Effect Of Imbibition Research Articles

An Improved Probabilistic Collocation Method for Uncertainty Quantification of Oil–Water Transport through Fractured Porous Media: Effect of Uncertain Gravity Imbibition

An Improved Probabilistic Collocation Method for Uncertainty Quantification of Oil–Water Transport through Fractured Porous Media: Effect of Uncertain Gravity Imbibition

Study on Variability Production Characteristics of Fracturing Fluid Imbibition Displacement for Typical Shale

Abstract CO2 injection is a prominent measurement to enhance the recovery of shale reservoirs. The imbibition of fracturing fluid + CO2 additive is considered important for promoting the enhancement and stabilization of shale oil production to ensure energy supply. The imbibition experiments of fracturing fluid + CO2 additive were carried out in shale reservoirs with a nuclear magnetic resonance (NMR) test. The imbibition displacement characteristics at different pore scales of shale were quantitatively evaluated. The variability of the imbibition effects in shale reservoirs was clarified in terms of shale type, fracturing fluid type, and CO2 additive (pressure). This finding indicates that the effectiveness of the fracturing fluid + CO2 additive imbibition on shale reservoirs is stronger, and the imbibition displacement efficiency ranges from 33.38 % to 41.56 %. The imbibition contribution rate is considerably higher for small pores than for large pores, and the difference between them is more than 10%. Therefore, the imbibition of fracturing fluid + CO2 additive mainly extracted crude oil from the small pores of shale reservoirs. CNI nano variable-viscous slippery water is more effective for imbibition displacement in laminar type shale. For laminated type shale, EM30+ + guanidine gum mixed water has a better imbibition effect than CNI nano variable-viscous slippery water. Under 16 MPa CO2 + fracturing fluid (miscible states), the imbibition displacement efficiency of the shale is significantly enhanced. The imbibition displacement degree at different pore scales is also increased. For different types of shale reservoirs, the imbibition displacement degree at different pore scales would be improved by methods, including the optimization of the fracturing fluid or the change of imbibition conditions. This study presents a theoretical underpinning for the high-efficiency exploitation in shale reservoirs.

Water interaction with MCC powder exposed to wetting–drying cycles: Comparison of capillary imbibition techniques

We investigate how wetting-and-drying (WD) cycles change the properties of microcrystalline cellulose (MCC) powder (Avicel PH101), due to hornification, by performing the following experiments: (i) drop absorption in a slightly compressed powder bed, (ii) capillary imbibition in a packed powder column, and (iii) drop absorption into tablets obtained by direct compression. We use the MCC powder as received, as well as the powder obtained after one or more WD cycles. In each case, the powder is sieved and fractionated into two samples, with different particle size distribution. First, we perform drop absorption experiments using both water and silicone oil (Polydimethylsiloxane - PDMS) drops. We observe that WD cycles increase the absorption time for water, a particularly marked effect after the first cycle, for both particle size distributions. Comparing the absorption times of water and oil drops we obtain a parameter β that characterizes the water-MCC interaction in lieu of the contact angle, and accounts for both capillary and swelling phenomena. We observed that the main effect is produced after the first WD cycle exhibited by a large (more than 50%) reduction in the β value. Column imbibition experiments performed using water and PDMS show that, initially, water penetrates at a larger rate than PDMS. This initialing faster water uptake is more significant for larger particles and fewer WD cycles. A power law regime is obtained in each case with a ζ exponent. In particular, a Washburn-like imbibition regime with ζ=0.5 is recovered at long times for both liquids. In the last experimental technique, we study the absorption of water drops deposited on tablets obtained by direct compression of the full distribution of powder particle sizes. We observe that absorption time increases with increasing number of WD cycles of the MCC powder. This is quantified by the 30% reduction of the ζ exponent that models the penetration rate of the drop.In summary, we use three kinds of experiments that cover a wide range of characteristic time scales to quantify the effect of WD cycles on the interaction of water with a swelling powder like MCC. The importance of comparing responses under different timescales is that the swelling phenomenon modifies the properties of the material in time, while imbibition happens. It is shown by this study that in some cases, the phenomena can be decoupled (droplet absorption in porous media) while in other cases it cannot be (droplet on tablets and intermediate times in capillary rise). Finally, at long times in capillary rise, even when the swelling and imbibition effects are not decoupled, it is possible to estimate the permeability ratio, χ, and its dependence with the WD cycles when the results are used in combination with the ones from the droplet absorption on powder test. The permeability decreased about 8 times for no WD cycles, and it decreased much less (2 and 3 for small and large particles respectively) for one and two WD cycles. We were able to quantitative characterize the effects of water-MCC interaction and this is important in order to predict how some pharmaceutical processes, like wet granulation, will be affected.

Displacement-imbibition coupling mechanisms between matrix and complex fracture during injecting-shut in-production process using pore-scale simulation and NMR experiment

Displacement-imbibition coupling oil production, which involves adjusting the operations of a well group (water injection huff and puff in one well, continuous oil production in another well), is an effective technique for enhancing oil recovery (EOR) for tight oil reservoirs. However, the research on displacement-imbibition coupling mechanisms is still missing, especially the combination of pore-scale numerical simulations and physical experiments. In this paper, a novel self-designed displacement-imbibition online nuclear magnetic resonance (NMR) experiment technique is developed. The effect of changes in fracture morphology on the mechanism of displacement-imbibition (oil saturation field and oil displacement efficiency) has been investigated. Based on the fracture morphology of physical experiments, a pore-scale model is established and solved by the finite element method. The pore-scale oil-water two-phase displacement-imbibition during the injecting-shut in-production process is simulated. The results show that the pressure oscillation makes the counter-current imbibition and co-current imbibition occur simultaneously in the matrix pores, which promotes oil recovery in matrix-fracture systems. The strength of displacement and imbibition effects is affected by the complexity of fractures. When the fracture complexity increases, the imbibition of the dense part of the fracture is stronger, while the displacement effect is weakened.

Effects of CO2-saturated brine imbibition on the mechanical and seepage characteristics of Longmaxi shale

Supercritical carbon dioxide (SC– CO2) serves as a promising anhydrous fracturing fluid that has the potential to simultaneously enhance shale gas recovery and accomplish CO2 sequestration within shale reservoirs. However, the hydromechanical properties of shale are considerably affected by CO2-brine-shale interaction. This study conducted shale imbibition experiments involving subcritical/supercritical CO2 saturated brine (Sub/SC-CO2+brine). Triaxial compressive strength tests were performed to evaluate the impact of Sub/SC-CO2+brine imbibition on the mechanical properties of shale, as well as the influence of SC-CO2+brine imbibition on shale permeability. The results indicate that, after SC-CO2 brine imbibition, noticeable macroscopic cracks are formed parallel to the bedding plane. The imbibition of Sub/SC-CO2+brine results in the reduction in axial stress and Young's modulus, while simultaneously increasing the axial strain of shales. Compared to Sub-CO2+brine, SC-CO2+brine exhibits a higher imbibition pressure and a more intense geochemical reaction with shale. Due to increased compressibility sensitivity, the averaged permeability after SC-CO2+brine imbibition shows a reduction of nearly 70 % compared to that before imbibition. The insights from this research are expected to provide theoretical support for shale gas recovery and CO2 geological sequestration.

Experimental investigation on forced imbibition characteristics of shale oil reservoir based on nuclear magnetic resonance method

After large-scale fracturing of shale reservoirs, the fracturing fluid will imbibe in the reservoir. In order to clarify the characteristics of imbibition and the distribution characteristics of crude oil in the stage of forced imbibition, this paper selects the core of some blocks in Qinghai and Gulong areas to carry out the shale forced imbibition experiment. Nuclear magnetic resonance technology is used to monitor the variation of crude oil. And the influence of core permeability and contact angle on forced imbibition is further analyzed. The results of the study show that the shale has a strong imbibition effect on the fracturing fluid. The content of oil phase in the core decreases, and the phenomenon of oil-water replacement occurs. Priority porosity for fracking fluids exists in the process of imbibition, where fracturing fluid preferentially enter smaller pores and can cause a short-term increase in the oil phase content in larger pores. With the continuous process of imbibition, the rate of imbibition oil gradually slowed down, and the fracturing fluid gradually permeates evenly into the rock sample. Both permeability and wettability affect the imbibition capacity of fracturing fluid in the forced imbibition stage.

A semi-analytical model for fractured horizontal wells production considering imbibition during shut-in periods

After hydraulic fracturing in tight oil reservoirs, part of the fracturing fluid is retained in the formation. Therefore, it’s essential to investigate the pressure and saturation distributions during and after fracturing to further understand the impact of fluid loss on productivity. Concerning the capillary pressure, fracture propagation, and fracture volume changes, a semi-analytical model was established innovatively. Comparisons between the model’s calculations and actual measurements demonstrate a high level of agreement, validating the model’s accuracy. Furthermore, the impacts of capillary pressure, shut-in time, injection rate, initial reservoir pressure, and initial water saturation on actual production performance were investigated. The results show that the effect of capillary pressure on production in the tight reservoir cannot be ignored. A reasonable shut-in operation should be carried out according to the actual situation. A smaller injection rate should be selected to achieve a larger fracture length and imbibition area. The proportion of oil produced by capillary pressure decreases with the increase of initial pressure. The initial water saturation is positively correlated with oil production and negatively correlated with water production. The imbibition effect of shut-in operation is more obvious in tight reservoirs with low initial pressure and low water saturation.

Imaging porosity evolution of tight sandstone during spontaneous water imbibition by X-ray Micro-CT

Water imbibition is an important process in reservoir rocks during hydraulic fracturing and water-based enhanced oil recovery operations. However, the water imbibition behavior in tight sandstones has not been fully understood due to their complex pore structure, including the presence of nano and micron-sized pores and throats, surface properties, and wide variation in mineralogy. The present study focuses on the effect of spontaneous water imbibition on the porosity evolution of a tight sandstone. Within this context, a core of Torrey Buff sandstone was characterized by using a combination of multiscale imaging methods (X-ray Computed Tomography, Scanning Electron Microscopy), laboratory experiments (porosity-permeability measurements), and analytical techniques (X-ray Diffraction, Fourier Transform Infrared Spectroscopy, Scanning Electron Microscopy-Energy Dispersive Spectroscopy, and Thermogravimetry). The studied tight sandstone core has a porosity of 12.3 % and permeability of 2.05mD with minerals of quartz (58 %), clays (kaolinite and illite, 23 %), K-feldspar (7 %), dolomite (7 %) and calcite (5 %). Primary and secondary pores, ranging in size from 60 to 140 μm and 30–50 μm, respectively, are mostly filled with highly-soluble carbonate minerals and hydrophilic illite, which influence the spontaneous water imbibition capacity of the tight sandstone. The multiscale imaging technique indicates that after a 10-h long water imbibition experiment, the average pore size of the tight sandstone increased by 1.28 %, reaching 2.35 % at the rock-water contact and 0.13 % at the top of the core. In other words, throughout the core, the porosity changes upon water imbibition are not uniform but show an almost linear trend. This observation could be explained by the significant contribution of highly-soluble carbonates and hydrophilic illite on the microstructure of the tight sandstone. This study implies that multiscale imaging techniques, crucial in examining spontaneous water imbibition, hold promise for further research in enhanced oil recovery or hydraulic fracking in tight sandstones.

Experiment of dynamic seepage of tight/shale oil under matrix fracture coupling

A physical simulation method with a combination of dynamic displacement and imbibition was established by integrating nuclear magnetic resonance (NMR) and CT scanning. The microscopic production mechanism of tight/shale oil in pore throat by dynamic imbibition and the influencing factors on the development effect of dynamic imbibition were analyzed. The dynamic seepage process of fracking–soaking–backflow–production integration was simulated, which reveals the dynamic production characteristics at different development stages and their contribution to enhancing oil recovery (EOR). The seepage of tight/shale reservoirs can be divided into three stages: strong displacement and weak imbibition as oil produced rapidly by displacement from macropores and fractures, weak displacement and strong imbibition as oil produced slowly by reverse imbibition from small pores, and weak displacement and weak imbibition at dynamic equilibrium. The greater displacement pressure results in the higher displacement recovery and the lower imbibition recovery. However, if the displacement pressure is too high, the injected water is easy to break through the front and reduce the recovery degree. The higher the permeability, the greater the imbibition and displacement recovery, the shorter the time of imbibition balance, and the higher the final recovery. The fractures can effectively increase the imbibition contact area between matrix and water, reduce the oil-water seepage resistance, promote the oil-water displacement between matrix and fracture, and improve the oil displacement rate and recovery of the matrix. The soaking after fracturing is beneficial to the imbibition replacement and energy storage of the fluid; also, the effective use of the carrying of the backflow fluid and the displacement in the mining stage is the key to enhancing oil recovery.

The Effect of Imbibition on Immersion Hydrocolloid Irreversible Alginate Sodium Hypochlorite Disinfectant Solution and Red Betel Leaf (Pipper Crocatum) Extract

Background: impressing the patient's oral cavity in dentistry can pose a risk of cross infection between doctor and patient. Therefore it is necessary to disinfect the impression material to remove bacteria that stick to the impression material. Disinfection that can be used besides sodium hypochlorite can also extract red betel leaves. Purpose: to find out the difference of imbibition on immersion hydrocolloid irreversible alginate in sodium hypochlorite 1% and red betel leaf extract 100%. Method: this research is experimental with pretest and posttest control group design with 4 treatment groups, 2 groups were immersed in sodium hypochlorite 1% and 2 groups were immersed in red betel leaf extract 100%. Immersing time is 5 and 10 minutes. Each repetition is done 6 times. Negative molds are measured before and after immersion. Data were analyzed using the OneWay Anova Test. Results: The effects of alginate mold imbibition on sodium hypochlorite immersion were greater than immersion in red betel leaf extract. Conclusion: There was a significant difference (p <0.05) in the imbibition of the printed hydrocolloid irreversible alginate soaked in sodium hypochlorite 1% and red betel leaf extract 100% for 5 minutes, and 10 minutes

Effects of hormopriming and pretreatment with gibberellic acid on fenugreek (Trigonella foenum graecum L.) seed germination

Various approaches are used to improve crop production. Seed priming is one of the simplest and least expensive methods currently used to ensure rapid and uniform yields. Our study highlights the role of priming and imbibition in improving seed germination. The objective of this study was to investigate the effect of seed imbibition and hormopriming with 0.1 mM gibberellic acid (GA3) on germination performance and biochemical changes in fenugreek (Trigonella foenum-graecum L.) radicles. The results showed that hydropriming and imbibition with GA3 significantly improved germination performance and radicle growth. Concurrently, treatments induced stimulation of the antioxidant activities of superoxide dismutase, ascorbic peroxidase, catalase and guaiacol peroxidase, and decreased lipid peroxidation, stimulated an increase in total non-enzymatic antioxidant capacity and reduced glutathione content. Accumulation of hydrogen peroxide and cytochemical analysis of reactive oxygen species (ROS) in situ confirmed the role of imbibition in stimulating ROS. Interestingly the effects of imbibition with gibberellic acid were more effective then hormopriming, probably due to the partial degradation of GA3 during dehydration process.

Study on the Effects of Wettability and Pressure in Shale Matrix Nanopore Imbibition during Shut-in Process by Molecular Dynamics Simulations.

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

Experimental Study on Forced Imbibition and Wettability Alteration of Active Carbonated Water in Low-Permeability Sandstone Reservoir

Summary Imbibition is one of the main mechanisms for fluid transport in porous media. A combination of carbonated water and active water [active-carbonated water (ACW)] has great prospects in enhanced oil recovery (EOR) and carbon reduction processes. To date, the law of hydrocarbon recovery induced by ACW imbibition is not clear. In this paper, the optimal surfactant concentration was first selected through a spontaneous imbibition experiment, and on this basis, CO2 was dissolved to form ACW. The imbibition effects of formation water (FW), surfactant solution DX-1, and ACW under different pressures were compared. The changes in rock wettability in the three imbibition solutions during imbibition were studied by measuring the contact angle. The effect of fracture on ACW imbibition was studied. Finally, the improved NB−1 was calculated to elucidate the mechanism of forced imbibition for EOR. The results show that 0.1% DX-1 produces the optimal imbibition effect. Pressure is positively correlated with imbibition recovery. ACW can significantly improve the imbibition effect due to its wettability reversal ability being better than those of FW and DX-1. CO2 in ACW can be trapped in the formation through diffusion into small rock pores. The contact angles of the three imbibition solutions decrease with increasing pressure. The contact angle between the rock and oil droplet in the ACW is as low as 38.13°. In addition, the fracture increases the contact area between the matrix and the fluid, thereby improving the imbibition effect. The alteration of NB−1 indicates that FW imbibition is gravity-driven cocurrent imbibition. DX-1 and ACW imbibitions are countercurrent imbibitions driven by capillary force and gravity. The above results demonstrate the feasibility of ACW in low-permeability reservoir development and carbon reduction.

A technique for enhancing tight oil recovery by multi-field reconstruction and combined displacement and imbibition

A seepage-geomechanical coupled embedded fracture flow model has been established for multi-field coupled simulation in tight oil reservoirs, revealing the patterns of change in pressure field, seepage field, and stress field after long-term water injection in tight oil reservoirs. Based on this, a technique for enhanced oil recovery (EOR) combining multi-field reconstruction and combination of displacement and imbibition in tight oil reservoirs has been proposed. The study shows that after long-term water flooding for tight oil development, the pressure diffusion range is limited, making it difficult to establish an effective displacement system. The variation in geostress exhibits diversity, with the change in horizontal minimum principal stress being greater than that in horizontal maximum principal stress, and the variation around the injection wells being more significant than that around the production wells. The deflection of geostress direction around injection wells is also large. The technology for EOR through multi-field reconstruction and combination of displacement and imbibition employs water injection wells converted to production and large-scale fracturing techniques to restructure the artificial fracture network system. Through a full lifecycle energy replenishment method of pre-fracturing energy supplementation, energy increase during fracturing, well soaking for energy storage, and combination of displacement and imbibition, it effectively addresses the issue of easy channeling of the injection medium and difficult energy replenishment after large-scale fracturing. By intensifying the imbibition effect through the coordination of multiple wells, it reconstructs the combined system of displacement and imbibition under a complex fracture network, transitioning from avoiding fractures to utilizing them, thereby improving microscopic sweep and oil displacement efficiencies. Field application in Block Yuan 284 of the Huaqing Oilfield in the Ordos Basin has demonstrated that this technology increases the recovery factor by 12 percentage points, enabling large scale and efficient development of tight oil.

Experimental investigation of CO2 foam flooding-enhanced oil recovery in fractured low-permeability reservoirs: Core-scale to pore-scale

Fractured low-permeability reservoirs are characterized by poor reservoir physical properties, strong interlayer heterogeneity and the existence of natural and artificial fractures, resulting in significant water or gas channeling during flooding development. CO2 foam can effectively control the mobility of CO2 and ensure a more stable flooding front. In this study, taking into account the imbibition effect of the flooding process, the flooding performance under different injection methods and the influencing factors of foam pre-injection volume, back pressure and fracture complexity on CO2 foam flooding were systematically analyzed using fractured low-permeability core flooding experiments. In addition, the mechanism of CO2 foam flooding enhanced oil recovery (EOR) in low-permeability fractured reservoirs was obtained in combination with microscopic flooding experiments. The results show that the maximum recovery of 59.36 % can be obtained by soaking the core samples for 12 h with pre-injection of 0.4 PV CO2 foam followed by CO2 foam flooding, which adequately considers the imbibition effect during the flooding process. The pressure difference and oil recovery increases with increasing foam pre-injection amount, and the oil recovery with back pressure (2 MPa and 4 MPa) is significantly higher than that without back pressure; however, a further increase in back pressure has less impact on the recovery. The oil recovery rate of the fracture-free core is lower than that of the multiple fracture core during CO2 foam flooding but higher than that of the single fracture core, and the fracture complexity of the fractured cores has less impact on the final oil recovery. Microscopic experiments show that CO2 foam can effectively prevent channeling and improve the sweep efficiency. Soaking during the CO2 foam flooding process makes foam enter the matrix through the fracture, and CO2 dissolves after the foam breaks to increase the mobility of the crude oil, while the surfactant solution emulsifies the crude oil and changes the rock wettability. The unbroken foam can increase the sweep range, and the crude oil that flows into the fracture is carried by the subsequent injected foam to be recovered as foamy oil.

A Dynamic Permeability Model in Shale Matrix after Hydraulic Fracturing: Considering Mineral and Pore Size Distribution, Dynamic Gas Entrapment and Variation in Poromechanics

Traditional research on apparent permeability in shale reservoirs has mainly focussed on effects such as poromechanics and porosity-assisted adsorption layers. However, for a more realistic representation of field conditions, a comprehensive multi-scale and multi-flowing mechanism model, considering the fracturing process, has not been thoroughly explored. To address this research gap, this study introduces an innovative workflow for dynamic permeability assessment. Initially, an accurate description of the pore size distribution (PSD) within three major mineral types in shale is developed using focussed ion beam-scanning electron microscopy (FIB-SEM) and nuclear magnetic resonance (NMR) data. Subsequently, an apparent permeability model is established by combining the PSD data, leading to the derivation of dynamic permeability. Finally, the PSD-related dynamic permeability model is refined by incorporating the effects of imbibition resulting from the fracturing process preceding shale gas production. The developed dynamic permeability model varies with pore and fracture pressures in the shale reservoir. The fracturing process induces water blockage, water-film formation, and water-bridging phenomena in shale, requiring additional pressure inputs to counteract capillary effects in hydrophilic minerals in shale, But also increases the overall permeability from increasing permeability at larger scale pores. Unlike traditional reservoirs, the production process commences when the fracture is depleted to 1–2 MPa exceeds the pore pressure, facilitated by the high concentration of hydrophobic organic matter pores in shale, this phenomenon explains the gas production at the intial production stage. The reduction in adsorption-layer thickness resulting from fracturing impacts permeability on a nano-scale by diminishing surface diffusion and the corresponding slip flow of gas. this phenomenon increases viscous-flow permeability from enlarged flow spacing, but the increased viscous flow does not fully offset the reduction caused by adsorbed-gas diffusion and slip flow. In addition to the phenomena arising from various field conditions, PSD in shale emerges as a crucial factor in determining dynamic permeability. Furthermore, considering the same PSD in shale, under identical pore spacing, the shape factor of slit-like clay minerals significantly influences overall permeability characteristics, much more slit-shaped pores(higher shape factor) reduce the overall permeability. The dynamic permeability-assisted embedded discrete fracture model (EDFM) showed higher accuracy in predicting shale gas production compared to the original model.

Embebição e germinação de sementes de chincuya (Annona purpurea Moc e Sessé Dunal) sob efeito de ácido giberélico e pH da água em imersão

Abstract: Germination is influenced by several factors, among them pH. Two experiments were conducted to determine the effect of imbibition-water pH on the water absorption curve of chincuya seeds and germination. The results were contrasted to the known effect of gibberellic acid imbibition. In the first year of fruit collection and evaluation, imbibition curves were constructed per treatment. The seeds of this evaluation were divided into two lots: the first at the initial moisture content (39.9 %) and the second at the moisture content of 34.1 % after three days of drying in the laboratory. The seeds were imbibed for 84 h in distilled water at three pH levels (5, 7, and 9) and kept in a water bath at 30 °C. In the second year of collection and evaluation, the pH treatments were repeated, and an imbibition treatment with gibberellic acid at 350 mg L-1 (pH 3.9) was added. A control treatment contained distilled water at pH 6.1. For both years, treated seeds were incubated on paper towels and placed under controlled conditions at a 12-hour photoperiod and alternating day and night temperatures (30 °C:25 °C). The three imbibition curves showed similar behavior and no statistical significance. Seeds with a higher moisture content did not gain weight after imbibition. The imbibition curves increased constantly in the seeds at 34.1 % moisture, and weight gain reached almost 46 % with the pH 9 treatment. However, there were no statistical differences among treatments. The highest rate of water absorption occurred in the first six hours in the open-air, dehydrated seeds, and after 72 hours, the weight of the seeds did not increase. Average daily germination kinetics indicated a slow and poor germination process. Gibberellic acid significantly promoted germination, causing 43 % germination. The absolute control reached 5.7 %, while the rest of the treatments did not promote germination.

Experimental study on the gas desorption law in coal affected by dynamic water injection

Water from hydraulic technology affects the desorption of gas from coal seams. Gas desorption behavior is critical information for gas control in coal mines. In this study, a designed coal seam water injection simulation experimental device was utilized to conduct dynamic water injection experiments on coal samples at different adsorption equilibrium pressures, analyzing the gas desorption law under dynamic water injection, as well as the role of water replacement, water imbibition and water blockage in gas desorption. The results showed that water altered the gas desorption rate in coal, causing fluctuating attenuation of the desorption rate of a water-injected coal sample (WCS). Under the same adsorption equilibrium pressure, the relationship between the desorption rate of the WCS and the non-water-injected coal samples (NCS) underwent a transition in desorption time. In contrast to the NCS desorption curves, the WCS desorption curves lacked a rapid growth phase and exhibited only a slow growth phase and a stopping phase. Water imbibition and water replacement promoted the desorption of gas in the non-wet area during the water injection process, while it inhibited the desorption of gas in the wet area. Under the effects of water imbibition, water blockage, and water replacement, the discharge rate of WCS is greater than the desorption rate of NCS, indicating that water injection increases the total amount of gas desorption. The study results have significant implications for gas extraction and the prevention and control of coal and gas outbursts.

Effect of root imbibition with selenium and iodine on antioxidant compounds in tomato (Solanum lycopersicum L.) crop

The use of trace elements such as iodine and selenium in agriculture is gaining great importance due to the benefits in plants before different types of biotic or abiotic stress. This research aimed to evaluate the seedling root priming with Na2SeO3 (0, 0,5, 1, 2, 3 mg L-1) and KIO3 (0, 100, 150, 200, 250 mg L-1) on the antioxidant compounds of tomato (Solanum lycopersicum L.) fruits and leaves. The crop was established under greenhouse conditions in 10-L polyethylene containers containing peat moss and perlite 1:1 (v/v), in a randomized complete block experimental design with a 52 factorial arrangement. In the fruits, the Na2SeO3 influenced the GHS, flavonoids, lycopene and β-carotene contents, while the KIO3 influenced the GHS, vitamin C and lycopene contents. The KIO3-Na2SeO3 interactions affected the GSH, phenols, flavonoids, lycopene and β-carotene contents in fruits. In the leaves the GHS content increased with the Na2SeO3, while the GSH, flavonoids, and chlorophyll contents increased with the KIO3 factor and KIO3-Na2SeO3 interactions. The evaluated enzymes in fruits and leaves decreased with the both the KIO3 and Na2SeO3 concentrations. The Na2SeO3 influenced the hydrophilic compounds by ABTS and DPPH, while the KIO3 influenced the hydrophilic compounds by ABTS. In the leaves, the KIO3 influenced the lipophilic compounds by ABTS. The KIO3-Na2SeO3 interactions influenced the hydrophilic compounds by ABTS in both the fruits and leaves. Seedling root imbibition in KIO3 and Na2SeO3 is a method that implemented in the tomato crop presents interesting aspects in the increase of the antioxidant capacity and the non-enzymatic compounds, such as vitamin C, phenols, flavonoids and GSH contents. However, this method presented an inhibition in the antioxidant enzymes.

Research on imbibition effect of surfactant fracturing fluid in offshore reservoirs with low permeability and high temperature

Surfactant imbibition can effectively improve the development effect of fracturing technique. In order to enhance oil recovery, a temperature resistant surfactant was selected using interfacial tension and contact angle testers based on the offshore reservoir conditions of high temperature and low permeability. Experiments on spontaneous and forced imbibition with artificial columnar cores were performed to optimize parameters of imbibition processes during fracturing in high temperature and low permeability reservoirs. Results show that among the three surfactants, amphoteric Gemini surfactant had a stable molecular structure with non-compressible hydrophobic groups which significantly reduced oil-water interfacial tension, enhanced rock wettability, and demonstrated good resistance to high temperatures The maximum recovery increase during amphoteric Gemini surfactant imbibition is 16.22%. The higher the core permeability, the higher the core inside pressure, and the longer the well shut-in time, the greater the forced imbibition effect. A proper well shut-in time and injection volume should be considered when using surfactant solution as fracturing liquid.