Carbonate Rock Surface Research Articles

Effect of brine type and ionic strength on the wettability alteration of naphthenic-acid-adsorbed calcite surfaces

Low-salinity/smart waterflooding is a technique, used in oil reservoirs, where the salinity and/or ionic composition of the injection water is tuned to improve oil recovery. It has been observed by many researchers that low-salinity waterflooding can enhance oil recovery by altering the wettability of carbonate rock surfaces from oil-wet to water-wet. Though wettability alteration is generally agreed to be the main mechanism for the improved oil recovery, the contributing parameters and necessary conditions for wettability alteration are not clearly understood. Hence, it is essential to decouple the effects of salinity, ionic composition, and oil composition on wettability alteration of the solid surface. In this work, we systematically investigated smart-water induced wettability alteration of naphthenic-acid-adsorbed oil-wet calcite surfaces. Well-characterized model systems were used to understand the effects of individual monovalent and divalent ions (Na+, Cl−, Mg2+ and SO42−), and salinity on the calcite surface wettability. Contact angle measurements were performed on smooth Iceland Spar calcite surfaces that were aged at 120 °C in 5M NaCl brine, acid number 1.5 model oil, and single-electrolyte-based brine solutions of different salinity and ionic composition. The extent of wettability alteration was assessed based on ACA values, which are more relevant during waterflooding, using a goniometer customized for obtaining multiple advancing and receding contact angles along the surface by the tilting plate method. The results indicate that, for 0.164 M ionic strength (equivalent to 4-times diluted seawater concentration) brine solutions, the wettability of calcite surfaces was changed from oil-wet state to water-wet state irrespective of the salt type. The lowest advancing contact angle (ACA) values (20°–30° range) were obtained for 0.164 M ionic strength NaCl and Na2SO4 solutions, indicating the presence of SO42− ions or reduction in NaCl concentration act in favor of wettability alteration towards water-wet. At this ionic strength, the relative merit of divalent SO42− ions over monovalent Cl− ions was not observed. Upon comparison of ACA values for 0.164 M ionic strength Na2SO4 and MgSO4 (SO42− ion is common) solutions, we concluded that the extent of wettability alteration is lower in the presence of Mg2+ ions. A similar conclusion was made by comparing ACA values for 0.164 M ionic strength NaCl and MgCl2 solutions (Cl− ion is common). The calcite surfaces aged in 0.656 M (equivalent to seawater concentration) NaCl solution demonstrated intermediate-wet state indicating the extent of wettability alteration towards water-wet state increases with a decrease in salinity.

Experimental investigation of wettability alteration of carbonate gas-condensate reservoirs from oil-wetting to gas-wetting using Fe3O4 nanoparticles coated with Poly (vinyl alcohol), (PVA) or Hydroxyapatite (HAp)

Wettability alteration near-wellbore region in a gas-condensate reservoir is an effective way to reduce liquid blockage. To this end, Fe3O4 NPs (nanoparticles) first synthesized by the co-precipitation method and then coated with Poly (vinyl alcohol) (PVA) and or Hydroxyapatite (HAp). Besides, the synthesized NPs and two core-shell nanostructures were characterized by the Field Emission Scanning Electron Microscopy (FE-SEM), X-ray diffraction (XRD) analysis and the Fourier-Transform Infrared spectroscopy (FTIR). The synthesized NPs coated with PVA and or HAp were then exploited to coat on the surface of carbonate rocks by the dip-coating method in the course of 48 h. Next, the contact angle on the surface of carbonate rocks in condensate/air and water/air systems was measured in a wide range of pressure from 1 to 40 bar. In contact angle measurements, the effect of different parameters including the NPs concentration, temperature and pressure was examined.Also, the spontaneous imbibition and fluid flow tests were fulfilled in the artificial core-plugs before and after the wettability alteration. The results show that the imbibition rate of water and condensate noticeably reduced after the wettability alteration by both core-shell nanostructures. Additionally, the pressure drop and breakthrough time significantly diminished after the wettability alteration by both core-shell nanostructures. Moreover, coating of the two core-shell nanostructures on the surface of carbonate rocks was confirmed by the Scanning Electron Microscope (SEM) analyses.Furthermore, based on contact angle measurements between gas-condensate and the carbonate artificial core-plug surface after the treatment with the Fe3O4-PVA and or Fe3O4-HAp nanostructures, the optimum concentrations of Fe3O4/PVA and Fe3O4-HAp nanostructures in distilled water were 0.5 wt % and 0.4 wt %, respectively, to attain the greatest wettability alteration from oil-wetting to preferentially gas-wetting. In this condition, the contact angle between gas-condensate and the treated carbonate artificial core-plug surface by the Fe3O4/PVA and or Fe3O4-HAp nanostructures shifted from 10 ͦ to 66 ͦ and or 90 ͦ, respectively. Also, the contact angle between water and the treated carbonate artificial core-plug surface using the Fe3O4/PVA and or Fe3O4-HAp NPs altered from 62 ͦ to 107 ͦ and or 116 ͦ, respectively.Generally, the iron oxide NPs coated with HAp significantly improved the wettability of the rock samples from oil-wetting to gas-wetting as compared to those coated with PVA.Finally, the spontaneous imbibition experiments were carried out in the tight rock before and after the wettability alteration. Results demonstrated that the imbibition rate of gas-condensate decreased about 63 and 64% after the wettability alteration by the Fe3O4-PVA/DW and Fe3O4-HAp/DW nanofluids with the optimum concentration of 0.5 and 0.4 wt %, in sequence. Additionally, experimental results of the fluid flow tests at high pressures showed that the pressure drop reduced 34 and 32% after the wettability alteration for both Fe3O4-PVA/DW and Fe3O4-HAp/DW nanofluids, respectively.

Insights into stability of silica nanofluids in brine solution coupled with rock wettability alteration: An enhanced oil recovery study in oil-wet carbonates

Stability of nanoparticle dispersion in brine solution is a key parameter for a successful nanofluid- based enhanced oil recovery processes. This paper aims to provide a systematic laboratory study to investigate the stability of silica nanoparticles (NPs) in presence of mono and divalent salts, namely NaCl and MgCl2, coupled with their potential to alter wettability of low-permeable, oil-wet carbonates at 80 °C. First, silica nanofluids with different salt concentrations were prepared using sonication process. Results showed that presence of divalent cations significantly hinders the stability of silica nanofluids as compared to monovalent ones. It was found that most of silica NPs was precipitated in presence MgCl2 even at a low concentration of 2000 ppm while no particle precipitation was observed with 10,000 ppm NaCl over a two- week period. This was in line with a smaller particle size of silica NPs with 10,000 ppm NaCl (73 nm) as compared to MgCl2, 388 nm. Also, we found a noticeable reduction in zeta potential of silica nanofluids with MgCl2, −8 mV, as compared to NaCl, −25 mV. This reveals that the negative surface charge of silica NPs became more neutralized in presence of MgCl2 and thus more chance for agglomeration of silica NPs through the aqueous phase. As to rock- nanofluid interaction, silica nanofluids in presence of NaCl exhibited a higher potential to alter rock wettability to more water-wetness than MgCl2. Such wettability alteration was discussed in terms of adsorption of silica NPs on the carbonate rock followed by a generation of thin layer of silica NPs on the rock surface, leading to an extra pressure on oil droplet. This was in line with SEM- EDX analyses indicting that silica NPs covers the carbonate rock surface. In terms of oil recovery, imbibition of silica nanofluid containing 10,000 ppm NaCl provided 14% incremental oil while the lowest oil recovery was obtained for silica nanofluids containing MgCl2 due to their less stability. These results showed that there could be a correlation between the stability of silica nanofluids and their EOR potential, which is strongly dependent on the salt type and concentration.

Reversible and irreversible adsorption of bare and hybrid silica nanoparticles onto carbonate surface at reservoir condition

Realistic implementation of nanofluids in subsurface projects including carbon geosequestration and enhanced oil recovery requires full understanding of nanoparticles (NPs) adsorption behaviour in the porous media. The physicochemical interactions between NPs and between the NP and the porous media grain surface control the adsorption behavior of NPs. This study investigates the reversible and irreversible adsorption of silica NPs onto oil-wet and water-wet carbonate surfaces at reservoir conditions. Each carbonate sample was treated with different concentrations of silica nanofluid to investigate NP adsorption in terms of nanoparticles initial size and hydrophobicity at different temperatures, and pressures. Aggregation behaviour and the reversibility of NP adsorption onto carbonate surfaces was measured using dynamic light scattering (DLS), scanning electron microscope (SEM) images, energy dispersive X-ray spectroscope (EDS), and atomic force microscope (AFM) measurement. Results show that the initial hydrophilicity of the NP and the carbonate rock surface can influence the NPs adsorption onto the rock surfaces. Typically, oppositely charged NP and rock surface are attracted to each other, forming a mono or multilayers of NPs on the rock. Operation conditions including pressure and temperature have shown minor influence on nano-treatment efficiency. Moreover, DLS measurement proved the impact of hydrophilicity on the stability and adsorption trend of NPs. This was also confirmed by SEM images. Further, AFM results indicated that a wide-ranging adsorption scenario of NPs on the carbonate surface exists. Similar results were obtained from the EDS measurements. This study thus gives the first insight into NPs adsorption onto carbonate surfaces at reservoirs conditions. High pressure/temperature cell for surface treatment with nanoparticles (nanofluid) at reservoir condition.

Characterization of Organic Layer in Oil Carbonate Reservoir Rocks and its Effect on Microscale Wetting Properties

Effective production of oil from carbonate reservoirs often requires the application of improved oil recovery technologies such as waterflooding. However, conventional waterflooding in carbonates usually results in low hydrocarbon recovery as most of these formations exhibit a complex pore throats structure and are mostly oil-wet. Therefore, improved insight into the causes of hydrophobic wetting behavior of such reservoirs is important for understanding the fluid distribution, displacement and enhancing recovery processes. The characterization of fluid-rock interactions is, however, challenging with existing laboratory methods, which are typically based on macroscale (mm) observations. In this experimental study, an advanced imaging technique, namely environmental scanning electron microscope, was applied for the comprehensive investigation of microscale (µm) wettability variations in carbonate rocks covered with organic layers. For the first time, the presence of organic layers on the sample was proved using energy dispersive X-ray mapping. Furthermore, the chemical bond of this layer and carbonate rock surfaces was determined using the transmission electron microscopy and electron energy-loss spectroscopy. The thickness of layer was estimated by using image processing software. These findings show that the application of combined microscopic techniques reveals important details about the reason of hydrophobic wetting properties of real carbonate rocks.

Ion type adjustment with emphasize on the presence of NaCl existence; measuring interfacial tension, wettability and spreading of crude oil in the carbonate reservoir

Finding the high-performance anions and cations in the aqueous solutions are crucially required during the smart water injection make it the main core of many enhanced oil recovery (EOR) studies. Nevertheless the previously published literature revealed a lack of understanding about the synergistic or antagonistic effect of NaCl (as the most abundant salt in the sea water) and other salts with the same ionic strength on the interfacial tension (IFT), wettability alteration and spreading coefficient. Therefore, the main purpose of this study is aimed on this concern. To reach this goal, the dynamic IFT values of crude oil/different aqueous solutions with ionic strength of 0.7 M and contact angle values between these phases on the oil wet carbonate surface soaked under different times in the prepared aqueous solutions are measured. After that, the measured values are used to calculate the spreading coefficient and distribution capability of oil and water phases on the carbonate rock surface. The obtained results revealed that to change the wetting state of carbonate rock toward a more water wet state, a synergistic effect was observed between NaCl and salts containing sulfate anion, i.e. Na2SO4 and MgSO4.

Experimental investigation of wettability alteration and oil recovery enhance in carbonate reservoirs using iron oxide nanoparticles coated with EDTA or SLS

Recently, nanoparticles (NPs) coated with chemical agents like polymers and surfactants have attracted much attention for the wettability alteration of reservoirs from oil-wetting to water-wetting in order to increase oil production rate. In this research, Fe3O4 NPs were synthesized using the co-precipitation method and coated with Ethylenediaminetetraacetic (EDTA) as a hydrophilic polymer or Sodium Lauryl Sulfate (SLS) as an ionic surfactant by the dip-coating method to alter the wettability from oil-wetting to water-wetting in carbonate rocks. The coated NPs were characterized by the Field Emission Scanning Electron Microscope (FE-SEM), X-ray diffraction device (XRD), Fourier-transform infrared spectroscopy (FTIR), Zeta-potential measurements, and the Vibrating-sample magnetometer (VSM) analysis. In addition, the effect of different parameters on wettability alteration including the variation of nanofluids concentration, pH level, salinity, temperature, pressure, and exposure time via contact angle experiments was investigated. Finally, the imbibition experiments were fulfilled to observe the performance of nanofluids in enhancing oil recovery at core-scale. Our results showed that the coated Fe3O4 NPs have excellent water-wetness properties in low salinities (i.e. less than 5000 ppm). Additionally, the Scanning Electron Microscope (SEM) micrographs, Zeta-potential measurement and FTIR analysis taken from the carbonate plates confirmed the adsorption of NPs on the carbonate-rock surface. Moreover, the Fe3O4 NPs coated with SLS in comparison with those coated with EDTA have higher performance in reduction of contact angle, and hence enhancing more oil recovery (EOR).

Lichens and other lithobionts on the carbonate rock surfaces of the heritage site of the tomb of Lazarus (Palestinian territories): diversity, biodeterioration, and control issues in a semi-arid environment

Investigations on the lithobiontic colonization of the stone cultural heritage in (semi-)arid regions are needed to address conservation strategies. In this work, lithobiontic communities were examined on the carbonate rock surfaces of the heritage site of the Tomb of Lazarus. We aimed to evaluate their distribution and interaction with the lithic substrate, together with the efficacy of biocidal treatments for their control. Diversity and abundance of lithobionts were surveyed on the Jerusalem stone blocks of three architectural elements. Observations at the lichen-rock interface were carried out by reflected light and scanning electron microscopy. The efficacy against lichens of the widely used biocide benzalkonium chloride (BZC) was compared for different concentrations and application methods, and evaluated by epifluorescence microscopy. Chlorolichens were the dominant component of lithobiontic communities, more thoroughly adapted to the semi-arid conditions of the site than mosses and black biofilms of cyanobacteria and dematiaceous fungi. A different structural organization, in terms of thallus thickness and depth of the hyphal penetration component, characterized epilithic and endolithic lichen species, responsible for different deteriogenic activities. Biocidal assays showed that even the methodologies that are usually effective in temperate conditions (as the application of BZC 1.5% by poultice) may not completely devitalize lichens adapted to the stress conditions of semi-arid climates, unless a pervasive biocide diffusion through metabolically active thalli is carefully guaranteed. Lithobionts act as biodeteriogens on the semi-arid surfaces of the investigated heritage site. Their removal is thus recommendable, but it needs to be adequately supported with a careful calibration of devitalization strategies.

New insights into the mechanism of wettability alteration during low salinity water flooding in carbonate rocks

There is not a consistent view about the mechanism of wettability alteration during low salinity water flooding. This paper highlights extensive wettability studies to investigate the wettability alteration on mineralogically different carbonates. Contact angle measurements were conducted to characterize wettability changes quantitatively. The results clearly revealed that wettability of carbonate rock surfaces can be altered to a more water-wet condition by lowering water salinity. The trend of the maximum change of contact angle (MCCA) variation with dolomite/calcite content in the rock is fairly linear under the same salinity, which demonstrates that carbonate minerals can affect rock wettability in a way. Also, the higher calcite content in the rock, the greater MCCA, i.e. the stronger effect of LSWF. Besides, the sensitivity of rock wettability to minerals is different under different salinity conditions. When the salinity is in the range of 2384.6 ∼ 4769.2 mg/L, rock wettability is most sensitive to minerals. The analysis of the effect of ion composition showed that the effect of Ca2+ on wettability alteration is greater than that of Mg2+ at room temperature, and with the increase of the content of calcite in the rock, the effect of Ca2+ is more pronounced than that of Mg2+.

Time-Dependent Physicochemical Changes of Carbonate Surfaces from SmartWater (Diluted Seawater) Flooding Processes for Improved Oil Recovery.

Over the past few decades, field- and laboratory-scale studies have shown enhancements in oil recovery when reservoirs, which contain high-salinity formation water (FW), are waterflooded with modified-salinity salt water (widely referred to as the low-salinity, dilution, or SmartWater effect for improved oil recovery). In this study, we investigated the time dependence of the physicochemical processes that occur during diluted seawater (i.e., SmartWater) waterflooding processes of specific relevance to carbonate oil reservoirs. We measured the changes to oil/water/rock wettability, surface roughness, and surface chemical composition during SmartWater flooding using 10-fold-diluted seawater under mimicked oil reservoir conditions with calcite and carbonate reservoir rocks. Distinct effects due to SmartWater flooding were observed and found to occur on two different timescales: (1) a rapid (<15 min) increase in the colloidal electrostatic double-layer repulsion between the rock and oil across the SmartWater, leading to a decreased oil/water/rock adhesion energy and thus increased water wetness and (2) slower (>12 h to complete) physicochemical changes of the calcite and carbonate reservoir rock surfaces, including surface roughening via the dissolution of rock and the reprecipitation of dissolved carbonate species after exchanging key ions (Ca2+, Mg2+, CO32-, and SO42- in carbonates) with those in the flooding SmartWater. Our experiments using crude oil from a carbonate reservoir reveal that these reservoir rock surfaces are covered with organic-ionic preadsorbed films (ad-layers), which the SmartWater removes (detaches) as flakes. Removal of the organic-ionic ad-layers by SmartWater flooding enhances oil release from the surfaces, which was found to be critical to increasing the water wetness and significantly improving oil removal from carbonates. Additionally, the increase in water wetness is further enhanced by roughening of the rock surfaces, which decreases the effective contact (interaction) area between the oil and rock interfaces. Furthermore, we found that the rate of these slower physicochemical changes to the carbonate rock surfaces increases with increasing temperature (at least up to an experimental temperature of 75 °C). Our results suggest that the effectiveness of improved oil recovery from SmartWater flooding depends strongly on the formation of the organic-ionic ad-layers. In oil reservoirs where the ad-layer is fully developed and robust, injecting SmartWater would lead to significant removal of the ad-layer and improved oil recovery.

Novel application of PEG/SDS interaction as a wettability modifier of hydrophobic carbonate surfaces

Wettability alteration of carbonate reservoirs from oil-wet to water-wet is an important method to increase the efficiency of oil recovery. Interaction between surfactants and polymers can enhance the effectiveness of surfactants in EOR applications. In this study, the interaction of polyethylene glycol (PEG) with an ionic surfactant, sodium dodecyl sulphate (SDS), is evaluated on an oil-wet carbonate rock surface by using contact angle measurements. The results reveal that wettability alteration of carbonate rocks is achieved through PEG/SDS interaction on the rock surface above a critical aggregation concentration (CAC). The behaviour of PEG/SDS aqueous solutions is evaluated using surface and interfacial tension measurements. Furthermore, the effect of PEG and SDS concentrations and impact of electrolyte addition on PEG/SDS interaction are investigated. It is shown that electrolyte (NaCl) can effectively decrease the CAC values and accordingly initiate the wettability alteration of rocks. Moreover, in a constant SDS concentration, the addition of NaCl leads to a reduction in the contact angle, which can also be obtained by increasing the aging time, temperature and pre-adsorption of PEG on the rock surface.

Biofilm forming bacteria and archaea in thermal karst springs of Gellért Hill discharge area (Hungary).

The Buda Thermal Karst System (BTKS) is an extensive active hypogenic cave system located beneath the residential area of the Hungarian capital. At the river Danube, several thermal springs discharge forming spring caves. To reveal and compare the morphological structure and prokaryotic diversity of reddish-brown biofilms developed on the carbonate rock surfaces of the springs, scanning electron microscopy (SEM), and molecular cloning were applied. Microbial networks formed by filamentous bacteria and other cells with mineral crystals embedded in extracellular polymeric substances were observed in the SEM images. Biofilms were dominated by prokaryotes belonging to phyla Proteobacteria, Chloroflexi and Nitrospirae (Bacteria) and Thaumarchaeota (Archaea) but their abundance showed differences according to the type of the host rock, geographic distance, and different water exchange. In addition, representatives of phyla Acidobacteria, Actinobacteria, Caldithrix, Cyanobacteria, Firmicutes Gemmatimonadetes, and several candidate divisions of Bacteria as well as Crenarchaeota and Euryarchaeota were detected in sample-dependent higher abundance. The results indicate that thermophilic, anaerobic sulfur-, sulfate-, nitrate-, and iron(III)-reducing chemoorganotrophic as well as sulfur-, ammonia-, and nitrite-oxidizing chemolithotrophic prokaryotes can interact in the studied biofilms adapted to the unique and extreme circumstances (e.g., aphotic and nearly anoxic conditions, oligotrophy, and radionuclide accumulation) in the thermal karst springs.

Surface-Charge Alteration at the Carbonate/Brine Interface During Single-Well Chemical-Tracer Tests: Surface-Complexation Model

Summary Water chemistry has been shown to affect oil recovery by affecting surface charge and rock dissolution. The single-well chemical-tracer (SWCT) test is a field method to measure residual oil saturation (Sor), in which hydrolysis reaction of an ester has been known as a key process that could displace the equilibrium state of a reservoir by changing formation-water (FW) composition. Because oil mobilization during the SWCT tests causes an error in the measurement of Sor, changes in water chemistry might be a concern for the accuracy of Sor measurements. In our previous work, the extent to which different reservoir parameters might change water composition and the effect of water-chemistry changes on the calcite dissolution and the oil liberation from the carbonate-rock surfaces were extensively evaluated. In this study, the effect of water-chemistry changes on surface-charge alteration at the carbonate/brine interface has been studied by constructing and applying a surface-complexation model (SCM) that couples bulk aqueous and surface chemistry. We present how the pH drop induced by the displacement of the equilibrium state and changes in water chemistry in the formation affect surface charge in a pure-calcite carbonate rock during the SWCT tests. The results show that a pH drop during the SWCT tests while calcium concentration is held constant in the FW by ignoring calcite dissolution yields a less-positive/more-negative surface charge so that wettability of carbonate rock might be altered to a less-oil-wetting state, when the oil is negatively charged. In reality, however, calcite dissolves by water-chemistry changes during the SWCT tests, which leads to an increasing calcium concentration in the FW. Consequently, an SWCT test in carbonates is accompanied by increasing calcium concentration while pH drops, which yields an increase in the surface charge of carbonate rocks. Therefore, the pH drop does not directly affect the surface charge of carbonate rock during an SWCT test, and calcium concentration increased from calcite dissolution could control the surface charge more significantly.

Application of fluorinated nanofluid for production enhancement of a carbonate gas-condensate reservoir through wettability alteration

Condensate blockage phenomenon in near-wellbore region decreases gas production rate remarkably. Wettability alteration using fluorinated chemicals is an efficacious way to vanquish this problem. In this study, new synthesized fluorinated silica nanoparticles with an optimized condition and mean diameter of 50 nm is employed to modify carbonate rock surface wettability. Rock characterization tests consisting Field Emission Scanning Electron Microscopy (FE-SEM) and Energy Dispersive x-ray Spectroscopy (EDX) were utilized to assess the nanofluid adsorption on rock surface after treatment. Contact angle, spontaneous imbibition and core flooding experiments were performed to investigate the effect of synthesized nanofluid adsorption on wettability of rock surface and liquid mobility. Results of contact angle experiments revealed that wettability of rock could alter from strongly oil-wetting to the intermediate gas-wetting even at elevated temperature. Imbibition rates of oil and brine were diminished noticeably after treatment. 60% and 30% enhancement in pressure drop of condensate and brine floods after wettability alteration with modified nanofluid were observed which confirm successful field applicability of this chemical.

Effects of dissolved binary ionic compounds and different densities of brine on interfacial tension (IFT), wettability alteration, and contact angle in smart water and carbonated smart water injection processes in carbonate oil reservoirs

Interfacial tension and wettability are among factors affecting forces in an oil reservoir. Both of these factors are influenced by chemical mechanisms. For example, the interactions between ions, the rock surface and fatty acids can alter the wettability. Moreover, the competitive effects of salting-out and salting-in on increasing and decreasing the salinity of injected water can lead the water-oil interfacial tension (IFT) to another direction where adding carbon dioxide to the injected water can create factors that change the properties of the oil droplet and consequently change the interfacial tension value. The dissolution of carbon dioxide in smart water (low salinity water) results in a chemical reaction and reduces the density as well, and its diffusion into the oil droplet adjacent to the smart water increases the volume of the droplet and affects its viscosity and other properties. The acid formed by the dissolution of CO2 in the injected water may dissolve some minerals in carbonate rock surface and change the surface properties. The goal in enhanced oil recovery (EOR) process through water injection is to minimize interfacial tension, and moderate rock wettability to exhibit hydrophilic characteristics. Ions in injection water in a certain density cause the interfacial tension to reach relative minimum, and alter oil-wet characteristics of carbonate rocks towards more water-wet characteristics. The effect of CO2 dissolution in injection water, forming carbonated water containing dissolved ions, on these two parameters is obvious and improves them.In this communication, K2SO4, KI, MgSO4, Na2SO4, CaCl2, MgCl2, KCl, and NaCl salts, as binary ionic compounds, were used for producing smart water with concentrations of 1000+1000, 2000+2000, 5000+5000, and 10,000+10,000ppm. Then, the effects of dissolution of these salts on interfacial tension and contact angle between water, oil, and carbonate rock were studied. In addition, CO2 was added to the ionic solution with optimal compositions and densities in terms of minimum interfacial tension under the pressures of 6894.7, 10,342.1, and 13,789.5kPa, and its effects on the latter two parameters were investigated. After that, the effects of ions dissolved in seawater (10 times diluted seawater) on water-oil interfacial tension, wettability of carbonate rock and contact angle under the pressure of 101.4kPa in the absence of CO2, and under the pressures of 6894.7, 10,342.1, and 13,789.5kPa in the presence of CO2 were studied. All tests were conducted at constant temperature of the reservoir (75°C). The minimum interfacial tension was obtained for MgCl2+K2SO4 composition (6.73mN/m), which was lower than the interfacial tension between the initial amount of fresh water and oil (24.145mN/m) by 72%. This reduction reached 83% after carbonating the solution under 2000ppm and 75°C conditions. The minimum contact angle in the aged segment for KCl+MgCl2 composition with concentration of 2000+2000ppm was recorded as 39.80°, which decreased by 49.62% and reached 20.05° by adding CO2 under 13,789.5kPa condition. The interfacial tension between seawater (initial density) and crude oil, under 101.4kPa and 75°C conditions, was obtained as 27.464mN/m. The interfacial tension values under 6894.7, 10,342.1, and 13,789.5kPa conditions were obtained as 25.315mN/m, 25.146mN/m, and 21.464mN/m, respectively. These results reveal a decreasing trend after each dilution stage. In addition to trend, reduction of the initial contact angle in the aged segment in the solution after each dilution step indicates better performance of ionized seawater relative to normal seawater.

Studying the Potential of Calcite Dissolution on Oil Liberation from Rock Surfaces during Single-Well-Chemical-Tracer Tests by Coupling a Multiphase Flow Simulator to the Geochemical Package

Calcite mineral dissolution has been considered to be an important mechanism for dampening the considerable pH-variation during Single-Well-Chemical-Tracer (SWCT) tests by improving the buffer capacity of the aqueous solution. Other parameters that also could have a great effect on the geochemistry of the reservoir during the SWCT tests are water buffer capacity, soluble hydrocarbon components, and temperature. Additionally, calcite mineral dissolution has been also presented over the last decade as an underlying mechanism for liberation of the adsorbed oil from the surface by modified salinity water injection (MSWI) in carbonate reservoirs. This contradiction of effects of calcite dissolution might pose a challenge for the accuracy of the SWCT tests in carbonates. This concern motivated us to highlight the potential of the calcite dissolution on the oil liberation from the carbonate rock surfaces during the SWCT tests by coupling a multiphase flow simulator to the geochemistry package PHREEQC. The results show that although the calcite dissolution is marginal during injection time, it might be substantial during shut-in time which is much longer. During shut-in time, the results show that the potential of calcite dissolution on the oil liberation from the rock surfaces could be more significant at higher reservoir temperatures although initial solid calcite concentration and buffer capacity also could have an effect. It is also clear that the pH of the system reaches the lowest level when the shut-in time reaches the transient time (i.e., injection and production times) and it is not changed significantly afterwards. At longer shut-in times, the additional ester hydrolysis and acid product is neutralized by the calcite dissolution and the buffer capacity of water. Therefore, the probability of the liberation of the adsorbed oil from the rock surface is higher at larger shut-in times so that test designs with shorter shut-in times and even as short as the transient time for the carbonate reservoirs is highly recommended. We hope that this study can be used to minimize the uncertainties of the SWCT tests and improve the reliability of the Sor measurements.

Exploring mechanisms for wettability alteration in low-salinity waterfloods in carbonate rocks

Low Salinity waterfloods, even in carbonates, have received a great deal of attention because of their potential to significantly increase waterflood recoveries in addition to being cost effective. Wettability alteration has been found to play a major role in affecting higher recoveries from carbonates in low salinity floods. A large volume of research has accumulated for determining the effect of brine chemistry on wettability alteration and consequent recoveries. Both divalent cations (Ca2+, Mg2+) and anions (SO42−) as well as their interactions have been found to affect wettability. Charges on the mineral surface were also linked to observed wettability change. Despite the efforts, a clear understanding of the mechanisms for such wettability changes seems to be still elusive. Here in our work, first we have attempted to find viable alternatives for sulfates which pose fouling risks for reservoirs. Sulfur oxyanions such as bisulfites and metabisulfites have been found to be potential anions capable of affecting the desired wettability change without the risk associated with sulfates. Secondly, an effort has been made to understand the mechanism (s) behind such wettability alteration in carbonates during low salinity waterfloods based on our work and that by various authors. A potential mechanism has been proposed for wettability alteration, which seems to explain the works of many researchers. The mechanism is based on the isoelectric point of the carbonate rock surface, pH and interfacial energy between the aqueous brine solution and the rock surface. It is proposed that carbonates would be strongly oil-wet at the isoelectric point of the carbonate rock crystal, when the aqueous solution-rock interfacial tension is maximum. On the other hand, it would exhibit more water-wet or less oil-wet behavior, the further the pH of the brine solution is away from the isoelectric point of the carbonate rock. The wettability change is as a result of electrostatic attraction between polar water molecules with the charged surface that helps to bring down the brine-rock interfacial energy. This minimization of interfacial energy is manifested as the wettability change at the 3- phase carbonate mineral-oil-water contact line. The shift in the isoelectric point due to changes imposed in brine composition needs to be accounted for in addition to brine pH and salinity in order to optimize recoveries from low-salinity waterfloods.

Toward a hydrocarbon-based chemical for wettability alteration of reservoir rocks to gas wetting condition: Implications to gas condensate reservoirs

Recently, wettability alteration has been much attended by researchers for studying well productivity improvement in gas condensate reservoirs. Previous studies in this area only utilized water/alcohol based chemicals for this purpose. While, hydrocarbon nature of the blocked condensate in retrograde gas reservoirs, may motivate application of hydrocarbon based chemical agents. In this study, a new hydrocarbon based wettability modifier is introduced to alter wettability of carbonate and sandstone rocks to preferentially gas wetting condition. Static and dynamic contact angle measurements, spontaneous imbibition and core flooding tests were conducted to investigate the effect of proposed chemical on surface wetting behavior, and fluid flow characteristics at core scale. SEM, EDX, EDX map and FTIR tests are used to characterize the adsorbed chemical layer and also to endorse the adsorption of fluorinated chemicals on both sandstone and carbonate rock surfaces. It is inferred from the results of contact angle hysteresis at different levels of tilt angle that the surface roughness increased as a result of treatment with the new chemical. Measurements of surface free energy of calcite thin section at different tilt angles, by means of dynamic contact angle method, showed a significance decrease due to treatment with the new chemical, the factor of reduction ranges from 0.24 to 0.03. The results of air-water and air-n-decane spontaneous imbibition tests showed remarkable decrease in the ultimate imbibed liquids by a factor of 0.14 and 0.34, respectively. Also, core flooding experiment results demonstrated improvement of liquid phase endpoint relative permeability by a factor of 1.73 as a result of treatment with the proposed chemical fluid. The proposed chemical is miscible with dropped out condensate and does not suffer from instability due to reservoir brine salinity. Effectiveness, as well as hydrocarbon base of the proposed chemical makes it an attractive candidate for possible applications to enhance condensate recovery due to both condensate and water blockage in gas reservoirs by wettability alteration technique.

Synthesis of fluorine- doped silica-coating by fluorosilane nanofluid to ultrahydrophobic and ultraoleophobic surface

Liquid repellency treatment has many applications in various sectors including oil and gas reservoirs and self-cleaning surfaces. In this study, effect of silica, fluorine-doped silica and fluorine-doped silica-coating by fluorosilane nanofluid on ultrahydrophobic and ultraoleophobic surface of carbonate and sandstone rock were investigated. The nanoparticles were synthesized by sol-gel method and characterized using XRD, FTIR, FESEM and DLS and nanofluid was prepared. F–SiO2–F nanoparticle was adsorbed on surface of rocks and confirmed by FESEM and EDXA. Effect of nanofluid on wettability was investigated by measuring contact angles of water, crude oil, condensate, n-decane and ethylene glycol in air and stability of ultrahydrophobic and ultraoleophobic was investigated. Results show that nanofluid (0.05 wt% of nanoparticle) changes contact angle from strongly liquid-wet to strongly gas-wet in all systems. The original contact angle of water, crude oil, condensate, n-decane and ethylene glycol were 37.95°, 0°, 0°, 0° and 0° for carbonate rock and 40.30°, 0°, 0°, 0° and 0° for sandstone rock which altered to 146.47°, 145.59°, 138.24°, 139.06° and 146.52° for carbonate rock and 160.01°, 151.40°, 131.85°, 140.27° and 151.70° for sandstone rock after treatment. The ultraoleophobic and ultrahydrophobic stability were >48 h and 120 min.

Nanograin formation and reaction-induced fracturing due to decarbonation: Implications for the microstructures of fault mirrors

Principal slip zones often contain highly reflective surfaces referred to as fault mirrors, shown to consist of a nanogranular coating. There is currently no consensus on how the nanograins form, or why they survive weathering on a geological time-scale. To simplify the complex system of a natural fault zone, where slip and heat generation are inherently coupled, we investigated the effect of elevated temperatures on carbonate rock surfaces, as well as their resistance to water exposure. This allows us to isolate the role of the decarbonation process in the formation of nanograins. We used cleaved crystals of Iceland spar calcite, manually polished dolomite protolith, as well as natural dolomite fault mirror surfaces. The samples were heated to 200–800 °C in a ∼5 h heating cycle, followed by slow cooling (∼12 h) to room temperature. Subsequently, we imaged the samples using scanning electron microscopy and atomic force microscopy. Nanograin formation on all sample surfaces was pervasive at and above 600 °C. The Foiana fault mirror samples were initially coated with aligned naturally-formed nanograins, but display a non-directional nanogranular coating after heating. The nanograins that were formed by heating rapidly recrystallized to bladed hydroxides upon exposure to deionized water, whereas the nanograins on unheated fault mirror samples remained unchanged in water. This shows that the nanograins formed by heating alone are different from those formed in fault zones, and calls for a better characterization of nanograins and their formation mechanisms. Furthermore, we find a characteristic star-shaped crack pattern associated with reacted regions of the carbonate surfaces. The existence of this pattern implies that the mechanical stresses set up by the decarbonation reaction can be sufficiently large to drive fracturing in these systems. We propose that this mechanism may contribute to grain size reduction in fault zones.