Spontaneous Imbibition Mechanism Research Articles

Nanoparticle size: A critical role in enhancing oil recovery

In recent years, nanomaterials have shown great potential in the enhanced oil recovery (EOR) process due to their superior properties. However, the influence of particle size on EOR is not clear and hinders the application. Therefore, it is vitally important to investigate the effect of the particle size on the EOR performance. In this work, Fe3O4 nanoparticles with different sizes, including 20 nm, 100 nm, 200 nm, and 300 nm, were controllably synthesized and used to innovatively clarify the critical role of nanoparticles size in enhancing oil recovery. The effects of sizes on the recovery were investigated by combining the experimental results of interfacial tension, wetting angle, and spontaneous imbibition. The results revealed that Fe3O4 nanoparticles with smaller size, which have the stronger ability to reduce the interfacial tension and change the wetting angle, exhibit a favorable capacity to enhance oil recovery. Compared with the spontaneous imbibition oil recovery (24.36 %) of standard brine, the nanofluid containing 0.1 wt% Fe3O4 with the size of 20 nm can increase the recovery to 30.87 %. Based on the results of nuclear magnetic resonance, the spontaneous imbibition mechanism was proposed and the effect of size on recovery was analyzed. In addition, the superparamagnetism of Fe3O4 was utilized for recycling, avoiding the issue of significant losses of nanofluids in the existing research after injection. The secondary spontaneous imbibition was carried out, showing good environmental friendliness.

Investigation of the Combination Mechanism of Spontaneous Imbibition and Water Flooding in Tight Oil Reservoirs Based on Nuclear Magnetic Resonance

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

Study on the main factors and mechanism of functional silica nanofluid spontaneous imbibition for enhanced oil recovery

Nanofluids have shown great potential as chemical additives for enhanced oil recovery in low-permeability reservoirs owing to their unique properties. However, their application in harsh reservoir conditions poses challenges due to the demanding stability requirements. In this work, the functional silica nanofluid capable of withstanding high salinity and elevated temperature was prepared by blending 0.1 wt% hydrophilic silica sol with the 0.1 wt% modifier lauramidopropyl hydroxy sulfobetaine. Multiple experiments of the nanofluid were conducted, encompassing characterization, interfacial tension (IFT) and contact angle measurements. The nanoparticles had an average size of approximately 17 nm, and the nanofluid exhibited excellent stability, interfacial activity and wettability alteration ability. Spontaneous imbibition tests demonstrated that the nanofluid achieved a remarkable recovery of 35.30 %, compared with only 5.53 % for simulated formation water. Subsequently, the relationship between spontaneous imbibition recovery and factors, such as temperature, salinity and core permeability, was investigated. The influence weight for each factor on the recovery is as follows: temperature (64.61 %) > core permeability (19.07 %) > salinity (16.32 %). Furthermore, a comprehensive description of the spontaneous imbibition mechanism of nanofluids was provided, incorporating insights from 1HNMR results. We expect that this study can offer valuable insights into nanofluid formulation, supporting the efficient development of low-permeability reservoirs and provide a theoretical basis for field applications.

Simulation Study on the Spontaneous Imbibition Mechanism and Influencing Factors of Laminated Shale Oil Reservoirs in Jiyang Depression, Eastern China

Simulation Study on the Spontaneous Imbibition Mechanism and Influencing Factors of Laminated Shale Oil Reservoirs in Jiyang Depression, Eastern China

Novel silicon quantum dots for efficient imbibition oil recovery in low permeability reservoirs

In this work, the active sulfonated silicon quantum dots (S-SiQDs) nanofluid composed of S-SiQDs nanoparticles and bitetradecyl sulfobetaine (BS) was prepared to enhance oil recovery of low permeability reservoir by spontaneous imbibition. Firstly, a facile hydrothermal synthesis method was proposed to fabricate silicon quantum dots (SiQDs), followed by sulfonated modification of SiQDs to obtain S-SiQDs. The average particle size of S-SiQDs was 5.4 nm and it can remain stable at 120 °C and 5 wt% NaCl for 7 days. In addition, the active S-SiQDs nanofluid had better abilities in interfacial tension reduction, wettability alteration, and oil detachment than single surfactants and single S-SiQDs due to the synergistic effect. Compared with single S-SiQDs (12.8 %) and BS surfactant (17.5 %), the active S-SiQDs nanofluid can significantly improve the imbibition recovery to 29.9 %. Finally, the spontaneous imbibition mechanism of this active S-SiQDs nanofluid was proposed through nuclear magnetic resonance and theoretical analysis. This work develops an active S-SiQDs nanofluid with ultra-small size, excellent temperature and salinity resistance, and high interfacial activity, which can efficiently improve oil recovery of low permeability reservoirs.

The enhancement of performance and imbibition effect of slickwater-based fracturing fluid by using MoS2 nanosheets

Slickwater-based fracturing fluid has recently garnered significant attention as the major fluid for volumetric fracturing; however, lots of challenges and limitations such as low viscosity, poor salt tolerance, and possible formation damage hinder the application of the conventional simple slickwater-based fracturing fluid. In addition, nanomaterials have proven to be potential solutions or improvements to a number of challenges associated with the slickwater. In this paper, molybdenum disulfide (MoS2) nanosheets were chemically synthesized by hydrothermal method and applied to improve the performance of conventional slickwater-based fracturing fluid. Firstly, the microstructure characteristics and crystal type of the MoS2 nanosheets were analyzed by SEM, EDS, TEM, XPS, and Raman spectroscopy techniques. Then, a series of evaluation experiments were carried out to compare the performance of MoS2 nanosheet-modified slickwater with the conventional slickwater, including rheology, drag reduction, and sand suspension. Finally, the enhanced imbibition capacity and potential mechanism of the nanosheet-modified slickwater were systematically investigated. The results showed that the self-synthesized MoS2 nanosheets displayed a distinct ultrathin flake-like morphology and a lateral size in the range of tens of nanometers. In the nano-composites, each MoS2 nanosheet plays the role of cross-linking point, so as to make the spatial structure of the entire system more compact. Moreover, nanosheet-modified slickwater demonstrates more excellent properties in rheology, drag reduction, and sand suspension. The nanosheet-modified slickwater has a higher apparent viscosity after shearing 120 min under 90 °C and 170 s−1. The maximum drag reduction rate achieved 76.3% at 20 °C, and the sand settling time of proppants with different mesh in the nano-composites was prolonged. Spontaneous imbibition experiments showed that the gel-breaking fluid of nanosheet-modified slickwater exhibited excellent capability of oil-detaching, and increase the oil recovery to ∼35.43%. By observing and analyzing the interfacial behavior of MoS2 nanosheets under stimulated reservoir conditions, it was found that the presence of an interfacial tension gradient and the formation of a climbing film may play an essential role in the spontaneous imbibition mechanism. This work innovatively uses two-dimensional MoS2 nanosheets to modify regular slickwater and confirms the feasibility of flake-like nanomaterials to improve the performance of slickwater. The study also reveals the underlying mechanism of enhanced imbibition efficiency of the nano-composites.

The spontaneous imbibition mechanisms for enhanced oil recovery by gel breaking fluid of clean fracturing fluid

The quick flowback treatment after conventional fracturing construction can waste a lot of energy from fracturing fluid. Meanwhile, spontaneous imbibition has great application potential for enhanced oil recovery (EOR). In this work, based on pre-developed silica nanoparticle-reinforced CO2-sensitive fracturing fluid system, the imbibition factors of the gel breaking fluid were studied. In addition, the HNMR technology, AFM, contact angle test, and interfacial tension (IFT) test were used to explore the mechanism of spontaneous imbibition. The results show that imbibition mainly occurs in the small pores, and the adsorption of components can reduce roughness and flow resistance. Meanwhile, the adsorption layer was formed by surfactants and nanoparticles, changing wettability from oil-wet to water-wet, reducing the IFT between oil and water. The synergistic effect of multi-component improves the imbibition effect. We expect that this study can broaden the application of multi-component gel breaking fluid in low permeability reservoirs.

Influencing Factors of Surfactant Stripping Crude Oil and Spontaneous Imbibition Mechanism of Surfactants in a Tight Reservoir.

Surfactants play a vital role in the working fluid during the exploitation of tight reservoirs. The main goal is to clarify the mechanism of surfactant production enhancement in the reservoir. In this paper, starting from the interface properties and emulsifying properties of surfactants, the factors affecting the stripping of crude oil by different surfactants were described in detail. Meanwhile, the imbibition experiments of cores were used to clarify the two spontaneous imbibition mechanisms of the surfactant. Namely, they are the capillary force expulsion caused by the emulsion stripping thermal diffusion–convection and the wettability change. When the interfacial tension between the surfactant and oil is in the range of 10–2–10–3 mN/m, the particle size of emulsion is less than 1 μm, and the oil stripping efficiency is greater than 58%. The imbibition is mainly caused by thermal diffusion–convection. The wetting angle of the surfactant mainly changing wettability is less than 15°, and the adhesion work is greater than 52 mN/m. Using X-ray computed tomography, the surfactant imbibition distance of different permeability types of cores was obtained. The results show that higher permeability cores have a deeper imbibition distance. The results of this paper enrich the mechanism of enhanced oil recovery by surfactants and have important implications for the exploitation of tight reservoirs.

An understanding of oil–water replacement mechanism based on interfacial tension gradient during the well shut-in

Spontaneous imbibition behavior of fracturing fluid retained in reservoirs is considered to be one of the important mechanisms of spontaneous oil–water displacement in tight reservoirs. However, the mechanism of imbibition displacement in oil-wet rocks remains unclear. Inspired by the principle of the Marangoni effect, a mathematical model of oil displacement driven by an interfacial tension gradient in an oil-wet capillary tube was established, and the effects of osmotic pressure and hydraulic mechanical dispersion were coupled in the model. The results show that the key component of this mechanism is the breakdown of the initial capillary equilibrium state due to the diffusion of solute, which changes the pressure distribution in the capillary and drives the water to drive oil out of the pores. This can explain the spontaneous imbibition of low-salinity fracturing fluid into the oil-wet tight sample and displace oil without any external force, despite its low permeability. In addition, the related factors were analyzed, including initial concentration, contact angle, solute type, osmotic behavior, and size of the capillary. The results show that for an oil wet reservoir with high salinity, the connate water interfacial tension gradient plays an important role in oil displacement, and the coupling effect of osmotic pressure and hydromechanical dispersion considerably improves recovery. This can provide new insight into the mechanism of spontaneous imbibition of fracturing fluid.

Study on Influencing Factors of Surfactant Stripping Crude Oil and Spontaneous Imbibition Mechanism of Surfactant in Tight Reservoir

Study on Influencing Factors of Surfactant Stripping Crude Oil and Spontaneous Imbibition Mechanism of Surfactant in Tight Reservoir

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference.

Interwell interference is a universal problem in shale gas development and can cause severe reductions in the productivity of producing wells. Studies have attempted to identify the root cause of interference in producing wells, but the mechanisms of production reduction and recovery in impacted wells are still not clear. Thus, an effective preventive strategy is needed for producing wells when fracturing is performed in adjacent wells. According to the mechanism of spontaneous imbibition and water drainage in shale mico- and nanoscale pores, this paper introduces the water–gas distribution during fracturing and production and reveals that water drainage in micro- and nanoscale pores is mainly controlled by the amount of stored gas and follows the order of pore size. Based on this analysis, the mechanism by which interwell interference impacts the production of producing wells is explained for the first time. It is concluded that the secondary water invasion caused by interwell interference completely blocks the pores associated with long-term gas production but has little influence on the pores that have not yet drained or have produced only a small amount of gas, and smaller pores face a greater risk of water blockage. The proportion of drained pores formed during long-term gas production determines the effect of interwell interference on production; when more pores are drained by long-term gas production, greater damage occurs to the productivity of the producing well. The suggestion for preventing interwell interference is to reduce the time interval between fracturing operations at two adjacent wells, thereby diminishing the reduction in production.

Study on mechanism of spontaneous imbibition and pressurized imbibition in shale oil reservoirs

Imbibition is one of the important methods of oil recovery in shale oil reservoirs. At present, more in-depth studies have been carried out on the fracture system and matrix system, and there are few studies on the effect of energy enhancement on imbibition in shale oil reservoirs. Therefore, based on the study of pressurized imbibition and spontaneous imbibition of shale oil reservoirs in Qianjiang Sag, Jianghan Basin, nuclear magnetic resonance technology was used to quantitatively characterize the production degree of shale and pore recovery contribution under different imbibition modes, and analyze the imbibition mechanism of shale oil reservoirs under the condition of energy enhancement. The experimental results showed that with the increase in shale permeability, the recovery ratio of pressurized imbibition also increased. The rate of pressurized imbibition was higher than spontaneous imbibition, and pressurized imbibition can increase the recovery ratio of fractured shale. Spontaneous imbibition can improve the ultimate recovery ratio of matrix shale. Pressurized imbibition can increase the recovery contribution of macroporous and mesoporous.

Mathematical model of the spontaneous imbibition of water into oil-saturated fractured porous media with gravity

Studying the mechanism of spontaneous imbibition into oil-saturated fractures is of great significance for unconventional oil reservoir development. Both theory and experimental observations indicate that SI in fractures is significantly different from that in tight matrix. In this work, the implicit analytical solution of the spontaneous water imbibition into a single oil-saturated fracture with gravity is first proposed. The results show that the difference in imbibition velocity with and without gravity increases with the increase in fracture aperture. There is a critical fracture length for SI in the single oil-saturated fracture. Based on the fractal/normal distribution of fracture apertures, the core-scale mathematical model of spontaneous imbibition in the oil-saturated fractured porous media is proposed. The effect of fracture distribution on the oil imbibition rate is investigated and discussed.

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 on the Application of NMR to Spontaneous Imbibition Recovery of Tight Sandstones: An Experimental Study

In this paper, the nuclear magnetic resonance (NMR) technique is applied to exploring the spontaneous imbibition mechanism in tight sandstones under all face open (AFO) boundary conditions, which will benefit a better understanding of spontaneous imbibition during the development of oil & gas in tight formations. The advantages of nuclear magnetic resonance imaging (NMRI) and NMR T2 are used to define the distribution of remaining oil, evaluate the effect of micro structures on imbibition and predict imbibition recovery. NMR T2 results show that pore size distributions around two peaks are not only the main oil distributions under saturated condition but also fall within the main imbibition distributions range. Spontaneous imbibition mainly occurs in the first 6 h and then slows down and even ceases. The oil signals in tiny pores stabilize during the early stage of imbibition while the oil signal in large pores keeps fluctuating during the late stage of imbibition. NMRI results demonstrate that spontaneous imbibition is a replacement process starting slowly from the boundaries to the center under AFO and ending with oil-water mixing. Furthermore, the wetting phase can invade the whole core in the first 6 h, which is identical with the main period of imbibition occurring according to NMR T2 results. Factors influencing the history of oil distribution and saturation differ at different periods, while it is dominated by capillary imbibition at the early stage and allocated by diffusion at later time. Two imbibition recovery curves calculated by NMRI and NMR T2 are basically consistent, while there still exists some deviations between them as a result of the resolutions of NMRI and NMR T2. In addition, the heterogeneity of pore size distributions in the two samples aggravates this discrepancy. The work in this paper should prove of great help to better understand the process of the spontaneous imbibition, not only at the macroscopic level but also at the microscopic level, which is significant for oil/gas recovery in tight formations.

Spontaneous imbibition in asymmetric branch-like throat structures in unconventional reservoirs

Unconventional reservoirs, especially shale plays, have abundant micro-nano pores. Large volume water was injected into the reservoir during hydraulic fracturing. Fracturing fluid can displace gas in pore spaces spontaneously, called spontaneous imbibition (SI), which has significant effects on the gas production after hydraulic fracturing. Throat structure in matrix is one of the key factors to influence SI process. In this work, at first, complex pore space is simplified as a spatial self-similar branch-like structure composed of several asymmetric sub-throats. Then, within asymmetric branch structure, the imbibition process is calculated by a newly established mathematical model, and the influence of both pore structure and fluid characteristics, including contract angle, viscosity, surface tension, are discussed. Finally, some lab experiments, especially SI tests, are included on shale and sandstone core plugs to verify our model. Results show that the coherence in wettability between the reservoir and the fracturing fluid is important to enhance the microscopic replacement effect. Pore size also has effect influence on imbibition curve. In addition, both in models and experiments, imbibition index n is useful to describe imbibition properties of rocks. In unconventional rock samples like shale, n is less than 0.4, while high-permeability sandstone, n approach to 0.5. These conclusions are useful to investigate the mechanism of spontaneous imbibition and microscopic displacement in unconventional reservoirs.

Wettability Alteration of Sandstone and Carbonate Rocks by Using ZnO Nanoparticles in Heavy Oil Reservoirs

Efforts to enhance oil recovery through wettability alteration by nanoparticles have been attracted in recent years. However, many basic questions have been ambiguous up until now. Nanoparticles penetrate into pore volume of porous media, stick on the core surface, and by creating homogeneous water-wet area, cause to alter wettability. This work introduces the new concept of adding ZnO nanoparticles by an experimental work on wettability alteration and oil recovery through spontaneous imbibition mechanism. Laboratory tests were conducted in two experimental steps on four cylindrical core samples (three sandstones and one carbonate) taken from a real Iranian heavy oil reservoir in Amott cell. In the first step, the core samples were saturated by crude oil. Next, the core samples were flooded with nanoparticles and saturated by crude oil for about two weeks. Then, the core samples were immersed in distilled water and the amount of recovery was monitored during 30 days for both steps. The experimental results showed that oil recovery for three sandstone cores changed from 20.74, 4.3, and 3.5% of original oil in place (OOIP) in the absence of nanoparticles to 36.2, 17.57, and 20.68% of OOIP when nanoparticles were added respectively. Moreover, for the carbonate core, the recovery changed from zero to 8.89% of OOIP by adding nanoparticles. By the investigation of relative permeability curves, it was found that by adding ZnO nanoparticles, the crossover-point of curves shifted to the right for both sandstone and carbonate cores, which meant wettability was altered to water- wet. This study, for the first time, illustrated the remarkable role of ZnO nanoparticles in wettability alteration toward more water-wet for both sandstone and carbonate cores and enhancing oil recovery.

Study of Spontaneous Imbibition of Water by Oil-Wet Sandstone Cores Using Different Surfactants

The mechanism of spontaneous imbibition of water by sandstone cores and the relationship between reservoir wettability and imbibition recovery were studied by investigating factors influencing the spontaneous imbibition of different surfactants by oil-wet sandstone cores. Ultimate oil recovery of cores using the cationic surfactant CTAB was higher than that of the cores using the nonionic surfactant TX-100 and the anionic surfactant POE (1) at the same concentration. For CTAB and TX-100, the ultimate oil recovery by spontaneous imbibition increased with increase in surfactant concentration. In regard to imbibition recovery, TX-100 and POE(1) at high temperatures were superior to those at low temperatures. Ultimate oil recovery of the high-permeability core was higher than that of the low-permeability core at room temperature. According to changes in the driving force during the imbibition process, the imbibition curve could be divided into three regions: (1) mainly capillary force, (2) both capillary and gravity forces, and (3) mainly gravity force. The stronger the hydrophilicity of the rock surface, the higher the spontaneous imbibition recovery.

Developments in spontaneous imbibition and possibilities for future work

Abstract Spontaneous imbibition controls many processes of practical importance. The subject is undergoing rapid growth in terms of the number of publications. This paper is a selective review of the literature which concentrates on the last ten years or so but also highlights, as necessary, earlier work. Insight into the mechanism of spontaneous imbibition is provided through consideration of the behavior of strongly wetted uniform tubes of any cross-section. The significance of cross-flow on the mechanism of advance of interfaces in tubes is related to imbibition in much more complex pore spaces. Details of the mechanism of imbibition by rocks and correlation of data for very strongly wetted conditions are discussed with respect to the numerous variables. Correlation of spontaneous imbibition data for a wide range of viscosity ratios demonstrates unequivocally that the operative relative permeabilities during counter current imbibition are not unique as is commonly assumed. They depend on viscosity ratio. This dependence points to the limitations of analytic models of spontaneous imbibition that also include the choice of specific boundary conditions at the open face. Experiments in which both the wetting and non-wetting phase are located at separate areas of the rock face demonstrate simultaneous co- and counter-current imbibition. This new configuration offers certain interpretive advantages, especially with respect to estimating operative relative permeabilities. The effective capillary pressure at the imbibition front drives the imbibition process. Imbibition is opposed by viscous resistance and the capillary back-pressure at the open face. Modeling advance of the imbibition front as a leaky piston gives agreement with experimental data for a range of scenarios. The piston model provides a consistent and more easily understood mechanistic account of frontal behavior than current network models. Experiment and theory for examples of when imbibition rate is and is not proportional to square root of time are explained. The predictive capability often claimed for network modeling with respect to spontaneous imbibition for very strongly wetted and other wetting states is questioned. Network modeling is now commonly tied to micro-CT images of small rock samples. Spontaneous imbibition is fundamentally a dynamic process and meaningful progress depends on it being modeled as such. There is a trend within the modeling community of reaching questionable conclusions based on so called quasistatic mechanisms while under-utilizing the versatility and predictive capabilities of network modeling with respect to dynamic processes. Topics for further investigations of spontaneous imbibition are suggested. They include several opportunities for testing network models against experimental data.

Fractal analysis of spontaneous imbibition mechanism in fractured-porous dual media reservoir

Low permeability oil reservoirs are usually accompanied with fracture development, forming fracture-matrix dual porosity medium. Spontaneous imbibition is a crucially important recovery mechanism in naturally fractured reservoir with water deriving, in which non-wetting phase is displaced in either co-current or counter-current manner. In this work, the criterion (inverse bond number) and fractal model for spontaneous imbibition mechanism of dual-porosity medium are developed, and the analytical expression for structure constant is also derived based on the fractal characteristics of pores in porous matrix. The improved fractal model for inverse bond number can be expressed as a function of porosity, pore fractal dimension, flow tortuosity, maximum pore diameter, height of matrix, density difference between oil and water, interfacial tension and contact angle. The present model predictions are shown to be in agreement with the available results. The dominion for criterion of imbibition mechanism is plotted, which provides a theoretical basis of adding surfactant in water for enhancing oil recovery in low permeability reservoirs.