Wettability Alteration Of Carbonate Rocks Research Articles

Experimental investigation of wettability alteration, IFT reduction, and injection schemes during surfactant/smart water flooding for EOR application

In recent years, the application of smart water and surfactant in order to improve oil recovery has attracted special attention in carbonate reservoirs. In this research, the effects of various salts in smart water and two surfactants of Cetyl Trimethyl Ammonium Bromide (CTAB) and Sodium Dodecyl Sulfate (SDS) on the wettability alteration of carbonate rock and IFT were studied. Besides, along with micromodel flooding, core flooding tests were conducted to assess the amount of oil recovery at reservoir conditions as an injection scheme was used. In this regard, the results illustrated that the presence of CTAB or SDS in seawater (SW) can act better in contact angle reduction compared to smart water. Also, a four times increase in the concentration of SO42− and removing Na+ from SW reduced the contact angle to 68° and 71°, respectively, being the best possible options to alter the carbonate surface wettability to more water-wet states. Moreover, in the second-order process in which the rock section was first placed in SW, and then was put in the smart solution (with or without surfactant), CTAB had a great effect on the wettability alteration. In the case of IFT reduction, although SW4Mg2+, compared to other ions, better decreased the IFT to 17.83 mN/m, SW + SDS and SW + CTAB further declined the IFT to 0.67 and 0.33 mN/m, respectively. Concerning different ions, divalent cations (Mg2+ and Ca2+) show better results in improving oil recovery factor. However, the combination of SW and surfactants has a more positive effect on boosting oil recovery, as compared to smart water flooding. It should be mentioned that the first-order injection is better than the second-order one since SW is flooded at first, and then, after the breakthrough, smart water is injected into the micromodel. In addition, the core flooding tests showed that SW + CTAB and SW + SDS in tertiary injection increased the oil recovery to about 59 and 57%, respectively, indicating that the presence of CTAB could be more effective than that of SDS.

Aqueous formate solution for enhanced water imbibition in oil recovery and carbon storage in carbonate reservoirs

This paper presents an experimental study of the injection of aqueous formate solution into oil-wet carbonate porous media at different formate concentrations and acidity levels. The research was motivated by the potential use of aqueous formate solution as a wettability modifier in enhanced oil recovery and/or a carbon carrier in geological carbon storage in carbonate reservoirs. However, the wettability alteration of carbonate rocks by formate has not been tested at elevated concentrations of formate or in any coreflood. The experimental program in this research consists of aqueous stability, wettability alteration, and three dynamic imbibition experiments with fractured carbonate cores with varying formate concentrations up to 30 wt% and initial pH between 6 and 7.With an excess amount of calcite powder, the 20 wt% formate solution in 15000 ppm NaCl brine showed essentially the same pH history as the base NaCl brine, where calcite dissolution caused the solution pH to increase to a stable value near 9. None of the samples studied in this research showed solid precipitation. Material balance of dynamic imbibition data indicated that the imbibition of formate into the matrix was most significant in coreflood #1, in which 30 wt% formate solution was injected into a fractured carbonate core. A large gradient in formate concentration between the fracture and the matrix likely caused the rapid mass transfer. Then, calcite dissolution and the resulting formate species caused wettability alteration to enhance water imbibition, which in turn expelled the oil in the matrix.The incremental oil recovery factor was 9.1 % for 30 wt% formate (pH = 7; coreflood #1), 2.9 % for 5 wt% formate (pH = 7; coreflood #2), and 7.0 % for 5 wt% formate + HCl (pH = 6; coreflood #3). A greater oil recovery factor resulted from a greater concentration of formate and a reduced pH. This is the first time corefloods were performed with aqueous formate solution at elevated concentrations up to 30 wt%.

Experimental study about the effect of SiO2 nanoparticle in surfactant performance on IFT reduction and wettability alteration

Recently, serious attention to the high potential of nanotechnology in the enhanced oil recovery (EOR) processes have been attracted. In this study, the effects of addition of SiO2 nanoparticle into the aqueous solutions containing octyl phenol ethoxylate (Triton-x100), sodium lauryl sulfate (SLS), and octyl pyridinium chloride ([C8Pyr][Cl]) on the interfacial tension (IFT) reduction, wettability alteration of carbonate rock, and the spreading coefficient were investigated. EDX and FeSEM analysis were taken on the rock that indicate the dolomite nature of the rock sample. The equilibrium IFT and contact angle values of different cases were measured in two series (i.e. with and without SiO2 nanoparticles). It is found that the performance of SiO2 nanoparticle remarkably affected by surfactants type and their combination. SiO2 could not have a positive effect on the IFT reduction and wettability alteration and had an adverse effect on the performance of some surfactants. In more details, SiO2 nanoparticles was able to slightly improve the TiO2 surfactant performance by falling the IFT value from 2.8 to 1.5 mN/m, while it did not have a significant effect on the performance of Pyr surfactant by changing the IFT value from 14 to 13.3 mN/m. The performance order of IFT reduction and wettability alteration was completely different as the lowest IFT and contact angle values were observed for the SLS in the presence of SiO2 (IFT reduction from 0.36 to 0.1 mN/.m) and Tr in the absence of SiO2 (wettability change from 49º to 32.5º), respectively. However, SiO2 nanoparticles have a favorable effect on the spreading coefficient of SLS, Pyr, SLS+Pyr, and SW; among them, the best performance was observed for SLS with spreading coefficient (Sc) value of − 0.06 mN/m.

Effect of UiO-66-NH2/TiO2 nano-fluids on the IFT reduction and their use for wettability alteration of carbonate rocks

One new technique to change the wettability of rocks (carbonate) is sea water (SW) flooding and nano-composite flooding. In this regard, this study investigated the performance of a new synthetic nano-composite called UiO-66-NH2/TiO2 (UT). In this study, this nano-composite is used next to SW. Generally, scanning electron microscopy (SEM), X-ray Powder Diffraction (XRD), Energy Dispersive X-ray Spectroscopy (EDS), and Brunauer-Emmett-Teller (BET) analyses investigated synthetic nano-composite physical and chemical properties. A comparative study of the effect of the synthesized Nano-fluids was performed using interfacial tension (IFT), contact angle (CA), and core flooding experiments. In this experimental study, SW contains Ca2+ and SO42− ions. Generally, nano-composite samples with differents concentrations (0.03 wt% and 0.3 wt%) dispersed in a base-fluid (BF) with varied salinities were prepared. Results showed that this sea-water (SW) + 0.3 wt%UT could reduce interfacial tension from 22 (mN/m) to 3.3 (mN/m) and CA from 118° to 37°. Generally, the interfacial tension between nano-fluids and crude oil is also a function of nano-fluid concentration and BF salinities. On the other hand, oil recovery results using the core flooding test show that SW and 0.3 wt% UT are high efficient than other concentrations. Thus, by injecting this nano-fluid (SW + 0.3 wt% UT), the ratios of oil recovery through the flooding process in the first and second core plugs to the total oil recovery increased by 24.8% and 26%, respectively. In the end, SW + 0.3 wt% UT showed the best performance in relation to increased oil recovery. This study offers new findings that can help oil recovery by understanding SW technology with nano-composite in carbonate reservoirs.

Wettability Alteration of Carbonate Rock by Chelating Agents and Viscoelastic Surfactants: Synergetic Impact

Wettability Alteration of Carbonate Rock by Chelating Agents and Viscoelastic Surfactants: Synergetic Impact

Improving the stability of nanofluids via surface-modified titanium dioxide nanoparticles for wettability alteration of oil-wet carbonate reservoirs

The main challenge of the application of nanofluids for enhanced oil recovery (EOR) in oil-wet carbonate reservoirs is maintaining their stability under high-temperature and high-salinity which is normally seen in reservoir conditions. In this work, surface-modified TiO2 nanoparticles were synthesized by N-(2-Aminoethyl)−3-Aminopropyltrimethoxysilane (AEAPTMS) as a coupling agent for surface modification of nanoparticles. Zeta potential and dynamic light scattering analyses were used to evaluate the stability of the prepared nanofluids. Results indicated that nanofluids had high stability in 90 °C and 20 wt% salinity. The influence of nanofluids on wettability alteration of carbonate rocks was studied by measuring the contact angle value. Untreated rock samples were strongly oil-wet, with water advancing and receding contact angles of 165.1° and 166.2°, respectively. After treatment with 3wt% concentration of surface-modified TiO2 nanoparticles, the rock plate wettability changed to a water-wet state, with water advancing and receding contact angles of 37.6° and 48.2°, respectively. Suggested surface-modified TiO2 nanoparticles were more effective in wettability alteration of the rock surfaces compared to the un-modified TiO2 nanoparticles. Furthermore, higher concentration of nanoparticles, higher the ability of the nanoparticles on changing the rock wettability.

New insights into modeling disjoining pressure and wettability alteration by engineered water: Surface complexation based rock composition study

Several laboratory studies observed wettability alteration of carbonate rocks towards a more water-wet state through modifying the composition of injected water. The change in carbonate surface charge was reported as the underlying reason behind this wettability alteration and the corresponding incremental oil recovery by engineered water injection (EWI). Although the reported results of carbonate rock sensitivity to injected water ionic strength, pH, salinity, and concentration of potential determining ions (Ca 2+ , Mg 2+ , and SO 4 2− ), there is still an ambiguity on the way carbonates interact with injected water/ions. This is due to the different mineralogical compositions and electrokinetic properties of carbonates. Therefore, this paper provides more insight into the role of major rock-forming carbonate minerals (calcite and dolomite) in engineered water injection at different water compositions by utilizing surface complexation modeling (SCM). The study utilizes a geochemical simulator to highlight the effect of dolomite surface complexation reactions. After determining the total rock surface charge and surface potential, the disjoining pressure was calculated to estimate the water film thickness and consequently, infer about wettability alteration. The results showed that a successful EWI operation creates three regimes: displacement regime, surface reaction regime, and quasi-equilibrium regime. These regimes can be characterized by the proposed surface complexation technique to calculate/optimize the injection pore volumes needed for each regime, determine the location of EWI effect in the reservoir, and predict the time ranges when EWI will reach to the surface in the form of additional oil recovery. Also, it was found that the surface reaction regime is the most important one where main surface reactions and oil recovery occur. Furthermore, the study utilizes SCM for both calcite and dolomite minerals for the first time highlighting their importance in geochemical reactions of EWI when the rock has dolomite in its composition. Existing SCM considers oil-brine and rock-brine interfaces where only calcite mineral is captured in the rock-brine interface. The latter is based on assuming that the rock composition is pure calcite, which is not necessary the case. The findings of this study confirm that seawater is capable of inducing wettability alteration in carbonates under certain favorable conditions due to adsorption/desorption of the potentially determining ions. • This paper provides novel insight into the role of major rock-forming carbonate minerals (calcite and dolomite) in EWI/LSWI at different water compositions by utilizing the surface complexation reactions. • It is found that in a successful EWI operation, three regimes would be created, i.e. displacement regime, surface reaction regime, and equilibrium regime. • These regimes can be characterized by the proposed technique to calculate/optimize the injection pore volumes needed for each zone. • The developed approach can determine the location of EWI effect in the reservoir, and predict the time ranges when EWI would reach to the surface in the form of additional oil recovery. • This study utilizes SCM for both calcite and dolomite minerals for the first time highlighting their importance in geochemical reactions during EWI when the rock has dolomite as a constituent.

Insight into the Synergic Effect of Ultrasonic Waves, SDS Surfactant, and Silica Nanoparticles on Wettability Alteration of Carbonate Rocks

Insight into the Synergic Effect of Ultrasonic Waves, SDS Surfactant, and Silica Nanoparticles on Wettability Alteration of Carbonate Rocks

Atomistic Insight into the Behavior of Ions at an Oil-Bearing Hydrated Calcite Surface: Implication to Ion-Engineered Waterflooding

This research provides an atomistic picture of the role of ions in modulating the microstructural features of an oil-contaminated calcite surface. This is of crucial importance for the rational design of ion-engineered waterflooding, a promising technique for enhancing oil recovery from carbonate reservoirs. Inspired by a conventional lab-scale procedure, an integrated series of molecular dynamics (MD) simulations were carried out to resolve the relative contribution of the major ionic constituent of natural brines (i.e., Na+, Cl–, Mg2+, Ca2+, and SO42–) when soaking an oil-bearing calcite surface in different electrolyte solutions of same salinity, namely, CaCl2, MgCl2, Na2SO4, MgSO4, and deionized water (DW). In all cases, we observed the gradual detachment of polar oil molecules (mimicked by decanoate) already paired to Na+ cations, covering the calcite substrate in such a way that carboxylate groups were in contact with the treating solution. The appearance of such a negatively charged interface in conjunction with the bare calcite/brine surface is a likely nanometric source for the disparity of surface characteristics of oil-bearing rocks reported in the literature. The MD results showed the affinity of divalent cations (Ca2+ or Mg2+) for pairing with negatively charged carboxylate functional groups, thereby facilitating desorption of decanoates. Having a compact solvation shell, Mg2+ was not as effective as Ca2+ cations; however, its performance was enhanced in the presence of sulfate anions. We further figured out the tendency of SO42– anions to shielding Na+ sites over the calcite surface, thus limiting the chance of readsorption of carboxylate compounds. Consistent with lab experiences, sulfate was found to assist the access of magnesium cations to the calcite surface as well. Altogether, the present results provide us with a molecular-level validation for the well-known multicomponent ion exchange mechanism proposed for the wettability alteration of carbonate rocks through enriching the divalent ionic content of the injection brine solution.

Investigating the impact of a walnut-extracted surfactant on oil-water interfacial tension reduction and wettability alteration in carbonate rocks

ABSTRACT Various types of Enhanced Oil Recovery (EOR) methods have generally been used to recover the residual oil left in the pores after secondary recovery processes. Surfactant flooding has been in use for quite a long time and has shown to be an efficient chemical EOR method. However, chemical surfactants usually result in a high cost and unfavorable environmental impacts. On the other hand, natural surfactants can be a good and promising alternative to the use of conventional surfactants. This paper introduces a newly extracted surfactant from the leaves of a walnut tree and was named UKHS. The ultimate aim of this paper is to experimentally study the applicability of the walnut extracted surfactant in lowering interfacial tension (IFT) and altering wettability in the carbonate rock of the Kurdistan Region at a reservoir temperature of 80°C.In contrast to most other studies, we have used a synthesized reservoir brine, as the aqueous phase, and a light crude oil sample (from an oil reservoir in the Kurdistan Region), during the IFT measurements. Moreover, carbonate samples of Pilaspi formation in the Kurdistan Region were employed with the crude oil sample to measure the contact angles to determine the wettability.The results show that the UKHS solution at a CMC of only1 weight% has significantly lowered the contact angle from a strongly oil-wet state of nearly 165⁰ to a fairly water-wet state of 56.7⁰. On the other hand, the IFT reduction was trivial as it has reduced from solely 11.18 mN/m to 2.54 mN/m. The obtained results of the wettability alteration at a low CMC of 1 wt% witness the higher efficiency of UKHS in comparison to other natural surfactants. Thus, UKHS can be considered as a promising EOR agent to mobilize the residual oil within pores, mainly via the wettability alteration mechanism, whereas the contribution from the IFT reduction is rather small.

Nitrogen-doped graphene quantum dot nanofluids to improve oil recovery from carbonate and sandstone oil reservoirs

Nanofluids based on nitrogen-doped graphene quantum dots (N-GQDs) are an emerging nanotechnology with potential applications in enhanced oil recovery (EOR). Herein, we report the EOR performances of N-GQDs that have different GQD-sizes and nanofluid concentrations. Wettability and hydrocarbons/water interfacial tension (IFT) studies establish that N-GQDs nanofluids at concentrations of 0.5 mg/mL and with the lowest mean GQDs size range (about 3.5 nm) lead to more wettability alteration of carbonate rocks and decrease the oil/water IFT and n-heptane/water IFT from 16.88 mN/m to 0.975 mN/m, and from 50.24 mN/m to 27.87 mN/m, respectively. Moreover, core flooding experiments show that the aforementioned nanofluid provided greater than 18% and 14% enhancements in the oil recovery factors from carbonate and sandstone core samples, respectively, versus water flooding. In the carbonate core, the alterations of wettability and IFT reduction simultaneously promote oil recovery factors. By comparison, for the case of sandstone core, only the reduction in oil/water IFT leads to higher oil recovery factors.

Isolating the effect of asphaltene content on enhanced oil recovery during low salinity water flooding of carbonate reservoirs

ABSTRACT Polar compounds in oil, especially asphaltene and resin, have important implications on the oil recovery from carbonate reservoirs; yet their isolated effects, independent of other oil properties, are not well understood. Thus, two different crude oils with similar densities and resin contents, but with dissimilar asphaltene contents, were selected to better understand asphaltene’s effect on: wettability alternations upon water injection, IFT changes, and areal sweep efficiency. It was found that crude oil with greater amount of asphaltene hinders the wettability alteration by undiluted and diluted seawaters, due to sustained hydrophobicity caused by polar compounds adsorbing onto the rock surface. Conversely, crude oil with lower amount of asphaltene, combined with low salinity waters, resulted in pronounced wettability alteration. Based on image analysis of the surface of carbonate rocks, higher areal sweep efficiencies were obtained for non-asphaltenic crude oil (around 35%, versus 6% to 30% for asphaltenic crude oil), using seawaters diluted ten-and fifty-fold, corresponding to the lowest contact angle values measured (36° and 22°, respectively). Asphaltene is thus deemed to play a key role in the wettability alteration of carbonate rocks, consequently affecting the performance of enhanced oil recovery during low salinity water injection.

Evaluation of a New Agent for Wettability Alteration During Enhanced Oil Recovery

Wettability alteration is an important mechanism when applying surfactants during enhanced oil recovery (EOR). Moreover, in carbonate reservoirs, the rock has more tendencies to be oil-wet than those of sandstone reservoirs. This mainly arises from the interaction amongst the carbonate surface chemistry exposed to the asphaltenic/aromatic components of crude oil. Therefore, it is of great significance to develop surfactants with high efficiency in wettability alteration of carbonate rocks. In this work, a cationic surfactant n-dodecyl trimethylammonium bromide (DTEAB), was prepared and applied in a wettability alteration experiment for the first time. Then, the critical micelle concentration and wettability properties were studied by means of electrical conductivity and sessile drop techniques, respectively. Consequently, it was observed that this surfactant can alter the wettability of Bangestan rock pellets from oil-wet to water-wet state, and the results are better than that of wettability alteration observed for Khark rock pellets. Based on this mechanism, nearby 22% Original Oil in Place (OOIP) was obtained by tertiary surfactant flood during core displacement in excess of ultimate recovery factor of secondary water injection. As a consequence, the suggested cationic surfactant in this study can be a good agent for increasing the oil recovery factors in the petroleum industry.

Effect of combination of cationic surfactant and salts on wettability alteration of carbonate rock

ABSTRACT Among several proposed enhanced oil recovery (EOR) methods, smart water injection is one of the most widely examined methods due to its unique advantages on wettability alteration. Besides, another well-known EOR method is surfactant flooding, which has a strong capability of altering both the IFT and the rock wettability. Thus, the current study is concentrated on the application of these two methods combined using Design Expert (DE) and Response Surface Methodology (RSM) approaches to make the measurements more systematic. Furthermore, for the purpose of this study, a cationic surfactant, namely, C12TAB and salts such as NaCl, Na2SO4, MgCl2, and CaCl2 are utilized. Contact angle measurements using constant concentrations of ions and C12TAB are performed to find the best operating conditions followed by the core flooding experiment. In summary, the obtained results revealed that the combination of ions and C12TAB is capable of changing the contact angle from 90° to 14 o while surfactant solution without divalent ions alters the wettability from 90° to 71°. Moreover, the results demonstrated that a combination of C12TAB and monovalent ions is less effective than a combination of C12TAB and divalent ions. Finally, the core flooding results illustrated that it is possible to achieve the ultimate oil recovery of about 43.7% to 90.66% based on original oil in place (OOIP).

Effect of a synthesized anionic fluorinated surfactant on wettability alteration for chemical treatment of near-wellbore zone in carbonate gas condensate reservoirs

The pressure drop during production in the near-wellbore zone of gas condensate reservoirs causes condensate formation in this area. Condensate blockage in this area causes an additional pressure drop that weakens the effective parameters of production, such as permeability. Reservoir rock wettability alteration to gas-wet through chemical treatment is one of the solutions to produce these condensates and eliminate condensate blockage in the area. In this study, an anionic fluorinated surfactant was synthesized and used for chemical treatment and carbonate rock wettability alteration. The synthesized surfactant was characterized by Fourier transform infrared spectroscopy and thermogravimetric analysis. Then, using surface tension tests, its critical micelle concentration (CMC) was determined. Contact angle experiments on chemically treated sections with surfactant solutions and spontaneous imbibition were performed to investigate the wettability alteration. Surfactant adsorption on porous media was calculated using flooding. Finally, the surfactant foamability was investigated using a Ross–Miles foam generator. According to the results, the synthesized surfactant has suitable thermal stability for use in gas condensate reservoirs. A CMC of 3500 ppm was obtained for the surfactant based on the surface tension experiments. Contact angle experiments show the ability of the surfactant to chemical treatment and wettability alteration of carbonate rocks to gas-wet so that at the constant concentration of CMC and at 373 K, the contact angles at treatment times of 30, 60, 120 and 240 min were obtained 87.94°, 93.50°, 99.79° and 106.03°, respectively. However, this ability varies at different surfactant concentrations and temperatures. The foamability test also shows the suitable stability of the foam generated by the surfactant, and a foam half-life time of 13 min was obtained for the surfactant at CMC.

An experimental investigation of smart-water wettability alteration in carbonate rocks – oil recovery and temperature effects

ABSTRACT The smart water flooding has found tremendous applications in the oil recovery sector. This technique is designed by changing the concentrations of cations – mainly SO4 2-, Ca2+, and Mg2+ – in the synthetic water mixtures being injected. The complexity of the underlying reaction mechanism, compared to the sandstone counterparts, calls for substantial research in this field. The present article lists an experimental investigation of wettability alteration in carbonate rocks by focusing on the role of individual ions for the fluid-solid interactions. The oil recovery results are reported for five synthetic smart waters, as well as the real formation water in the temperature range between 25 and 70 Celsius. A chemical-based mechanism is proposed – supported by zeta-potential data – to render the role of ions in the wettability alteration process. The smart-water samples are designed to hold the same level of total dissolved solids as the seawater of the Persian Gulf. The increase in the concentration of SO4 2- ion is found to accelerate the rate of reaction in the crude oil-brine-rock (CBR) system, resulting in more wettability alteration. In addition, the Mg2+ ion is rendered more effective in the wettability change process than the Ca2+ ion. The seawater enriched with sulfate ions (two/four-fold) has yielded the highest recovery, with essential increase in higher temperatures. The elevation of temperature to 70°C has yielded an impressive outcome on the recovery – approximately 17.20% – for the best smart-water samples evaluated.

Wettability alteration and oil recovery by spontaneous imbibition of smart water and surfactants into carbonates

Naturally fractured carbonate reservoirs have very low oil recovery efficiency owing to their wettability and tightness of matrix. However, smart water can enhance oil recovery by changing the wettability of the carbonate rock surface from oil-wet to water-wet, and the addition of surfactants can also change surface wettability. In the present study, the effects of a solution of modified seawater with some surfactants, namely C12TAB, SDS, and TritonX-100 (TX-100), on the wettability of carbonate rock were investigated through contact angle measurements. Oil recovery was studied using spontaneous imbibition tests at 25, 70, and 90 °C, followed by thermal gravity analysis to measure the amount of adsorbed material on the carbonate surface. The results indicated that Ca2+, Mg2+, and SO42− ions may alter the carbonate rock wettability from oil-wet to water-wet, with further water wettability obtained at higher concentrations of the ions in modified seawater. Removal of NaCl from the imbibing fluid resulted in a reduced contact angle and significantly enhanced oil recovery. Low oil recoveries were obtained with modified seawater at 25 and 70 °C, but once the temperature was increased to 90 °C, the oil recovery in the spontaneous imbibition experiment increased dramatically. Application of smart water with C12TAB surfactant at 0.1 wt% changed the contact angle from 161° to 52° and enhanced oil recovery to 72%, while the presence of the anionic surfactant SDS at 0.1 wt% in the smart water increased oil recovery to 64.5%. The TGA analysis results indicated that the adsorbed materials on the carbonate surface were minimal for the solution containing seawater with C12TAB at 0.1 wt% (SW + CTAB (0.1 wt%)). Based on the experimental results, a mechanism was proposed for wettability alteration of carbonate rocks using smart water with SDS and C12TAB surfactants.

Wetting behavior of oppositely charged polystyrene sulfonate/hexadecyl trimethyl ammonium bromide complexes near critical aggregation concentration on carbonate reservoir rocks

This paper reports on the wettability alteration of carbonate rocks from super-hydrophobic to super-hydrophilic in the presence of surfactant-polyelectrolyte complexes. In numerous industries such as oil recovery or paint technology, there is a recognized need for controlling the wettability of solid surfaces and particularly for producing super-hydrophobic or hydrophilic coatings. A growing body of evidence suggests that the surface activity of the Hexadecyl Trimethyl Ammonium Bromide (CTAB) will considerably increase in the presence of the oppositely charged Polystyrene Sulfonate (PSS) and form a surface-active multilayer complex in a range of concentrations from much lower than conventional surfactant critical micelle concentration (CMC) to CMC. The impact of adsorbing such a surface-active multilayer complex on the wetting behavior of CTAB-PSS solutions on solid surfaces, however, has scarcely been dealt with in the previous studies. This study sets out to determine the wetting behavior of CTAB-PSS mixtures on carbonate surfaces around the critical aggregation concentration, CAC, above which the multilayer surface structuring has been reported. Dynamic surface tension, dilational surface elastometry, and contact angle measurements were undertaken to first indicate the occurrence of multilayer structuring and second to explore the potential relationship between that and the wettability alteration of an oil-wet carbonate rock. The results are quite revealing, introducing an optimum CTAB concentration where surface elasticity and also the standard deviation of solution drop shapes from Laplacian profile are maximized and at the same time the contact angle is minimized. These values are 0.55 mM (for 50 ppm PSS) and 0.74 mM (for 20 ppm PSS), both quite lower than conventional CMC and above CAC. These findings are of crucial importance in coating science and in the manufacturing super-hydrophilic surfaces.

A Review on Wettability Alteration in Carbonate Rocks: Wettability Modifiers

More than half of the global oil reserves are in carbonate reservoirs. Carbonate rocks, however, in most cases tend to be mixed-wet or oil-wet. Wettability alteration of carbonate reservoir rock ha...

Quantitative Monitoring of Cleaning Time and Wettability Alteration of Carbonate Rocks During Soxhlet Cleaning

Summary Core analysis is one of the most important steps in formation evaluation. The availability of routine–core–analysis (RCAL) and special–core–analysis (SCAL) data results in a better characterization of reservoirs and prediction of their behaviors. Unfortunately, the process of running core experiments, in both RCAL and SCAL phases, is very time consuming. Because all plug samples should be cleaned during the RCAL phase, finding a solvent that can speed up this process is desirable. The cleanliness of a core sample during Soxhlet extraction is usually determined by monitoring the color of solvents qualitatively. The main contribution of this study is to propose a methodology during RCAL to determine the best solvent during the Soxhlet–cleaning experiments. By introducing a novel quantitative method, the cleaning time of different solvents (i.e., tetrachloroethene, acetone, toluene, chloroform, xylene, and n–hexane) is investigated. This quantitative method is based on turbidity measurement of the solvent that siphons periodically from the Soxhlet extractor. Moreover, the wettability alteration of the implemented solvents is monitored by contact–angle measurements. To perform the analysis, two crude–oil samples (a heavy oil and a light oil with different asphaltene/resin fractions) and carbonate rocks from two Iranian formations are implemented. The results show that the polar solvents can speed up the cleaning process while altering the wettability of the carbonate samples toward more–water–wet conditions. The introduced methodology of measuring the cleaning time can be implemented as a routine screening tool in RCAL projects to determine the proper solvent that can reduce the Soxhlet–cleaning time.