Oil-wet Surface Research Articles

Janus SiO2-surfactant dispersion designed for enhanced imbibition oil recovery in ultra-low permeability reservoirs

The use of nanofluids in formations with high temperatures and high salinity is currently encountering significant obstacles. Therefore, a Janus SiO2-surfactant dispersion consisting of Janus nanoparticles and surfactants was constructed in the current study. The Janus SiO2-surfactant dispersion is resistant to both high temperatures and high salinity. The Janus SiO2-surfactant dispersion, consisting of Janus SiO2 nanoparticles and the non-ionic surfactant Tween80, is abbreviated as JASN-T80 hereafter. The system can be dispersed and kept stable for one week at a salinity of 30,000 mg/L and a temperature of 85 ℃. The concentration of f nanoparticles and surfactant in the system was optimized at 0.02 wt% Janus SiO2 nanoparticles + 0.04 wt% Tween80 based on the particle size. An assessment was conducted to measure the system's capacity to decrease interfacial tension and alternate wettability. The interfacial tension between oil and water was reduced to 1.21 mN/m. The JASN-T80 system demonstrates a notable capacity to change wettability by decreasing the contact angle of water on an oil-wet rock surface from 100.6° to 70.5°. The combination of nanoparticle and surfactant leads to a synergistic effect, resulting in an imbibition recovery of 44.28 % for ultra-low permeability core. This work provides a novel concept for the advancement and utilization of nanofluid imbibition system for unconventional reservoir.

The effect of low salinity water on wettability alteration of oil-wet calcite surfaces

To shed light on the chemical and physical aspects of low-salinity (LS) water flooding to enhance oil recovery, we explored the impact of the brine salinity on the modifications of the oil-calcite interface using a multi-technique surface science approach based on FTIR, AFM, XPS, and Contact angle measurements. Our findings reveal that Nujol-model oil adsorbs on fresh-cleaved CaCO3 (104) surface and initially forms a continuous film. Chemical and morphological surface characterizations were performed on oil-wet calcite, followed by their conditioning with formation (FW), demineralized (DW), and low salinity water (LS25, LS50, LS75, and LS100). The oil removal was quantified by semi-quantitative FTIR analysis and was found to vary from ∼20 % for FW up to ∼81 % for LS75 conditioning. In the investigated experimental conditions the fresh-cleaved calcite surface is most efficiently converted from oil-wet to water-wet when conditioned with LS75 brines. Significant surface wettability alterations were observed for LS 75 brines as contact angle measurements were found to reach a minimum contact angle of ∼18°. The changes in calcite wettability correspond to the formation of fragmented oil islands and calcite step bunches, the signature of surface dissolution, and changes in the oil-calcite chemical interactions. A model for Nujol adsorption and its detachment from the calcite surface was proposed for oil removal, competitive mechanisms related to the brine chemical composition are discussed.

Occurrence and Flow Behavior for Oil Transport in Mixed Wetting Nanoscale Shale Bedding Fractures.

Shale reservoirs are characterized by an abundance of nanoscale porosities and microfractures. The states of fluid occurrence and flow behaviors within nanoconfined spaces necessitate novel research approaches, as traditional percolation mathematical models are inadequate for accurately depicting these phenomena. This study takes the Gulong shale reservoir in China as the subject of its research. Initially, the unique mixed wetting characteristics of the Gulong shale reservoir are examined and characterized using actual micropore images. Subsequently, the occurrence and flow behavior of oil within the nanoscale bedding fractures under various wettability scenarios are described through a combination of microscopic pore image and molecular dynamics simulations. Ultimately, a mathematical model is established that depicts the velocity distribution of oil and its apparent permeability. This study findings indicate that when the scale of the shale bedding fractures is less than 100 nm, the impact of the nanoconfinement effect is significant and cannot be overlooked. In this scenario, the state of oil occurrence and its flow behavior are influenced by the initial oil-wet surface area on the mixed wetting walls. The study quantifies the velocity and density distribution of oil in mixed wetting nanoscale shale bedding fractures through a mathematical model, providing a crucial theoretical basis for upscaling from the nanoscale to the macroscale.

An efficient method for imbibition in asphaltene-adsorbed tight oil-wet reservoirs

Spontaneous imbibition (SI) has been proposed as a crucial approach to enhance oil recovery in unconventional reservoirs. Previous research suggests that wettability alteration rather than oil-water interfacial tension (IFT) reduction is the key mechanism for imbibition oil recovery enhancement. However, our experimental results indicate that for asphaltene-adsorbed oil-wet surfaces it's challenging to substantially modulate wettability. In such oil-wet pores, the negative capillary force cannot function as an imbibition driving force, and hence, the method of altering wettability and maintaining the oil-water IFT at relatively high values to enhance imbibition efficiency is insufficiently applicable. When the capillary cannot work, reducing the IFT to ultra-low levels to induce the transformation of the imbibition pattern may be more effective for imbibition efficiency enhancement. In this paper, low-field nuclear magnetic resonance (NMR) was employed to monitor the SI process. The results suggested that for the asphaltene-adsorbed oil-wet tight sandstone, the surfactants combined system with ultra-low oil-water IFT possessed the highest oil recovery, followed by the medium-IFT systems and high-IFT systems. The spontaneous formation of emulsion was observed when the IFT value was reduced to the ultra-low level. Oil droplets can pass through the small pores easily since the deformability of oil is greatly enhanced. The ultra-low IFT system transforms the imbibition pattern from capillary force-driven to gravity-driven, and exhibits the highest oil utilization rate in micropores, mesopores, and macropores among all imbibition agent systems, thereby having the highest total oil recovery. Consequently, the imbibition-enhancing potential of the ultra-low IFT system is considerable and deserves more attention, especially for the oil-wet pores that can hardly be altered to the water-wet state.

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.

Interfacial Behaviors and Oil Detachment Mechanisms by Modified Silica Nanoparticles: Insights from Molecular Simulations.

Surfactant flooding has been considered as a promising approach for chemically enhanced oil recovery (EOR). However, this technique encounters several limitations, such as high costs, environmental concerns, and reduced efficiency under high-temperature and high-salinity reservoir conditions. Recently, nanoparticles have also been proposed as an alternative for EOR due to their superior properties compared with surfactants. This research employs molecular dynamics simulations to explore the impact of modified SiO2 nanoparticles on oil-water interfacial behaviors and the detachment of oil droplets from an oil-wet surface. The simulation results reveal that modified nanoparticles, featuring hydrophilic and hydrophobic functional groups, have slight impacts on interfacial tension reduction of the oil-water interface. Nanoparticles with varying degrees of modification exhibit distinct positions within the interface, consequently influencing the thickness of the interfacial layer. Notably, the interactions among the nanoparticles, oil molecules, and surface facilitate the formation of a water channel, thereby enhancing the process of oil detachment. Comparative analysis indicates that in terms of oil displacement efficiency, the thickness of the interfacial layer has a more significant impact than interfacial tension reduction. Furthermore, to elucidate the mechanisms of modified nanoparticles enhancing the oil recovery rate, the interaction energies among the oil droplet, nanoparticles, water, and surface are analyzed. The molecular-level insights derived from this investigation could provide valuable guidance for the design of modified nanoparticles tailored to EOR applications.

Quantitative analysis on resistant forces at oil-surfactant-rock interfaces with dynamic wettability characterization

Adhesion of oil at rock surface plays an important role in the liberation of oil from micro-/nano-pores, especially for heavy oil that has extremely high viscosity. Although molecular dynamics simulation is widely used to study the interfacial interaction for some specific oil-water-rock systems, experimental measurements provide more realistic and reliable evidence. In this work, we propose a dynamic wettability characterization method to indirectly measure resistant forces at oil-surfactant-rock interfaces, including frictional force, wettability hysteresis force, and viscous force, which are parallel with the oil-solid interface. The adhesive force, which is normal to the oil-solid interface is calculated through measurement of work of adhesion. The results show that work of adhesion instead of contact angle can better describe the adhesion of oil at solid surface. The effect of surfactant concentration on work of adhesion is different for water-wet and oil-wet surfaces. Moreover, average viscous forces are calculated through force analysis on oil drops moving along solid surface in different surfactant environments. It is found that viscous force has a magnitude comparable to the frictional force during the movement, while the wettability hysteresis force is negligible. On the other hand, the adhesive force calculated from the work of adhesion is also comparable to the viscous force. Therefore, both the resistant forces parallel with and normal to the oil-solid interface should be minimized for the liberation of oil from rock surface. This work proposes a simple method to evaluate the wetting capability of different surfactants and measure the adhesive force between heavy oil and rock surfaces indirectly, which provides insight into the adhesion of heavy oil at rock surface and would be valuable for the development of surfactant-based oil recovery methods.

Effect of the capillarity and viscosity on the change of flow paths during two-phase displacement in porous media

Pore-scale direct numerical simulations were conducted to explore the changes of flow paths and dynamic distribution of water-oil phases during two-phase displacement in porous media. Three contact angles, i.e., 45°, 90°, and 135°, correspond to water-wet, intermediate-wet, and oil-wet rock surfaces, respectively. The medial axis within complex pore channels is obtained using a grid-based method. Subsequently, a novel particle tracking-based approach is proposed to extract the flow paths during two-phase displacement. The results show that when water enters a porous medium filled with oil, the distribution of oil phase flow paths is uniform, indicating that all oil phases are movable. As water continues to be injected, some water-oil interfaces stop at pores or throats due to capillary force, causing the flow paths through these locations to disappear. In oil-wet and intermediate porous media, capillary forces always act as resistance; therefore, the water-oil interfaces stop at the throat channels. Interestingly, under water-wet conditions, the water-oil interface can reverse, and the capillary force presents resistance, resulting in the interfaces being blocked at enlarging areas, usually from throats to pores. Once breakthrough occurs, preferential flow paths for pure water are established, resulting in a rapid decrease of flow paths with moving water-oil interfaces under oil-wet and intermediate-wet conditions, while movement continues in a water-wet medium. Due to the typically lower viscosity of water than oil, the viscous force decreases as water saturation increases. As water injection continues, the water in some channels gradually displaces oil, resulting in differences in flow rates between oil-filled and water-filled channels. This study provides a method for identifying the changes in flow paths during two-phase displacement in porous media and gives potential benefits for designing strategies to improve oil recovery.

Multiscale study of Janus nanosheets’ interfacial activity

As the challenge of enhancing oil recovery from reservoirs continues to grow, it becomes increasingly crucial to seek out new materials for oil displacement. Janus graphene oxide (JGO) with excellent interfacial activity stands out as a promising candidate, which enables it to locate crude oil and effectively displace it towards production wells. One key advantage of JGO is its ability to reduce interfacial tension and create interfacial films, attributed to JGO nanosheets adsorbing at oil–water interfaces. Another noteworthy property of JGO is its capacity to transform oil-wet rock surfaces into water-wet surfaces, which is because JGO nanosheets can interact hydrophobically with crude oil molecules on rock surfaces. In addition, JGO helps mitigate capillary resistance by altering the concave oil–water front to a flat state. Microscopic displacement shows that JGO nanosheets enlarge the sweep efficiency and oil-washing efficiency of water. Nuclear magnetic resonance experiment indicates that JGO nanofluid can increase oil recovery by 17.1 %. This research presents a comprehensive exploration of the interfacial activity of Janus nanofluid, spanning from the molecular scale to the micro and core scales.

New insights from nanoscale in-depth investigation into wettability modification in oil-wet porous media

In the context of fluid-surface studies of oil reservoirs, wettability alteration plays an important role, especially in carbonate reservoirs. This investigation, utilizing molecular dynamics simulation, delves into the effect of oil movement during interactions with brine ions. The calculation of adsorption energy, radial distribution function, diffusion coefficient, and configurational changes of the NaCl brine molecules allowed for an examination of the role of ions in oil movement from an oil-wet calcite surface. Findings indicate that the polarity of oil has a marked influence on oil detachment, as evidenced by the more than 30% adsorption energy for the acrylic acid system compared to the decane system. The diffusion coefficient of Na[Formula: see text] ions in the acrylic acid system was found to be five times as high as in the decane system. Configuration changes showed that brine ions are more active — in a regular eight shape — in interacting with the acrylic acid-wet surface as opposed to the decane-wet surface. The hierarchical significance of oil polarity [Formula: see text] brine ions [Formula: see text] mineral surface in altering the wettability of the system demonstrates the significance of sodium ions in the presence of the polar oil component. The findings greatly contribute to the development of effective Smart Water flooding technology.

Molecular dynamics simulation of surfactant induced wettability alteration of shale reservoirs

Shale oil has recently received considerable attention as a promising energy source due to its substantial reserves. However, the recovery of shale oil presents numerous challenges due to the low-porosity and low-permeability characteristics of shale reservoirs. To tackle this challenge, the introduction of surfactants capable of modifying wettability has been employed to enhance shale oil recovery. In this study, we perform molecular dynamics simulations to investigate the influence of surfactants on the alteration of wettability in shale reservoirs. Firstly, surfaces of kaolinite, graphene, and kerogen are constructed to represent the inorganic and organic constituents of shale reservoirs. The impact and underlying mechanisms of two types of ionic surfactants, namely, the anionic surfactant sodium dodecylbenzene sulfonate (SDBS) and cationic surfactant dodecyltrimethylammonium bromide (DTAB), on the wettability between oil droplets and surfaces are investigated. The wettability are analyzed from different aspects, including contact angle, centroid ordinates, and self-diffusion coefficient. Simulation results show that the presence of surfactants can modify the wetting characteristics of crude oil within shale reservoirs. Notably, a reversal of wettability has been observed for oil-wet kaolinite surfaces. As for kerogen surfaces, it is found that an optimal surfactant concentration exists, beyond which the further addition of surfactant may not enhance the efficiency of wettability alteration.

Cationic-anionic surfactant mixtures based on gemini surfactant as a candidate for enhanced oil recovery

The surface and interfacial properties of bisquaternary ammonium salts (16−4−16), sodium dodecyl benzene sulfonate (SDBS), and their mixture were investigated. Moreover, the effects of adsorption on the crude oil/water interfacial tension (IFT) of the SDBS/16–4–16 mixture were examined. Finally, the wettability alternation, oil film peeling-off performance, and core flooding were used to evaluate the enhanced oil recovery of the SDBS/16–4–16 mixture. Results show that the cationic Gemini surfactant 16–4–16 exhibits a strong synergistic effect with SDBS in surface/interfacial activity. At αSDBS = 0.66, the CMC value of the SDBS/16–4–16 mixtures reaches the lowest (0.016 mmol/L), and the interaction parameter (βm) exhibits a minimal value (−11.47), indicating a strong attraction between the cationic and anionic surfactants. When αSDBS is between 0.2 and 0.7, the diesel/water IFT is reduced below 10−2 mN/m, and the IFT shows little relationship with the mixing ratio. For crude oil, when αSDBS is equal to 0.4 and 0.5, the SDBS/16–4–16 mixtures can also reduce the crude oil/water IFT to ultra-low (<10−2 mN/m). When the mineralization is between 5000 mg/L and 20,000 mg/L, the IFT of crude oil/water can be reduced to 3.3 × 10−3 mN/m.Adsorption time, temperature, and liquid-solid ratio have less effect on the IFT of the SDBS/16–4–16 mixture (αSDBS = 0.4) than cationic surfactant 16–4–16. As static adsorption time increases to 24 h, the IFT of the SDBS/16–4–16 mixture only increases from 3.13 × 10−3 mN/m to 4.58 × 10−3 mN/m, while 16–4–16 increases the IFT from 0.121 mN/m to 0.202 mN/m. Furthermore, the SDBS/16–4–16 mixture takes only 10 min to reach dynamic adsorption equilibrium, shorter than the two pure components. The ability of the SDBS/16–4–16 mixtures to reduce the contact angle on the lipophilic glass surface and the oil film peeling-off performance is significantly superior to 16–4–16 and SDBS. As low as 0.1 mmol/L, the SDBS/16–4–16 mixture (αSDBS = 0.4) can reduce the contact angle of oil-wet glass surface from 107° to 46°, while 16–4–16 reduces it to 68° and SDBS to 79°. Eventually, the SDBS/16–4–16 mixture (αSDBS = 0.4) shows excellent performance in the core flooding experiments. The SDBS/16–4–16 mixture could improve crude oil recovery by 26.2%, demonstrating great potential in EOR.

Underground hydrogen storage: The microbiotic influence on rock wettability

Hydrogen geo-storage could be the large-scale solution needed for a hydrogen economy. Biological factors have been considered but mainly in terms of hydrogen-metabolising microbes. We demonstrate consistently the direct influence of underground biofilm formation on the wettability of sandstone reservoirs. The biofilm, formed by incubation with cyanobacteria Geitlerinema sp. in seawater, increases the advancing and receding brine contact angles on water-wet quartz. The angles decrease only slightly on oil-wet quartz surfaces even though biomass accumulation is more significant. We formulate an explanation using Cassie's approach to heterogeneous surfaces, taking into account the predominant surface chemical groups. Wettability strongly affects the distribution, trapping and mobility of phases (brine and hydrogen) inside the rock formation. Our results, obtained at typical reservoir conditions (25–50 °C, 3–130 bar), are relevant to understanding and assessing hydrogen injectivity, withdrawal rates, storage capacity and containment security. This fundamental research supports the development of an industrial-scale decarbonized hydrogen economy.

Experimental investigation of wettability alteration of oil-wet carbonate surfaces using engineered polymer solutions: The effect of potential determining ions ([Mg2+/ SO42−], and [Ca2+/ SO42−] ratios)

Engineered water polymer flooding (EWPF) is a promising method to improve oil recovery in carbonate reservoirs holding more than half of the world's oil reserves. It involves combining engineered water (EW) and polymer flooding (PF) to modify rock wettability, reduce mobility ratio, promote polymer stability, and lower required polymer concentration. However, limited studies addressed the simultaneous effect of engineered water compositions (i.e. potential determining ions (PDIs)) on the viscosity of polymer and wettability alteration of various carbonate surfaces. Accordingly, this study aimed to investigate the effect of salinity, PDIs, and polymer functional groups (partially hydrolyzed polyacrylamide (HPAM), and acrylamide tertiary butyl sulfonic acid (ATBs)) on the wetting properties of calcite, chalk, and dolomite surfaces as well as the viscosity of solutions at static conditions. The experimental protocol included viscosity, contact angle (CA), pH, and static adsorption tests. Two combinations of PDIs were considered in the study: [Mg2+/SO42−], and [Ca2+/SO42−]. The results revealed that the polymer becomes more tolerant to the salinity as the sulfonation degree increases, given the same molecular weight. However, at a polymer concentration of 5000 ppm, the HPAM polymer showed higher viscosity than the ATBs-based polymers, as the formation brine (FB) was diluted to 100 folds (100DFB). The tendency of shifting the wettability of carbonate surfaces towards a more water-wet state using EW and EWP treatment solutions decreased in the following order: Chalk ≥ Calcite˃ Dolomite. The study also indicates that, the wettability alteration towards favorable condition is dependent on the initial wettability of the carbonate surface. The higher level of oil-wetness detected in aged dolomite, compared with calcite and chalk, resulted in less effectiveness of EWP for dolomites. However, the low polymer interaction with dolomite surfaces indicates a positive impact on reducing polymer consumption. Moreover, the HPAM polymer was more effective in altering the wettability of dolomite towards a water-wet state compared to the ATBs-based polymer. The overall results indicate that ATBs-based polymer is a potential candidate for optimizing the effectiveness of EWPF in carbonates.

Synergistic study of xanthan-gum based nano-composite on PELS anionic surfactant performance, and mechanism in porous media: Microfluidic & carbonate system

Rising global energy demand and decrease in world fossil fuels reserves draw attention toward production from trapped oil in the reservoirs. CEOR methods are proved and efficient methods which can be applied for increased oil recovery. In this research, the EOR potential of a novel nanocomposite and a developed surfactant was evaluated in the presence of various ions and the production enhancement mechanisms were studied using glass micromodel. Primary, the synergistic effect of the nanocomposite and the natural surfactant on Interfacial tension (IFT) reduction and wettability alteration was studied. After quantitative analysis and investigation of the various mechanisms, it was understood that the presence of the nanocomposite in the surfactant solution alters the wettability of an oil-wet carbonate surface to a water-wet one. Adding nano-composite to surfactant solution can improve the wettability alteration ability of the surfactant up to 60.02%. The adsorption tests revealed that combining the nanocomposite with surfactant solution can reduce surfactant adsorption by 18.99 %. The Zeta potential test was utilized to evaluate the stability of the solution. The zeta potential of the nano/surfactant solution was equal to −28 which illustrated a stable solution. In addition, the zeta potential measurements demonstrated the wettability alteration mechanism. After investigating the properties of the nano-surfactant solutions in the presence of different ions, optimum concentrations were determined and the mechanisms of the nano-chemical EOR method were visually investigated by injecting the desired solutions into the glass micromodel. Eventually, five different injection scenarios were designed for the core flood tests to evaluate the performance of each solution in the porous medium. The achieved final recovery for PELS, PELS/NaCl, and PELS/NaCl/NC solutions were 48.05%, 55.62%, and 60.38%, respectively and the Alternative injection scenario was the best injection plan.

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.

Effect of Methyl Orange on the Hydrogen Wettability of Sandstone Formation for Enhancing the Potential of Underground Hydrogen Storage

Hydrogen is expected to play a significant role as a clean energy carrier. However, the development of a hydrogen economy requires the use of large amounts of hydrogen; therefore, large-scale hydrogen storage is a considerable problem that needs to be resolved. Hydrogen can be stored underground in aquifers, salt caverns, depleted oil and gas reservoirs, and coal seams. In this context, wettability is a critical parameter in determining the containment security, storage capacity, fluid dynamics, and withdrawal rate during underground hydrogen geo-storage operations. Meanwhile, the toxic soluble dye, methyl orange (MO), is widely used in the textile and other industries and released in large quantities into the surface and subsurface waters. Hence, in the present study, the use of MO to alter the wettability of reservoirs in favor of hydrogen geo-storage is investigated. To this end, model oil-wet rock surfaces are prepared by aging quartz substrates with stearic acid and then treating them with various amounts of aqueous MO for 1 week at 50 °C. The brine contact angles on these model surfaces are then measured in a hydrogen environment under various reservoir conditions to demonstrate that the MO treatment makes the surface more hydrophilic. Moreover, the contact angle is seen to increase significantly with the increase in the temperature, pressure, and salinity. In addition, the importance of pH is assessed, and various brines (NaCl, KCl, MgCl2, and CaCl2) are compared. The proposed treatment is expected to improve the hydrogen trapping efficiency of sandstone reservoirs while simultaneously providing a safe disposal route for MO via deep well injection.

Evaluation of oil displacement potential of genetically engineered strain WJPAB fermentation broth

Rhamnoolipids are the most widely studied and used biosurfactants, which can be used in microbial flooding to enhance oil recovery. Pseudomonas aeruginosa is the main species of rhamnoolipids synthesized at present. In this study, wild strain WJ was modified by directional genetic engineering, and the strong promoter PoprL was used to replace the original promoter of rhlAB gene, and the genetically engineered strain with increased copy number of Popr-Rhlab gene was constructed, which was named as the genetically engineered strain WJPAB. The optimal carbon source of WJPAB was rapeseed oil. Under the optimal fermentation conditions, the product yield of WJPAB was 57.83g/L, which was 91.17% higher than that of wild strain WJ.The metabolites of strain WJPAB are purified and analyzed by high performance liquid chromatography mass spectrometry (HPLC-MS). The products are confirmed to be rhamnose homologues, including 3 single rhamnose homologues and 5 double rhamnose homologues. The physical and chemical properties of the metabolites of strain WJPAB were studied, and it was found that the metabolites of strain WJPaB had good surface/interfacial activity, which could reduce the surface tension of water to 27.34 mN/m, and change the surface of oil-wet core from oil-wet surface to water-wet surface. The emulsification index of simulated oil, cetane and liquid paraffin is above 60%. In addition, bacterial metabolites have good stability and can maintain good surface activity even at pH 3–11, salinity 0–20g/L and temperature 120 °C, and can adapt to a wide range of reservoir environmental conditions. In the oil displacement experiment, a compound oil displacement system is established by combining fermentation broth and xanthan gum. The compound system can increase the recovery rate by 15.45%, save the separation and purification process of biosurfactant, and reduce the application cost. The results show that Pseudomonas aeruginosa WJPAB has a good application prospect in the microbial oil recovery field.

Effect of oil carboxylate hydrophobicity on calcite wettability and its reversal by cationic surfactants: An experimental and molecular dynamics simulation investigation

The oil-wet state of carbonate reservoirs presents a serious challenge for oil recovery. While cationic surfactants are able to reverse the wettability, their efficiency depends on the oil composition, particularly on the carboxylates as the main surface-active compounds. In this study, calcite surface was aged by two distinct carboxylates: a shorter, less hydrophobic octanoate and a more hydrophobic stearate. The surface wettability and its reversal by a quaternary ammonium cationic surfactant were studied both experimentally by contact angle measurements and Scanning Electron Microscopy (SEM) imaging, and by molecular dynamics (MD) simulations. Both simulations and experiments show that aging with the more hydrophobic stearates yields more strongly oil-wet surfaces, whose wettability is more difficult to reverse by the cationic surfactant, than aging with octanoates. While the surfactant ultimately reverses the wettability in both cases, significantly higher surfactant concentration is required for the stearate-aged calcite. The difference in the wettability can be rationalized by the greater hydrophobicity of the stearate, which strengthens both the surface adsorption and attraction of the non-polar oil phase.

Residual Trapping of CO2 and Enhanced Oil Recovery in Oil-Wet Sandstone Core – A Three-Phase Pore-Scale Analysis Using NMR

HypothesisCombining Carbon Geo-sequestration (CGS) with Enhanced Oil Recovery (EOR) in three-phase flow oil reservoirs is an effective and economically attractive technology to mitigate global warming caused by emission of anthropologic CO2 from fossil fuel combustion, as it offsets some of the costs of CO2 extraction. The targeted oil reservoirs display oil-wet characteristics, primarily because of the strong affinity of polar molecules present in oil; a mixture of a large number of chemical compounds to the rock's surface; and oil-wet surfaces that drastically reduce storage capacity of geological trapping mechanisms and increase the vertical migration of CO2. Thus, it is essential to characterise the effect of wettability of rock on pore-scale physics in a pore network that dominate three-phase flow, which in turn control overall reservoir‐scale fluid dynamics and; thus, determine residual CO2 trapping and the success of CO2‐EOR projects. ExperimentalTo fully examine this, we present the first in situ NMR T1-T2 2D images and transverse relaxation time (T2) to quantify residual CO2 (capillary) trapping for an oil-wet core at reservoir conditions, representative of virgin oil reservoirs at around 1000-meter depth. We also systematically measure how much additional oil can be produced, where we compared the results with measurements performed on an analogous water-wet core. ResultsThe results show a significant residual CO2 saturation (12%) can be stored, which is similar to the values found in analogue two-phase flow for oil-wet sandstone samples, although some details are different and displacements are significantly complex, and a substantial amount of oil (51%) was recovered. In contrast, results of similar tests conducted on an identical analogous water-wet core show a higher CO2 trapping (20%), where oil production was substantially higher (77%). We have also presented the oil displacement efficiency (η) versus CO2 injection (PV), showing the percentage oil displacement efficiency of water-wet (0.6%) to be significantly higher than that of analogue oil-wet core (0.4%). Interpretation of the findingThese results significantly improve geo-storage integrity; i.e. capacities and containment security, over reservoir-scale implementations, in addition to having a substantial impact on outlining CO2-EOR projects in term of budgets and storage capacities for CO2-EOR and CO2 geo-sequestration.