Imbibition Rate Research Articles

An experimental investigation into the spontaneous imbibition of surfactant assisted low salinity water in carbonate rocks

Surfactant assisted smart water injection is one of the areas of research interests in enhanced oil recovery. Simultaneous use of smart water and surfactants has drawn great attention in last decades. Majority of studies highlight co-injection of cationic surfactant and sea water/low salinity water. Therefore, this paper opens a new approach by examining the effect of diluted sea water, termed as dSW, containing Sodium Dodecyl Sulfate (SDS) on spontaneous imbibition in carbonate media. Reservoir core plugs and oil samples were provided, saline waters were synthesized in laboratory and different tests were accomplished. It was observed that the brine spiked in Mg2+ is able to improve water wetness of calcite by reducing contact angle from 114° to 42° and reduction in interfacial tension (IFT) from 34.2 to 13.9 mN/m. Measurement of oil properties before and after imbibition, showed that Mg2+ plays the main role in increasing microscopic sweep efficiency and improving ultimate oil recovery. Moreover, faster imbibition rate and higher capillary number was gained by increasing Mg2+ concentration. Ca2+ was found to be a disturbing ion as it led to incompatible condition in the fluid system. We confirmed that in the presence of excess Ca2+, SDS molecules not only aggregate in the bulk of solution, but also another form of incompatibility, known as salt bridge, was occurred. It was also demonstrated that activity of SO42- was concealed in the presence of SDS.

Experimental study of wettability alteration and spontaneous imbibition in Chinese shale oil reservoirs using anionic and nonionic surfactants

Wettability alteration exhibits a significant potential to improve the oil recovery of shale reservoirs by means of spontaneous imbibition through shifting the rock wetness from oil-wet to water-wet. The wettability of the oil-wet shale can be modified by adding surfactants in hydraulic fracturing fluids in the field practice. However, the mechanisms of wettability alteration in shale rocks are still unclear and there are reported discrepancies in different types of surfactants solutions. This work attempts to investigate the mechanisms of anionic and nonionic surfactants on wettability alteration of shale rocks of the Sichuan Basin in China, and to analyze their effects of wettability alteration and interfacial-tension (IFT) reduction on the spontaneous imbibition process of the oil-wet shale samples. By measuring the contact-angle, ζ-potential, and IFT, the efficiencies of different surfactants in terms of wettability alteration and IFT reduction are evaluated. The contact-angle experiments show that the water contact angle in rock/oil/water systems decreases when we add more surfactants, which indicates the hydrophilicity of shales is increased by surfactants. Specifically, for the anionic surfactant solutions, the contact angle doesn't immediately change, and it decreases with time, which is different from the sudden change of nonionic surfactants. Moreover, for different surfactants, the IFT decreases in a similar trend with the increase of surfactant concentration. Finally, spontaneous imbibition experiments are conducted and the results show that anionic surfactants are more favorable to recover shale oil than the nonionic surfactants. From the results obtained, it can be concluded that the anion surfactants and nonionic surfactant have different mechanisms for wettability alteration on the shale surface; anionic surfactants have better effect on wettability alteration than nonionic surfactants, however, the mechanism of wettability alteration in anionic surfactants have time delay. The wettability alteration dominates the oil recovery in the way of spontaneous imbibition. More water-wetness tends to yield a higher recovery. In addition, for anionic surfactant solutions, the reduction of IFT increases the final oil recovery and leads to a decrease of the imbibition rate. For nonionic surfactant solutions, the reduction of IFT increases both the imbibition rate and the final recovery, but the enhancement is not significant.

Tolerance of crambe (Crambe abyssinica Hochst) to salinity and water stress during seed germination and initial seedling growth

ABSTRACT Crambe is an oilseed plant whose oil is suitable for various industrial purposes, such as production of biodiesel, plastics, rubbers, and cosmetics. There are reports of the rusticity of this species and its potential for growth in arid and semi-arid environments, where water scarcity and soil salinity are common. However, studies regarding the tolerance of its seeds to these stresses and the physiological responses triggered during germination and seedling establishment under these conditions are incipient. The objective of this study was to evaluate the tolerance of crambe seeds to water deficit and salt stress during germination and early seedling development, as well as to investigate the role of antioxidant enzymes on tolerance to these conditions. The seeds were exposed to water and salt stresses and their performance was analyzed. Seed water content, imbibition rate, percentage and speed of germination, and the base water potential for seed germination were evaluated. In the seedlings, the following measurements were made: root and shoot length, fresh and dry matter of roots and shoots, moisture content, and activity of the enzymes superoxide dismutase (SOD), catalase (CAT), and peroxidase (POX). Water deficit and salt stress reduce the water uptake rate of the seeds, the germination and growth of seedlings. The crambe seeds had higher tolerance to salt stress than to water deficit. Absorption of salt and the action of the SOD and CAT antioxidant enzymes are part of the tolerance mechanisms of crambe seeds to salt stress.

Foam drainage placed on a thin porous layer.

Drainage of foams placed on porous substrates has only recently been theoretically investigated (O. Arjmandi-Tash, N. Kovalchuk, A. Trybala, V. Starov, Foam Drainage Placed on a Porous Substrate, Soft Matter, 2015, 11(18), 3643-3652), where an equation describing foam drainage (with non-slip boundary conditions on the liquid-air interfaces) was combined with that of imbibition of liquid into the thick porous substrate. Foam-based applications have been used as a method of drug delivery, which is a recent and promising area of research related to application of medicinal products onto the skin or hair, which are both thin porous layers. A theory of foam drainage (taking into account surface viscosity) placed on a completely wettable thin porous layer is developed: the rate of foam drainage and imbibition inside the porous layer and other characteristics of the process are predicted. The "effective slip" caused by the surface viscosity increased a movement of the top boundary of the foam. The theoretical predictions are compared with experimental observations of foam drainage placed on thin porous layers. The comparison showed a reasonable agreement between the theoretical predictions and experimental observations. One of the phenomena during foam application is the possibility of a build-up of a free liquid layer on the foam/porous layer interface, which can be very useful for applications. Three different regimes of spreading/imbibition process have been predicted. Conditions and durations of free liquid layer formation have been theoretically predicted and compared with experimental observations.

Improvement of Relative Permeability and Wetting Condition of Sandstone by Low Salinity Waterflooding

Waterflooding is generally performed to maintain reservoir pressure and as a consequence, production period is extended. However, conventional waterflooding may be not suitable for every reservoir. Low Salinity Waterflooding (LSW) which is recently the most mentioned technique is therefore, considered. Although clear explanation of oil recovery mechanism is not available, it is believed that the key mechanism is Multi-component Ion Exchange (MIE). This study aims to assess improvement of relative permeability and wetting condition of sandstone formation from oilfield in Thailand, through the MIE mechanism. The study is divided into two major parts. The first part is laboratory study including core and fluid preparations, imbibition test, coreflooding test and ion-exchange detection. After laboratory data including fluid production rate and pressure difference versus time are obtained, core simulation using reservoir simulation program called STAR® commercialized by Computer Modelling Group (CMG) is performed to study the change of wetting condition through the shifting of relative permeability. Obtaining results would help verifying suitability of the implementation of this technique in oilfield. Results from imbibition test showed that LSW yields higher oil recovery factor compared to formation water. Diluted formation water at 5,000 ppm which is approximately one-third of formation water, is the best water formulation, yielding the fastest rate of imbibition in this study. From ion-exchange detection test, results showed the variation of divalent ion concentrations compared to injected water and moreover, presence of calcium and magnesium ions in oil phase supports the occurrence of MIE during the displacement mechanism. The theoretical model matching with physical data using reservoir simulation program indicates that LSW slightly affects the original wetting condition. Water wetness is lessened as can be observed from the increment of relative permeability to water at the end point saturation. Moreover, LSW reduces residual oil saturation and at the same time, increases relative permeability to oil. From the detection of MIE together with the observation of wetting condition through core simulation, it can be concluded that LSW is a promising technique for oilfield in Thailand. As produced water must be reinjected back into reservoir based on zero discharge regulation of Thai government, this low-cost technique of diluting water salinity prior to reinjection would fulfil the requirement of government and at the same time helps increasing oil recovery of the total field.

Method of moderate water injection and its application in ultra-low permeability oil reservoirs of Yanchang Oilfield, NW China

Abstract To explore the method of improving development effect and solving the problem of water breakthrough and water out for ultralow permeability fractured reservoirs, an indoor evaluation method of dynamic imbibition for fracture-matrix system was established taking the Chang 8 reservoir in southern Yanchang Oilfield as a research target. Key factors for the imbibition effect were obtained, an imbibition's rate expression was obtained, a model considering the double effects of imbibition-displacement was built and optimal injection and production parameters for the research area were obtained as well. The results show that an optimum displacement rate that maximizes the oil displacement efficiency exists in the water displacing oil process, and the optimal displacing rate becomes smaller as the permeability decreases. The imbibition displacement efficiency increases as the reservoir quality index and water wettability index of rock become bigger. But the larger the initial water saturation or oil-water viscosity ratio is, the smaller the imbibition displacement efficiency is. The optimal injection-production ratio for the Chang 8 reservoir of southern Yanchang Oilfield is 0.95, and the predicted recovery is 17.2% when the water cut is 95%, it is 2.9% higher than the recovery of conventional injection-production ratio 1.2. By using the moderate water injection technique based on the double effects of imbibition-displacement mechanism, the water injection development effect for the ultra-low permeability fractured reservoirs can be improved significantly.

The impact of asphaltene deposition on fluid flow in sandstone

Asphaltene deposition in oil reservoirs is a contentious issue affecting both well and reservoir productivity. Though the phenomenon has been previously studied in several laboratory experiments, the uniformity aspects of the asphaltene deposit are usually overlooked. We have previously developed an experimental workflow to create a uniform deposit of asphaltene inside the core sample. In this study, the impact of this uniform deposit on fluid flow is quantified through imbibition, corefloods and relative permeability experiments. In addition, the lab results are used in a field scale simulation to investigate the impact of deposition on field performance. The results exhibit a shift in the wettability state where a reduction in both water imbibition rate and capacity are observed after deposition. Besides, up to 25% reduction in absolute permeability is detected. Results of pressure drop experiments across the core conducted on the exposed rocks indicate a change in the wetting characteristics, with the exposed rocks becoming more mixed/intermediate wet and varying with the change in the initial brine saturation in the rock. Subsequently, the relative permeability set is affected where a shift in the oil residual saturation, a downgrade in the oil curve and an upgrade in the water curve are observed. Upscaling this new data to field scale indicated a loss of more than half of the well productivity and an earlier breakthrough if waterflooding is implemented.

Comparison of micro- and macro-wettability measurements and evaluation of micro-scale imbibition rates for unconventional reservoirs: Implications for modeling multi-phase flow at the micro-scale

Significant advances have been made in the evaluation of micro- and nano-scale variations of pore structure in low-permeability (unconventional) reservoirs using imaging techniques. In parallel, digital rock physics (DRP) methods have been advanced so that pore structure information extracted from these images may be used, in combination with pore-scale modeling, to predict critical petrophysical rock properties such as porosity and permeability. Recent work using DRP applied to multi-phase flow of unconventional reservoirs has suggested that wettability variations at the micro-scale caused by mineralogical heterogeneity or aging can have a profound effect on simulated capillary pressure and relative permeability curves. However, wettability is typically measured at the macro-scale, with the resulting contact angles used for populating DRP models. Further, fluid imbibition rates are usually measured at the macro-scale to compare, for example, the impact of fracturing fluid additives on oil recovery.This study compares water contact angle measurements made at the micro-scale, using an environmental field emission scanning electron microscope (E-FESEM) combined with innovative procedures for contact-angle extraction, with a conventional macro-scale approach (sessile drop) for low-permeability samples obtained from the Montney Formation in Western Canada. For the first time, quantification of imbibition rates at the micro-scale is demonstrated. Two micro-wettability evaluation procedures developed previously are applied to these samples to evaluate water micro-contact angles: 1) imaging of condensation/evaporation experiments and 2) imaging of injected fluids using a micro-injection system. Micro contact angles were first estimated by extracting sessile droplet profiles (with user-guided software developed in-house) and then fitting a parameterized Young-Laplace equation to the droplet profile. For some of the micro-injection experiments, the geometry of the micro-droplet, as captured with the parameterized Young-Laplace equation, was used to compute the volume of the micro-droplet at different stages of imbibition, which in turn was used to evaluate imbibition rates at this scale. Macro contact angles were evaluated using the parameterized Young-Laplace equation and commercial software.This study suggests that laboratory-derived macro-droplet contact angles cannot be confidently and consistently applied at the micro-scale for use in DRP models for tight heterogeneous formations such as the Montney. Significant errors in simulating fluid displacement processes, fluid saturation distributions, capillary pressure and relative permeability curves using DRP methods will result if micro-scale variations in wettability are not taken into account. Finally, the study demonstrates that fluid imbibition measurements may be performed at the micro-scale, enabling fine-scale rock composition/pore structure controls on fluid imbibition to be explored.

Nuclear Magnetic Resonance Measurement of Oil and Water Distributions in Spontaneous Imbibition Process in Tight Oil Reservoirs

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

Experimental study of influence of natural surfactant soybean phospholipid on wettability of high-rank coal

Changing wettability of coal rock surface for enhanced gas recovery, surfactant is widely used in coalbed methane exploitation. Recently, soybean phospholipid as non-toxic and degradable natural surfactant has gained increasing importance. However, effect of soybean phospholipid on wettability of high-rank coal is still unclear. In this work, typical high-rank coals were selected from the Qinshui Basin to analyze this effect mechanism. Experiments including surface tension, surface contact angle, coal fines imbibition, dispersion effect as well as gas-based permeability were carried out. Moreover, water locking mechanism of fracturing fluid in microfractures of coal reservoir was analyzed in detail. Results show that surface of high-rank coal is negatively charged in solution and have weak hydrophilicity. Soybean phospholipid can significantly reduce the surface tension of gas-liquid, and increase wettability of coal surface. Thus, soybean phospholipid contributes coal fines to disperse observed from filter cake using scanning electron microscope. Additionally, many conventional surfactants e.g. SDBS, CTMAB, OP-10 as well as soybean phospholipid were experimentally compared in performance in reducing capillary pressure. Results indicate that single soybean phospholipid do not show perfect performance. Specially, the imbibition rate of single soybean phospholipid solution along the pipe filled with coal fines was lower than that of conventional anionic and cationic surfactants, but still higher than that of stilled water and non-ionic surfactant. To further improve the capability of soybean phospholipid solution, composite surfactant was prepared with soybean phospholipid and OP-10. We found that composite surfactant at the mass ratio of 1:3 has a lowest capillary pressure with low surface tension and large contact angle. Finally, effect of three typical surfactants on permeability of coal was investigated. Results show that this suggested compound surfactant may be conducive to discharge of fracturing fluid from coal reservoir microfractures as well as improve gas-phase relative permeability in coal engineering practice.

Experimental study of dynamic imbibition during water flooding of naturally fractured reservoirs

Capillary imbibition is an important recovery mechanism in naturally fractured reservoirs when water-filled fractures surround water-wet matrix blocks. A large amount of studies of imbibition process is simply total or partial immersion of nonwetting phase saturated rock in aqueous wetting phase. However, water advance in fractures during water flooding or water encroachment from an active aquifer introduces time dependent boundary conditions where invariant exposure of rock surface to water is not representative. In this work, a laboratory simulated matrix-fracture system was used to investigate different aspects of imbibition in the presence of fracture fluid flow (namely dynamic imbibition). A limestone and a sandstone core plug samples were selected as porous media. A total number of 11 dynamic imbibition and one static imbibition experiments were performed. Core plugs were strongly water-wet to maximize the role of capillary forces. Kerosene and air were the nonwetting fluids in experiments. The impact of water injection rate in the fracture was examined and the results revealed that as the injection rate increases above a critical rate, breakthrough recovery declines, however when injection rate is less than the critical rate increasing injection rate enhances recovery rate without any loss in recovery. Increasing wetting phase viscosity by means of glycerol solution was examined, as well. This reduced the imbibition rate and breakthrough recovery in both water-oil and water-air systems. Furthermore, comparing dynamic imbibition recovery data with a conventional immersion static experiment showed clear discrepancy which is due to different counter- and co-current flow modes. This emphasizes that static imbibition results should not be used for prediction of fractured reservoir performance under water flooding.

Recent advances in spontaneous imbibition with different boundary conditions

Spontaneous imbibition plays an important role in many practical processes, such as oil recovery, hydrology, and environmental engineering. The development in spontaneous imbibition goes fast in the past few years. In this paper, we focus on boundary conditions of spontaneous imbibition, which has important effects on spontaneous imbibition rate and efficiency. We introduce the fundamental physical mechanism of spontaneous imbibition with different boundary conditions by capillary model. Then, the studies of spontaneous imbibition in core scale are reviewed. The feature of spontaneous imbibition with different boundary conditions is discussed and the relative permeability for co- and counter-current imbibition is analyzed. The scaling of imbibition data with different boundary condition is also discussed by combination of experimental and numerical methods. At last, the analytical model of spontaneous imbibition is discussed. Cited as : Meng, Q., Cai, J. Recent advances in spontaneous imbibition with different boundary conditions. Capillarity, 2018, 1(3): 19-26, doi: 10.26804/capi.2018.03.01

Investigation into the Classification of Tight Sandstone Reservoirs via Imbibition Characteristics

Tight sandstone reservoirs are often produced by shutting in the well and inducing imbibition. However, by adopting current reservoir classifications, the heterogeneity of reservoirs cannot be properly treated. Based upon the analysis of the imbibition curves and mercury intrusion porosimetry tests, Chang-7 tight sandstone reservoirs were classified into three categories according to the newly proposed standards. Imbibition tests demonstrated that for the first category, imbibition and drainage occurred continuously and never reached the plateau within the experiment duration. It was suggested that a longer shut-in time favors the production of oil. For the second category, a steady state for imbibition was reached and a shut-in time as short as three days resulted in a high imbibition rate. For the third category, a plateau was reached for the first time and imbibition restarted until a steady state was reached. The average shut-in time for the third category was eight days. Compatibility between reservoir characteristics and a soaking development regime based upon the proposed classification methods effectively enhances the oil recovery efficiency of formations with distinct petrophysical properties. This provides insight into the classification methods of tight sandstone reservoirs.

Dynamic response characteristics of water and methane during isobaric imbibition process in remolded coal containing methane

Addition of water to the coal is actually an isobaric imbibition process. To study the dynamic response characteristics of water and methane, the isobaric imbibition process was stimulated by a self-designed experimental device which can eliminate the reabsorbing phenomenon. The results indicate that adding water can displace absorbed gas. The displacement mechanism is attributed to the capillary effect and competitive adsorption during isobaric imbibition process. A competitive adsorption phenomenon exists between gas molecules and water molecules. Since oxygen-containing functional groups in coal and the hydrogen bond of water, water can easily occupy high-energy sites and only the low-energy sites are available for methane. The imbibition quantity increases with increasing water content or adsorption equilibrium pressure. Moreover, the imbibition quantity would reach a maximum value. The relationship between water content and maximum imbibition quantity or the maximum imbibition rate can be described by a Langmuir function under the same adsorption equilibrium pressure. The maximum imbibition quantity increases with increasing adsorption equilibrium pressure under the same water content, which also can be described by a Langmuir function. However, the maximum imbibition rate decreases with increasing adsorption equilibrium pressures under the same water content, which can be described by an exponential function. Compared to the adsorption equilibrium pressure, the water content has a greater effect on the imbibition quantity and imbibition rate. This study revealed the mechanisms of the dynamic response characteristics of water and methane during isobaric imbibition process based on the transformation form of Hagen–Poiseuille equation, adsorption force of coal and gas and adsorption force of coal and water, which can provide a new method to control gas in deep coal seams.

Darcy-Scale Simulation of Boundary-Condition Effects During Capillary-Dominated Flow in High-Permeability Systems

Summary We present numerical interpretations of two experimental sets of spontaneous-imbibition tests with combined cocurrent/countercurrent flow in high-permeability, unconsolidated sandpacks. The experiments were conducted using the two-ends-open free-spontaneous-imbibition (TEOFSI) boundary condition, in which one end face was in contact with the wetting (W) phase and the other with the nonwetting (NW) phase. The simulations quantified the impact from boundary-condition effects during capillary imbibition in the low-capillary sandpacks; the flow resistance in the outlet filter controlled imbibition rates, end recovery, and countercurrent production in tests with high NW-phase viscosity. A hydrostatic water column of a few centimeters at the W-phase end face also affected the imbibition process. Numerical and analytical solutions provided insight into when such boundary effects become important. In particular, the observed linear recovery with time and variations in time scale could not be explained by conventional modeling, but were captured by incorporating a thin, low-permeability filter into the models. For high-viscosity NW-phase tests with a low-permeability filter, countercurrent production is strongly enhanced and controlled by the capillary backpressure (CBP).

A Two-Phase Flow Model for Pressure Transient Analysis of Water Injection Well considering Water Imbibition in Natural Fractured Reservoirs

The pressure injection falloff test for water injection well has the advantages of briefness and convenience, with no effect on the oil production. It has been widely used in the oil field. Tremendous attention has been focused on oil-water two-phase flow model based on the Perrine-Martin theory. However, the saturation gradient is not considered in the Perrine-Martin method, which may result in errors in computation. Moreover, water imbibition is important for water flooding in natural fractured reservoirs, while the pressure transient analysis model has rarely considered water imbibition. In this paper, we proposed a semianalytical oil-water two-phase flow imbibition model for pressure transient analysis of a water injection well in natural fractured reservoirs. The parameters in this model, including total compressibility coefficient, interporosity flow coefficient, and total mobility, change with water saturation. The model was solved by Laplace transform finite-difference (LTFD) method coupled with the quasi-stationary method. Based on the solution, the model was verified by the analytical method and a field water injection test. The features of typical curves and the influences of the parameters on the typical curves were analyzed. Results show that the shape of pressure curves for single phase flow resembles two-phase flow, but the position of the two-phase flow curves is on the upper right of the single phase flow curves. The skin factor and wellbore storage coefficient mainly influence the peak value of the pressure derivatives and the straight line of the early period. The shape factor has a major effect on the position of the “dip” of pressure derivatives. The imbibition rate coefficient mainly influences the whole system radial flow period of the curves. This work provides valuable information in the design and evaluation of stimulation treatments in natural fractured reservoirs.

Cocurrent Spontaneous Imbibition In Porous Media With the Dynamics of Viscous Coupling and Capillary Backpressure

Summary This paper presents a numerical study of water displacing oil using combined cocurrent/countercurrent spontaneous imbibition (SI) of water displacing oil from a water-wet matrix block exposed to water on one side and oil on the other. Countercurrent flows can induce a stronger viscous coupling than during cocurrent flows, leading to deceleration of the phases. Even as water displaces oil cocurrently, the saturation gradient in the block induces countercurrent capillary diffusion. The extent of countercurrent flow may dominate the domain of the matrix block near the water-exposed surfaces while cocurrent imbibition may dominate the domain near the oil-exposed surfaces, implying that one unique effective relative permeability curve for each phase does not adequately represent the system. Because relative permeabilities are routinely measured cocurrently, it is an open question whether the imbibition rates in the reservoir (depending on a variety of flow regimes and parameters) will in fact be correctly predicted. We present a generalized model of two-phase flow dependent on momentum equations from mixture theory that can account dynamically for viscous coupling between the phases and the porous media because of fluid/rock interaction (friction) and fluid/fluid interaction (drag). These momentum equations effectively replace and generalize Darcy's law. The model is parameterized using experimental data from the literature. We consider a water-wet matrix block in one dimension that is exposed to oil on one side and water on the other side. This setup favors cocurrent SI. We also account for the fact that oil produced countercurrently into water must overcome the so-called capillary backpressure, which represents a resistance for oil to be produced as droplets. This parameter can thus influence the extent of countercurrent production and hence viscous coupling. This complex mixture of flow regimes implies that it is not straightforward to model the system by a single set of relative permeabilities, but rather relies on a generalized momentum-equation model that couples the two phases. In particular, directly applying cocurrently measured relative permeability curves gives significantly different predictions than the generalized model. It is seen that at high water/oil-mobility ratios, viscous coupling can lower the imbibition rate and shift the production from less countercurrent to more cocurrent compared with conventional modeling. Although the viscous-coupling effects are triggered by countercurrent flow, reducing or eliminating countercurrent production by means of the capillary backpressure does not eliminate the effects of viscous coupling that take place inside the core, which effectively lower the mobility of the system. It was further seen that viscous coupling can increase the remaining oil saturation in standard cocurrent-imbibition setups.

Enhancement of the imbibition recovery by surfactants in tight oil reservoirs

Hydraulic fracturing technology can significantly increase oil production from tight oil formations, but performance data show that production declines rapidly. In the long term, it is necessary to increase the development efficiency of block matrix, surfactant-aided imbibition is a potential way. The current work aimed to explain comprehensively how surfactants can enhance the imbibition rate. Laboratory experiments were performed to investigate the effects of wettability, interfacial tension (IFT), and relative permeability as the key parameters underlying surfactant solution imbibition. Two different types of surfactants, sodium dodecyl sulfate and polyethylene glycol octylphenol ether, at varied concentrations were tested on reservoir rocks. Experimental results showed that the oil recovery rate increased with increased wettability alteration and IFT and decreased residual oil saturation. A mechanistic simulator developed in previous studies was used to perform parametric analysis after successful laboratory-scale validation. Results were proven by parametric studies. This study, which examined the mechanism and factors influencing surfactant solution imbibition, can improve understanding of surfactant-aided imbibition and surfactant screening.

Evaluation of the near fracture face formation damage caused by the spontaneously imbibed fracturing fluid in unconventional gas reservoirs

In the present study, spontaneous imbibition experiments, steady-state permeability measurements, and numerical simulation were integrated to quantify the changes in the effective water permeability, capillary pressure, and water relative permeability curves due to the polymer adsorption of the spontaneously imbibed fracturing fluid. The effect of the nonionic surfactant and core bedding plane on the fluid spontaneous imbibition volumes were also investigated.The researchers considered the impact of the spontaneous imbibition of a friction reducer fluid in tight sand and shale core samples. Three comparative systematic spontaneous imbibition experiments were conducted for each of the core samples using brine, anionic friction reducer fluid, and brine again. The core sample water permeability before and after the imbibition experiment was measured using a constant rate steady-state permeability apparatus.The polymer adsorption from the spontaneously imbibed fracturing fluid significantly reduced the brine spontaneous imbibition volumes in tight sand samples and in shale samples, though to a lesser degree. Moreover, the effective water permeability was decreased because of the polymer adsorption effect. Therefore, the polymer adsorption during hydraulic fracturing reduces the fluid leak-off into the formation and also the fluid flowback.The nonionic surfactant increased the fluid spontaneous imbibition volumes in both tight sand and shale samples. Thus, adding a nonionic surfactant to the friction reducer pad fluid during hydraulic fracturing leads to enhance both of the fluid leak-off and fluid flowback. The results also showed that the effect of polymer adsorption on the imbibition rates is less when the rock-fluid contact surface is parallel to the bedding plane.The imbibition potentials and imbibition capillary pressure curves were calculated before and after polymer adsorption. The polymer adsorption led to a slight increase in the capillary pressure; moreover, the tight sand samples had higher capillary pressure than the shale samples. The imbibition water relative permeability curves were calculated using ECLIPSE commercial simulator. The polymer adsorption significantly reduces the water relative permeability curves for tight sand samples and in less degree for shale samples.

Study of the Imbibition Behavior of Hydrophilic Tight Sandstone Reservoirs Based on Nuclear Magnetic Resonance

Hydraulic fracturing is one of the key technologies to enhance the oil recovery from tight sandstone reservoirs. The study on the behavior of imbibition for tight sandstone reservoir is of great significance to increase oil production after fracturing. In this paper, nuclear magnetic resonance (NMR) and high-pressure mercury injection were implemented on the samples taken from the Yanchang Formation of the Ordos Basin. The NMR T2 curves of the core at the state of 100% water saturated were converted to pore-throat radius distribution curves. On this basis, the experiments of imbibition and displacement were conducted and the changes of fluid distribution, imbibition quantity, and imbibition rate with different scale pores and different imbibition times were analyzed. Moreover, the results of imbibition and displacement were compared to assess the distribution of the recoverable and remaining oil under two exploitation modes and the contribution of imbibition made to displacement in pores at different scales. The result shows that imbibition is a relatively slow process. The entire imbibition process is mainly affected by nanopores, which are widely distributed in cores, and the imbibition rate of total pores constantly decreases as the imbibition time increases. Moreover, the relative recovery in pores at different scales shows a huge difference under the two exploitation modes of imbibition and displacement. During imbibition, smaller pores produced higher degrees of oil, while during displacement, larger pores have higher relative recovery. The contribution of imbibition made to displacement in nanopores was the highest and decreased with the increase of the pore-throat size.