduction in connectivity which results in the collapse of pores. However, high content of brittle minerals (e.g. calcite and quartz) promotes the formation of intergranular and intercrystalline pores of inorganic minerals as well as micro-fractures, which favours good pore connectivity in shale. Increase in available space for fluid movement in shales with higher porosity results in a beneficial increase in the mobility of the fluid within the pores. Hence, mineral composition and organic matter content are the two main factors affecting the pore structures within the Zhanhua Sag of the Jiyang Depression in the Bohai Bay Basin.

Competitive adsorption effect during spontaneous external water imbibition in loaded gas-bearing coal and application of a normalized desorption rate model

The competitive adsorption effect of water and gas during the coal seam water injection process plays an important role in improving the coalbed methane (CBM) drainage rate of coal seams that do not meet the standards for gas drainage. However, competitive adsorption mainly occurs in the spontaneous imbibition process for coal seam water injection, which is not clear under the dual action of ground stress and gas pressure during spontaneous imbibition process. Here, some spontaneous imbibition experiments under isobaric water addition and isobaric desorption conditions are conducted using a spontaneous imbibition experimental system. The obtained results are as follows. (1) The accumulated replacement gas degree is negatively correlated with the gas pressure, which shows that the principle of spontaneous imbibition can be adopted to improve the gas drainage rate for coal seams whose gas drainage is not up to standard. (2) For spontaneous imbibition with loading stress does not change the adsorption pore structure, the average seepage pore diameter is negatively correlated with the wetting range, while the wetting range is positively correlated with the competitive adsorption effect. (3) The spontaneous imbibition process is a process of effectively wetting the pores of gas-bearing coal, which can effectively increase the pore water content and wetting uniformity. (4) A normalized desorption rate model of the relative replacement degree during spontaneous imbibition is established based on the dimensionless method. This study provides a technical method for improving the gas drainage rate for the drainage of substandard low-permeability coal seams.

Spontaneous Imbibition Experiment and Main Influence Factors in Ultra-Low-Permeability Reservoirs

The imbibition has an important influence on the water injection development of ultra-low-permeability reservoirs. In this paper, the nuclear magnetic resonance (NMR) high-temperature and high-pressure displacement system was used to simulate the formation temperature and pressure and the spontaneous imbibition of single porosity medium and dual porosity medium (containing fractures), and imbibition displacement experiments at different injection rates were carried out. The NMR T2 spectrum curves of simulated oil signals in the pores, throats, and fractures were obtained. The characteristics of oil content change and oil displacement efficiency in dual porosity medium under different experimental conditions were quantitatively evaluated, and the contribution of spontaneous imbibition to oil displacement efficiency was clarified. The experimental results show that the oil displacement efficiency of single porosity medium is lower than that of dual porosity medium. The smaller the pore is, the greater the displacement speed is, and the greater the contribution rate of imbibition is. The porosity, permeability, and maximum pore throat radius are positively correlated with the oil displacement efficiency of spontaneous imbibition but are poorly correlated with the oil displacement efficiency of under the dual action of spontaneous imbibition and displacement. The poor correlation also includes the median pressure, maximum mercury saturation, median radius, and displacement rate. Fractures play a positive role in improving oil displacement efficiency.

Aqueous formate solution for enhanced water imbibition in oil recovery and carbon storage in carbonate reservoirs

This paper presents an experimental study of the injection of aqueous formate solution into oil-wet carbonate porous media at different formate concentrations and acidity levels. The research was motivated by the potential use of aqueous formate solution as a wettability modifier in enhanced oil recovery and/or a carbon carrier in geological carbon storage in carbonate reservoirs. However, the wettability alteration of carbonate rocks by formate has not been tested at elevated concentrations of formate or in any coreflood. The experimental program in this research consists of aqueous stability, wettability alteration, and three dynamic imbibition experiments with fractured carbonate cores with varying formate concentrations up to 30 wt% and initial pH between 6 and 7.With an excess amount of calcite powder, the 20 wt% formate solution in 15000 ppm NaCl brine showed essentially the same pH history as the base NaCl brine, where calcite dissolution caused the solution pH to increase to a stable value near 9. None of the samples studied in this research showed solid precipitation. Material balance of dynamic imbibition data indicated that the imbibition of formate into the matrix was most significant in coreflood #1, in which 30 wt% formate solution was injected into a fractured carbonate core. A large gradient in formate concentration between the fracture and the matrix likely caused the rapid mass transfer. Then, calcite dissolution and the resulting formate species caused wettability alteration to enhance water imbibition, which in turn expelled the oil in the matrix.The incremental oil recovery factor was 9.1 % for 30 wt% formate (pH = 7; coreflood #1), 2.9 % for 5 wt% formate (pH = 7; coreflood #2), and 7.0 % for 5 wt% formate + HCl (pH = 6; coreflood #3). A greater oil recovery factor resulted from a greater concentration of formate and a reduced pH. This is the first time corefloods were performed with aqueous formate solution at elevated concentrations up to 30 wt%.

Wettability Alteration with Weak Acid-Assisted Surfactant Flood

Summary Oil-wetness and heterogeneity are two key reasons for low oil recovery by waterflooding in carbonate reservoirs. Surfactants have been effective in altering the oil-wet matrix to a more water-wet condition and initiating spontaneous imbibition. Because it takes time for the surfactant to alter wettability, oil recovery from the tight matrix is slow and sometimes not economically feasible. Acids have the potential of dissolving minerals, which may alter wettability. In this study, the enhanced oil recovery (EOR) performance of an acid-assisted surfactant solution, a novel technique, was evaluated for low-temperature applications. A set of acids and their acetates were tested. Bulk rock-acid reaction, wettability alteration (WA) tests, and spontaneous imbibition measurements were conducted at reservoir temperature (35°C) to identify effective candidates. Coreflood tests were then performed to evaluate the selected acid-surfactant formulations. Before and after a coreflood test, the core was scanned using micro-computed tomography (CT) to investigate pore structure alteration. Bulk reaction measurements showed that weak acids, especially acetic acid (AA), have the desired low reaction rates at 35°C. WA tests showed that AA can remove the crude oil off the rock surface and alter wettability through mineral dissolution. The surfactant can reduce contact angles from 160° to 58°; adding acid into the surfactant can further reduce it to 52°. Spontaneous imbibition experiments showed the synergy between the acid and the surfactant; the AA-surfactant solution had the highest oil recovery (62.6%) among acid-surfactant formulations. The acid improves the WA efficiency by the surfactant through surface mineral dissolution and lower ζ-potential. The imbibition transports the acid-surfactant solutions into the matrix, which minimizes face dissolution. Coreflood tests show that the AA-surfactant flood can increase the oil recovery rate and recover about 8% more oil compared to the surfactant flood. Micro-CT showed that a few mineral particles were transported along the core and partially plugged pore throats, which reduced permeability and diverted flow leading to improved oil recovery. The transport of the acid in reservoirs and the potential plugging issues have to be carefully evaluated in future studies.