Spontaneous Imbibition Research Articles

Experimental Study on Alternating Injection of Silica and Zirconia Nanoparticles with Low Salinity Water and Surfactant into Fractured Carbonate Reservoirs for Enhanced Oil Recovery

Recently, the application of low salinity water (LSW), nanoparticles (NPs), and surfactants (collectively abbreviated as LNS) in carbonate formations for enhanced oil recovery (EOR) purposes has been under investigation, but relatively few studies have been performed for their implementation in fractured carbonate reservoirs (FCRs). The objective of this study is to apply the recently proposed method of alternatively injecting LNS in cycles into FCRs using silica and zirconia NPs. The cumulative oil recovered from the two coreflooding experiments performed at 3000 psi overburden pressure and 70 °C temperature is reported in this study in addition to spontaneous imbibition (SI) experiments. The experimental design is structured to depict the best industrial practice for the injected fluids in FCRs. Furthermore, this work investigates the effect of zirconia NPs on the interfacial tension (IFT) between the injected fluids and crude oil under the previously stated experimental conditions. The outcome of these experiments divulges that the alternating injection of LNS employing silica and zirconia NPs is effective and well suited for EOR applications in FCRs owing to a cumulative oil recovery of approximately 8 and 7% of the original oil in place (OOIP), respectively. This study validates the implementation of the recently proposed alternating injection of the LNS technique for FCRs and shows its performance utilizing newly acquired zirconia NPs, which is relevant for industrial application at a large scale.

Influencing Factors and Application of Spontaneous Imbibition of Fracturing Fluids in Tight Sandstone Gas Reservoir.

This work is based on high-precision fluid spontaneous imbibition experiments to quantitatively study the imbibition rate, imbibition capacity, and imbibition curve characteristics of fracturing fluids in tight sandstone reservoirs. The objective of the work is to explore the influence of tight sandstone physical characteristics, fracturing fluid composition, salinity, viscosity, surface tension on fracturing fluid imbibition, and further analyze its main controlling factors. To evaluate imbibition characteristics more deeply, the pore throat structure and micromorphology of tight sandstone before and after imbibition were described by mercury intrusion test and scanning electron microscope test, respectively. Furthermore, the mineral composition and dilatation characteristics of the tight sandstone samples were identified by XRD and a linear dilatometer, respectively. The results show that the drilled tight sandstone samples from the Shaximiao Formation reservoir have strong heterogeneity, high clay mineral content, more developed micro/nanopores, less developed fractures, and strong hydration expansion. Since the average pore throat radius of tight sandstone samples is between 0.1 and 0.2 μm, the imbibition driving force is strong. The imbibition rate is fast, and the imbibition basically reaches a steady state within 24 h, which makes the imbibition capacity basically greater than 50%. Based on the analysis of the main control factors of imbibition, the surface tension of the fluid properties has the greatest impact on the imbibition recovery factor. The result not only helps to understand the absorption mechanism of fracturing fluid in tight sandstone reservoirs and then evaluates the degree of interaction between fluid and tight sandstone but it is also crucial for the prediction of flowback rate.

A Closed-Form Equation for Capillary Pressure in Porous Media for All Wettabilities

A saturation–capillary pressure relationship is proposed that is applicable for all wettabilities, including mixed-wet and oil-wet or hydrophobic media. This formulation is more flexible than existing correlations that only match water-wet data, while also allowing saturation to be written as a closed-form function of capillary pressure: we can determine capillary pressure explicitly from saturation, and vice versa. We propose Pc=A+Btanπ2-πSeCfor0≤Se≤1,\\documentclass[12pt]{minimal} \\usepackage{amsmath} \\usepackage{wasysym} \\usepackage{amsfonts} \\usepackage{amssymb} \\usepackage{amsbsy} \\usepackage{mathrsfs} \\usepackage{upgreek} \\setlength{\\oddsidemargin}{-69pt} \\begin{document}$$P_{{\ ext{c}}} = A + B\ an \\left( {\\frac{\\pi }{2} - \\pi S_{e}^{C} } \\right)\\,{\ ext{for}}\\,0 \\le S_{{\ ext{e}}} \\le 1,$$\\end{document}where S_{{text{e}}} is the normalized saturation. A indicates the wettability: A>0 is a water-wet medium, A<0 is hydrophobic while small A suggests mixed wettability. B represents the average curvature and pore-size distribution which can be much lower in mixed-wet compared to water-wet media with the same pore structure if the menisci are approximately minimal surfaces. C is an exponent that controls the inflection point in the capillary pressure and the asymptotic behaviour near end points. We match the model accurately to 29 datasets in the literature for water-wet, mixed-wet and hydrophobic media, including rocks, soils, bead and sand packs and fibrous materials with over four orders of magnitude difference in permeability and porosities from 20% to nearly 90%. We apply Leverett J-function scaling to make the expression for capillary pressure dimensionless and discuss the behaviour of analytical solutions for spontaneous imbibition.

Spontaneous Imbibition Oil Recovery by Natural Surfactant/Nanofluid: An Experimental and Theoretical Study.

Organic surfactants have been utilized with different nanoparticles in enhanced oil recovery (EOR) operations due to the synergic mechanisms of nanofluid stabilization, wettability alteration, and oil-water interfacial tension reduction. However, investment and environmental issues are the main concerns to make the operation more practical. The present study introduces a natural and cost-effective surfactant named Azarboo for modifying the surface traits of silica nanoparticles for more efficient EOR. Surface-modified nanoparticles were synthesized by conjugating negatively charged Azarboo surfactant on positively charged amino-treated silica nanoparticles. The effect of the hybrid application of the natural surfactant and amine-modified silica nanoparticles was investigated by analysis of wettability alteration. Amine-surfactant-functionalized silica nanoparticles were found to be more effective than typical nanoparticles. Amott cell experiments showed maximum imbibition oil recovery after nine days of treatment with amine-surfactant-modified nanoparticles and fifteen days of treatment with amine-modified nanoparticles. This finding confirmed the superior potential of amine-surfactant-modified silica nanoparticles compared to amine-modified silica nanoparticles. Modeling showed that amine surfactant-treated SiO2 could change wettability from strongly oil-wet to almost strongly water-wet. In the case of amine-treated silica nanoparticles, a strongly water-wet condition was not achieved. Oil displacement experiments confirmed the better performance of amine-surfactant-treated SiO2 nanoparticles compared to amine-treated SiO2 by improving oil recovery by 15%. Overall, a synergistic effect between Azarboo surfactant and amine-modified silica nanoparticles led to wettability alteration and higher oil recovery.

Effect of ion concentration of smart water on oil recovery by spontaneous imbibition test

Smart waterflooding has proven successfully improving oil recovery in numbers of laboratory and field scale applications. The phenomena behind the positive outcome is concluded to be wettability alteration. The smart water composition changes the wettability of the rock surface into partially water-wet, thus promoting a spontaneous imbibition of the aqueous phase and displacing the oil. However, there are some mechanisms causing the wettability alteration that have been proposed by researchers. The present study examines the oil recovery from spontaneous imbibition tests by modifying certain ion composition of the smart water. Prepared core samples with initial water and oil saturation were immersed in spontaneous imbibition cells filled with smart water and the oil recovered was monitored for some period of time. The predesigned smart water compositions consist of different ions concentration, i.e., Na+, Ca2+, and Mg2+, while maintaining identical total dissolved solid (TDS). The experimental results found that the ion composition of smart water affects the oil recovery regardless of the TDS, and low Ca2+ and Mg2+ concentrations shows the highest recovery factor.

Ion Composition Effect on Spontaneous Imbibition in Limestone Cores

Studies on low salinity oil recovery have accelerated in recent years. Detailed focus has been put on understanding competing underlying mechanisms behind observed improved oil recovery. The main aim in this work is to tune the ionic composition of imbibing brine to maximize the oil recovery from spontaneous imbibition experiments on limestone outcrop cores, as an analogue for an offshore Brazilian carbonate reservoir. Improved spontaneous imbibition experiments with smooth natural brine exchange between primary, secondary, and tertiary fluid imbibition cycles at high temperatures were accomplished, reducing systematic errors in the recovery data. Contact angle, zeta potential, and interfacial tension measurements completed the data set. It was observed through improved oil recovery from tertiary imbibition that holistic dilution of synthetic seawater (10 times) had limited the impact on improved oil recovery on our limestone cores. However, selective dilution of synthetic seawater with respect to the NaCl content resulted in significantly improved oil recovery. In line with this observation, brines depleted in NaCl and enriched in Mg2+ and SO42– ions were tested and resulted in improved oil recovery in tertiary modes. A positive test on the role played by the SO42– ion was recorded when synthetic seawater was enriched 2 and 4 times in SO42– ion concentration; however, substantial recovery increases required an increased Mg2+ content. Contact angle measurements on polished rock chips, cut and shaped from the same rock material and aged in brines at 96 °C, confirmed the observed results, where zeta potential measurements at both 25 and 70 °C showed inconclusive results.

Counter-current imbibition and non-linear diffusion in fractured porous media: Analysis of early- and late-time regimes and application to inter-porosity flux

The displacement of non-aqueous phase liquid (NAPL) in permeable porous rock by water saturating the surrounding fractures is studied. In many situations of practical interest, capillarity is the dominant driving force. Using the global pressure concept, it is shown that the water saturation is driven by a generic non-linear diffusion equation governing the matrix block counter-current spontaneous imbibition. In addition, in most cases, the saturation-dependent diffusion coefficient vanishes at the saturation end points, that renders the driving equation highly singular.In this paper, two exact asymptotic solutions valid for short and long times are presented, under the assumption that the conductivity vanishes as a power-law of both phase saturations at the extreme values of the fluid saturation.Focusing on the late-time domain, the asymptotic solution is derived using an Ansatz that is written under the form of a power-law time decay of the NAPL saturation. In the spatial domain, this solution is an eigenvector of the non-linear diffusion operator driving the saturation, for a problem with Dirichlet boundary conditions. If the diffusion coefficient varies as a power law of the NAPL saturation, the spatial variations of the solution are given analytically for a one-dimensional porous medium corresponding to parallel fracture planes. The analytical solution is in very good agreement with results of numerical simulations involving various realistic sets of input transport parameters.Generalization to the case of two- or three-dimensional matrix blocks of arbitrary shape is proposed using a similar Ansatz, solution of a non-linear eigenvalue problem. A fast converging algorithm based on a fixed-point sequence starting from a suitable first guess was developed. Comparisons with full-time simulations for several typical block geometries show an excellent agreement.These results permit to set-up an analytical formulation generalizing linear single-phase representation of matrix-to-fracture exchange term. It accounts for the non-linearity of the local flow equations using the power-law dependence of the conductivity for low NAPL saturation. The corresponding exponent can be predicted from the input conductivity parameters. Similar findings are also presented and validated numerically for two- or three-dimensional matrix blocks. That original approach paves the way to research leading to a more faithful description of matrix-to-fracture exchanges when considering a realistic fractured medium composed of a population of matrix blocks of various size and shapes.

Effect of Fe3O4/Mineral–Soil Nanocomposites on Wettability Alteration and Oil Production Under the Spontaneous Imbibition Process

Effect of Fe3O4/Mineral–Soil Nanocomposites on Wettability Alteration and Oil Production Under the Spontaneous Imbibition Process

Multiple experimental studies of pore structure and mineral grain sizes of the Woodford shale in southern Oklahoma, USA

Pore structure study is an important part of unconventional shale reservoir characterization, since the pore system provides the primary petroleum storage space and fluid flow pathways. Previous studies have suggested that the pore structure is related to the total organic carbon (TOC) content, mineral compositions, and the maturity of the organic matter (OM). However, few studies have focused on the mineral grains, the primary grains being deposited but before cementation, which are the building blocks of shale. Eight Woodford Shale outcrop samples from southern Oklahoma were chosen to study the effects of mineral grain size on the pore structure characterization, using multiple and complementary experimental approaches, including laser diffraction, mineralogy, TOC, pyrolysis, liquid immersion porosimetry, mercury intrusion porosimetry, gas physisorption, (ultra) small angle X-ray scattering, scanning electron microscopy, and spontaneous imbibition. The results from different experiments of eight samples show that the Woodford Shale has the mean mineral grain diameters at 3–6 μm, a wide range of porosity at 3–40% and pore diameters at 50–1,000 nm, and various pore connectivity. Grain size variation was probably caused by the sea-level fluctuation during its deposition, which affect the porosity, pore size distribution, and pore connectivity. With decreasing mineral grain sizes, the porosity tends to increase while the pore connectivity worsens. The results also indicate that OM and carbonates in this low-maturity Woodford Shale could block the pores and decrease the porosity. Coupling with the grain size analyses, the control of depositional environment on grain sizes and subsequent effects on pore structure is identified. The pore structure characteristics over a wide pore-diameter range provided by multiple experiments could improve the understanding of storage space and fluid flow in the Woodford Shale to further increase its petroleum production.

Spontaneous imbibition characteristics of shale oil reservoir under the influence of osmosis

The spontaneous imbibition (SI) process in shale oil reservoirs is not only influenced by capillary force, but also by the osmotic pressure between the fracturing fluid and formation water in the nanopores media. In this study, experimental methods are used to investigate the mechanisms of osmosis in the SI, taking into account the presence of initial formation water in shale oil reservoirs. To investigate the effect of osmosis, SI experiments were performed on the fine-grained felsic shale of the Qikou sag of Dagang oilfield. Low-field NMR testers and high-precision electronic balances are utilized for the measuring of oil–water migration. The results show that, when Sw ≠ 0, high-salinity fluid SI can be divided into four stages: initial imbibition stage, drainage stage, secondary imbibition stage and stationary stage; when Sw = 0, there is no drainage stage of high-salinity fluid SI; when Sw ≠ 0 or Sw = 0, low-salinity fluid SI can be called the “osmosis-enhanced SI”; and we have found that “newly formed pores or microfractures” as well as reducing salinity can promote SI. This article presents a systematic study of SI of shale oil reservoirs under the influence of osmosis, which provide useful information for reservoir numerical simulation and development program design.

Pore scale numerical investigation of counter-current spontaneous imbibition in multi-scaled pore networks

The multi-scaled pore networks of shale or tight reservoirs are considerably different from the conventional sandstone reservoirs. After hydraulic fracturing treatment, the spontaneous imbibition process plays an important role in the productivity of the horizontal wells. Applying the color-gradient model of Lattice Boltzmann Method (LBM) accelerated with parallel computing, we studied the countercurrent spontaneous imbibition process in two kinds of pore structures with different interlacing distributions of large and small pores. The effect of geometry configuration of pore arrays with different pore-scale and the capillary number Ca on the mechanism of counter-current spontaneous imbibition as well as the corresponding oil recovery factor are studied. We found that the wetting phase tends to invade the small pore array under small Ca in both types of geometry configurations of different pore arrays of four pore arrays zones. The wetting phase also tends to invade the pore array near the inlet for injecting the wetting phase no matter if it is a large pore array or small pore array except for the situation when the Ca is large to a certain value. In this situation, the small pore arrays show resistance to the wetting phase, so the wetting phase doesn't invade the small pore near the inlet, but invades the large pore preferentially. Both the geometry configurations of different pore arrays and Ca have a significant effect on the oil recovery factor. This work will help to solve the doubt about the selectivity of the multi-scaled pores of the wetting phase and the role of pores with different sizes in imbibition and oil draining in countercurrent spontaneous imbibition processes.

Wettability alteration agents to promote spontaneous imbibition in tight reservoirs: Achievements and limitations

Wettability alteration agents to promote spontaneous imbibition in tight reservoirs: Achievements and limitations

Shale Wettability: Untangling the Elusive Property with an Integrated Imbibition and Imaging Technique and a New Hypothetical Theory

Summary The importance of wettability in reservoir evaluation and dynamics in shale is gaining increasing attention. Wettability is also a key consideration in the strategy development of enhanced oil recovery (EOR) in unconventional reservoirs. However, the determination of shale wettability is often elusive, and an understanding still remains incomplete. Several commonly applied assumptions and methods for evaluating shale wettability are considered inaccurate or problematic. In this work, important clarifications about shale wettability and the methods of measurement or evaluation are made. Wettability is studied for six shale samples from Eagle Ford and Wolfcamp Shale formations with increasing thermal maturity using an integrated imbibition and imaging method. Wettability was evaluated based on the results of water-oil displacement via spontaneous imbibition and the dominant pore type in the sample. Wettability of the samples is ranged from strong water-wet (SW) to oil-wet and has a general trend of becoming less water-wet (or more oil-wet) with increasing thermal maturity (Ro value from ~0.45 to 1.4%). A new hypothesis on shale wettability transformation from the original water-wet status is proposed based on the results. This new hypothesis emphasizes the evaluation of shale wettability under a dynamic context of oil-water displacement and oil aging history, and shale wettability is a result of oil-water-rock interaction through the geological time frame. Enhanced oil mobility caused by increasing thermal maturity is the main drive of oil imbibition, whereas pore type and pore size also play an important role in oil-water displacement and consequently wettability transformation. The ease of wettability transformation of the pore system in shale is in the order of calcite &amp;gt; quartz, dolomite &amp;gt;&amp;gt; clay. Pores with mixed boundaries of different minerals fall in between. Other geological factors [e.g., total organic carbon (TOC) and pore pressure] also affect oil imbibition and thus wettability. Important implications of shale wettability on water and oil saturation and on improved oil recovery are also discussed.

Influence of Sandstone Mineralogy on the Adsorption of Polar Crude Oil Components and Its Effect on Wettability

The crude oil–brine–rock (COBR) system is a combination of contacting phases where polar organic molecules in crude oil, inorganic ions from the brine phase, and charged mineral surfaces participate in complex interactions. One of the surface phenomena that occur in the COBR system is the adsorption of polar crude oil components, which can directly affect the capillary forces and wettability of the rock. The purpose of this research work was to determine polar organic component (POC) adsorption trends for sandstones of different origins and mineralogical compositions. Adsorption preferences for acidic and basic POCs were quantified by potentiometric titration during dynamic core flooding tests using modified crude oil. The influence of POC adsorption on wettability was investigated by evaluating capillary forces during the displacement of oil in a spontaneous imbibition (SI) process. The results of this work showed a clear relationship between the intensity of POC adsorption and sandstone mineralogy. Greater adsorption capacity and a predominant affinity for bases compared to that for acids were found in the sandstone material containing a sufficient amount of reactive illite clay minerals. On the other hand, the sandstone material consisting mainly of quartz with an insignificant content of kaolinite clay did not show a pronounced tendency to adsorb POCs. All the studied rock materials have also shown a significant impact of POC adsorption on capillary forces and wettability, confirmed during SI tests. As a result, a detailed mineralogical analysis along with crude oil chemistry is required to properly evaluate sandstone wettability and competently plan core flooding laboratory studies.

Experiment on the silica sol imbibition of low-permeability rock mass: With silica sol particle sizes and rock permeability considered

It’s a universal engineering problem to seal micro-cracks of low-permeability argillaceous rock mass by grouting in the fields of civil engineering and mining. This paper achieved the grouting sealing of low- permeability artificial rocks with the permeability of 0.1–40 mD by adopting silica sol imbibition grouting. The variation characteristics of particle size, viscosity, and contact angle of silica sol during solidification and the pore size distribution of low-permeability artificial rocks were measured, and spontaneous imbibition tests of the artificial rocks were carried out. Finally, combined with the imbibition theory, percolation theory, and fracture medium grouting principle, the silica sol imbibition mechanism of low-permeability rocks and soil was discussed. The results show that: (1) Silica sol can be injected into artificial rocks with the minimum permeability of 0.1 mD through spontaneous imbibition; (2) The particle size increase of silica sol leads to decreased wettability, affinity, and injectability in grouting materials; and (3) In the range of 0.1–40 mD, the grout absorption first increases and then decreases with increased permeability. The number of large pores and fractures in the rock mass is related to injectability, and the number of small and medium pores is related to the internal driving force of imbibition. This study provides a theoretical basis for silica sol grouting sealing of low-permeability argillaceous rocks and is, therefore, an important reference for application.

NMR-Based Shale Core Imbibition Performance Study

Shale gas reservoirs are unconventional resources with great potential to help meet energy demands. Horizontal drilling and hydraulic fracturing have been extensively used for the exploitation of these unconventional resources. According to engineering practice, some shale gas wells with low flowback rate of fracturing fluids may obtain high yield which is different from the case of conventional sandstone reservoirs, and fracturing fluid absorbed into formation by spontaneous imbibition is an important mechanism of gas production. This paper integrates NMR into imbibition experiment to examine the effects of fractures, fluid salinity, and surfactant concentration on imbibition recovery and performance of shale core samples with different pore-throat sizes acquired from the Longmaxi Formation in Luzhou area, the Sichuan Basin. The research shows that the right peak of T2 spectrum increases rapidly during the process of shale imbibition, the left peak increases rapidly at the initial stage and changes gently at the later stage, with the peak of the left peak shifting to the right. The result indicates that water first enters the fracture system quickly, then enters the small pores near the fracture wall due to the effect of the capillary force, and later gradually sucks into the deep and large pores. Both imbibition rate and capacity increase with increased fracture density, decreased solution salinity, and decreased surfactant concentration. After imbibition flowback, shale permeability generally increases by 8.70–17.88 times with the average of 13.83 times. There are also many microcracks occurring on the end face and surface of the core sample after water absorption, which may function as new flowing channels to further improve reservoir properties. This research demonstrates the imbibition characteristics of shale and several relevant affecting factors, providing crucial theory foundations for the development of shale gas reservoirs.

A novel property enhancer of clean fracturing fluids: Deep eutectic solvents

Fracturing fluid properties are closely related to the oil recovery of unconventional reservoirs. In the meantime, deep eutectic solvents (DESs) have provided a new method to improve the properties of clean fracturing fluids (CFFs) due to their low-toxicity raw materials and mild synthesis conditions. In this work, DESs were developed as the enhancers to intensify rheological characteristics and spontaneous imbibition performance of CFFs. The adjustment of hydrogen bond donors (HBDs) can effectively regulate the rheological characteristics of CFFs. The DES composed of choline chloride (ChCl) and malonic acid (MA) can significantly increase the viscosity of CFF from 38.1 mPa·s to 60.1 mPa·s, the shear resistance and viscoelastic modulus were both improved. The interactions between HBDs and sodium p-toluenesulfonate (TsONa) anion has an influence on the electrostatic shielding of TsONa anion for OAHSB, which further determines the strength of micelle networks. For the spontaneous imbibition of CFFs, DESs improved the imbibition efficiency from 33.0% in 98 h to 40.1–47.2% in 78–90 h through the reduction of oil–water interfacial tension and oil viscosity, change of oil-contacting surface wettability and the increase of core porosity and permeability. The DESs here provide a novel strategy to enhance CFF properties in an environmentally friendly and efficient way.

Oil drop stretch and rupture behavior at throat and pore junction during imbibition with active nanofluid: A microfluidic approach

Imbibition is an effective method to recover oil from small pore and throat. Here we report the formation of oil drop at pore and throat junction during spontaneous imbibition with active nanofluid. A T-channel microfluidic model combined with high-speed camera was used to observe the stretch and rupture process of oil discharged from throat to pore. When oil drop was discharged from throat gradually, its width/length was kept deceasing before rupturing. With more active content in the aqueous phase, the interfacial tension decreased from 33.8 to 8.7 mN/m, and the oil recovery increased by 12.4% by spontaneous imbibition. The oil drop rupture frequency increased by 3.0 times, but the length and width of the oil drop decreased by 32.2% and 28.0%, respectively. The reduced size of the oil drop would benefit the oil transportation in porous media. Higher flow rate in pores and throat would all intensify rupturing of the oil drop. Moreover, small throat could further reinforce the rupturing process. From combination of fluid flow rate, interfacial tension, and viscosity, higher capillary number reduced the maximum dimensionless width and length of the oil drop by 44.3% and 42.7%, respectively. The reduced size of oil drops ruptured at pore and throat junction contributes to the transportation of oil in porous media. Overall, this study provides a basic theory for active nanofluid to enhance imbibition oil recovery in tight reservoirs.

Insight into spontaneous water-based working fluid imbibition on the dynamic tensile behavior of anisotropic shale

Shale gas is becoming a new energy development focus worldwide with advances in horizontal wells and hydraulic fracturing, and spontaneous water-based working fluid imbibition is one of the strongest phenomena that can impact borehole stability and the gas extraction rate. Our present experimental work was carried out on shale Brazilian discs with 5 different bedding orientations (0°, 30°, 45°, 60° and 90°) after air-drying and spontaneous water imbibition using a split Hopkinson pressure bar. The results illustrate that under the same loading rate (100–900 GPa/s), spontaneous water imbibition obviously weakens the dynamic tensile strength of shale discs, except for shale discs with a bedding orientation of 90° when the loading rate exceeds 400 GPa/s, and does not change the anisotropic dynamic tensile strength variation trend versus bedding orientations. Models that can well fit test data and reveal the coupling effects of bedding orientation and loading rate on the dynamic tensile strength of shale after air-drying and spontaneous water imbibition are proposed. The rate-dependent failure mode only appears among shale discs with bedding orientations of 30°, 45° and 60°, and this phenomenon is exacerbated and more complex after spontaneous water imbibition. Bedding planes of shale discs after air-drying and spontaneous water imbibition both play three different roles in affecting the failure crack propagation, i.e., intersecting propagation, promoting propagation and promoting turning. Finally, the dynamic tensile strength responses of shale after spontaneous water imbibition are analyzed and discussed, and potential field applications in borehole stability, perforation design and hydraulic fracturing are suggested.

Effects of brine valency and concentration on oil displacement by spontaneous imbibition: An interplay between wettability alteration and reduction in the oil-brine interfacial tension

Brine fluids have recently been of high interest to enhanced oil recovery process in both academia and industry. Both diluted formation brines and specifically formulated brines were reported to improve crude oil displacement in porous rock, owing to either their bulk salinity or brine-type. Mechanisms for such an improvement were widely proposed, including microscopic interfacial phenomena: wettability alteration and reduction in the oil-brine interfacial tension (σ), although their synergistic or interlinked contributions were vaguely clarified. To elucidate insights into this “low-salinity” enhanced oil recovery, crude oil displacement by spontaneous imbibition was conducted in the current research with focus on the effects of brine valency and concentration. Monovalent (NaCl) and divalent (CaCl2) brines at elevated concentrations (10, 100, and 1000 mM) were examined as imbibing fluids. Changes in the three-phase contact angle and the crude oil-brine interfacial tension were also investigated. Imbibition results showed that NaCl brine at ‘suitable’ concentration (100 mM) displaced greater oil (95.8 %) than too-low (10 mM) or too-high (1000 mM) concentrations, and these monovalent brines displaced more effective than those of divalent CaCl2 due to an oil-wetting as a result of divalent ion bridging phenomenon. This echoes crucial influences of both brine valency and concentration. Since no direct individual contribution from either the contact angle or σ on the oil displacement was obtained, an interplay between these two parameters were thought to control. The imbibition results were a capillary-dominated process (capillary number < 2.1 × 10−6), re-confirmed by their correlations with the calculated capillary pressures and inverse Bond numbers. The findings revealed that in a given imbibition system a required σ is a wettability-dependent: water-wet system needs high σ to enhance a driving capillarity while oil-wet system prefers lower σ to weaken a resisting capillary force. Brine formula directly attributed to wettability and σ: NaCl brines secure water-wetting with high σ while CaCl2 brines reduced σ more effectively with an assured oil-wetting. Low-salinity enhanced oil recovery mechanism was thus found to be contributed from capillary effect, which was an interplay between the interfacial tension and wettability. Paring these two parameters by formulating imbibing brine to anticipate high oil recovery is crucial and of challenge.