Water-wet Conditions Research Articles

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.

Study on interfacial tension, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery

Over 50% of the original oil in place (OOIP) is immobile or trapped in the reservoir. Therefore, today, more efficient methods have been introduced in the tertiary oil recovery sector as a scheme of enhanced oil recovery (EOR). Due to the decline of conventional hydrocarbon reserves, polymers are increasingly used in EOR methods, such as surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding. SP flooding has a complex formulation and design, leading to undesirable phase separation if improperly mixed. Polymeric surfactants are a promising alternative to SP flooding. They consist of hydrophobic groups attached to hydrophilic polymers, which help to improve the mobility ratio and reduce interfacial tension (IFT). This paper examines the rheological and synthesis properties of a new polymeric surfactant produced through bond co-polymerization reaction using different hydrolyzed polyacrylamide (HPAM) ratios and a zwitterion hydrophobic group. The synthesized hydrophobically modified zwitterionic polyacrylamide (HMZPAM) was characterized by FTIR and HMNR analysis. HMZPAM performed better than other substances in IFT, viscosity, wettability, oil recovery, and resistance to different one and two-valence cations. The results indicate that HPAM reduced the IFT to 13.65, while HMZPAM reduced it to 0.441 mN/m. Wettability change evaluated on a rock carbonate/crude oil/HMZPAM system that changed the water-wet state of the primary oil-wet rock carbonate to strongly water-wet state as wettability change measurements showed a decrease in contact angle from 62.76 to 21.23 degree. Comparative studies on the effectiveness of HPAM and HMZPAM were also conducted according to the measurement of viscosity and shear rate in the presence of salt, which indicates the higher shear rate and viscosity of HMZPAM. Core flooding tests revealed that HMZPAM resulted in better additional recovery due to microscopic displacement, resulting in a total oil recovery of 84%, compared to 48% of residual oil saturation for HPAM. Also, salts decreased oil recovery in HPAM injection but increased oil recovery in HMZPAM injection.

Choline chloride-Urea based deep eutectic Solvent: Characterization, interfacial behavior and Synergism in binary (surfactant) systems

The paper focusses on the synthesis and characterization of choline chloride: urea (molar ratio 1:2) DES. The influence of the varying DES concentration on the surface and interfacial behavior of low-concentration commercial surfactant (cetyl trimethyl ammonium bromide) was examined. The incorporation of DES into the surfactant solution resulted in an augmentation of electrophoretic mobility and absolute zeta potential values, indicative of enhanced surfactant adsorption at the interface. Sessile drop measurements demonstrated the capacity of binary mixture to modify the wettability of sandstone from intermediate-wet state to water-wet condition. In summary, physicochemical evaluation revealed the capability of DES to augment the self-assembly and wetting behavior of surfactant at low concentrations (below critical micelle concentration). The observed phenomenon in these solvents primarily finds utility in nanoscience, drug delivery systems, colloids, catalysis, and applications in many other fields.

Impact of Wettability on CO2 Dynamic Dissolution in Three-Dimensional Porous Media: Pore-Scale Simulation Using the Lattice Boltzmann Method.

Understanding the dissolution behavior of supercritical CO2 (scCO2) in porous media is crucial for efficient CO2 storage. However, the precise modeling of dynamic dissolution behavior at this pore scale remains a huge challenge, and the impact of wettability on this process still needs to be clarified. In this study, the influence of rock wettability on CO2 dynamic dissolution in the three-dimensional porous media is investigated using the lattice Boltzmann method (LBM). The LBM is coupled with scCO2-water two-phase flow, solute transport, and heterogeneous and homogeneous reactions. The size, number, and dissolution pattern of scCO2 bubbles during the dissolution process are observed under strongly water-wet, weakly water-wet, intermediate-wet, and mixed-wet conditions. The CO2(aq) concentration and pH are investigated, followed by a quantitative investigation of the impact of wettability on the specific interface area and the mass transfer coefficient. An empirical relationship between the specific interface area and scCO2 saturation is established. The findings reveal that under weakly water-wet and intermediate-wet conditions, the sizes of scCO2 clusters and monomers are small and mostly distributed at the dead end of the pores. In contrast, under strongly water-wet and mixed-wet conditions, the clusters are larger and interconnected, and distributed in the center of the pore. This results in a greater scCO2-water interface area, consequently enhancing the dissolution rate. Furthermore, a strong linear correlation is observed between scCO2 saturation and specific interface area. It is noted that as the hydrophilicity of the rock increases, the mass transfer coefficient initially rises and then declines.

Locally Synthesized Zwitterionic Surfactants as EOR Chemicals in Sandstone and Carbonate.

Zwitterionic surfactants are found to be highly effective in reducing the IFT and changing the wettability. This work studied the solubility and wettability alteration performance of locally synthesized zwitterionic surfactants in Berea sandstone and Indiana limestone. Contact angle measurements were conducted to study the wettability under different conditions. SEM images and TGA results were combined to reflect on the wettability alteration mechanism. The zeta potential test was adopted to study the surface charge of the Indian limestone powder. Results showed that five of the six surfactants dissolved in deionized water to form 1.0 wt % solution, indicating efficient solubility for EOR purposes. Although its wettability alteration performance on oil-aged Berea sandstone is weak to moderate, the performance of ZW6 on Indiana limestone is excellent. ZW6 can change the strongly oil-wet (162°) rock back to water-wet (62.9°) conditions. Increasing its concentration from 0.01 to 0.5 wt % continuously enhanced the performance. The addition of NaCl to 150000 ppm did not affect the wettability alteration. However, the addition of CaCl2 largely suppressed the wettability alteration, while Na2SO4 and MgCl2 both enhanced the performance. With the same headgroup, a more hydrophobic tail group impairs the wettability alteration. The quite different wettability alteration performance of MgCl2 and CaCl2 cases (which had approximately the same amount of calcite dissolution), and the comparable wettability alteration performance of Na2SO4 and MgCl2 (which had very different calcite dissolution amounts) indicate that calcite dissolution is unrelated to wettability alteration.

Enhancing Oil Recovery in Eagle Ford Shale: A Multiscale Simulation Study of Surfactant Huff ’n’ Puff Methodology

In this paper, we present a simulation case study of a surfactant huff ’n’ puff pilot in the black oil window of the Eagle Ford (EF) Shale. The target horizontal well, which had been depleted for nearly 8 years, underwent stimulation via a surfactant huff ’n’ puff treatment. The surfactant was selected through laboratory screening using reservoir rock and fluid samples. After a 17-hour injection and a 1-month shut-in period, the well’s production increased fivefold from the baseline oil rate, sustaining incremental oil production for at least 2 years. The surfactant enhances oil recovery by altering rock wettability toward a more water-wet state and moderating oil/water interfacial tension (IFT). This process is modeled by surfactant adsorption in the simulator, indicating the degree of dynamic changes in relative permeability (krl) and capillary pressure (Pc) curves. We propose a comprehensive workflow comprising three stages: development of core-scale and field-scale models, sequential model calibrations, and multiobjective optimization to integrate laboratory measurements and field data from this pilot into multiscale numerical simulations. By matching oil recoveries from imbibition experiments on the core model and field production histories on the field model, krl and Pc profiles of two extreme states, basic reservoir properties, and additional reservoir properties altered during huff ’n’ puff operations are characterized. The matched core model reproduces a 15.1% incremental oil recovery for surfactant-assisted spontaneous imbibition (SASI) process relative to pure brine imbibition process. The matched reservoir model predicts the surfactant huff ’n’ puff treatment increases the oil production by 21.9% relative to water huff ’n’ puff treatment and by 52.9% relative to primary depletion for a 4-year period. The calibrated reservoir model also serves as a base case for optimizing well operation schedules through the implementation of a multiobjective genetic algorithm. The surfactant injection rate, injection time, and well shut-in time of the base case are varied to achieve higher oil production and reduced surfactant usage. Statistical analysis of eight trade-off cases indicates that optimal well operations, compared with existing practices, frequently involve increased injection rates [16.6–18.9 barrels per minute (bpm)], shorter injection periods (10–11.3 hours), and prolonged shut-indurations (49–65 days). This workflow offers valuable insights into surfactant huff ’n’ puff treatments for unconventional reservoirs, thereby facilitating the optimization of well operations and maximizing tertiary oil recovery.

Secondary utilization of self-suspending proppant's coating polymer: Enhance oil recovery

Fracturing is associated with significant economic costs, and the loss of the utility of the self-suspending proppants' coating polymer after fracturing appears highly wasteful. To enhance the utilization of the self-suspending proppant's coating polymer, we propose a novel concept: the secondary utilization of coating polymer, enabling the coating polymer to gel-breaking within the reservoir and generate surface-active substances, thereby enhancing the oil recovery efficiency. To realize this concept, this study designed and synthesized a hydrophobic associative polymer, which was combined with ceramic proppant to form self-suspending proppant. Using the surface-active monomer octadecyl dimethyl allyl ammonium chloride (DMDAAC-18), acrylamide (AM), acrylic acid (AA), and 2-acrylamido-2-methylpropane sulfonic acid (AMPS) via aqueous free-radical copolymerization synthesized the PAAAD (Polymer (AM/AA/AMPS/DMDAAC-18)). PAAAD has demonstrated excellent thickening properties, with a viscosity of 240.01 mPa s at a concentration of 6 g/L in shear rate 170s−1. Its solution exhibits high viscoelasticity, and a loss factor (tan δ) < 1 over the frequency range of 0–20 Hz at a shear stress of 0.56 Pa indicates that it behaves like a viscoelastic solid with gel-like characteristics, which is beneficial for proppant suspension. The gel-breaking solution of PAAAD reduced surface tension (29.33 mN/m at a PAAAD concentration of 6 g/L), converted oil-wet rocks to water-wet conditions (reducing the contact angle of oil-wet shale to 46.7° and of oil-wet sandstone to 19.9°), and enhanced shale imbibition oil recovery efficiency in 16.5%. The basic properties of self-suspending proppants meet the Chinese Petroleum Industry Standard SY/T 5108-2014 and exhibit good suspension properties, with sedimentation of 1.7 mm in 40 min at a sand ratio of 15%. This study is the first to propose the secondary utilization of the self-suspending proppant's coating polymer, significantly enhancing their utilization value.

Enhanced oil recovery and mitigating challenges in sandstone oil reservoirs employing EDTA chelating agent/ seawater flooding

While low salinity water (LSW) holds promise for improving oil recovery, its implementation is comparatively costly due to the substantial volumes of fresh water required to dilute seawater (SW). Additionally, concerns arise regarding potential issues related to LSW, including fines migration in sandstone reservoirs and scale formation in carbonate reservoirs. Chelating agents can be introduced into undiluted SW to bind with metal ions, thereby lowering its salinity. This approach mimics the behavior of LSW injection while overcoming associated challenges. This study involves measuring oil/injected solution interfacial tension (IFT), evaluating sandstone surface wettability alteration, along with conducting different sand pack flooding scenarios using Ethylenediaminetetraacetic acid (EDTA) chelating agent. The aim was to comprehend the EDTA oil recovery mechanisms and determine the optimal concentration of EDTA that minimizes chemical consumption while maximizing oil recovery. The findings indicated that incorporating 5 wt% EDTA into SW significantly reduced IFT from 29.52 mN/m to 4.75 mN/m, making the oil nearly miscible in the solution. Moreover, wettability tests confirmed that a minimum EDTA concentration of 5 wt% is required to shift wettability from oil-wet to strongly water-wet conditions. Sand pack flooding experiments, on the other hand, further demonstrated that this optimized fluid system can potentially recover an additional 16.1 % of oil following SW flooding. Finally, inductively coupled plasma (ICP) analysis revealed a notable increase in metal ion concentration during EDTA flooding, indicating enhanced leaching of metals from the sandstone surface and improved wettability characteristics.

Interfacial tension and contact angle of asphaltenic and resinous model oil in the presence of binary salts mixtures

Using smart or low salinity waters known as green processes gained increasing attention due to their unique features and their positive impacts on the environment. In light of this fact and since there is limited knowledge about the effects of salts under engineered concentrations or binary mixtures and crude oil fractions on the interfacial tension (IFT) reduction and wettability alteration of the resinous (RSO) and asphaltenic synthetic oil (ASO), the current investigation is designed and performed for the first time. Moreover, the dynamic behavior of the IFT variation was carefully investigated and the relaxation time was obtained and modeled to see the impact of mono and divalent salts individually and in binary conditions. The relaxation times revealed that the lowest adsorption times were obtained for NaCl/CaCl2 brine regardless of the examined oil types of ASO and RSO due to the high movement affinity of the polar functional groups toward the interface consequently reducing the required time for coverage and packing of active agents at the interface. Finally, the measured contact angle values revealed a significant effect of binary salts on the wettability alteration toward strongly water-wet conditions, especially for the RSO and ASO compared with crude oil.

Lattice Boltzmann simulation of counter-current imbibition of oil and water in porous media at the equivalent capillarity

The characterization of oil and water displacement in porous media often relies on the capillary number (Ca = μv/σ cos θ). However, limited investigations have been conducted to explore the relative significance of interfacial tension and wettability in determining oil recovery, particularly under the imbibition mode. To address this research gap, the modified color gradient lattice Boltzmann method has been employed. This study aims to systematically investigate the transient imbibition characteristics, pore-scale events, and morphological features of the two-phase distribution in the matrix, all under the same capillarity but varying capillary numbers. The obtained results indicate that, for a given capillary number, a more water–wet condition generally leads to a higher imbibition recovery. Conversely, the influence of capillary number on oil recovery is complex and contingent upon the capillarity value, i.e., the interfacial tension between oil and water. Additionally, the oil recovery data from all cases have been effectively fitted using the Minkowski functionals, demonstrating a linear correlation. Moreover, an attempt has been made to elucidate the mechanism behind the varying oil recovery observed in different capillarity combinations. This analysis considers factors such as energy conversion, the transient change of the ratio of viscous force over capillarity, and the capillary valve effect. The findings of this study contribute to our understanding of the use of chemical agents to enhance oil recovery and provide valuable insights for determining key two-phase parameters in reservoir simulations.

Synthesis of amphiphilic silicon quantum dots and its application in high efficiency imbibition oil recovery in low permeability reservoirs

In this work, a novel three-step method was used to modify the surface of silicon quantum dots to synthesize amphiphilic silicon quantum dots (A-SiQDs) with higher interfacial activity. The particle size of A-SiQDs was only 3.5 nm. By adding a small amount of dodecyl dimethyl betaine (BS-12), the performance of A-SiQDs was further improved. Through particle size and zeta potential testing, it can be seen that the mixed system of A-SiQDs and BS-12 had good temperature and salinity resistance, and can be stable at 120 °C and 50,000 mg/L NaCl. Meanwhile, the mixed system exhibited superior interfacial activity compared with individual A-SiQDs and BS-12. The mixed system can lower the interfacial tension from 32.15 mN/m to 1.82 mN/m and transform the rock surface from an oil-wet to a strong water-wet state. This ensured the excellent imbibition ability of the mixed system, which can increase the oil recovery to 35.7 %. Finally, from the perspective of force, the influence of nanofluids on oil stripping and migration was analyzed to reveal the imbibition mechanism. This paper proposes a facile three-step method for synthesizing A-SiQDs, and also provides a novel nanomaterial for high efficiency imbibition in low-permeability reservoirs.

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.

Surface charge change in carbonates during low-salinity imbibition

Optimizing the injection water salinity could present a cost-effective strategy for improving oil recovery. Although the literature generally acknowledges that low-salinity improves oil recovery in laboratory-scale experiments, the physical mechanisms behind it are controversial. While most experimental low-salinity studies focus on brine composition, this study investigated the influence of carbonate rock material on surface charge change, wettability alteration, and spontaneous imbibition behavior. Zeta potential measurements showed that each tested carbonate rock material exhibits characteristic surface charge responses when exposed to Formation-water, Seawater, and Diluted-seawater. Moreover, the surface charge change sensitivity to calcium, magnesium, and sulfate ions varied for the tested carbonate materials. Spontaneous imbibition tests led to high oil recovery and, thus, wettability alteration towards water-wet conditions if the carbonate-imbibing brine system’s surface charge decreased compared to the initial zeta potential of the carbonate Formation-water system. In the numerical part of the presented study, we find that it is essential to account for the location of the shear plane and thus distinguish between the numerically computed surface charge and experimentally determined zeta potential. The resulting model numerically reproduced the experimentally measured calcium, magnesium, and sulfate ion impacts on zeta potential. The spontaneous imbibition tests were history-matched by linking surface charge change to capillary pressure alteration. As the numerical simulation of the laboratory-scale spontaneous imbibition tests is governed by molecular diffusion (with a time scale of weeks), we conclude that molecular diffusion-driven field scale wettability alteration requires several hundred years.

Experimental investigation and machine learning modeling of diethylenetriaminepentaacetic acid agents in sandstone rock wettability alteration: Implications for enhanced oil recovery processes

Chelating agents have garnered increasing attention due to their unique capabilities in addressing challenges associated with chemical enhanced oil recovery (CEOR) materials. This research investigates the transformative potential of diethylenetriaminepentaacetic acid (DTPA) chelating agent in altering sandstone rock wettability. Wettability and zeta potential measurements were used to assess the impact of crucial factors including DTPA concentration, salinity, and potential determining ions (PDIs) on contact angle and rock surface charges. The findings revealed that there is an optimal level for DTPA concentration and salinity that can shift rock wettability from an oil-wet to strongly water-wet state. Moreover, while PDIs in their natural concentrations had no significant impact on DTPA performance, a threefold increase in their concentration was found to adversely affect DTPA efficacy. After conducting rock wettability tests, two advanced machine learning (ML) techniques, namely Random Forest (RF) and Boosted Regression Tree (BRT), were employed to assess rock/oil contact angle based on the aforementioned factors. Data were collected from 240 experimental datasets of contact angles. The findings indicated that both models performed well, but BRT exhibited exceptional performance. Sensitivity analysis, conducted using the Jackknife method, revealed the order of importance for parameters affecting wettability as follows: PDIs > salinity > time > DTPA concentration.

The reversal of carbonate wettability via alumina nanofluids: Implications for hydrogen geological storage

Underground hydrogen storage (UHS) has been recognized as a key enabler of the industrial-scale implementation of a hydrogen-based economy. However, the efficiency and storage capacity of hydrogen (H2) in carbonate aquifers can be influenced by the presence of organic acids. Nevertheless, the existing literature contains few investigations of H2/calcite/brine wettability and the influence of organic acids on H2 storability in carbonate reservoirs. Therefore, the present study examines the influence of stearic acid on the dynamic H2/brine wettability of calcite substrates (as a proxy of carbonate formation) under various geological conditions (0.1–20 MPa at 323 K), equilibrated in 10 wt% NaCl brine. In addition, the application of various alumina nanofluid concentrations (0.05, 0.1, 0.25, and 0.75 wt%) is evaluated under the same experimental conditions for enhancing the organic-aged calcite wettability. The results demonstrate a significant impact of stearic acid on the dynamic (advancing and receding) contact angles of the calcite substrates, thereby resulting in a shift from intermediate water-wet to H2-wet conditions, representing an unfavorable state for H2 geological storage. Conversely, the application of alumina nanofluid on the organic-aged calcite substrate enhances the H2/brine/calcite wettability towards an intermediate water-wet state, which is more favorable for H2 residual trapping in carbonate formations. The optimal concentration of alumina nanofluid for the wettability modification of the organically aged calcite samples is found to be 0.25 wt%. These findings highlight the influence of organic acid contamination and the potential of alumina nanofluid application in enhancing H2 geo-storage conditions in carbonate reservoirs.

Exploring in-situ combustion effects on reservoir properties of heavy oil carbonate reservoir

Laboratory modeling of in-situ combustion is crucial for understanding the potential success of field trials in thermal enhanced oil recovery (EOR) and is a vital precursor to scaling the technology for field applications. The high combustion temperatures, reaching up to 480 °C, induce significant petrophysical alterations of the rock, an often overlooked aspect in thermal EOR projects. Quantifying these changes is essential for potentially repurposing thermally treated, depleted reservoirs for CO2 storage.In this study, we depart from conventional combustion experiments that use crushed core, opting instead to analyze the thermal effects on reservoir properties of carbonate rocks using consolidated samples. This technique maintains the intrinsic porosity and permeability, revealing combustion's impact on porosity and mineralogical alterations, with a comparative analysis of these properties pre- and post-combustion. We characterize porosity and pore geometry evolution using low-field nuclear magnetic resonance, X-ray micro-computed tomography, and low-temperature nitrogen adsorption. Mineral composition of the rock and grain-pore scale alterations are analyzed by scanning electron microscopy and X-ray diffraction.The analysis shows a significant increase in carbonate rocks’ porosity, pore size and mineral alterations, and a transition from mixed-wet to a strongly water-wet state. Total porosity of rock samples increased in average for 15%–20%, and formation of new pores is registered at the scale of 1–30 μm size. High-temperature exposure results in the calcite and dolomite decomposition, calcite dissolution and formation of new minerals—anhydrite and fluorite. Increased microporosity and the shift to strongly water-wet rock state improve the prospects for capillary and residual CO2 trapping with greater capacity. Consequently, these findings highlight the importance of laboratory in-situ combustion modeling on consolidated rock over tests that use crushed core, and indicate that depleted combustion stimulated reservoirs may prove to be viable candidates for CO2 storage.

Experimental and Molecular Dynamics Simulation to Investigate Oil Adsorption and Detachment from Sandstone/Quartz Surface by Low-Salinity Surfactant Brines.

In this study, we explore the impact of monovalent (NaCl) and divalent (CaCl2) brines, coupled with sodium dodecyl sulfate (SDS) surfactant at varying low concentrations, on the detachment and displacement of oil from sandstone rock surfaces. Employing the sessile drop method and molecular dynamics simulations, we scrutinize the behavior of the brine solutions. Our findings reveal that both low salinity and low-salinity surfactant solutions induce a gradual shift in rock wettability toward a more water-wet state. This wettability transformation is not instantaneous but evolves over time, as observed through meticulous molecular motion analyses. Through contact angle measurements and molecular dynamics simulations, we delve into the molecular motion at subpore and micropore scales on sandstone/quartz surfaces. The adsorption of surface-active agents from the oil to the oil-brine interface results in a reduced interfacial tension, significantly contributing to oil displacement. Notably, low salinity concentrations ranging from 1000 to 10,000 ppm exhibit the lowest contact angles within 30 min across all solutions. However, higher concentrations deviate from this declining trend, especially with divalent ions like Ca2+, which bridge polar molecules onto the rock surface, resulting in an increased oil-wetting state. This research unveils the intricate molecular motions involved in employing low-salinity surfactant solutions for oil detachment from surfaces. Furthermore, it provides valuable insights into the underlying forces driving oil detachment and wettability alteration.

Pore scale investigation of chelating agents flooding for enhanced oil recovery

Recently, laboratory tests have shown a positive response to chelating agent brines in sandstone and carbonate reservoirs as a new enhanced oil recovery technique. There is little research on direct and visual evidence of underlying mechanisms behind the chelating agent effects. In this study, a microfluidic method was established using glass micromodel to investigate the micro-mechanisms of displacement under ethylenediaminetetraacetic acid (EDTA) and diethylenetriaminepentaacetic acid (DTPA) chelating agent at the pore-scale level. Furthermore, for the study of fluid/fluid interactions, EDTA brine and DTPA brine were brought into contact with two different crude oils to examine the possible compositional changes. For this purpose, sample tests, Fourier Transform Infrared Spectroscopy (FTIR), microscopic image analysis, and dynamic interfacial tension (IFT) measurements were conducted. The FTIR data showed EDTA brine and DTPA brine induced changes in the oil sample composition compared to seawater, which can be related to the formation of water-in-oil micro-dispersions. Microscopic image analysis on samples confirmed the formation of these micro-dispersions. The visual study by the micromodel demonstrated the micro-dispersion formation in the tertiary injection of EDTA and DTPA brine. Based on the observation made, the pore-scale mechanisms of chelating agent flooding involve the chelating agent brine penetrating the crude oil, resulting in micro-dispersion formation. These micro-dispersions tend to alter wettability to a more water-wet state, facilitate oil detachment from the surface, redistribution of oil saturation, and thus leading to improved oil recovery. The observed IFT reduction aids the penetration of EDTA and DTPA brine into the crude oil to form micro-dispersions.

The effect of methylene blue on stearic acid-aged quartz/CO2/brine wettability: Implications for CO2 geo-storage

Carbon dioxide sequestration in geological formations has been proposed as a promising solution to reach net zero carbon emissions but the success of underground CO2 storage in sandstone formations depends on the brine/CO2 wettability of sandstone. Research evidence showed that natural geological formation is hydrophobic even in the presence of minute concentration of inherent organic acids. This study investigates the effect of methylene blue (MB) on CO2 wettability of organic-acid contaminated quartz through the tilted plate contact angle measurement method. Pure quartz substrates were aged in a stearic acid/n-decane solution for one week and subsequently modified with different concentrations of MB (ranging from 10 to 100 mg/L) at a temperature of 60 °C. Advancing (θa) and receding (θr) contact angles were measured under varying conditions of temperature (25 °C and 50 °C), pressure (ranging from 10 to 20 MPa), and salinity (0–0.3 M). The experimental results indicate that pure quartz, when aged in a stearic acid solution, becomes CO2-wet at all temperature, pressure, and salinity conditions. However, at any physio-thermal condition, the wettability of the quartz surfaces was reversed when treated with different concentrations of MB, transitioning to a water-wet state. The findings of this research demonstrate the potential of MB to modify the wetting behaviour of quartz surfaces and enhance CO2 residual trapping in sandstone formations.

INTERFACIAL TENSION AND CONTACT ANGLE TESTS OF RHAMNOLIPIDS AND SOPHOROLIPIDS IN SANDSTONE FOR ENHANCED OIL RECOVERY

In the context of the development of enhanced oil recovery technology, biotechnology can be used to develop new methods that are more environmentally friendly and sustainable, one of which is the use of biosurfactants. Rhamnolipids and sophorolipids are non-toxic biosurfactants, biodegradable, and environmentally favorable substances. This study compares the results of laboratory studies on fluid-to-fluid interactions, including the interfacial tension and rock wetness tests at various concentrations and salinities, which represent high salinity, medium salinity, and low salinity. The mechanism of these two biosurfactants is based on reducing the interfacial tension (IFT) between the fluids and changing the wettability of the rock to a more water-wet state. In the interfacial tension test, the reduction in the interfacial tension of rhamnolipids reached 10-2 mN/m, while that of sophorolipids only reached 10-1 mN/m. Then, the sandstone wettability test showed that the two biosurfactants were classified as water-wet (&lt;75°). This happens because of its chemical structure, which has two parts: the hydrophobic part and the hydrophilic part. Within the salinity range of 8,000-32,000 ppm, the rhamnolipids work better in the higher salinity to reduce interfacial tension, and the salinity has a subtle effect on the contact angle. On the other hand, sophorolipids were not affected by salinity for both interfacial tension and contact angle. These two biosurfactants have the potential to increase oil recovery in sandstone so that they can contribute to environmentally friendly biotechnology.