Water-wet Conditions Research Articles

Effect of different low salinity flooding schemes and the addition of alkali on the performance of low-salinity waterflooding during the recovery of heavy oil from unconsolidated sandstone

Low salinity waterflooding (LSW) is a promising enhanced oil recovery process. The LSW advantage has been associated to changes in rock wettability toward a more water wet state. This study evaluated the effect of different flooding schemes on the performance of LSW in terms of production rate and incremental oil recovery from sand-pack systems. This work also investigated the main mechanism prompting sand wettability changes during LSW.Flooding Scheme-1 consisted of high salinity waterflooding, low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-2 consisted of low salinity waterflooding, alkali aided low salinity waterflooding, and low salinity waterflooding. Flooding Scheme-3 consisted of alkali aided low salinity flooding and low salinity waterflooding. The main mechanism causing wettability reversal was verified employing contact angle analysis, inductively coupled plasma spectrometry, and scanning electron microscopy.This new study reveals in a straightforward manner the effect of low salinity waterflooding schemes on both production rate and incremental oil recovery. LSW in secondary mode, as conducted in FS-2, expedited the oil production rate by 15% and increased the overall oil recovery by 20% relative to flooding schemes FS-1 and FS-3. Furthermore, this study determined that multi-component ionic exchange was the dominant mechanism for the reversal of sand wettability to a more water wet state.This paper provides new insights for heavy oil producers on the relevance of the flooding schemes during LSW and on the dominant mechanism for wettability alteration during the recovery of heavy oil from unconsolidated sands.

PH effect on wettability of –NH+-brine-muscovite system: Implications for low salinity effect in sandstone reservoirs

Wettability alteration remains the main mechanism of low salinity water flooding (LSWF) which is controlled by several factors including crude oil composition. Although presence of acidic components in crude oil confirmed to be necessary to enhance wettability during LSWF, yet the effect of basic components remain unclear. In this work we used the concept of surface energy to explicate the dependency of wettability on a high base number (BN) oil as a function of water pH, ion type and salinity. We measured Oil/Brine contact angle and interfacial tension, which then were used to compute Oil/Solid (mica) interfacial tension using Neumann's equation of state. In addition, we measured the zeta potential and simulated the concentration of base components (–NH+ groups) in the oil using a surface complexation model to understand the underlying mechanisms of wettability and interfacial tension alterasion. We found that wettebility is also dependant on the basic components of crude oil where pH plays a major role and salinity and ion type play a secondary role. Increasing pH (from pH=3 to pH=11) decreased the contact angle moving the system to a more hydrophilic or water-wet state (contact angle decreased from 162° to 68° for CaCl2 solution and from 163° to 66° for NaCl solution). We also found that Oil/Solid interfacial tension increased with pH, where changes were more pronounced in the presence of divalent cations compared to monovalent. We hypothesise that changes in the contact angle and Oil/Solid interfacial tension are due to the chemo-physical adsorption of –NH+ groups at the oil surface to the muscovite negative sites. The hypothesis is consistent with the changes in the zeta potential and –NH+ surface concentration computed from the surface complexation model. The results of this study underscore the importance of the basic component on system wettability as a function of pH, providing insights into the low salinity EOR in sandstone reservoirs.

The role of polar organic components in dynamic crude oil adsorption on sandstones and carbonates

An appropriated wettability characterization is crucial for the successful implementation of waterflooding operations. Understanding how crude oil adsorption takes place on different mineral surfaces and how these processes impact reservoir wettability are essential aspects that can help unlock and produce large underground oil reserves.
 Polar organic components (POC) present in crude oil are surface-active molecules with high affinity towards mineral surfaces. POCs are quantified by the acid and base numbers (AN and BN) with units of mgKOH/g. The POC adsorption behavior is highly influenced by the type of minerals and brines present in the reservoir system.
 This study aims to shed light onto the most important features of oil adsorption on carbonates and sandstones mineral surfaces; particular attention is given to the role of acidic components. Therefore, outcrop sandstone and carbonate materials were used. The sandstone material contains various silicates, including quartz, Illite clay, and feldspars. The carbonate outcrop material came from the Stevns Klint quarry in Denmark and is considered a very pure calcium carbonate with minimum silicate impurities.
 Dynamic adsorption tests were performed at 50°C by injecting low asphaltene crude oils into core plugs, and AN and BN values of the effluent oil samples were measured and compared with the influent oil values. Furthermore, spontaneous imbibition (SI) tests were performed to assess the wettability impact of crude oil injection in oil flooded cores.
 The results showed that after crude oil injection, the cores became mix-wet. Confirmation of a reduction in capillary forces and a shift towards a less water-wet state was reported for both mineralogies, i.e., sandstones and carbonates. The acidic polar components had a substantial impact on carbonates wettability, while on sandstones, the experiments suggested that acidic polar components had a lower impact on wettability than that observed in the basic polar components.

Ion-induced oil–water wettability alteration of rock surfaces. Part I: Polar interactions between oil and solid

We experimentally study the influence of inorganic salt ions on the wettability of originally oil-wet rock surfaces, formed by adsorbing polar molecules via polar interactions. It is found that the ions can alter the surface to a more water-wet state with a reduction in the water contact angle of about 20° at most. At lower concentrations, the effect of CaCl2 solutions is more obvious than that of NaCl solutions, and Na2SO4 solutions are more effective than NaCl solutions. Through a series of characterization, underlying mechanisms are revealed as: (1) the octadecylamine protonates at oil–water interface and attracts with the anions, reducing oil–water interfacial tension; (2) the cations are adsorbed on the negatively charged quartz surface, weakening the electronegativity of quartz surface and replacing the adsorbed octadecylamine molecules. Finally, a quantitative theoretical model is established based on the Young equation to predict the dependence of contact angle on the ion concentration.

Interfacial properties of crude oil/imidazolium based ionic liquids in the presence of NaCl and Na2SO4 during EOR process

The current investigation is aimed to investigate the effect of new families of ionic liquid (IL) based surfactants for considering the enhanced oil recovery process. Imidazolium based ILs with chloride anion ([Cn mim][Cl]) with long alkyl chains, (n = 12 and 18) are synthesized and their effectiveness on the interfacial tension (IFT) and emulsification phenomena at the co-presence of NaCl and Na2SO4 salts are examined. Dynamic IFT and critical micelle concentration (CMC) values of different solutions were measured and determined. Moreover, the performance of the considered solutions at the CMC was examined on the wettability alteration of the oil-wet carbonate rock surface. The obtained results revealed that for the shorter alkyl chain length IL (C12), the presence of NaCl was more effective compared with the Na2SO4 while a reverse trend is observed for the longer alkyl chain length IL (C18). The contact angle measurement revealed that IL solutions containing sulfate anion altered the wettability of the oil-wet surface (from about 160°) toward the strongly water-wet state (41° for C12 and 45° for C18) and alkyl chain length introduces no significant effect. Besides, the solution containing chloride anion affected by IL type, that means longer alkyl chain length (C18) was unable to change wettability toward the water-wet state and wettability changed to 113° while C12 changed wettability to 34°. It is also found that although increasing the concentration of both ILs led to the lower IFT values with the minimum value of 0.6 mN/m, raising the temperature from 298 K to 348 K increased the IFT values.

Phenomenological study of the micro- and macroscopic mechanisms during polymer flooding with SiO2 nanoparticles

The incorporation of SiO2 nanoparticles in polymer solutions for oil recovery has generated considerable interest in recent research. Although this approach improves the polymer performance, little evidence is available about the recovery mechanisms that intervene in the polymeric nanofluid suspension or polymer nanofluid. Therefore, the purpose of this study is to describe the microscopic and macroscopic mechanisms involved during oil recovery with polymeric nanofluid flooding. Changes in the rheology and capillary forces (contact angle and interfacial tension) in the polymeric solution due to the incorporation of SiO2 nanoparticles were evaluated. Coreflooding tests were made to evaluate the retention, apparent viscosity, and impact on the relative permeability. Finally, macroscopic oil recovery was measured by displacement tests in a quarter 5-spot system, and microscopic displacement was evaluated by a microfluidic test. Results indicated that the conservation of a favorable mobility ratio in polymeric nanofluids along the porous medium is the phenomenon that most impacts macroscopic oil recovery. This behavior was associated with a reduction in loss retention and the conservation of the apparent viscosity in the porous medium. A direct relationship was observed between the concentration of SiO2 nanoparticles and the viscoelastic behavior of the polymer and the water-wet condition on the surface exposed to the nanofluid. Moreover, residual oil distribution in microscopic displacement revealed that the reduction in residual oil mainly originated from the decrease in the size of the oil clusters. Consequently, the evidence suggests that microscopic oil displacement in polymeric nanofluid is attributed to the reduction in the capillary forces and increases in the viscoelastic nature of the polymer. Results in this work indicated that the additional oil recovery obtained by polymeric nanofluid flooding is generated by the improvement of macroscopic recovery mechanisms and the activation of microscopic mechanisms.

Pore scale visualization of fluid-fluid and rock-fluid interactions during low-salinity waterflooding in carbonate and sandstone representing micromodels

Low Salinity Waterflooding (LSWF) has become a popular tertiary injection EOR method recently. Both fluid-fluid and fluid-rock interactions are suggested as the contributing mechanisms on the effectiveness of LSWF. Considering the contradictory remarks in the literature, the dominating mechanisms and necessary conditions for Low Salinity Effect (LSE) varies for different crude oil-brine-rock (CBR) systems. The aim of the present study is to investigate LSE for an oil field in the Middle East that is composed of separate sandstone and limestone layers. Contact angles and Interfacial Tension (IFT) are measured to have more insight on the CBR under investigation. Visual experiments were conducted in micromodels to determine the dominating mechanisms of LSE. Experiments were conducted under water-wet and oil-wet conditions for both sandstone and limestone representing micromodels. Several secondary and tertiary injection scenarios were performed with different levels of salinities. Consecutive injection of high-salinity and low-salinity water illustrated that LSE occurs under certain conditions. For both rock types, during the secondary high salinity injection, the oil trapping mechanism was mostly snap-off under water-wet condition, while fingering/bypassing was dominant under oil-wet conditions. LSWF causes diminutive changes of saturation redistribution in water-wet micromodels. Even in rare occasions that oil ganglia started to reshape or redistribute, it became trapped again in the downstream pores of the model, and not produced effectively. Contrary to this, LSWF was very effective under oil-wetting conditions. Continuous oil films, which exist in oil-wet condition, are beneficial for the effectiveness of LSE. Measured IFT and contact angles cannot justify the observed LSE. Additionally in the designed micromodels, any contribution of clay or fine migration to the LSE is ruled out. Spontaneous formation of the micro-emulsion was a very weak mechanism in our experiments and did not contribute to pushing oil out of the dead end pores or divert the flow path to the un-swept areas. Visual investigations suggested that formation of the visco-elastic interface can be the dominating mechanism for LSE in the investigated CBRs which is more effective in the case of oil-wet system due to the lack of snap-off trapping mechanism.

Wettability alteration and oil recovery by surfactant assisted low salinity water in carbonate rock: The impact of nonionic/anionic surfactants

Combining low salinity water (LSW) and chemicals to enhance oil recovery has recently received more attention in the oil industry. In this study, a systematic experimental procedure was conducted to evaluate the performance of low salinity nonionic surfactant with/without anionic surfactant in wettability alteration and oil recovery of oil-wet carbonate having high salinity formation water (FW) (196 g/L) and moderate temperature (75 °C). A polyethoxylated nonionic surfactant (C13EO12) and two anionic surfactants: sulfonate (IOS 20–24) and carboxylate (AEC 938) were used in this study. Contact angle (CA) results showed that low salinity nonionic surfactant was effective in altering the wettability of oil-wet calcite toward water-wet state. While the low salinity anionic surfactants' systems were only able to reduce the oil-wetness of the oil-wet calcite. When nonionic surfactant is mixed with anionic surfactant, the wettability of oil-wet calcite was altered toward intermediate-wet or only a reduction of its oil-wetness occurred depending on the type of the anionic surfactant. Spontaneous imbibition tests using oil-wet limestone cores showed that among the low salinity single surfactants’ systems, carboxylate anionic surfactant resulted in the highest oil recovery (61% of oil initially in place (OIIP)) and sulfonate anionic surfactant resulted in the lowest oil recovery (31% of OIIP). The low salinity nonionic surfactant recovered 51% of OIIP by spontaneous imbibition. Addition of sulfonate anionic surfactant to the nonionic surfactant resulted in an oil recovery of 49% of OIIP while addition of carboxylate anionic surfactant to the nonionic surfactant considerably improved the oil recovery to 74% of OIIP. Hence, selection of proper surfactant class is crucial for a successful oil recovery.

Graphene Quantum Dots for the Mobilization and Solubilization of Nonaqueous Phase Liquids in Natural Porous Media

This study proposes an approach to synthesize graphene quantum dots (QDs) with remarkable physicochemical properties that allow them to effectively mobilize and solubilize nonaqueous phase liquids (NAPLs) such as crude oils in porous media. QDs are first extracted by mild oxidation of coal and then partially functionalized by alkylamines using a starch template to generate engineered QDs (EQDs). When mixed in equal amounts, the nanofluid can synergistically interact at oil/water interfaces and lower the interfacial tension (IFT) from 19.6 to 0.9 mN/m. The two quantum dots exhibit different behavior on minerals. EQDs do not adsorb because of steric hindrance caused by their aliphatic tails, whereas QDs adsorb moderately on sandstones through hydrogen bonding, leading to wettability alteration from oil-wet to weakly water-wet state. The nanofluid provides mixed-wet conditions that, together with IFT reduction, result in 21 vol % of incremental NAPL recovery compared to waterflooding. The performance of this mixture is curbed in carbonates with only 9.6 vol % of additional recovery because of strong QD adsorption and pore plugging. The ability of this nanofluid to alter wettability was further confirmed in a miniature silicate-rich rock using X-ray microtomography. The in situ contact angle distributions on quartz and carbonate shifted to a more water-wet state and covered a wide range of values, denoting a nonuniform wettability reversal. Thus, the application of QD-based nanofluids is more suitable in silicate-rich formations where chemical retention by the rock is minimum. This study paves the way for the development of more EQDs by tuning their structure via chemical functionalization of their oxygen-rich active sites.

Detection of Corrosion-Indicating Oxidation Product Colors in Steel Bridges under Varying Illuminations, Shadows, and Wetting Conditions

Early detection of corrosion in steel bridges is essential for strategizing the mitigation of further corrosion damage. Although various image-based approaches are available in the literature for corrosion detection, most of these approaches are tested on images acquired under uniform natural daylight illuminations i.e., inherent variations in the ambient lighting conditions are ignored. Owing to the fact that varying natural daylight illuminations, shadows, water wetting, and oil wetting are unavoidable in real-world scenarios, it is important to devise a robust technique for corrosion identification. In the current study, four different color spaces namely ‘RGB’, ‘rgb’, ‘HSV’ and ‘CIE La*b*’ along with a multi-layer perceptron (MLP) is configured and trained for detecting corrosion under above-mentioned real-world illumination scenarios. Training (5000 instances) and validation (2064 instances) datasets for this purpose are generated from the images of corroded steel plates acquired in the laboratory under varying illuminations and shadows, respectively. Each combination of color space and an MLP configuration is individually assessed and the best suitable combination that yields the highest ‘Recall’ value is determined. An MLP configuration with a single hidden layer consisting of 4 neurons (1st Hidden Layer (HL)(4N)) in conjunction with ‘rgb’ color space is found to yield the highest ‘Accuracy’ and ‘Recall’ (up to 91% and 82% respectively). The efficacy of the trained MLP to detect corrosion is then demonstrated on the test image database consisting of both lab-generated partially corroded steel plate images and field-generated images of a bridge located in Moorhead (Minnesota). Lab-generated images used for testing are acquired under varying illuminations, shadows, water wetting, and oil wetting conditions. Based on the validation studies, ‘rgb’ color space and an MLP configuration consisting of single hidden layer with 4 neurons (1st HL(4N)) trained on lab-generated corroded plate images identified corrosion in the steel bridge under ambient lighting conditions.

Interaction of low salinity surfactant nanofluids with carbonate surfaces and molecular level dynamics at fluid-fluid interface at ScCO2 loading

HypothesisThe advanced low salinity aqueous formulations are yet to be validated as an injection fluid for enhanced oil recovery (EOR) from the carbonate reservoirs and CO2 geosequestration. Interaction of various ionic species present in the novel low salinity surfactant nanofluids with scCO2/CO2 saturated aqueous phase interface and at the interface of CO2 saturated aqueous phase/mixed wet (with CO2 and Decane) limestone surface at the conditions of low salinity at reservoir conditions are to yet to be understood. ExperimentsThis study, carried out for the first time in low salinity at scCO2 loading conditions at 20 MPa pressure and 343 K temperature, comprises of wettability study of the limestone surface by aqueous phase contact angle measurements using ZrO2 nanoparticles (in the concentration range of 100–2000 mg/L) and 0.82 mM Hexadecyltrimethylammonium bromide (CTAB) surfactant. Molecular dynamics simulations results were used to understand the underlying mechanism of wettability alteration and interfacial tension (IFT) change. FindingsThis study reveals that a low dosage (100 mg/L) of ZrO2 nanoparticles forming ZrO2-CTAB nano-complexes helps in wettability alteration of the rock surface to more water-wetting state; certain ionic species augment this effect when used in appropriate concentration. Also, these nano-complexes helps in scCO2/CO2 saturated aqueous phase IFT reduction. This study can be used to design advanced low salinity injection fluids for water alternating gas injection for EOR and CO2 geosequestration projects.

In Situ Wettability Investigation of Aging of Sandstone Surface in Alkane via X-ray Microtomography

Wettability of surfaces remains of paramount importance for understanding various natural and artificial colloidal and interfacial phenomena at various length and time scales. One of the problems discussed in this work is the wettability alteration of a three-phase system comprising high salinity brine as the aqueous phase, Doddington sandstone as porous rock, and decane as the nonaqueous phase liquid. The study utilizes the technique of in situ contact angle measurements of the several 2D projections of the identified 3D oil phase droplets from the 3D images of the saturated sandstone miniature core plugs obtained by X-ray microcomputed tomography (micro-CT). Earlier works that utilize in situ contact angles measurements were carried out for a single plane. The saturated rock samples were scanned at initial saturation conditions and after aging for 21 days. This study at ambient conditions reveals that it is possible to change the initially intermediate water-wet conditions of the sandstone rock surface to a weakly water wetting state on aging by alkanes using induced polarization at the interface. The study adds to the understanding of initial wettability conditions as well as the oil migration process of the paraffinic oil-bearing sandstone reservoirs. Further, it complements the knowledge of the wettability alteration of the rock surface due to chemisorption, usually done by nonrepresentative technique of silanization of rock surface in experimental investigations.

Mechanistic study to investigate the injection of surfactant assisted smart water in carbonate rocks for enhanced oil recovery: An experimental approach

More than half of the world's discovered oil is held in carbonate reservoirs, most of which are naturally oil-wet fractured reservoirs. Oil Recovery efficiency can be improved noticeably if the rock wettability is changed from an oil-wet to a water-wet state. However, what factors control the wettability alteration are not clearly specified. In this study, a comprehensive mechanistic study is performed using different experimental tools to investigate the effects of active ions, non-active ions, CTAB, and different combinations of ions and CTAB on the sample rock's wettability. The results indicate that using CTAB and a smart water solution, in which the sodium and chloride ions are eliminated and the concentration of sulfate ions is increased, (SW-0NaCl-4SO42− + 1CTAB) reduced the contact angle to 43.58°. The zeta potential value of the oil-wet calcite powder increased from −61.12 to −7.6 mV after treatment with SW-0NaCl-4SO42− + 1CTAB. Moreover, the mean roughness value of oil-wet calcite powder increased from 5.02 to 25.89 nm after treatment with SW-0NaCl-4SO42− + 1CTAB. In fact, sulfate ions are capable of removing the strongly adsorbed carboxylic groups from the surface and changing the wettability of the calcite surface to a more water-wet state. Also, the cationic surfactant monomers tend to ionically react with carboxylic groups and separate them from the calcite surface. Moreover, the removal of sodium and chloride ions also leads to significant changes in the wettability. The imbibition results showed that the change of wettability from an oil-wet to a more water-wet state results in a critical increase in oil recovery efficiency during imbibition of distilled water into the calcite rock slice. High oil recovery efficiency can be obtained by optimizing the smart water solution composition and using a proper concentration of surfactant.

Application of anionic surfactant∖engineered water hybrid EOR in carbonate formations: An experimental analysis

Abstract A hybrid enhanced oil recovery (EOR) method by combining low salinity water (LSW) and low salinity surfactant (LSS) flooding techniques was designed. Different experiments were done to screen the Caspian seawater (SW) with altered ionic composition and surfactant, for the optimized performance in Kazakhstani carbonate oil fields. Changing to a more water-wet state and creating the middle phase were studied as the main criteria to select the best-engineered brine and anionic surfactant. The largest alteration towards the water-wet condition was recorded at 10 times dilution of the SW with 3- and 6- times spiked calcium and sulfate ions, respectively (10xSW-6SO4, Mg, 3Ca). This combination of anionic surfactants with carbonate formations is considered as a new approach in hybrid EOR methods. Among the anionic surfactants screened, Soloterra-113H (Alkyl Benzenesulfonic acid) showed the best solubilization ratio, aqueous stability, and Winsor type 3 microemulsions. The wettability alteration by the combination of optimized brine and screened surfactant was greater compared to the standalone LSW, which was confirmed by the 10° difference in contact angle measurement. The microemulsion phase constituted nearly 40% of the total height of the oil/brine column by the hybrid method. The recovery factor after injecting formation water was 52%, and it increased to 61% after optimized LSW injection. After switching to the engineered brine/surfactant, the recovery factor reached 70%, which proves the effectiveness of the hybrid method. The proposed combined method works better than either standalone EOR method due to the higher alteration in capillary number by changing wettability and reducing IFT, which leads to higher oil recovery.

Pore-scale imaging with measurement of relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions

Using micro-CT imaging and differential pressure measurements, we design a comparative study in which we simultaneously measure relative permeability and capillary pressure on the same reservoir sandstone sample under water-wet and mixed-wet conditions during steady-state waterflooding experiments. This allows us to isolate the impact of wettability on a pore-by-pore basis and its effect on the macroscopic parameters, capillary pressure and relative permeability, while keeping the pore-space geometry unchanged.First, oil and brine were injected through a water-wet reservoir sandstone sample at a fixed total flow rate, but in a sequence of increasing brine fractional flows with micro-CT scans of the fluid phases taken in each step. Then the sample was brought back to initial water saturation and the surface wettability of the sample was altered after prolonged contact with crude oil and the same measurement procedure was repeated on the altered-wettability sample which we call mixed-wet.Geometric contact angles were measured, which discriminated the water-wet and mixed-wet cases with average values of 75° and 89° respectively. Additionally, an energy balance was used to determine the effective contact angles for displacement which indicated that a higher advancing contact angle of 116° was needed to displace oil in the mixed-wet case. For the water-wet experiment the filling sequence was pore-size dependent, with a strong correlation between pore size and oil occupancy. However, in the mixed-wet experiment the principal determinant of the filling sequence was the wettability rather than the pore size, and there was no correlation between pore size and the residual oil occupancy.The oil-water interfacial area had a larger maximum in the mixed-wet case which was supported by the observation of sheet or saddle-like menisci shapes present throughout the sample volume that impede the flow. These shapes were quantified by much larger negative Gaussian curvature which indicated better connectivity of the phases, consistent with the lower residual oil saturation. Mean curvature and associated capillary pressure were positive for the water-wet case but decreased to a negative value for the mixed-wet case pointing to forced displacement from oil-wet pores. This analysis explained why the relative permeabilities for the mixed-wet case were lower than for the water-wet case for the same fractional flow.

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.

Variations in Wettability and Interfacial Tension during Alkali-Polymer Application for High and Low TAN Oils.

The injection of chemicals into sandstones can lead to alterations in wettability, where oil characteristics such as the TAN (total acid number) may determine the wetting state of the reservoir. By combining the spontaneous imbibition principle and the evaluation of interfacial tension index, we propose a workflow and comprehensive assessment to evaluate the wettability alteration and interfacial tension (IFT) when injecting chemical-enhanced oil-recovery (EOR) agents. This study examines the effects on wettability alteration due to the application of alkaline and polymer solutions (separately) and the combined alkali–polymer solution. The evaluation focused on comparing the effects of chemical agent injections on wettability and IFT due to core aging (non-aged, water-wet and aged, and neutral to oil-wet), brine composition (mono vs. divalent ions); core mineralogy (~2.5% and ~10% clay), and crude oil type (low and high TAN). Amott experiments were performed on cleaned water-wet core plugs as well as on samples with a restored oil-wet state. IFT experiments were compared for a duration of 300 min. Data were gathered from 48 Amott imbibition experiments with duplicates. The IFT and baselines were defined in each case for brine, polymer, and alkali for each set of experiments. When focusing on the TAN and aging effects, it was observed that in all cases, the early time production was slower and the final oil recovery was longer when compared to the values for non-aged core plugs. These data confirm the change in rock surface wettability towards a more oil-wet state after aging and reverse the wettability alteration due to chemical injections. Furthermore, the application of alkali with high TAN oil resulted in a low equilibrium IFT. By contrast, alkali alone failed to mobilize trapped low TAN oil but caused wettability alteration and a neutral–wet state of the aged core plugs. For the brine composition, the presence of divalent ions promoted water-wetness of the non-aged core plugs and oil-wetness of the aged core plugs. Divalent ions act as bridges between the mineral surface and polar compound of the in situ created surfactant, thereby accelerating wettability alteration. Finally, for mineralogy effects, the high clay content core plugs were shown to be more oil-wet even without aging. Following aging, a strongly oil-wet behavior was exhibited. The alkali–polymer is demonstrated to be efficient in the wettability alteration of oil-wet core plugs towards a water-wet state.

Impact of SO42\u2212, Ca2+, and Mg2+ ions in Caspian Sea ion-engineered water on the rate of wettability alteration in carbonates

Tuning the salinity and concentration of potential-determining ions, such as Mg2+, Ca2+, and SO42−, could alter the wettability toward a more water-wet state. The rate of alteration in carbonate rock wettability is a critical parameter to design the duration of the ion-engineered water flooding. Characteristic experiments, such as dynamic contact angle and pH measurements, ion chromatography, and spontaneous imbibition, are applied to study the rate of wettability alteration using different samples of ion-engineered water. Our study shows that the Caspian Sea water (CSW) with a salinity of 15,000 ppm is an efficient displacing fluid as it can initiate the multi-ion exchange (MIE) mechanism and alter the wettability from 86° to 35° within 2 d. The adjustment of salinity and active ion concentration makes the MIE mechanism much faster. For example, with five times diluted CSW, the same change in wettability is only achieved only within 9 h. Spiking the concentration of Ca2+ and SO42− ions is used to further shift the contact angle to 22° within 9 h. Spontaneous imbibition tests demonstrate that the rate of oil production doubles as a result of the ion-engineered brine due to the faster MIE process. The results obtained from this research work suggest that even a short period of interaction with optimized engineered water can affect the brine, oil, and carbonates interactions and change the reservoir rock initial wettability from neutral to strongly water-wet state. This allows to efficiently design engineered water flooding based on CSW in the field scale and make such projects more profitable.

Insights into effects of water chemistry on the sandstone wetting characteristics

Ion-engineered water injection has been received more attention as a promising method to produce extra oil from oil-wet rocks mainly through altering rock wettability. In this paper, we aimed to provide a mechanistic experimental study on the effects of water chemistry on the dynamic behavior of rock wettability for a system of clayey sandstone/asphaltenic crude oil/ion-engineered seawater at 80 °C. To explore the effect of ionic composition on the wettability of oil-wet sandstones, diluted seawater with different concentrations of potential determining ions (PDIs: calcium, magnesium and sulfate) were designed. We investigated the mutual impact of PDIs on the sandstone wettability by tracking the contact angle profile aided by zeta potential and pH data. We found that as the ionic strength decreases, rock wettability alters to a more water-wet condition although there is an optimum salinity beyond that no further improvement could be obtained in rock wettability. Such a positive impact on rock wettability was justified by the establishment of a thicker electrical double layer and higher solubility of organic components in the aqueous phase. Also, the capability of PDIs to make a hydrophilic surface was found to be sulfate > calcium ≫ magnesium. This trend was supported by larger zeta potential and pH value mainly due to multiple ion exchange processes. Statistical interpretations of wettability alteration results in the light of response surface methodology revealed that dilution of injected brine could not be a sufficient condition for altering sandstone wettability. In fact, tuning the water chemistry with the focus on the ionic composition needs to be considered for a successful wettability alteration process.

Investigation of interactions between silica nanoparticle, alkaline, and polymer in micromodel flooding for enhanced oil recovery

ABSTRACT Given that alkaline-polymer flooding features the two mechanisms of the increase in viscosity of injection fluid and the decrease in oil/solution interfacial tension, it is common among chemical flooding methods. It should be noted that currently, scanty information is existing on the effect of nanoparticles on alkaline-polymer flooding. Hence, this study explores the role of silica nanoparticles in alkaline-polymer flooding along with their effects on the change of wettability, and also the viscosity of the solution as well as on the polymer adsorption. To this end, contact angle, viscosity, and static adsorption tests were carried out. Afterward, a test was designed by adopting a response surface method to determine the degree of importance of alkaline, nanoparticles, and polymer in enhanced oil recovery through micromodel flooding. The results of the viscosity test demonstrated that by rising the nanoparticle concentration, viscosity increases initially and then decreases. In addition, by increasing silica nanoparticle concentration to 0.1 wt%, the contact angle can decrease to around 30° at certain concentrations of polymer and alkaline, resulting in a more water-wet condition. Static adsorption tests showed that nanoparticles reduce polymer adsorption on the rock, and when 1 wt% of alkaline and 0.08 wt% polymer were employed, polymer adsorption rate at concentrations of 0, 0.05, and 0.1 wt % of silica nanoparticles was 58.45, 53.12, and 47.23 mg/g, respectively. Also, the results of the design of experiments indicated that polymer, alkaline, and nanoparticles, respectively, have the greatest effect on increasing oil recovery. Furthermore, at a constant concentration of alkaline and polymer, an optimum concentration was determined for the nanoparticle. Up to that concentration, nanoparticles in alkaline-polymer flooding increased the rate of oil recovery, and from this optimal concentration onward, the presence of the nanoparticles showed a reverse effect. It should be noted that the maximum oil recovery was 64.46% at concentrations of 1 wt% of alkaline, 0.08 wt% of polymer and 0.055 wt% of nanoparticle, and the presence of silica nanoparticle in alkaline-polymer flooding can improve the efficiency of oil recovery by about 3– 4%.