Wettability Of Carbonate Rocks Research Articles

Effects of Sulfate Ions on Crude Oil Adsorption/Desorption on Carbonate Rocks: Experimental and Molecular Simulations.

In the background of the strong oil wettability and low production by water flooding in carbonate reservoirs, low-salinity water containing sulfate ions can significantly change the surface wettability of carbonate rocks and thus increase the sweeping area; however, the absorption and desorption mechanisms of the oil film in the carbonate rock surface remain unclear. This paper analyzed the wettability alternation of carbonate rocks' surface in pure water and sodium sulfate solution. At the same time, MD (Materials Studio) software was used to simulate the formation process of the oil film and the effect of sulfate ions on the desorption of the oil film on the surface of carbonate rocks. The experimental results showed that sodium sulfate solution could accelerate the rate from oil-wet to water-wet and the final contact angle (49°) was smaller than that in pure water. The simulation results showed that dodecane molecules moved to the surface of calcite to form a double layer of the oil film and that the oil film near the calcite surface had a high-density stable structure under the van der Waals and electrostatic action. The hydrating sulfate ions above the oil film broke through the double oil film to form a water channel mainly under the action of electrostatic force and a hydrogen bond and then adsorbed on the calcite surface. A large number of water molecules moved down the water channel based on a strong hydrogen bonding force and crowded out the oil molecules on the surface of the calcite, resulting in the oil film detachment. This work aims to explain the interaction of oil molecules, water molecules, and SO42- ions at the molecular scale and guide the practical application of low-salinity water flooding in carbonate reservoirs.

Influence of pH On The Wettability of Carbonate Rocks for Carbon Dioxide Sequestration in Deep Saline Aquifer

The escalating carbon dioxide (CO2) emissions have precipitated climate change, underscoring the urgent need for innovative solutions. Carbon Capture and Storage (CCS) represents a groundbreaking technology to mitigate carbon emissions by capturing CO2 and depositing it deep within reservoirs. This study focuses on the storage aspect of CCS by scrutinising reservoir properties. A pivotal factor influencing the geological storage of CO2 is the wettability of the CO2 /rock/brine system, which is intricately linked to the contact angle. However, previous research has indicated that pH can significantly influence the wettability of this system. Acetic acid, a prevalent organic acid in the petroleum industry, is commonly encountered and serves as a means to modulate pH. This experiment investigates pH variations, ranging from 3 to 7, through the introduction of acetic acid, while maintaining a salinity level of 30,000 ppm. Additionally, the type of rock mineral plays a crucial role in these findings. Therefore, this paper emphasises carbonate rocks, with a particular focus on limestone composed primarily of calcium carbonate (CaCO3). The experiment is conducted under elevated supercritical conditions, encompassing pressures of 10 MPa and 15 MPa, along with temperatures of 305 K and 323 K. Equilibrium contact angles are determined by measuring receding and advancing angles using the Vinci IFT 700 instrument under supercritical conditions. The results reveal a consistent trend wherein contact angles decrease as pH, temperature, and pressure increase, indicating a shift towards a water-wet system at higher pH, temperature, and pressure levels.Keywords: Carbon Capture and Storage (CCS), Wettability, Contact angle, pH, Acetic acid, Salinity, Carbonate rocks, Limestone, Supercritical conditions

Mechanism and synergic effect of smart water and amphoteric surfactant on oil recovery in carbonate rocks: Marangoni flow and changing disjoining pressure of water film

One way to increase oil production was to inject various water-based fluids to move oil into the reservoirs, which in some cases used surfactants to produce oil trapped in the water-based fluid, but later found that thess materials can change the wettability of the rock surface to the desired, so various mechanisms have been introduced for them. In this study, using CAPB, CTAB SDS and Triton X-100s surfactants, wettability tests (contact angle), interprocess tension, zeta potential between different procedures, video experiments for Marangoni flow and intrusive vampire tried to explain the primary production mechanism. They are dealt with different reactants. The results showed that the cationic surfactant CTAB, due to its positive ionic charge and the presence of electrostatic forces, approaches the fatty acid groups attached to the rock surface with a negative ionic charge and forms a complex of cationic-anionic ion pairs with them. General condition Compared to cationic surfactants, the performance of anionic surfactants on the change in wettability of carbonate rocks is inferior. This is due to the homonymous electric charge of the oil groups adhering to the rock surface and the anionic surfactants of SDS.

Performance evaluation of a novel multi-metal catalyst solution obtained from electronic waste bioleaching on upgrading and enhancing oil recovery

Due to the high costs and associated high CO2 emissions of thermal methods, this study focuses on upgrading heavy oil and enhancing oil recovery within reservoir temperature ranges. In this research, a novel, low-cost, and environmentally friendly multi-metal catalyst has been used, which is actually extracted from electronic waste (E-waste). At optimal conditions, which include 80 °C, 12 h of retention time, and 0.2 % v/v of the multi-metal catalyst, this catalyst effectively reduced the viscosity of heavy oil from 687 to 580 mPa.s. To analyze heavy oil before and after the process, Fourier transform infrared spectroscopy (FTIR) was conducted. FTIR spectra indicates that the multi-metal catalyst has reduced the amount of aromatic compounds, shortened hydrocarbon chains, and decreased double and triple bonds. Micromodel tests were conducted by multi-metal catalyst flooding at optimal temperature and retention time obtained from static experiments. Heavy oil recovery through multi-metal catalyst flooding reached 38 %, which is a 10.5 % increase compared to deionized water flooding. The contact angle of the rock was measured after contact with the multi-metal catalyst. The multi-metal catalyst reduced the contact angle by 55 °, changing the wettability of carbonate rock from oil-wet to water-wet. The absorption test indicates that the multi-metal catalyst dissolves certain metals in the rock, most likely due to the high pH of the catalyst. As a result, the permeability of the rock may increase due to the dissolution of the rock metals.

Experimental investigation of combined carbon nanoparticles (CNPs), ionic liquid (I.L), and low salinity water to enhance oil recovery (EOR) at Iraq's southern oil fields

By 2030, global energy demand is expected to increase by 50% with respect to 2020. However, supplies of natural gas and oil are steadily depleting. Therefore, implementing innovative enhanced oil recovery (EOR) technology in producing reservoirs is essential to meeting the growing energy demand.EOR is a technique that has currently been in use to increase the rate of oil production. This research demonstrates the novel opportunities of combining carbon nanoparticles, ionic liquid surfactant (dodecyl pyridinium chloride), and low-salinity water to improve oil recovery from carbonate reservoirs. A series of experimental works, comprising sedimentation technique, zeta potential analysis, contact angle measurements, and surface tension tests, were conducted to study the stability and choose the optimal nanofluid for application in EOR.It was discovered that by adding various concentrations of an ionic liquid to a 50 ppm nanocarbon solution, the density of the nanofluid formulations could be slightly reduced, the surface tension could be changed, and the wettability of carbonate rocks could be altered from an oil-wet to a water-wet system. Core-flooding tests were carried out for optimum nanofluid formulation (50 ppm of nanocarbon with 250 ppm of ionic liquid) at different flow rates. Additional oil recoveries of 8.46 % and 20.5 % of the original oil in place were achieved at flow rates of 0.667 cm3/min and 0.334 cm3/min, respectively. This study is one of the first to be conducted in Iraq's oil fields to investigate the potential for EOR using carbon nanoparticles, ionic liquid, and low-salinity water. The results of this research highlight the potential of hybrid nanofluids as a new type of injection fluid for EOR.

Mechanistic investigation of using low salinity alkaline surfactant solutions in carbonate reservoirs based on polarity of crude oil

The chemical enhanced oil recovery (CEOR) process is introduced as one of the most effective methods for reducing the residual oil saturation through oil reservoirs. Because the chemical phase has a great potential for altering the reservoir rock and fluids properties. The main purpose of this study is a combination of low saline water (LSW) with surfactant and alkaline-surfactant to achieve maximum oil recovery by the combination of different mechanisms. In this work, the fluid–fluid and rock-fluid interactions were investigated by conducting several experimental techniques for two varied crude oil samples. Due to the high polarity of resin and asphaltene molecules, these two crude oil samples were divided into low-polar and high-polar samples. The optimum diluted seawater was used as LSW for both crude oil samples at 3000 ppm total dissolved solids. Based on obtained results from the interfacial tension (IFT) measurement tests and dynamic contact angle, using NaOH with LSW and AOS at critical micelle concentration (CMC) has a greater influence on reducing the IFT and altering the carbonate rock wettability from oil-wet to water-wet condition compared to Na2CO3. Adding only 100 ppm NaOH to the LSW-AOS(CMC) solution, the IFT values between an alkali-surfactant solution with low-polar and high polar crude samples were decreased from 0.43 and 1.33 mN/m to 0.21 and 0.55 mN/m, respectively. Moreover, the pH of LSW-AOS solution rises with the addition of NaOH to the solution and the surface charge moves toward a more negative charge based on the zeta potential results. This phenomenon increases the repulsion between surface charge and negatively charged polar components and, consequently desorption of polar components from the rock surface get improved. Furthermore, some in-situ surfactant (soap) generates by a reaction between NaOH and carboxylic acids and the creation of an ion pair between surfactants (AOS and Soap) and adsorbed polar groups which lead to the creation of a hybrid mechanism between LSW, AOS, and NaOH for changing the wettability from oil-wetness toward water-wetness. Therefore, the maximum oil recovery was achieved by flooding with LSW- AOS(1000 ppm)-NaOH (100 ppm) solution for both crude oil samples, high polar and low polar cured oil samples, that obtain 42.24 % and 71.67% recovery factors, respectively. Moreover, coreflooding results confirmed the micromodel results in the presence of initial water saturation at high temperature condition.

Micro-scale wettability of carbonate rocks via high-resolution ESEM imaging

The wettability of several materials has been traditionally quantified using macro-scale contact angles. However, precise identification of the three-phase contact (TPC) line is often difficult due to the resolution limit of macro-scale setups. Moreover, micro-level surface chemical heterogeneities can have a notable impact on the predicted wetting behavior which limits macro-scale contact angles. Thus, here, we investigate the micro-scale water wettability of condensed micro-droplets on carbonate rock surfaces via a high-resolution Environmental Scanning Electron Microscopy (ESEM). Macro- and micro-scale contact angles were evaluated under three conditions: 1) natural carbonate surfaces, 2) surfaces aged in crude oil, and 3) surfaces aged in cationic surfactant to allow for a broader insight of the impact of rock composition and surface morphology on wettability.At the macro-scale, carbonate rocks were preferentially oil-wet to intermediate-wet. However, a profound variability was observed in wetting behavior at the micro-scale where a weakly water-wet state (50° ≥ θ ≥ 80°) was prevalent with evidence of minor oil-wet patches too. At the micro-scale, for the 100% dolomite sample, the contact angle (θ) varied from ∼66° to 76° under natural conditions, while the same sample aged in crude oil depicted a remarkable variability, i.e., θ ranged from 58° to 132° with the majority of micro-droplets having θ of ∼85° – thus suggesting a mixed-wet behavior. For the same sample aged in surfactant, θ was <5° at micro and macro-scales, with few micro-droplets having θ of ∼89°. However, the macro-scale θ values were 105° (natural) and 90° (oil-aged) – suggesting notable variability at macro- and micro-scales.These findings reflect: a) significant differences among macro- and micro-scale contact angles, and b) surface wetting at the micro-scale captures physical and chemical properties of the rock, i.e., surface roughness, pore size and distribution, and chemical composition. The study herein presents qualitative and semi-quantitative analyses of the non-uniform wetting behavior of carbonate rocks and the associated rock/fluid interactions through a multi-scale perspective and thus have broader implications for flow in porous medium.

The synergistic effects of cationic surfactant and smart seawater on the recovery of medium-viscosity crude oil from low-permeability carbonates

In the petroleum industry, there is a continuous search for cost-effective enhanced oil recovery (EOR) methods to increase oil extraction. Surfactant-based EOR is one of these effective methods, which is applied after the primary and secondary recovery phases. This paper presents an experimental study on the use of a cationic surfactant, hexadecyltrimethylammonium bromide (CTAB, CH3(CH2)15N(Br)(CH3)3), and smart seawater (SW) for EOR in low-permeability carbonate rock with medium viscosity crude oil. Smart SW was prepared by modifying the concentrations of Ca2+, Mg2+, and SO42- in synthetic offshore SW. The aqueous stability of CTAB was tested in different salinities of smart SW at the reservoir temperature. It was demonstrated that CTAB is stable at 55 °C, which was further confirmed through optical transmittance measurements, revealing values mostly exceeding 93%. The use of smart SW and CTAB significantly altered the wettability of carbonate rock towards water-wet and reduced the interfacial tension (IFT) between crude oil and water, reaching levels below 0.087 mN/m. However, the presence of smart SW increased the adsorption of CTAB onto the surface of carbonate rock. Nevertheless, the adsorption values were significantly below 1 mg/g-rock. Smart SW + CTAB resulted in a total oil recovery of 76.71% of original oil-in-place (OOIP), compared to 71.70% of OOIP with unmodified SW + CTAB. These results suggest that the use of smart SW in combination with CTAB is a promising approach for enhancing the recovery of medium-viscosity oil from tight carbonate reservoirs. Findings from this study can help in better understanding the optimal conditions for the application of smart SW-CTAB flooding to improve the effectiveness of tertiary recovery operations in the upstream oil sector.

Exploring carbonate rock wettability across scales: Role of (bio)minerals

HypothesisThe wettability of carbonate rocks is expected to be affected by the organic components of biominerals which are complex, nanostructured organo-mineral assemblages. Elucidating the nanoscale mechanisms driving the wettability of solid surfaces will enable a better understanding of the role of biominerals in the wetting properties of carbonate rocks to control various geological, environmental and industrial processes. ExperimentsUsing Atomic Force Microscopy and Spectroscopy (AFM/AFS) we probed the wettability properties of carbonate rocks with different amounts of organic material. The adhesion properties of two types of limestones were determined in liquid environments at different length scales (nm to mm) using functionalized tips with different chemical groups to determine the extent of surface hydrophobic and hydrophilic organo-mineral interactions. FindingsWe observed homogeneous hydrophobic areas at length scales below < 5 µm. The origin of this hydrophobicity is linked to the presence of organics, whose amount and spatial distribution depend on the rock composition. Specifically, our results reveal that the biogenic vs non-biogenic origin of the mineral grains is the main rock property controlling the wettability of the solid surface. Overall, our methodology offers a multi-scale approach to unravel the role that organic moieties and biominerals play in controlling the wettability of rock-water interfaces.

Salinity, temperature and pressure effect on hydrogen wettability of carbonate rocks

Hydrogen had been injected into the geologic formations, and the geologic formation wettability would influence the hydrogen storage. Hydrogen wettability of sandstone reservoirs (quartz), mica and other rocks have been explored in the previous study. However, the research on hydrogen wettability of carbonate rocks was lacked. In this study, we studied the carbonate rock wettability alteration when exposed to the hydrogen environments. Salinity, temperature and pressure effect on H 2 /carbonate rock/brine wettability were explored. When the solutions ions concentration increased, the advancing/receding contact angle would increase, and divalent ions could make the contact angle higher than monovalent ion, which was because ions could compress the electric double layer. The carbonate rock powder in brine showed negative charge, and the zeta potential increased with higher ions concentration. When temperature increased and the pressure decreased, the contact angle would decrease, which was related to the H 2 gas density and molecular interactions. • The divalent ions showed higher effect on the hydrogen wettability alteration than monovalent ion. • The contact angle increased with the increase of ions concentration. • The contact angle increased with the decrease of temperature. • The contact angle increased with the increase of pressure. • The high salinity could compress the electric double layer, and increased the contact angle.

Nanofluid based on 1-dodecylpyridinium chloride for enhanced oil recovery

The use of nanoparticles is considered promising for enhanced oil recovery (EOR), especially when they are combined with surfactants. However, the combination of nano-sized material with surface-active ionic liquids (SAILs) is an unexplored EOR method. In this work, the advantages of mixing Al2O3 nanoparticles with the SAIL 1-dodecylpyridinium chloride were investigated. Stable nanofluids in brine could only be achieved using the polymer polyvinylpyrrolidone (PVP) as a stabilizing agent. It was found that the addition of nanoparticles (and PVP) to the surfactant formulation helped to: slightly increase its viscosity, enhance its water-oil interfacial tension (IFT) reduction capacity, and reduce the adsorption on carbonate rocks (adsorption on sandstone was found to be excessive). IFT was selected as target property to minimize for the design of EOR formulations. Core flooding tests were carried out with surfactant (0.5 wt% [C12py]Cl), surfactant-polymer (0.5 wt% [C12py]Cl, 1.0 wt% PVP) and nanofluid (0.05 wt% Al2O3, 1.0 wt% PVP, 0.5 wt% [C12py]Cl) formulations in brine (0.5 wt% NaCl). Additional oil recoveries of 3.4%, 7.4% and 12.0% OOIP were achieved, respectively, the nanofluid formulation being the most promising for the application. Moreover, it was found capable of changing the wettability of carbonate rocks from oil-wet to intermediate-wet. The significance of this work lies in showing the new possibilities resulting from the combination of SAILs and nanoparticles for EOR, specifically the combination of [C12py]Cl with Al2O3.

Application of surfactants in enhancing oil recovery from tight carbonates: Physicochemical properties and core flooding experiments

Surfactant formulations are optimized according to reservoir conditions to ensure their efficiency in enhanced oil recovery (EOR). This experimental study aimed to examine the EOR performance of a group of novel Alfoterra surfactants, which are based on alcohol propoxy sulfates. The performance of the Alfoterra surfactants (anionic) was compared to that of sodium dodecyl sulfate (SDS, anionic), dodecyltrimethylammonium bromide (DTAB, cationic), cetyltrimethylammonium bromide (CTAB, cationic) and t-octylphenoxypolyethoxyethanol (Triton X-100, nonionic). First, surfactant formulations were optimized based on their critical micelle concentration as well as their aqueous stability at 55 °C under different salinities. Next, the effects of the stable surfactant formulations on the interfacial tension (IFT) and rock wettability were examined. It was shown that the presence of the surfactants and the increase in salinity both caused a significant reduction in the oil-water IFT. Additionally, all surfactant formulations altered the wettability of carbonate rock from intermediate-to water-wet conditions. Next, tests of surfactant adsorption onto a carbonate-rock adsorbent were performed, showing that the anionic surfactants tend to adsorb more onto carbonates compared to other surfactants. Finally, core flooding tests involving medium-viscosity oil recovery from tight carbonate cores showed an EOR of 25.7–39.4% of original-oil-in-place above that achieved using regular waterflooding.

Calcite–Brine Interface and Its Implications in Oilfield Applications: Insights from Zeta Potential Experiments and Molecular Dynamics Simulations

Carbonate reservoirs are made up of predominantly calcite and dolomite minerals and hold significant hydrocarbon reserves globally. However, the production from carbonate reservoirs is limited due to their wettability, which controls the production and fluid distribution. To develop efficient strategies for producing from these formations, it is necessary to understand the underlining mechanisms of carbonate rock wettability. We believe that understanding the native state of the rock mineral in the reservoir environment and how oilfield operations affect the wetting state of minerals is critical to demystifying the change in carbonate rock wettability. Thus, this study extends the understanding of the surface charge development of calcite minerals and provides useful insight into the mineral’s surface charge development. Zeta potential measurements and molecular dynamics (MD) simulations of calcite in different fluids of varying composition and salinity were investigated. We have considered both the mixed brine (seawater and reservoir water) and individual salt brine (i.e., NaCl, MgCl2, and CaCl2). The results show that the calcite mineral surface charge is controlled by the composition and salinity of the surrounding fluids. Indeed, we found that monovalent ions have dominant contributions to the total calcite surface charge. The adsorptions of Na+ and Cl– shape the stern layer structure in the first two calcite hydration monolayers. We found that the interplay between the calcite surface affinity to the brine ions and the hydration-free energies are the two critical parameters shaping the final mineral surface charge. We believe that our study provides essential atomic insights into the calcite–brine interfaces and how ions interact with the surface to control the surface charge, which are vital to the quest for wettability control.

Modelling of carbonate rock wettability based on surface charge and calcite dissolution

The lack of consensus on the mechanisms underpinning low salinity waterflooding (LSWF) oil recovery has affected the successful implementation of LSWF in carbonate reservoirs. Many investigators link the improved oil recovery observed from LSWF to wettability alteration. Several models are proposed in the literature to study the wettability alteration mechanism. However, the reliability of some of the models is being contested, as they struggle to accurately predict the oil recovery trend. This study aims to develop a new wettability alteration model that can predict the performance of LSWF oil recovery processes. We propose a new wettability indicator (WI) that integrates three mechanisms (surface charge alteration/ζ-potential, calcite dissolution, and ion exchange) which, are suggested, dictate LSWF wettability alteration. The model was implemented in UTCHEM, which was coupled with PHREEQCRM, and was used to simulate several experimental LSWF oil recoveries.The results produced from the simulations with the new model are consistent with experimental data. The outcomes from this study show that adsorption of crude oil is still possible even when the oil-brine and the rock-brine interfaces have the same polarities of ζ-potentials. The results further demonstrate that the improved oil recovery observed in LSWF is not always caused by the wettability alteration, but also caused by other factors such as rock quality and physical displacement. The outcome of the study also indicate that early injection of the low salinity brine can significantly improve the oil recovery.Findings from this study can improve the understanding of the LSWF process. Moreover, the model proposed in this study can be applied in the design and planning of LSWF projects to estimate the performance of the LSWF.

A comprehensive study on the application of a natural plant-based surfactant as a chemical enhanced oil recovery (CEOR) agent in the presence of different ions in carbonate reservoirs

Surfactant flooding is a promising CEOR approach in carbonate reservoirs and its efficiency has been verified. Commercial surfactants may impose various health and environmental issues. Therefore, utilizing a natural biodegradable surfactant at a low cost is a valuable option for the petroleum industry. In this research, a non-ionic surfactant derived from Acanthophyllum Plant Root Extract (APRE) was used as a bio-surfactant. The EOR potential of this surfactant was evaluated through various tests. Oil-water system interfacial tension (IFT) measurement, contact angle test for carbonate rock wettability alteration assessment, emulsion stability, compatibility, and surfactant flooding test were conducted. The effect of different ions of various salts on the IFT, carbonate rock wettability and the chemical interactions were also studied. The emulsion stability created by the surfactant was assessed through observational tests. The compatibility test (at 25 °C) showed that negligible sediment below the salinity of 50,000 ppm was formed. The IFT at CMC in formation water (optimum concentration of 12000 ppm) was reduced to 1.06 mN/m from an initial value of 2.16 mN/m. The optimum IFT value at different salinities was also determined. The wettability of the carbonate rock from a strongly oil-wet state (168°) was altered to water-wet (60.3°) in the presence of surfactant and FW with a concertation of 10,000 ppm. In the core flood test, the effect of different slug sizes and soaking time was also determined. It was observed that increasing slug size results in a lower mobility ratio and consequently higher oil recovery.

Effect of Brine and Organic Acids on Initial Wettability of Carbonate Rocks

Effect of Brine and Organic Acids on Initial Wettability of Carbonate Rocks

Design and synthesis of a new ionic liquid surfactant for petroleum industry

This study is intended to synthesize and assess a new pyridinium-based Ionic Liquid (IL) surfactant, 1-octadecyl-pyridinium bromide, in terms of crude oil–water Interfacial Tension (IFT) reduction and wettability alteration. The synthesized IL surfactant is firstly characterized through proton Nuclear Magnetic Resonance (1H NMR). Then, the pendant-drop and sessile drop techniques are employed to study crude oil–water IFT and the wettability of carbonate rocks. Based on the IFT results, the synthesized IL has a Critical Micelle Concentration (CMC) of 200 ppm, at which crude oil–water IFT reduces by 95.9 %, from an initial value of 23.7 mN/m to 0.97 mN/m. Increasing the salinity up to 100,000 ppm could not make the synthesized IL less effective than that of free from salinity, as the magnitude of IFT is obtained to be 0.938 mN/m at CMC. Based on the wettability investigation phase, the synthesized IL changes the wettability of carbonate slices from oil-wet to intermediate-wet (140.47°–90.97°). It is also observed that the synthesized IL can tolerate harsh salinity conditions as no appreciable change in the contact angle is noticed after increasing the salinity even up to 150,000 ppm (84.54° at CMC). It should be noted that an optimal salinity of 50,000 ppm is found based on the results of IFT and contact angle measurements. The introduced surfactant is expected to exhibit a significant positive impact on the oil recovery factor while implementing chemical flooding.

A mechanistic comparison of formate, acetate, and glycine as wettability modifiers for carbonate and shale formations

Previous studies indicated the efficacy of the simplest amino acid, glycine, as a wettability modifier that enhances the imbibition of water in carbonate reservoirs. The objective of this research was to compare the performance of formate, acetate, and glycine as wettability modifiers for carbonate and shale formations. Formate and acetate were studied for the first time as novel wettability modifiers. Note that the aminomethyl and amino groups are the only structural differences between formate and glycine, and acetate and glycine, respectively. The experiments consisted of contact-angle measurements on oil-aged calcite and shale plates, and imbibition displacements (spontaneous and forced). The comparison among these additives was made with/without adding hydrogen chloride (HCl) for adjusting the pH of the solutions. Amott indexes of glycine and formate + HCl solutions were noticeably higher than the rest of the cases in the imbibition experiments. We found that formate can be very effective in altering the wettability of carbonate rocks to water-wet state when the pH of the solution is reduced. This indicates the synergy of pH adjustment and the attraction of formate to the rock surface, which resulted in an improvement of the oil recovery. Glycine showed a superior behavior as a wettability modifier in comparison to formate and acetate for all the experimental conditions of this study. This indicated that the amino group, in the presence of the carboxyl group, plays a key role in altering the rock wettability. We demonstrated that the ability of glycine to alter wettability comes from two factors: one is the chelate effect caused by the amino group as an electron donor in the presence of the carboxyl group. The chelate effect makes glycine entropically more favorable for binding to calcium cation in the brine, which triggers calcite dissolution, and/or attaching directly to the calcite surface. The other factor is the calcite dissolution induced by pH reduction, followed by the attraction of glycine to the rock surface.

Interfacial tension of acidic heavy crude oil type and dolomite surface wettability: salinity and nanoparticles impact

ABSTRACT Waterflooding is the widespread method for displacing the residual oil toward well production because of its accessibility and low cost. Currently, several oil-rich countries are investigating to untangle the current shortcomings to make waterflooding method efficacious more. On the other side, salinity composition has been considered in enhanced oil recovery (EOR) for better sweep efficiency and has captured great interest for EOR techniques. In this study, oil–water interfacial tension (IFT) was measured between acidic heavy crude oil (AHCO) and brine solutions of MgCl2, CaCl2, KCl, NaCl, and Na2SO4 in various concentrations from 0.1 to 1 M and analyzed to obtain the highest IFT reduction. Moreover, the effects of AHCO and water composition on initial wettability of carbonate rock were investigated. The variations of surface properties of dolomite rock samples were investigated by contact angle (CA) measurements after aging thin sections in oil and brine. In addition, silica nanoparticles (NPs) as the IFT reducer and wettability alteration affordable agent were examined to compare their effects on salinity. The lowest IFT value between AHCO and brine solutions was reported 6.5 mN/m by magnesium chloride at 1 M concentration. Likewise, the highest impact on wettability alteration from oil-wet system (137.37◦) to strongly water-wet system (30.79◦) was obtained by magnesium chloride at 1 M concentration as well. Moreover, the application of silica NPs based on different salinity showed an inconspicuous impact in this study.

Increasing Reservoir Recovery Efficiency through Laboratory-Proven Hybrid Smart Water-Assisted Foam (SWAF) Flooding in Carbonate Reservoirs

This contribution introduces a new hybrid enhanced oil recovery (EOR) method which combines smart water-assisted foam (SWAF) flooding, known as the SWAF process. The concept of applying SWAF flooding in carbonate reservoirs is a novel approach previously unexplored in the literature. The synergy effect of the SWAF technique has the potential to mitigate a number of limitations related to individual (i.e., conventional water injection and foam flooding) methods encountered in carbonates. In general, carbonate rocks are characterized by a mixed-wet to oil-wet wettability state, which contributes to poor oil recovery. Hence, the smart water solution has been designed to produce a dual-improvement effect of altering carbonate rock wettability towards more water-wet, which preconditions the reservoir and augments the stability of the foam lamellae, which has for some conditions more favorable relative permeability behavior. Then the smart water solution is combined with surfactant (surfactant aqueous solution or SAS) and gas injection produces a synergy effect, which leads to more wettability alteration, and interfacial tension (IFT) reduction, and thus improves the oil recovery. Accordingly, to determine the optimal conditions of smart water solution with an optimal SAS, we conducted a series of experimental laboratory studies. The experimental design is divided into three main steps. At first, the screening process is required so that the candidates can be narrowed down for our designed smart water using the contact angle tests that employ calcite plate (i.e., Indiana limestone or ILS) as the first filter. Following this, the optimum smart water solutions candidates are blended with different types of cationic and anionic surfactants to create optimum SAS formulations. Subsequently, a second screening process is performed with the aim to narrow down the SAS candidates with varying types of gases (i.e., carbon dioxide, CO2 and nitrogen, N2) via the aqueous stability test (AST), foamability test (FT), and foam stability test (FST). We employed the state-of-the-art R5 parameter tests for rapid and accurate results in place of the conventional foam half-life method. The most effective combination of SAS and gas candidates are endorsed for the core-flooding experiments. In this work, two types of crude oils (Type A and B) with different total acid and base numbers (TAN and TBN). Results showed that the greatest wettability changes occurred for SW (MgCl2) solution at 3500 (ppm) for both crude oil types. This demonstrates the efficacy of our designed SW in the wettability alteration of carbonates, which is also supported by the zeta-potential measurements. The concentrations of both SW (MgCl2) and CTAB-based surfactants considerably affect the stability of the SAS (i.e., up to 90% foam stability). However when in the presence of crude oil, for the same SAS solution, the foam stability is reduced from 90% to 80%, which indicates the negative effect of crude oil on foam stability. Moreover, the core floods results showed that the MgCl2-foam injection mixture (MgCl2 + CTAB + AOS + N2) provided the highest residual oil recovery factor of SWAF process of 92% cumulative recovery of original oil in core (OIIC). This showcases the effectiveness of our proposed SWAF technique in oil recovery from carbonate reservoirs. Additionally, changing the large slug of 5 PVs to a small slug of 2 PVs of smart water solution was more effective in producing higher OIIC recovery and in reducing the fluid circulation costs (i.e., thereby, lowering CO2 footprint), making the SWAF process environmentally benign. Thus, it is expected that under optimum conditions (SW solution and SAS), the novel SWAF process can be a potentially successful hybrid EOR method for carbonate reservoirs, having both economic and environmental benefits.