Wettability Of Rock Surface Research Articles

Study on combination of surfactant and acid for depressure and increasing injection oil displacement in heterogeneous sandstone reservoirs

This study addresses the challenges faced by unconventional tight sandstone reservoirs, including low porosity, permeability, high clay content, and complex wettability, which lead to increased flow resistance and injection pressures. The research aims to optimize depressure and increasing injection methods by investigating the effects of various two-phase and three-phase displacement systems, employing experimental treatments including acids, alkalis, and surfactants. Nuclear magnetic resonance, computed tomography, scanning electron microscopy, inductively coupled plasma, and wettability tests are utilized to investigate the mechanisms of these treatments. Key findings indicate that weak alkaline ethylenediaminetetraacetate tetrasodium and weak acids like hydroxyethylidene diphosphonic acid and acetic acid can cause significant pore blockage, while hydrochloric acid can dissolve pore minerals, achieves a high depressure rate of 89.42%. Although surfactants exhibit a negative effect in two-phase displacement systems, they demonstrate considerable potential in three-phase displacement. Surfactants can modify the wettability of rock surfaces, reduce oil saturation, and improve water phase permeability, resulting in a depressure rate of 11.68%. Notably, the combination of surfactants and HCl enhances the depressure rate to 60.82% and improves oil displacement efficiency from 26.12% to 57.96%. The optimal formulation identified is “0.5% unconventional agent (CNI-A) +3% HCl,” which improves oil displacement capacity and alleviates injection pressure, providing valuable insights for the management of heterogeneous sandstone reservoirs.

Modification and mechanistic study of fluid/fluid and carbonate rock/fluid interfaces using a glycolipid biosurfactant from an indigenous strain of Gordonia terrae for MEOR applications

To clarify the mechanism of the interface behavior between carbonate surface/biosurfactant solution/oil systems, the interfacial tension (IFT), surface wettability, spreading coefficient (SC), and capillary number were investigated with regard to the synergistic effects of a biosurfactant from an indigenous Gordonia terrae strain (isolated from an Iranian oil reservoir), formation water salinity, and pH using response surface methodology (RSM-CCD). According to the analysis of variance results, the process effectively depicted by the quadratic model demonstrated statistical significance in terms of the responses of IFT, wettability alteration, and SC, which were significantly affected by biosurfactant concentration. The optimal conditions were 0.260 g/L biosurfactant, 36.202 g/L salinity, and a pH of 5.9. Accordingly, the quadratic model was verified using the estimated optimal parameters, thereby confirming the accuracy of the model in which a strongly water-wet surface (contact angle change from 159° to 31°) and IFT reduction (from 23.96 to 1.26 mN/m) resulted in an SC of near-zero value (−0.18) and 25 % recovery of oil during the imbibition experiments after secondary water flooding. The desorption of the polar components of crude oil from the dolomite rock surface was also investigated through determining the un-coverage ratios of the elements using energy dispersive X-ray microanalysis and characterization. Although the solutions containing biosurfactants contributed to the alteration of the rock surface wettability, their performance strongly depended on the pH and salinity, resulting in different desorption ratios. The desorption of approximately 40 % of the adsorbed organic compounds from the carbonate surface was a critical limiting factor affecting the surface properties of the rock, and was responsible for altering the wettability to water-wet conditions. The results of this study are expected to contribute to the development of effective biosurfactant-flooding techniques for MEOR.

Bacillus subtilis-mediated synthesis of ZnO and Ag-ZnO nanoparticles for eco-friendly displacement agents: Enhancing oil recovery in middle/low permeability reservoirs with nanofluid

Microorganisms, known for their widespread distribution and nonpolluting nature, are extensively used as raw materials. In this study, ZnO nanoparticles (ZnO NPs) and Ag-ZnO nanoparticles (Ag-ZnO NPs) were synthesized using Bacillus subtilis, and their efficacy as nano-displacement agents for enhancing oil recovery in medium and low permeability reservoirs was investigated. The morphology, structure, and properties of these nanomaterials were analyzed using various characterization methods. The results indicated that ZnO NPs are irregularly blocky with an average particle size of 44.7 nm, while Ag-ZnO NPs are approximately spherical with an average particle size of 35.5 nm, both exhibiting high purity and stability. These two nanoparticles can effectively reduce oil–water interfacial tension and improve rock wettability, with Ag-ZnO NPs showing superior performance. In core displacement tests at 60 °C, the recovery rates for intermediate permeability cores (30–40 mD) were 12.43% for ZnO nanofluids and 14.10% for Ag-ZnO nanofluids. For low-permeability cores (<10 mD), the recovery rates were 8.63% and 10.26%, respectively. Microscopic oil displacement experiments revealed that the mechanism of oil displacement by nano-displacement agents includes altering rock surface wettability, penetrating narrow pores, emulsifying crude oil, and exerting viscoelastic effects. In summary, these two nanomaterials significantly improve oil recovery in reservoirs, offering an important reference for their application in the oilfield and pointing toward a new direction for developing green and efficient alternatives to chemical flooding agents.

Pore-scale modeling of wettability alteration coupled two-phase flow in carbonate porous media

The Middle East marine carbonate reservoirs are the primary targets for global crude oil exploration and production. In contrast to the clastic rock reservoirs, the marine carbonate reservoirs have undergone more complicated deposition, diagenesis and transformation, and the rock surface tends to be oil-wet or mixed-wet. One of the most effective methods for enhancing oil recovery in marine carbonate reservoirs is the use of an ion matched (IM)-surfactant (S) system to alter the wettability of rock surfaces. In this paper, we propose a microscale mathematical model of wettability alteration-coupled fluid flow by considering oil–water two-phase flow, wettability alteration, solute advection- diffusion and surfactant adsorption. The proposed microscale mathematical model is solved using the multi-component lattice Boltzmann model, and its accuracy is further verified. Finally, the effects of displacing fluid, ion-matched water concentration and surfactant concentration on oil mobilization at pore-scale are studied. Results show that, ion-matched water has a positive effect on wettability alteration, and typically shifts the cross-point of oil–water relative permeability curve to the right. The concentration of ion-matched water primarily affects fluid morphology of the wetting-phase and has little effect on phase permeability. After adding surfactant to the ion-matched water, the Euler coefficient of oil-phase gradually increases as the displacement continues, a large amount of remaining oil is gradually dispersed into scattered oil droplets and the oil-phase relative permeability is further improved.

Evaluation of the Synergistic Oil Displacement Effect of a CO2 Low Interfacial Tension Viscosity-Increasing System in Ultra-Low Permeability Reservoirs

In addressing the issue of poor control over gas permeability during the CO2 flooding process in ultra-low permeability reservoirs, this study proposes the use of a low interfacial tension viscosity-increasing system as a substitute for water in CO2–water alternating flooding to enhance CO2 mobility control and increase oil recovery. The performance of the system was evaluated through tests of viscosity, interfacial tension, wettability, and emulsification properties, and the injection behavior and gas channeling prevention effect of the viscosity-increasing system with CO2 alternate flooding were investigated. The results indicate that the low interfacial tension viscosity-increasing fluid exhibits good thickening properties, interfacial activity, hydrophilic wettability, and oil–water emulsification performance, also demonstrating strong environmental adaptability. The CO2–low interfacial tension viscosity-increasing fluid alternate flooding shows good injectivity in ultra-low permeability cores (1.085 mD). Following water flooding in heterogeneous ultra-low permeability cores, the implementation of CO2 low interfacial tension viscosity-increasing fluid alternate flooding can lead to a 15.91% increase in overall recovery compared to water flooding, outperforming CO2 flooding and CO2–water alternating flooding. The mechanisms by which the CO2 low interfacial tension viscosity-increasing fluid enhances oil recovery include reducing interfacial tension, improving mobility ratio, altering rock surface wettability, and emulsification effects. The low interfacial tension viscosity-increasing systems demonstrate effective mobility control and oil displacement capabilities and synergistically enhance the efficiency of CO2, presenting potential application prospects in the development of CO2 flooding in ultra-low permeability reservoirs.

Impact mechanism of active nanofluid on oil–water two-phase seepage during and after fracturing fluid invasion in tight oil reservoirs

Due to damage caused by fracturing fluid invasion, tight oil reservoirs exhibit slow post-hydraulic fracturing production recovery and low productivity. This study investigates the impact of a nanoclay-based active agent system on oil–water two-phase flow during and after fracturing fluid invasion, emphasizing its potential for enhancing recovery in tight oil reservoirs. Laboratory experiments using crude oil and natural core samples analyze the mechanism of how nanofluids affect oil–water distribution and flow characteristics during fracturing fluid invasion and oil recovery stages. Results show that nanofluids rapidly disrupt the emulsified state of “water-in-oil” emulsions, reducing emulsion viscosity by 84.19% and oil–water interfacial tension by two orders of magnitude, facilitating oil droplet dispersion and deformation and altering the wettability of oil-wet rock surfaces to aid crude oil detachment. Nanofluids increase the accessible volume of the water phase in pores and throats, enlarging flow paths for fracturing fluid flowback and oil recovery. The oil recovery process post-fracturing fluid invasion is delineated into three stages: substantial fracturing fluid flowback in the first stage, with nanofluids reducing the fluid return rate by 11.08% upon crude oil breakthrough; emulsion droplets occupying pores and throats in the second stage, with nanofluids reducing additional resistance during emulsion flow; and continuous oil production in the third stage, with nanofluids consistently and stably altering rock surface wettability to reduce invaded rock matrix resistance to oil flow. The findings of this study hold potential value in mitigating damage from fracturing fluid invasion in tight oil reservoirs.

Study on the Adaptability Evaluation of Micro-Dispersed-Gel-Strengthened-Alkali-Compound System and the Production Mechanism of Crude Oil

A novel micro-dispersed-gel (MDG)-strengthened-alkali-compound flooding system was proposed for enhanced oil recovery in high-water-cut mature oilfields. Micro-dispersed gel has different adaptability and application schemes with sodium carbonate and sodium hydroxide. The MDG-strengthened-alkali flooding system can reduce the interfacial tension to an ultra-low interfacial-tension level of 10−2 mN/m, which can reverse the wettability of rock surface. After 30 days aging, the MDG-strengthened-Na2CO3 flooding system has good viscosity retention of 74.5%, with an emulsion stability of 79.13%. The enhanced-oil-recovery ability of the MDG-strengthened-Na2CO3 (MDGSC) flooding system is 43.91%, which is slightly weaker than the 47.78% of the MDG-strengthened-NaOH (MDGSH) flooding system. The crude-oil-production mechanism of the two systems is different, but they all show excellent performance in enhanced oil recovery. The MDGSC flooding system mainly regulates and seals micro-fractures, forcing subsequent injected water to enter the low-permeability area, and it has the ability to wash the remaining oil in micro-fractures. The MDGSH flooding system mainly removes the remaining oil on the rock wall surface in the micro-fractures by efficient washing, and the MDG particles can also form weak plugging of the micro-fractures. The MDG-strengthened-alkali flooding system can be used as an alternative to enhance oil recovery in high-water-cut and highly heterogeneous mature oilfields.

Using X-ray computed tomography and pore-scale numerical modeling to study the role of heterogeneous rock surface wettability on hydrogen-brine two-phase flow in underground hydrogen storage

Underground hydrogen storage (UHS) is receiving increasing attention to address the challenges in hydrogen storage. A crucial aspect of UHS is understanding the transport of hydrogen in subsurface porous media. In this work, hydrogen core flooding experiments were conducted in a sandstone sample and then the pore-scale distribution of hydrogen and brine was visualized using high-resolution X-ray micro-computed tomography (micro-CT). After CT image processing, we measured the surface contact angles (CAs) on rock surfaces and found that the measured CAs followed a log-normal distribution. To investigate the influence of rock surface wettability on the transport properties in the hydrogen-brine-sandstone system, the lattice Boltzmann (LB) method was used to simulate two-phase flows with different surface CA distributions; hydrogen-brine relative permeability and capillary pressure curves through the primary drainage, imbibition, and secondary drainage processes were obtained by LB simulations. X-ray CT scanning showed that hydrogen resided in both large pores and small pores and pore throats after the primary drainage process (i.e., hydrogen displacing brine), whereas after the imbibition process (i.e., brine displacing hydrogen) hydrogen stayed primarily in large pores where the capillary pressure barriers were low. The LB two-phase flow modeling illustrated that water’s relative permeability increased whereas hydrogen’s relative permeability decreased when the core flooding moved from primary drainage to imbibition; in contrast, when the core flooding moved from imbibition to secondary drainage, water’s relative permeability decreased whereas hydrogen’s relative permeability increased. Decreasing the surface CA increased the capillary pressure and reduced the hydrogen residual rate, which indicates high hydrogen retrievability and thus is favorable for UHS practice. The change in CA’s standard deviation did not cause noticeable changes in water’s relative permeability curves, whereas it resulted in noticeable changes in hydrogen’s relative permeability curves. This work is the first study that utilizes X-ray micro-CT scanning and pore-scale multiphase flow modeling to quantitatively and comprehensively investigate hydrogen-brine two-phase flow properties under different rock surface wettability distributions. The research findings from this study will advance the understanding of hydrogen transport in an underground storage system and provide essential data for large-scale field studies in UHS.

On the role of disjoining pressure in nanofluid-assisted enhanced oil recovery: a mini-review.

Nanofluid application in enhanced oil recovery (EOR) recently emerged and garnered significant attention within the field. Nanofluids possess unique properties of reducing oil-water interfacial tension, stabilizing emulsions, altering rock surface wettability, and enhancing disjoining pressure between crude oil and rock surfaces, therefore have potential for the oil recovery process. This review provides an in-depth exploration of various aspects related to nanofluids in EOR. Different types of nanofluids are presented with their preparation methods and representative properties. More importantly, the disjoining pressure, a key physical concept in nanofluid-assisted EOR, is introduced and discussed in terms of the mechanism of oil displacement and measurement methods. Further understanding the role of disjoining pressure in nanofluid-assisted oil displacement is necessary for the development and application of effective nanofluids for EOR.

Pseudo gemini surfactant fracturing fluid with dual function of fracturing and oil flooding for enhanced oil recovery

The flow back treatment after the completion of hydraulic fracturing leads to inevitable formation damage and economic losses. Herein, a Pseudo gemini surfactant (5-SSIPA/EA) was formed by the assembly of Erucamidopropyl dimethylamine (EA) and 5-sulfoisophthalic acid (5-SSIPA). 5-SSIPA/EA exhibited high viscoelasticity in aqueous solution and suggested oil-induced gel-breaking behavior, which features the dual functions of fracturing and oil flooding. 5-SSIPA/EA with a concentration of 30 mM suggested excellent resistance for temperature and shear, whose viscosity remained 49 mPa·s with a shear rate of 170 s−1 at 110 °C. 5-SSIPA/EA showed good sand carrying capacity with a sand settlement rate of 0.006 cm·min−1, Resulting from the adsorbed 5-SSIPA/EA molecules reducing the adhesive force of oil droplets and alerting the wettability of rock surface, the oil-induced gel breaking fluid of 5-SSIPA/EA exhibited excellent oil washing efficiency and oil flooding efficiency. Therefore, 5-SSIPA/EA is expected to evade the flowback process and realize the integration of fracturing and oil flooding. We confirmed that the 5-SSIPA/EA system has a potential application prospect in the development of a low permeability reservoir.

Effect of rock surface wettability on hydrogen-cushion gas adsorption with application to hydrogen storage in depleted oil and gas reservoirs

In this study, adsorption capacity of Berea sandstones varying wettability states with respect to hydrogen (H2) and hydrogen-methane (H2-CH4) mixture are examined to assess the viability of depleted oil and gas reservoirs for large scale hydrogen storage. We investigate pure hydrogen and hydrogen-methane mixture adsorptions as a function of pressure, temperature, and rock surface wettability. The obtained results indicate that as the CH4 fraction increases from 0 to 20 %, the gas uptake exhibits a more significant rise, going from 0.98 to 1.68 cm3/g for oil-wet sandstone and from 1.04 to 1.2 cm3/g for untreated samples, both at 25 °C. This suggests a pronounced affinity of CH4 for the aged rock. The adsorption capacity of the H2-CH4 mixture increases from 1.2 to 1.68 cm3/g at 80 bar and 25 °C when rock samples are exposed to crude oil compared with the untreated rock samples. Investigating the impact of temperature on adsorption capacity reveals a decrease in gas uptake as the measurement temperature rises from 25 to 60 °C across all pressure levels. All rock samples exhibit a positive hysteresis in adsorption and desorption isotherms at various temperatures. The Freundlich, Redlich-Peterson, and Sips models are found to be more representative in describing the adsorption characteristics, suggesting multilayer adsorption on the rock surface. Our findings provide insights into the impact of natural gas adsorption and desorption on overall hydrogen production. This study can improve the accuracy and efficacy of reservoir simulations and flow models that depict the movement of hydrogen and natural gas through porous media within sandstone reservoirs.

Underground hydrogen storage: A recovery prediction using pore network modeling and machine learning

Understanding the hydrogen-brine transport properties and the hydrogen trapping rate (i.e., ratio of residual hydrogen saturation after recovery to initial hydrogen saturation) is critical to the site selection for underground hydrogen storage (UHS). In this study, a three-dimensional pore network model (PNM) was used to simulate hydrogen-brine two phase flow in various porous media, including sandstone, carbonate, and sand packs. Surface contact angles measured from previous experiments were used to study the influence of the wettability on hydrogen transport in porous media. Many studies have investigated the impact of these factors on carbon dioxide sequestration. However, because of the difference in the thermal dynamic properties of the fluids and the purpose of UHS and carbon dioxide sequestration, it is still essential to analyze the UHS performance under the different rock and fluid properties. PNM simulations showed that a relatively larger contact angle with low water affinity was more suitable for UHS due to its low hydrogen trapping rate. Two machine learning methods, the least square fitting and the support vector machine (SVM), were developed to classify the ability of a rock to trap hydrogen and to predict hydrogen trapping rates. Hydrogen trapping rates simulated using the PNM were used as the training data in the machine learning models. The SVM classified rock samples into two groups which had high hydrogen trapping rates (>50 %) and low hydrogen trapping rates (<50 %). The machine learning results showed that rock samples with a low ratio of pore size to throat size and high pore connectivity (i.e., average number of throats connected to a given pore) were favorable for a low hydrogen trapping rate. This study illustrated that the impact of both rock surface wettability and pore structural geometry should be accounted for when evaluating a hydrogen-brine two-fluid system in porous media. This work is the first study that combined PNM simulation with machine learning to investigate the influence of rock surface wettability and pore structure features on the hydrogen trapping rate, which will provide insights into site selections and decision making in large-scale UHS projects.

Analysis of the Influencing Factors on the Extraction of Residual Oil through the Gel Foam Flooding of Underground Reservoirs in the Tahe Oilfield.

Fractured-vuggy reservoirs are mainly composed of three types: underground rivers, vugs, and fractured-vuggy structures. Based on the similarity criterion, a 3D model can truly reflect the characteristics of the multi-scale space of a fractured-vuggy reservoir, and it can reflect fluid flow laws in the formation. Water flooding, gas flooding, and gel foam flooding were carried out in the model sequentially. Based on gas flooding, the enhanced recovery ratio of gel foam flooding in the underground river was approximately 12%. By changing the injection rate, the average recovery ratio of nitrogen flooding was 6.84% higher than that of other injection rates at 5 mL/min, and that of gel foam flooding was 1.88% higher than that of other injection rates at 5 mL/min. The experimental results showed that the gel foam induced four oil displacement mechanisms, which selectively plugged high-permeability channels, controlled the mobility ratio, reduced oil-water interfacial tension, and changed the wettability of rock surfaces. With different injection-production methods, gel foam flooding can spread across two underground river channels. Two cases of nitrogen flooding affected one underground river channel and two underground river channels. By adjusting the injection rate, it was found that after nitrogen flooding, there were mainly four types of residual oil, and gel foam flooding mainly yielded three types of remaining oil. This study verified the influencing factors of extracting residual oil from an underground river and provides theoretical support for the subsequent application of gel foam flooding in underground rivers.

Zwitterionic-nonionic compound surfactant system with low chromatographic separation effect for enhanced oil recovery

Ultra-low oil/water interfacial tension (IFT) is an important parameter for evaluating the enhanced oil recovery performance of surfactant flooding. It is difficult to achieve ultra-low interfacial tension with crude oil by a single surfactant, so compound system is often used. However, the chromatographic separation effect of each component in the compound system will severely affect the practical oil displacement performance. In this study, a novel compound oil displacement system was prepared by a zwitterionic surfactant (oleic amidopropyl betaine, OAB) and a nonionic surfactant (coconut oil diethanolamide, CDEA) at a mass ratio of 1:1. The capability of reducing IFT, emulsification, wettability reversal and oil film peeling performance of this system were evaluated. The results show that by promoting the dense arrangement of surfactants at the oil/water interface and realizing hydrophilic-lipophilic balance, the OAB-CDEA compound system can reduce the IFT to 10−4 mN/m. The system also exhibits excellent emulsification performance, and when placed at undisturbed state, the small and uniform emulsion droplets demulsify spontaneously and completely within 3 h. The compound system can regulate the wettability of rock surface from oleophilic to strongly hydrophilic, increasing the underwater oil contact angle from 24° to 157°. Based on the static oil film peeling tests, the oil film reduction rate can reach 88%. Using a 0.3% compound system for the core flooding tests, a recovery up to 75% can be attained, which is ∼30% higher than that of simulated formation water flooding. Meanwhile, the system exhibits low chromatographic separation effect, with chromatographic separation factor Foc close to 1. The OAB-CDEA compound system proposed in this work demonstrates excellent oil displacement performance as well as low chromatographic separation effect, exhibiting great potential in oilfield practical application.

Effect of the Type and Concentration of Salt on Production Efficiency in Smart Water Injection into Carbonate Oil Reservoir Rocks.

Smart waterflooding is one of the most practical emerging methods of enhanced oil recovery in carbonate reservoirs. In this study, the effect of salt type and its concentration in smart water on oil recovery from a carbonate reservoir rock is investigated. A series of experimental measurements, including zeta potential (ZP), interfacial tension (IFT), and contact angle (CA), were conducted to examine the effect of ions on the oil/brine/rock interaction. IFT, ZP, and CA were also used as screening methods to select effective solutions for flooding experiments. The results of the study show that synthesized brines containing sodium acetate and potassium acetate salts have a significant effect on the reduction of IFT; however, rock surface wettability due to such brines is insignificant. The presence of organic salts in the injected water can alter the properties of the fluid and rock surface, leading to improved oil recovery. The salts can reduce the interfacial tension between the oil and water phases, making it easier for the water to displace and mobilize trapped oil. This effect is particularly beneficial in reservoirs with high oil-water interfacial tension as it enhances the capillary forces and improves the sweep efficiency. Smart water with sodium acetate (MSW.NaOAc) caused a 7% increase in oil production in the tertiary injection process due to IFT and CA reduction. The secondary injection of MSW.NaOAc led to an oil production efficiency of 76%, which is 10% higher than that of the secondary injection of seawater (SW), confirming the effectiveness of acetate ions in enhancing oil recovery. Doubling the concentration of sulfate ions in modified SW (MSW.NaOAc.2S) caused a 19% increase in oil production in tertiary injections after SW flooding. The secondary injection of MSW.NaOAc.2S produced a 13% increase in the recovery factor compared to SW flooding in the secondary mode. The main driving mechanism for oil mobilization was found to be wettability alteration, which is supported by the analyses of CA and ZP. This study confirms that the salt type and concentration present in a brine solution play a vital role in the movement of trapped oil in carbonate reservoirs.

Construction and performance evaluation of novel compound oil displacement system for enhanced oil recovery

Conventional methods of flooding leave behind a significant amount of oil films that adhere to the rock surfaces. Developing novel compound oil displacement system to achieve efficient oil film peeling and migration is of great significance for further enhanced oil recovery. Herein, a novel compound oil displacement system was developed through optimization experiments using a binary surfactant mixture composed of SDBS and BS-18, along with a wetting regulator known as CAS. The minimum interfacial tension attained of compound oil displacement system was 0.0042 mN/m, indicating an ultra-low level. Meanwhile, the compound system could alter the rock surface wettability from oleophilic to strong hydrophilic, with the underwater oil contact angle substantially increasing from 18° to 123.1°. The compound system demonstrated remarkable stability at high water salinity (60000 ppm) and high temperature (90 °C). The surface strong hydrophilicity contributed to the excellent oil film peeling performance of compound system, leading to an 89.14% reduction in the oil film area within 12 h. The superior ability in interfacial tension reduction and wettability alteration of the compound system facilitated the “peeling off” and “migrating out” process of the residual oil film, and impressive enhanced oil recovery of 18.68% was achieved compared to that of the surfactant mixture SDBS/BS-18 (7.23%) and wetting regulator CAS (7.64%). It is believed that the outcomes of this work provide valuable insights into the design and optimization of effective oil displacement systems for residual oil development.

A Regulation Method of the Wettability of Solid Surfaces: Oil–Water Wettability Alteration by Replacing Adsorbed Polar Molecules via Salt Ions

Wettability of solid surfaces is generally regulated by modifying the microstructures and other properties of surfaces themselves. Here, we present that the wettability of solid surfaces exhibiting polar interactions with fluids can be substantially regulated only by adding a small amount of substances in fluids, instead of modifying the physicochemical properties of solid surfaces. We show that the adsorbed polar molecules on rock surfaces can be replaced by salt ions in the water phase, and ultimately the oil-wet surfaces are altered to water-wet. The influence of Na+ and Ca2+ ions on the wettability of rock surfaces with initially adsorbing stearic amine and pyrrole is revealed via molecular dynamics simulations. The contact angles of oil droplets are altered from 68.1° to 132.0° at most, which is very consistent with previous experimental measurements. The contact angles’ increase with increasing ionic concentration and the effect of divalent Ca2+ ions on the wettability alteration is more obvious compared to the monovalent Na+ ions. It is proved from the aspects of spatial distribution, microscopic interaction, and system energy of polar molecules and ions that the replacement of polar molecules is due to the negative substrates preferentially contacting with the free cations in the water phase. This work opens a new route for the regulation of surface wettability, especially in the field of water-flooding oil recovery technology.

Fatty Alcohol Polyoxyethylene Ether Sodium Sulfate–Modified Cement to Improve the Bonding and Sealing of Cement to Oil-Wet Casing or Formation Surface in Shale Gas Wells

Summary In shale gas wells, oil-based mud (OBM) changes the casing and rock surface wettability during drilling. It negatively affects the bonding and sealing of cement sheaths with casing or formation rock. Although the spacer is widely used in primary cementing, the casing and formation rock surface are wetted by OBM or oil phase due to poor displacement. For this work, a novel oleophilic cement slurry modified by fatty alcohol polyoxyethylene ether sodium sulfate (AES) was investigated to decrease the negative effect of OBM- or oil-wetted surface. The contact angle of nonpolar solvent 1-bromonaphthalene on the cement surface decreased from 35° to 8°, showing an ideal oleophilic property. The hydraulic isolation capacity; microstructure of the cement-casing or cement-rock interface; and the pore structure, hydration, and mechanical property of AES-modified cement were investigated by interfacial hydraulic isolation test device, computed tomography (CT), mercury intrusion porosimetry (MIP), X-ray diffraction (XRD), thermogravimetric analyses (TGAs), and mechanical test. The results showed that the oleophilic cement could directly bond with an oil- or OBM-wetted surface and significantly eliminate the microchannel and connected pores caused by the oil phase or OBM on the interface. The fluid channeling on the OBM-wetted cement-rock and casing interface was prevented, and the sealing pressure of the interface was increased from approximately 3 to 7 MPa/m (fluid channeling occurred) to higher than 275 MPa/s (fluid channeling did not occur), respectively. Besides, the hydration degree, porosity, and mechanical property of the oleophilic cement remained at the same level as the conventional cement, indicating that the AES has no adverse effect on cement hydration and properties. The findings of this study can contribute to the cement slurry design in shale gas well cementing to improve the interface bonding and sealing when poor displacement happens.

Wettability Alteration to Reduce Water Blockage in Low-Permeability Sandstone Reservoirs

This study is a continuation of our previous work, which focused on a near-wellbore water blockage alleviation by applying a thermally cured silane-functionalized benzoxazine to modify rock wettability. In this new analysis, we have demonstrated that the resin can be applied in low-permeability sandstones (approximately 15 mD as opposed to 100 to 200 mD in the previous study) to change the rock surface wettability from water-wet to intermediate gas-wet. We have also demonstrated that curing temperatures as low as 125 °C (as opposed to 180 °C in our previous study) can significantly change wettability, indicating surface functionalization through the silane moiety and ring-opening polymerization of the benzoxazine moiety. In drainage core flooding experiments at 2.5 wt.% resin loading, compared to untreated samples, brine recovery increments of 6.3 to 6.9% were obtained for curing temperatures of 125 to 180 °C, respectively. A maximum 20% increment in the end-point relative gas permeability was achieved at a curing temperature of 180 °C. A coupled experimental and numerical study, conducted at core and wellbore scales, demonstrates the potential effectiveness of our chemical treatment in improving gas productivity at the field scale. Reservoir simulations indicate a 2.9 to 10.6% improvement in gas deliverability for a treatment radius of 4 to 16 m, respectively.

Application of unsupervised deep learning to image segmentation and in-situ contact angle measurements in a CO2-water-rock system

Rock surface wettability is a critical property that regulates multiphase flows in porous media, which can be quantified using the surface contact angle (CA). X-ray micro-computed tomography (μCT) provides an effective approach to in-situ measurements of surface CAs. However, the CA measurement accuracy depends significantly on the quality of CT image segmentation, which is the clustering of CT pixels into separate phases. Inspired by this, we developed a deep learning (DL)-based CA measurement workflow. Motivated by the recent tremendous progress in unsupervised learning techniques and aiming to avoid expensive manual data annotations, an unsupervised DL pipeline for CT image segmentation was proposed and implemented, which includes unsupervised model training and post-processing. The unsupervised model training was driven by a novel loss function constrained with feature similarity and spatial continuity and implemented by iterative forward and backward paths; the former clustered the pixel-wise feature vectors extracted by convolution neural networks, whereas the latter updated the parameters using gradient descent. An over-segmentation strategy was adopted for model training. The post-processing steps based on agglomerative hierarchical clustering (AHC) were implemented to further merge the over-segmented model output to the desired cluster number, which is intended to improve the efficiency of image segmentation. The developed unsupervised DL pipeline was compared with other commonly-used image segmentation methods using pixel-wise and physics-based evaluation metrics on a synthetic raw-image dataset, which had a known ground truth. The unsupervised DL pipeline showed the best performance. Next, the segmented images were input to an automatic CA measurement tool, and the results were validated by comparisons with manual measurements. The CA values from the manual and automatic measurements showed similar distributions and statistical properties. The automatic measurement demonstrated a wider spectrum because of the much larger number of measurement data points. The primary novelty of the unsupervised DL pipeline developed in this study lies in the novel loss function and the over-segmentation strategy associated with AHC post-processing. The workflow has been proven an efficient tool for pore-scale wettability characterization, which has a wide range of applications in fundamental studies of multiphase flows in natural porous media, which have critical implications to geological carbon sequestration, hydrocarbon energy recovery, and contaminant transport in groundwater.