Spontaneous Imbibition Process Research Articles

A Practical Methodology to Screen Oil Recovery Processes Involving Spontaneous Imbibition

We present a general novel technique to monitor saturation changes on small rock samples of only 15 mm in diameter and 20 mm in length for the purpose of assessing the kinetics of spontaneous imbibition processes. With a fully 3D imbibition configuration involving countercurrent flows through all faces of the sample, the method is based on an NMR technique in which the sole oil phase present within the sample is monitored. The experimental method is fast for two reasons that are (1) the possibility to perform accurate measurements on tiny samples and (2) the adoption of a 3D flow geometry. The kinetics of oil desaturation during spontaneous imbibition is analyzed with the help of an analytical 3D diffusion model, according to which the kinetics is proportional to the value of a “capillary” diffusion coefficient. For the purpose of demonstrating our methodology, we used this technique to compare the spontaneous imbibition of restored sandstone miniplugs from a sandstone reservoir, with and without alkali in the imbibing brine. The imbibition kinetics was quantified as capillary diffusion coefficient values. The studied case results revealed mixed impacts of alkali on the spontaneous imbibition kinetics, involving both a brine–oil interfacial tension change and a wettability alteration of the rock, the latter requiring further investigation beyond the scope of this article.

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.

Dos and Don’ts When Developing a System to Investigate Spontaneous Imbibition in Unconsolicdated Porous Media

This paper describes the development of a consistent model system to measure spontaneous imbibition and determine saturation functions in unconsolidated porous media. Sand grains or glass beads were packed in up to 0.5 m long, transparent glass tubes with optical access to local saturation development during spontaneous imbibition processes. The Two Ends Open-Free spontaneous imbibition (TEOFSI) boundary condition was used, where one end face is exposed to the wetting fluid and the other end to the non-wetting fluid. Dynamic measurement of the advancing displacement front and volumetric production from each open end-face enabled estimation of capillary pressure and relative permeability for the system. A range of wetting- and non-wetting phase viscosities and viscosity ratios was used during spontaneous imbibition in unconsolidated sand or glass packs. Wetting phase (water) viscosity was increased using water soluble glycerol or polymers. Air or mineral oil of varying composition provided a wide range of non-wetting phase viscosities. High permeable systems are extremely sensitive to laboratory properties, which may dominate the viscous resistance and determine flow behaviour. Systematic discrepancies observed in early testing indicated that end effects were present, even in long systems, in the filters at each end of the glass tube to maintain the grains or beads in place. Different filters were tested (no filter, glass, paper and micro-porous discs) to determine the impact of the filter on spontaneous imbibition. In addition to slower oil recovery than anticipated, developmentof a non-uniform displacement front was observed, demonstrating the large influence from minute heterogeneities within the packs, and at the end faces. A standard sand grain packing procedure, using a custom-designed packing device, was therefore developed to ensure homogeneous properties throughout theporous media, and limited the spread in porosity and permeability values. Homogeneous sand packs with reproducible properties are necessary, to systematically investigate flow parameters and changes in wettability in unconsolidated porous media.

A novel experimental approach for studying spontaneous imbibition processes with alkaline solutions

Spontaneous imbibition processes can play an important role in oil production. It can be enhanced or influenced by wettability changes generated by properly designed chemicals or by the natural surfactants resulting from reactive crude oils in the presence of alkaline solutions. The reaction of basic salts with some components of oil can, indeed, lead to the formation of natural soaps that reduces the interfacial tension between oil and brine. The latter scenario is studied herein on samples and oil from the St Ulrich oil field in the Vienna basin. To that end, spontaneous imbibition experiments were performed with two brines differing by the absence or presence of alkali. We first present a general novel technique to monitor saturation changes on small rock samples for the purpose of assessing the efficiency of a given recovery process. Samples of only 15 mm in diameter and 20 mm in length and set at irreducible saturation were fully immersed in the solution of interest, and the evolution of the samples’ saturation with time was monitored thanks to a dedicated NMR technique involving the quantification of the sole oil phase present within the sample. A fully-3D imbibition configuration was adopted, involving counter-current flows through all faces of the sample. The experimental method is fast for two reasons: (i) the kinetics of capillary imbibition process is proportional to the square of sample size, i.e. very rapid if accurate measurements can be acquired on tiny samples, (ii) the present 3D situation also involves faster kinetics than the 1D configuration often used. The NMR technique was crucial to achieve such conditions that cannot be satisfied with conventional volumetric methods. The kinetics of oil desaturation during spontaneous imbibition is interpreted with the help of an analytical 3D diffusion model. For the alkaline solution, the diffusion coefficient is reduced by a factor of only two compared to the non-alkaline brine, although the interfacial tension between the oil and the imbibing solution is reduced by a factor of 10. Hence, a wettability change to a more water wet state has to be assumed when the alkaline solution replaces the non-alkaline solution in the imbibition process. However, no significant impact on the final saturation was observed.

Modelling shale spontaneous water intake using semi‐analytical and numerical approaches

AbstractShale matrix water intake during hydraulic fracturing is considered undesirable due to the high volume of unrestrained water loss; however, it is also rewarding because it can reduce the possibility of groundwater contamination. The water intake also plays a dual role in changing the shale production performance; water imbibition into matrix pores can dramatically reduce the effective permeability and, at the same time, might enhance hydrocarbon production by creating adsorption‐induced micro‐fractures. Quantifying the formation intake capacity and its breadth is the key to optimizing fracturing operation, flowback, and production strategy. This work entails complementary semi‐analytical and numerical analyses and investigates the effects of basic rock and fluid properties, wettability heterogeneity, and pore space connectivity on the shale imbibition characteristics. We consider a semi‐analytical formulation of the spontaneous water imbibition, together with model results and validations, and try to provide a framework to link the capillary imbibition capacity/rate to lab‐scale observations. The core‐scale measurements provide input for a sensitivity study on the matrix imbibition capacity in six shale plays in North America. The results suggest that rock permeability, hydraulic tortuosity, and initial and residual hydrocarbon saturations are among the most influential factors on the spontaneous water intake during shut‐in periods. Direct quasi‐static simulations are then conducted through a submicron tomography image of the Eagle Ford shale, and two‐phase pore‐level fluid occupancies are reconstructed during spontaneous and forced imbibition processes. According to the numerical results, the presence of continuous organic matter laminae can lower the destructive effects of water imbibition on the hydrocarbon permeability.

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.

Pore‐Scale Modeling of Spontaneous Imbibition Behavior in a Complex Shale Porous Structure by Pseudopotential Lattice Boltzmann Method

AbstractSpontaneous imbibition of fracturing fluid into shale matrix is one of the primary reasons for the low flowback rate in shale gas wells after the hydraulic fracturing. This leads to concerns of impacts on both environment and shale gas production. A direct pore‐scale simulation is crucial to gain a deep understanding of spontaneous imbibition behavior and its impacts. The porous structures in the shale matrix are characterized by not only a geometrical complexity but also a mixed wettability, which bring great challenges to simulation methods. An improved pseudo‐potential lattice Boltzmann method is proposed to simulate the spontaneous imbibition behavior in a reproduced three‐dimensional porous structure of shale. The results show that the nanoscale hydrophilic pores provide the driving force and a storage place for the residual treatment fluid. The pore size and wettability heterogeneity lead to the nonuniform menisci propagation and fracturing fluid distribution in the model. Specifically, the fracturing fluid imbibed quicker in the larger pores at the early stage and gradually migrated into the smaller pores during the process. With a limited volume of the fracturing fluid, a portion of the larger pores was finally reopened. The analysis of saturation and apparent gas permeability data during the spontaneous imbibition process showed a great recovery of the model permeability along with the reopened pores. These results provide direct evidence of the residual fracturing fluid migration pattern in the shale reservoir and its influence on shale gas production.

The visual and quantitative study of remaining oil micro-occurrence caused by spontaneous imbibition in extra-low permeability sandstone using computed tomography

Spontaneous capillary imbibition plays a significant role in oil displacement mechanism during water flooding operation in extra-low permeability sandstone reservoirs. However, after long-term of waterflooding, most of the oil blobs still remain within the pore space. In this context, quantitative assessment of the micro-occurrence of remaining oil in pore space is indispensable to conduct for an efficient waterflooding operation. In this work, the core sample with 3 mm × 10 mm dimensions was prepared from the southeast area of Ordos Basin Chang6 extra-low permeability formation. Subsequently, high-resolution X-rays CT scanning technology was employed to visualize the changes in fluid distribution during spontaneous imbibition process. By means of image segmentation and three-dimensional (3-D) image reconstruction technique, the images of the remaining oil in the 3-D pore space were obtained. After that, the shape factor and relative volume factor were used to quantify the micro-occurrence of remaining oil in the 3-D pore space. The experimental results show that the total volume of oil was declined to 2.27 × 107 μm3 from 4.25 × 107 μm3 after spontaneous imbibition in the core sample. Consequently, the continuous oil phase was disrupted by the water in pore space and segmented oil blocks were appeared. Meanwhile, the number of oil blocks was increased to 6027 from 958 that led to severe Jamin’s effect and spontaneous imbibition was resultantly came to an end. While in 3-D pore space, three different kinds of micro-occurrences of remaining oil were spotted, such as network (54.31%), cluster (35.28%), and isolated (10.51%). The network and cluster type of remaining oil micro-occurrences are considered as dominant types owing to the large volume and better communication. Because of abrupt capillary force reduction in suddenly enlarge channel and multiple Jamin’s effects, the network and cluster remaining oil would mainly be confined in large channels (over than peak pore radius). Therefore, our work provides some beneficial understanding of the remaining oil micro-occurrence in pore space after imbibition.

An Experimental Study on Interactions Between Imbibed Fracturing Fluid and Organic-Rich Tight Carbonate Source Rocks

Summary Carbonate reservoirs dominate oil (70%) and gas (90%) reserves in the Middle East, and imbibition is the main mechanism for fracturing-fluid uptake during the hydraulic-fracturing stimulation process. Because of the highly heterogeneous nature of tight carbonate source rocks, it is crucial to understand the effects of imbibed fluid on the mechanical, morphological, and flow properties of carbonate rocks. Although the influence of imbibed fluids on the wettability of carbonate reservoir has been studied extensively, research regarding the effects of imbibed fluids on the texture and mineralogy of carbonate rocks is still very limited. This paper aims to provide a conceptual approach and work flow to characterize and quantify microstructure and mineralogy changes in carbonate rocks caused by imbibed fluids. A thin section of a low-permeability organic-rich carbonate-rock sample [7×7×0.3 mm (length×width×thickness)] was used in the study. The sample was submerged into 2%-KCl (pH = 7.1) fluid from one end to simulate the spontaneous-imbibition process. A scanning electron microscope (SEM) was used to capture the sample's morphological changes before and after spontaneous imbibition. Energy-dispersive-spectroscopy (EDS) maps were measured before and after fluid treatment to investigate changes in various elemental distribution. In addition, inductively coupled plasma (ICP) equipped with an optical-emission-spectrometer (OES) detector was used to quantify dissolved-ion concentration in the treatment fluid. Permeability and porosity were measured using core plugs with dimensions of 1.0×1.5 in. (diameter×length) before and after fluid treatment. During the imbibition process, approximately one-half of the sample was submerged in the treatment fluid. The SEM images for the thin-section sample showed three zones with distinct fluid-uptake characteristics. In Zone I, which was fully submerged in the testing fluid, a significant amount of mineral dissolution was observed. In Zone III, which was above the testing-fluid level, considerable mineral precipitation was detected. While in the transition zone just above the water/air interface (Zone II between the previous two zones), only a minor level of mineral dissolution was observed. Elemental-distribution changes resulting from the fluid treatment were identified by EDS analysis in all three zones. Gypsum and calcite crystals dissolved into imbibed fluids upon reaction. Gypsum was found reprecipitated on the rock surface in the zones above fluid level. The observed gypsum formation likely resulted from the dissolution of the gypsum from the rock matrix, then reprecipitation later from the imbibition experiment caused by water evaporation. Absolute-permeability and porosity measurements for core-plug samples have shown that both were increased after the imbibition process.

Enhanced oil recovery from carbonate reservoirs by spontaneous imbibition of low salinity water

An experimental study was performed to investigate the impact of low salinity water on wettability alteration in carbonate core samples from southern Iranian reservoirs by spontaneous imbibition. In this paper, the effect of temperature, salinity, permeability and connate water were investigated by comparing the produced hydrocarbon curves. Contact angle measurements were taken to confirm the alteration of surface wettability of porous media. Oil recovery was enhanced by increasing the dilution ratio of sea water, and there existed an optimum dilution ratio at which the highest oil recovery was achieved. In addition, temperature had a very significant impact on oil recovery from carbonate rocks. Furthermore, oil recovery from a spontaneous imbibition process was directly proportional to the permeability of the core samples. The presence of connate water saturation inside the porous media facilitated oil production significantly. Also, the oil recovery from porous media was highly dependent on ion repulsion/attraction activity of the rock surface which directly impacts on the wettability conditions. Finally, the highest ion attraction percentage was measured for sodium while there was no significant change in pH for all experiments.

Mathematical Model for the Fluid-Gas Spontaneous Displacement in Nanoscale Porous Media considering the Slippage and Temperature

The fracturing fluid-gas spontaneous displacement during the fracturing process is important to investigate the shale gas production and formation damage. Temperature and slippage are the major mechanisms underlying fluid transport in the micro-/nanomatrix in shale, as reported in the previous studies. We built a fracturing fluid-gas spontaneous displacement model for the porous media with micro-/nanopores, considering two major mechanisms. Then, our spontaneous displacement model was verified by the experimental result of the typical shale samples and fracturing fluids. Finally, the influences of temperature, slip length, and pore size distribution on the spontaneous imbibition process were discussed. Slippage and temperature significantly influenced the imbibition process. Lower viscosity, higher temperature, and longer slip length increased the imbibition speed. Ignoring the temperature change and slippage will lead to significant underestimation of the imbibition process.

Time scales of relaxation dynamics during transient conditions in two‐phase flow

AbstractThe relaxation dynamics toward a hydrostatic equilibrium after a change in phase saturation in porous media is governed by fluid reconfiguration at the pore scale. Little is known whether a hydrostatic equilibrium in which all interfaces come to rest is ever reached and which microscopic processes govern the time scales of relaxation. Here we apply fast synchrotron‐based X‐ray tomography (X‐ray CT) to measure the slow relaxation dynamics of fluid interfaces in a glass bead pack after fast drainage of the sample. The relaxation of interfaces triggers internal redistribution of fluids, reduces the surface energy stored in the fluid interfaces, and relaxes the contact angle toward the equilibrium value while the fluid topology remains unchanged. The equilibration of capillary pressures occurs in two stages: (i) a quick relaxation within seconds in which most of the pressure drop that built up during drainage is dissipated, a process that is to fast to be captured with fast X‐ray CT, and (ii) a slow relaxation with characteristic time scales of 1–4 h which manifests itself as a spontaneous imbibition process that is well described by the Washburn equation for capillary rise in porous media. The slow relaxation implies that a hydrostatic equilibrium is hardly ever attained in practice when conducting two‐phase experiments in which a flux boundary condition is changed from flow to no‐flow. Implications for experiments with pressure boundary conditions are discussed.

Simulation of counter-current imbibition in single matrix and field scale using radical integral boundary element method

During the water driving process in reservoir which has complex fracture networks, water flows in the fractures and matrix blocks are surrounded by fractures, under this circumstance, spontaneous counter-current imbibition is the dominant mechanism for oil recovery. Therefore, modelling the counter-current behavior properly is such essential when evaluate the production performance of fractured reservoir that contains large amount of water. In this paper, the Radical Integral Boundary Element Method(RIBEM) is firstly introduced to simulate spontaneous counter-current imbibition process, this method successfully transforms the governing equation of counter-current imbibition into the complete boundary integral form and thus the boundary element method can be applied to calculate counter-current imbibition rate, the core advantage of this method is that RIBEM can achieve acceptable results without the need to divid the matrix block into many subgrids, which is convinient for application and reducing a lot computational burden. The validation of RIBEM is tested both on core and field scale, simulated results are in good agreement with corresponding experiment and fine grid simulation data.

Scaling one- and multi-dimensional co-current spontaneous imbibition processes in fractured reservoirs

Spontaneous Imbibition (SI) is in particular a very important mechanism for oil and gas recovery from matrix blocks in naturally fractured reservoirs. An analytical solution to the one-dimensional co-current spontaneous imbibition (COCSI) problem was proposed by Schmid et al. (2011). On the basis of this analytical solution, a set of scaling equations as well as a simplified one were developed for the COCSI process (Mirzaei-Paiaman and Masihi, 2014). The objective of this study was to validate these scaling equations using 12 one-dimensional COCSI experiments. To accommodate for multi-dimensionality of the COCSI process, a shape factor was proposed and incorporated into the one-dimensional scaling equations to make them applicable for any matrix size, shape and boundary conditions. The resulted scaling equations were validated through the use of data associated with 17 multi-dimensional water-oil COCSI experiments. The necessity of accounting for matrix anisotropy in the proposed scaling equations was also investigated.

Spontaneous Imbibition Experiments of Enhanced Oil Recovery with Surfactants and Complex Nano‐Fluids

AbstractTwo types of porous media were analyzed with the intention of exploring alternative enhanced oil recovery methods. Core samples were taken from the Tensleep Formation of the Black Mountain Field in Hot Springs County, WY. The lithology is mainly sandstone and dolomite. The measured effective porosity values ranged from 13.0 to 18.0%, and permeabilities from 19 to 68 md. Production from the Tensleep and Phosphoria formations using conventional methods has resulted in a low secondary recovery factor, possibly due to high capillary forces and an oil‐wet formation. Different surfactants were investigated to determine the viability of a possible enhanced oil recovery process using a spontaneous imbibition process in Amott cells. A very high enhanced recovery factor of more than 89% was achieved using a complex nano‐fluid that consists of a mixture of surfactant, solvent, co‐solvent and water. These recovery factors compared with 13% by brine imbibition and up to 21% using commercial surfactants. At the other end of the scale, very high porosity volcanic pumice was also subjected to the same tests. For this rock the porosity values ranged from 65 to 90% and permeabilities were 2.0–2.7 d. Secondary recovery showed values up to 81% on spontaneous imbibition and up to 91% when surfactants were employed. These experimental results indicate that pumice has favorable reservoir characteristics, but, due to its weak brittle nature, it would not be expected that it could withstand the overburden stress at any significant depth. However, it does represent a useful laboratory specimen.

Investigation of Oil Saturation Development behind Spontaneous Imbibition Front Using Nuclear Magnetic Resonance T2

Spontaneous imbibition is a critical mechanism for the development of water-wet fractured reservoirs. In order to improve the ultimate oil recovery, it is important to understand the change of in situ oil saturation during the spontaneous imbibition process. In this study, spontaneous imbibition experiments of two ends open (TEO) are conducted using unconsolidated sand packs. The sand packs are filled with quartz sands of three different particle sizes respectively and are fully oil-saturated. Nuclear magnetic resonance (NMR) T2 is used to monitor the saturation development behind spontaneous imbibition front. For porous media of the same lithology, the imbibition speed and final oil recovery decline with the reduction of average pore size. As the imbibition front constantly moves forward, the change of oil saturation behind the imbibition front does exist, and the major decrease of oil saturation happens in the large pore space. In terms of a particular region behind the spontaneous imbibition front, with the progression of the front, the oil saturation gradient in the area declines. Specifically, the dramatic gradient descent occurs when the spontaneous imbibition front just passes by. The smaller the average pore size is (the larger the mesh of sand is), the more rapid the saturation changes behind imbibition front. For porous media of small pore size, even when the imbibition front has moved far away, oil saturation still changes a lot.

Wettability alteration and oil recovery by spontaneous imbibition of low salinity brine into carbonates: Impact of Mg2+, SO42− and cationic surfactant

A large amount of the discovered oil reserves are reserved in carbonate formations, which are mostly naturally fractured oil-wet. Wettability alteration towards more water-wet state reduces the capillary barrier, hence improving the oil recovery efficiency in such reservoirs. In this study, wettability alteration towards favorable wetting state was investigated by combining modified low salinity brine with surfactant during water flooding. The diluted brine was modified by increasing the concentration of Mg2+ and SO42−, individually as well as both ions in combination. Different brine formulations were tested experimentally through the observations of contact angle measurements and spontaneous imbibition tests for oil-wet limestone core samples both in the presence and absence of surfactant. Contact angle measurements revealed that both magnesium and sulfate ions can act as wettability modifying agents for the oil-wet calcite and all of the modified low salinity brine solutions changed the wettability of oil-wet surface towards more water-wet state. In the presence of cationic surfactant, utilizing both wettability influencing ions and surfactant molecules resulted in more water-wet surfaces. The spontaneous imbibition results showed that the combination of salting-in effect, mineral dissolution and electric double layer expansion, cause wettability alteration towards more water-wet state and result in critical increase in oil recovery efficiency during spontaneous imbibition of diluted brine into limestone core sample. Modified brine which contains a higher concentration of sulfate ions was more efficient in wettability alteration in comparison to the brine modified with magnesium ions. High oil recovery efficiency can be achieved by optimizing the brine composition without using costly surfactant solutions. However, the combination of the effect of wettability influencing ions (Mg2+ and SO42−) along with the cationic surfactant can result in a remarkable oil production during the spontaneous imbibition process.

ANALYSIS OF SPONTANEOUS IMBIBITION IN FRACTAL TREE-LIKE NETWORK SYSTEM

Spontaneous imbibition in porous media is common in nature, imbibition potential is very important for understanding the imbibition ability, or the ability to keep high imbibition rate for a long time. Structure parameters have influence on imbibition potential. This work investigates the process of spontaneous imbibition of liquid into a fractal tree-like network, taking fractal structure parameters into consideration. The analytical expression for dimensionless imbibition rate with this fractal tree-like network is derived. The influence of structure parameters on imbibition potential is discussed. It is found that optimal diameter ratio [Formula: see text] is important for networks to have imbibition potential. Moreover, with liquid imbibed in more sub-branches, some structures of parameter combinations will show the characteristic of imbibition potential gradually. Finally, a parameter plane is made to visualize the percentage of good parameter in all possible combinations and to evaluate the imbibition potential of a specific network system more directly. It is also helpful to design and to optimize a fractal network with good imbibition potential.

Experimentally investigation of the effects of nanoparticles‐enriched ASP formulations on the spontaneous imbibition in a fractured sandstone reservoir

AbstractAmong the chemical methods used in oil industry to boost the ultimate oil recovery, ASP (alkaline surfactant polymer) flooding has gained much attention because of beneficial effects related to simultaneous usage of three different chemical agents. This study is devoted to investigate the separate influences of each chemical agent in the ASP on the attained oil recovery. Furthermore, four different ASP formulations are prepared, and effects of hydrophilic nanoparticles are examined on the ASP spontaneous imbibition process. The utilized core sample in all experiment series belongs to one of the Iranian‐fractured sandstone reservoirs. Interfacial tension and contact angle measurements were also included in the experiments to investigate the effects of chemical solutions as well as hydrophilic nanoparticles on the indicated parameters. Results of the experiments indicate that ASP is an appropriate Enhanced Oil Recovery (EOR) approach not only because effects of each chemical agent on the recovered oil but also because beneficial effects relevant to combination of these chemical solutions. It was also revealed that inclusion of the nanoparticles can significantly increase the ultimate oil recovery because of additional decrease in the interfacial tension of the system and altering the rock's wettability toward a more water‐wetted one. Therefore, inclusion of the nanoparticles in the ASP systems should be considered for future ASP implementing schemes. © 2015 Curtin University of Technology and John Wiley & Sons, Ltd.

Investigation on the variation of shale permeability with spontaneous imbibition time: Sandstones and volcanic rocks as comparative study

The development of gas shale needs a large scale of hydraulic fracturing during the process of well completion. However, the rate of flow-back is always less than the half of the injected fluid. Thus, a large number of fracturing fluid becomes retention in the shale reservoir and aqueous phase trapping (APT) appears. APT appears after well drilling, completion, work over and stimulation operation, caused by fluid filtrating into formation and resulting in permeability reduction. However, after the well was shut in for a period of time in shale gas development, the APT can be auto-removed. In order to investigate the auto-removal mechanism of shale reservoirs, related experiments were performed. In this paper, we used pulse-decay permeability method to monitor the permeability change of shale rocks during the process of shale rocks spontaneous imbibition. At the same time, the sandstones and volcanic rocks did as control samples. From the experiments, the permeability of sandstones and volcanic rocks decreases with increasing imbibition time, and there are no cracks produced in the process of imbibition of these two kinds of samples. However, during the process of shale rocks imbibition, cracks appear on the surface of samples, which may be caused by clay swelling. Simultaneously, the permeability of shale rocks fluctuates apparently. Some shale samples even have the specific interval that the permeability increases with soaking liquid time. This specific phenomenon may be caused by the new produced cracks, which increases the pore volume. Because the matrix of shale has the characteristic of hydrophobicity, much of the new pores couldn't be occupied by the liquid under the effect of spontaneous imbibition. Thus, the gas flowing channels tremendously increase. However, the stress sensitivity can lead to shale permeability decrease, which impacts the variation of permeability under certain confining pressure. These findings contribute to better understanding the shale APT auto-removal after hydraulic fracturing.