Low Salinity Waterflooding Research Articles

Enhancing oil recovery by nano SiO<sub>2</sub> expansion oil displacement agent

As a new mechanism of enhancing oil recovery by low-salinity waterflooding, osmotic pressure has been widely studied in recent years. The injected water molecules enter the original formation water-drops wrapped by oil droplets under osmotic pressure, resulting in apparent expansion of crude oil. However, at present, the effect of osmotic pressure alone on crude oil droplets expansion is not obvious, and the research is only limited to qualitative research, lacking quantitative analysis. In this study, three kinds of nano silica are used as an oil droplet expansion displacement agents, and the water in oil (W/O) emulsion is used to simulate the original oil-water distribution in the reservoir to observe the expansion effect of W/O emulsion droplets and quantitatively calculate droplets’ expansion ratio. The experimental results show that both hydrophilic and hydrophobic nano silica can enhance the expansion ratio of oil droplets, and the expansion ratio by hydrophilic HS-40 nano silica is higher than that by other two kinds of nano silica because of its smaller particle size and higher absolute zeta potential. With the increase of HS-40 concentration, the surfactant molecules at the oil-water interface enter the oil droplets and accelerate the expansion of the droplets. The maximum expansion ratio reaches 3.29 when the concentration of HS-40 is 0.20%. With the continual increase of HS-40 concentration, nano silica particles will hinder the transfer of water molecules at the oil-water interface into the droplets. On the condition that there are large salinity differences between formation water and injection water, the existence of nano silica can accelerate the expansion of oil droplets, which provides a new way for low-salinity waterflooding.

Comprehensive investigation of low salinity waterflooding in carbonate reservoirs

Waterflooding has been practiced as a secondary recovery mechanism for many years with no regard to the composition of the injected brine. However, in the last decade, there has been an interest to understand the impact of the injected water composition and the low salinity waterflooding (LSWF) in oil recovery. LSWF has been investigated through various laboratory tests as a promising method for improving oil recovery in carbonate reservoirs. These experiments showed diverse mechanisms and results. In this study, a comprehensive review and analysis for results of more than 300 carbonate core flood experiments from published work were performed to investigate the effects of several parameters (injected water, oil, and rock properties along with the temperature) on oil recovery from carbonate rock. The analysis of the results showed that the water composition is the key parameter for successful waterflooding (WF) projects in the carbonate rocks. However, the salinity value of the injected water seems to have a negligible effect on oil recovery in both secondary and tertiary recovery stages. The study indicated that waterflooding with optimum water composition can improve oil recovery up to 30% of the original oil in place. In addition, the investigation showed that changing water salinity from LSWF to high salinity waterflooding can lead to an incremental oil recovery of up to 18% in the tertiary recovery stage. It was evident that applying the optimum composition in the secondary recovery stage is more effective than applying it in the tertiary recovery stage. Furthermore, the key parameters of the injected water and rock properties in secondary and tertiary recovery stages were studied using Fractional Factorial Design. The results revealed that the concentrations of Mg2+, Na+, K+, and Cl− in the injected water are the greatest influence parameters in the secondary recovery stage. However, the most dominant parameters in the tertiary recovery stage are the rock minerals and the concentration of K+, HCO3−, and SO42− in the injected water. In addition, it appears that the anhydrite percentage in the carbonate reservoirs may be an effective parameter in the tertiary WF. Also, there are no clear relations between the incremental oil recovery and the oil properties (total acid number or total base number) in both secondary and tertiary recovery stages. In addition, the results of the analysis showed an incremental oil recovery in all ranges of the studied flooding temperatures. The findings of this study can help to establish guidelines for screening and designing optimum salinity and composition for WF projects in carbonate reservoirs.

A Comparison of Different Nanoparticles’ Effect on Fine Migration by Low Salinity Water Injection for Oil Recovery: Introducing an Optimum Condition

Abstract Today, enhance oil recovery (EOR) methods are attracting more attention to increase the petroleum production rate. Some EOR methods such as low salinity water flooding can increase the amount of fine migration and sand production in sandstone reservoirs which causes a reduction in permeability and inflict damages on to the reservoir and the production equipment. One of the methods to control fine migration is using nanotechnology. Nanoparticles (NPs) can reduce fine migration by various mechanisms such as reducing the zeta potential of fine particles’ surfaces. In this paper, three NPs including SiO2, MgO, and Al2O3’s effects on controlling fine migration and sand production were investigated in two scenarios of pre-flush and co-injection using sandpack as a porous media sample. When NPs are injected into the porous media sample, the outflow turbidity and zeta potential of particles decrease. Experiments showed that SiO2 has the best effect on controlling fine migration in comparison with other NPs and it could reduce fine migration 69% in pre-flush and 75% in co-injection. Also, MgO and Al2O3 decreased fine migration 65% and 33% in the pre-flush scenario and 49% and 13% in the co-injection scenario, respectively.

Electrostatic Characterization of the −COOH–Brine–Clay System: Implications for Wettability Alteration during Low Salinity Waterflooding in Sandstone Reservoirs

Electrostatic Characterization of the −COOH–Brine–Clay System: Implications for Wettability Alteration during Low Salinity Waterflooding in Sandstone Reservoirs

Molecular dynamics simulation for the effect of cation replacement on the oil-brine-rock interaction

The low salinity waterflooding can increase oil recovery by 5%-20% in sandstones, which has attracted more and more attention. However, the mechanism of low salinity waterflooding is not clear. In this paper, the effect of cation replacement on the interaction between oil and silica is investigated via molecular dynamics simulation to reveal the mechanism of low salinity waterflooding. The results show that the stable adsorption of oil droplets on the silica surface is mainly due to the strong interaction between oil and rock caused by cations. Replacing Ca2+ with Na+ can effectively reduce the interaction between oil and rock and make oil droplets easier to be peeled off. This work is helpful for the further study of the oil-brine-rock interaction and can provide theoretical guidance for the oil film stripping of sandstone reservoir.

The effect of carbonate rock wettability on the performance of low salinity waterflooding: an experimental approach

While the “low salinity waterflooding” (LSWF) has been praised for enhancing oil recovery from different core rocks, the performance of the technique in different wettability environments remains unclear. The consensus is that LSWF does not work well in water-wet carbonate oil reservoirs. The main research objective was to determine the effect of LSWF on the displacement efficiency (DE) in different wettability environments. Carbonate core flooding experiments on rocks with different wettabilities were performed at in-situ reservoir conditions using seawater as a “base water”. Seawater was sequentially diluted 10 to 50 times and spiked 2 and 6 times with sulfate. Following sequential flooding with four different waters, the DEs were measured for different wettabilities. Five different sequential brine floodings were performed on carbonate rocks. Results indicated that optimum low salinity water is a function of system wettability. Seawater (≈ 50,000 ppm) is the optimum brine for oil-wet and intermediate-wettability systems. Sequential flooding consisting of seawater followed by diluted seawater in a water-wet system yielded the highest DE of 88%. Besides, low-salinity brine followed by sulfate performed better in a water-wet environment than in oil- and intermediate-wettability systems.

Pore-Scale Simulation of the Interplay between Wettability, Capillary Number, and Salt Dispersion on the Efficiency of Oil Mobilization by Low-Salinity Waterflooding

Summary Nonuniform mixing during low-salinity waterflooding (LSWF) is a function of the pore geometry and flow patterns within the porous system. Salinity-dependent wettability alteration (WA) changes the entry capillary pressure, which may mobilize the trapped oil depending on the flow regime and salt dispersion pattern. The complex interplay between the wettability, capillary number (NCa), and salt dispersion caused by pore-scale heterogeneity on the efficiency of LSWF is not well understood. In this paper, direct numerical simulations in a pore-doublet model (PDM) were carried out with OpenFOAM® (OpenCFD, Berkshire, UK) using the volume-of-fluid (VOF) method. Oil trapping and remobilization were studied at relevant NCa as low as 10−6 under different initial wettability states. Depending on the effective salinity ranges (ESRs) for the low-salinity effect (LSE), three WA models were implemented, and the effects of WA degree and salinity distribution on LSWF flow dynamics were investigated. The slow process of WA by means of thin film phenomena was captured by considering a diffuse interface at the three-phase contact line. Because of the pore structure of the pore doublet, only in nonwater-wet cases, oil is trapped in the narrower side channel (NSC) after high-salinity waterflooding (HSWF) and may be remobilized by LSWF. In strongly oil-wet cases, oil is recovered gradually by LSWF by means of a film-flow mechanism near the outlet. In moderately oil-wet cases, however, the entire trapped oil ganglion can be mobilized, provided that the entry capillary pressure is sufficiently reduced. The degree of WA, ESR, kinetics of WA, and the wettability of pore surface at the outlet are determining factors in the drainage of the trapped oil. The salt dispersion pattern in the flowing region [i.e., wider side channel (WSC)] controls the wettability distribution and the rate and magnitude of oil recovery from the stagnant region (i.e., NSC). The difference between the WA models is more apparent near the outlet, where the salinity profile is more dispersed. The ESR in which WA occurs determines the speed of the entry capillary pressure reduction and, thus, the recovery factor. In cases where WA occurs at a salinity threshold (ST), the highest recovery is obtained, whereas with the full-salinity-range WA model, the oil recovery performance is lowest. From the capillary desaturation perspective, it is found that the LSE becomes more pronounced when NCa is less than 10−5, and the dispersion regime is in the power-law interval. Because the adverse effect of salt dispersion in the flowing region is delayed, the LSE is intensified. For the simulations to be representative of the actual conditions in the porous medium, much lower NCa than currently used in many research works must be studied. Otherwise, the simulations may lead to over- or underestimation of the LSE. The synergetic or antagonistic effects caused by the interplay between viscous and capillary forces and dispersion may lead to total recovery or entrapment of oil, regardless of WA. Based on the pore geometry, initial wettability state, and balance of forces, the mobilized oil may flow past the conjunction (favorable) or in the backward direction (unfavorable) to the WSC and get retrapped. Successful drainage of oil from the pore system after WA is essential for observing incremental oil recovery by LSWF.

Application of DLVO Modeling to Study the Effect of Silica Nanofluid to Reduce Critical Salt Concentration in Sandstones

Critical salt concentration (CSC) is the minimum salt concentration of injected water used for different oil recovery operations, below which fines migration initiates within sandstone reservoirs having clay contents and could be one of the potential causes of formation damage. This paper estimated CSC for Berea sandstone-NaCl brine system experimentally and by using DLVO modeling based on Van der Waals and electric double layer (EDL) surface forces. Furthermore, the effectiveness of silica nanofluid to reduce CSC and control fines migration was investigated. At different salinities of the injected fluid, the experimental CSC was determined by performing corefloods and analyzing effluent turbidity and absorbance. Attractive (van der Waals) and repulsive (EDL) forces were estimated by DLVO theory to predict the value of CSC. The experimental data were used to validate the model. The application of silica nanoparticles (NPs) was studied by injecting 0.1 wt% silica nanofluid and the resultant reduction in CSC was observed. During the injection of brines at different salinities ranging from 0.2 M to 0.05 M into the sandstone porous media, fines production was detected in the effluent after the injection of 0.1M NaCl solution, indicating that the CSC was 0.1M for this sand-fine-brine (SFB) system. The zeta potentials for SFB systems of different salinities were measured by zeta-sizer and were in the range of -32 mV to -24 mV. DLVO model based on attractive and repulsive forces was then used to predict the CSC, at which the total DLVO energy shifts from negative to positive and was around 0.1M for NaCl solution. The model prediction was in close agreement with the experimental results. Both the experiment and DLVO model showed the efficiency of silica nanofluid to mitigate fines migration as no fines production was observed for 0.1M NaCl case after the treatment with nanofluid. The estimation of CSC is critical to avoid formation damage during many oil recovery processes, included but not limited to low salinity waterflooding and alkaline flooding. The utilization of nanofluid provided promising results in controlling fines migration and reducing CSC. The proposed model based on DLVO theory can work as a useful tool to predict CSC without the need for extensive experimental work.

Dynamics of ion depletion in thin brine films

Low-salinity water flooding (LSW) effects are generated by the reduction of ionic concentration of environment electrolytes to which thin brine films confined between oil and rock are exposed. We study the dynamics of ion depletion from thin brine films upon a reduction of environment electrolyte concentration using the Poisson-Nernst-Planck (PNP) model. Interestingly, the model predicts that the timescale of ion depletion is not prolonged, but slightly shortened, by charged oil and rock surfaces in comparison with the absence of surface charges. This phenomenon is also reproduced quantitatively using a reduced ion depletion model inspired by the membrane science literature, in which salt diffusion and Donnan equilibrium between brine film and environment are considered. Furthermore, the self-diffusion of ions confined between n-decane and negatively charged quartz surface is investigated via atomistic simulations. It is found that, on average, the diffusion of ions in nanometer-thin brine films is slowed down up to ~8 times compared to that in bulk, although the slowdown relevant to ion depletion in event of a salinity reduction in the environment is most likely only about 2–3 times. These results provide new, pore-scale insights into LSW processes. The reduced salt depletion model and molecular simulation of ion diffusion demonstrated here help to develop a multiscale, bottom-up modeling framework for predicting LSW processes.

Probing of the hydrated cation bridges in the oil/brine/silica system via atomic force microscopy and molecular dynamics simulation

Strong interaction between oil and rock in oil/brine/silica system can not only lay a theoretical foundation for improving the crude oil recovery of unconventional reservoirs, but also provide ideas for the remediation of oil-contaminated soil and the reduction of energy consumption in the process of oil pipeline transportation. Cations have a substantial impact on the interaction between oil and rock, and low salinity water flooding can enhance oil recovery by 4%~38%. However, the existence form and functional mechanism of cations between oil and rock remain to be elucidated. In this paper, the interaction between oil and rock is quantitatively characterized via atomic force microscopy (AFM). The polar components of oil have a strong interaction with rock, which is 2–10 times stronger than that between the nonpolar components of oil and the quartz glass in the same cationic environment. Cations have readily observable impacts on the interactions between the polar components of oil and rock. The interactions are strong in brine with high valence cations and a high cation concentration. Molecular dynamics simulation (MD) was used to investigate the micro conformation between oil and rock and to identify the existence form and functional mechanism of cations. The results demonstrate that cations act as bridges that connect polar components in oil to rock surfaces. Besides, we also found that cations are present as hydrated cations and the water molecules that form the hydrated cations connect oil to the rock surface via hydrogen bonds. Hydrogen bonds are essential for the strong interaction between oil and rock. Therefore, the strength of the hydrogen bonds that connect the oil to the rock surface in systems with Na+, Ca2+ and Al3+ was calculated using density functional theory (DFT), and the result is consistent with that of AFM experiments. This study identifies the key action site of the strong interaction between the oil film and rock and provides a theoretical basis for the study of peeling oil films and renovating oil-contaminated soil.

Integral effects of initial fluids configuration and wettability alteration on remaining saturation: characterization with X-ray micro-computed tomography

Wettability alteration is the key process in low salinity waterflooding to enhance oil recovery. However, wettability alteration cannot necessarily lead to better oil recovery as other factors such as initial fluids morphology plays critical roles. We used Micro-CT X-ray imaging to investigate the effects of initial water morphology and wettability alteration on final remaining oil saturation and oil ganglia size distribution. The results show that presence of percolating water pathways impedes the oil recovery and oil can be produced mostly from large pores at tertiary mode, whereas the secondary low salinity waterflooding unlocks oil from a much broader range of pores. Moreover, the in-situ contact angles decrease towards less oil-wet regardless of initial water saturation, suggesting that wettability alteration is not dependent on the initial water saturation. We observed that at the end of secondary low salinity waterflooding, larger trapped ganglia were identified which is in agreement with the ganglia mobilisation theory. This work provided novel insights into the source of additional oil recovery during low salinity waterflooding and addressed the unrecognized role of initial fluids morphology in hydrocarbon recovery and multiphase flow.

Assessment of low salinity waterflooding in carbonate cores: Interfacial viscoelasticity and tuning process efficiency by use of non-ionic surfactant

Hypothesis. A large number of papers discuss merits and mechanisms of low salinity waterflooding. For each mechanism proposed, there are counter examples to invalidate the stated mechanism. The effect of wettability from low salinity water, which is predominantly stated in literature as the dominant mechanism, may not be valid. We introduce a direct correlation between oil-brine interfacial viscoelasticity and oil recovery from waterflooding.Experiments. The oil recovery is investigated in carbonate rocks for three light crude oils, by injection of a wide range of aqueous phases, ranging from deionized water to very high salinity brine of 28 wt%, and low concentration of a non-ionic surfactant at 100 ppm. The oil-brine interfacial viscoelasticity is quantified and supplementary measurements of interfacial tension and wettability are performed.Findings. In our experiments, oil recovery is higher from high salinity water injection than from low salinity water injection. A strong relationship is observed between interface elasticity and oil recovery for different concentrations of salt in the injected brine as well as for ultra-low concentration surfactant. An elastic oil-brine interface results in high oil recovery. The surfactant molecule we have selected prefers the oil–water interface despite high solubility in the oil phase and makes ultra-low concentration of 100 ppm in injection water very effective. Contrary to widespread assertions in the literature, we find no definitive correlation between oil recovery and wettability.

RSM for Modelling the CO2 Effect in the Interfacial Tension Between Brine and Waxy Dulang Crude Oil During LSW-WAG EOR

Recent studies on low-salinity waterflooding (LSW) and CO2 water-alternating gas (WAG) use are noteworthy because of their effectiveness in recovered oil content retention in mature fields. s the brine salinity decreases, the solubility of CO2also increases. The CO2in the injected water is expected to reduce the water/oil interfacial tension (IFT), and thus previouslytrapped oil in the rock by capillary forces will flow. However, as of yet, a fewresearches havefocusedon the fluid/fluidinteraction involving waxy crude oil/brinein the LSW-WAGprocess. Twomodels, both of which have been developed from experimental interfacial tension measurements, assist in estimating the CO2's effect on oil/water interfacial tension in the presence and absence of CO2. This objective is accomplished by designing experiments using the modified central composite design (CCD)method in response surface methodology (RSM). Theeffectof pressure, brine salinity, and CO2on oil/water IFT are taken into consideration while modelling.Analysis of variance (ANOVA) was used to determine the optimal values of input variables based on the developed model to obtain an acceptable model. The R-squared values indicate that the developed models arecapable of accurately forecasting the experimental results of oil/water IFT using Dulang crude oil and seven different brine salinities. The findings of this study are expected to shed light on the fluid/fluid interaction behaviour during the LSW-WAG recovery process in a mature field producing waxy crude oil.

Pore-doublet computational fluid dynamic simulation of the effects of dynamic contact angle and interfacial tension alterations on the displacement mechanisms of oil by low salinity water

Using our recently developed model, for the first time in the literature, the effect of fluid/fluid and rock/fluid interactions on the performance of Low Salinity Waterflooding (LSWF, as an Enhanced Oil Recovery process) at pore-doublet scale is investigated. The model is incorporated into OpenFOAM and both the Navier-Stokes equation for oil/water two-phase flow and the advection-diffusion equation for ion transport (at both fluid/fluid and rock/fluid interface) are solved via direct numerical simulation (DNS).The model is validated against imbibition and drainage pore-doublet experiments reported in the literature, and then applied to investigate the sole effect of wettability alteration as well as its coupled effect with interfacial tension (IFT) variations on the redistribution and transport of phases within the model. Different degrees of contact angle alteration, different trends of IFT variations reported in the literature, as well as different injection scenarios (secondary or tertiary) are considered.Simulation results show that in the case of high salinity water flooding (HSWF), IFT (within the range of 30 to 5 mN.m−1) has very limited effect on the residual oil saturation of the investigated model. For the case of HSWF in the oil-wet pore-doublet model (contact angle = 140°), significant amount of oil will be trapped in the small pores of the model. This residual oil cannot be produced in the absence of wettability alteration, no matter how much the IFT be reduced during LSWF (even as low as 0.1 mN.m−1). However in the absence of any IFT variation (IFT = 10 mN.m−1), the residual oil ganglia can be displaced with the sufficient degree of wettability alteration (contact angles below or equal to 30°). Nevertheless, in the presence of adequate contact angle reduction, fluid/fluid interactions (different IFT variation) can affect the outcome of the enhanced oil recovery. The LSWF performance boosts under appropriate degree of fluid/fluid and rock/fluid interactions as it leads to the coalescence of the detached or partially detached residual oil blobs and progress of chasing water front in both small and large pores of the doublets towards the downstream of the model. The results confirm the importance of fluid/fluid interactions such as IFT variation on such coalescence and dynamic LSWF, especially in the case of secondary LSWF.

Modeling the Effect of Reaction Kinetics and Dispersion during Low-Salinity Waterflooding

SummaryWettability alteration has been recognized as the primary mechanism responsible for improved oil recovery during low-salinity waterflooding (LSWF). A complex network of ionic reactions at the oil/brine/rock interfaces facilitates the alteration in wettability. The objective of this paper is to evaluate the effects of reaction kinetics and dispersion during LSWF.In this research, we construct a mechanistic binary model that has been implemented on carbonate reservoirs. We consider the impact of physical dispersion and reaction kinetics on recovery. The proposed model is based on the premise that the wetting species are known and can be lumped as either oil-wetting or water-wetting pseudocomponents. For the cases studied, the model was found to reproduce the experimental results well. Further, simulations show a significant impact of reaction kinetics on the rate of wettability alteration compared to assuming instantaneous equilibrium. To adequately represent field-scale response from the laboratory scale, one needs to ensure that comparable Damköhler numbers are used. Some laboratory corefloods for LSWF may underestimate the recovery because the Damköhler number is not representative of field scale. For the limiting case of a slow reaction rate [Damköhler number [(Da) ∼ 0] that corresponds to laboratory scale, low-salinity injection does not alter wettability. For fast reactions (Da ∼ 105) that correspond to the field-scale behavior, the ultimate oil recovery is highly sensitive to the injected fluid salinity. The wettability alteration front is delayed compared to the injected fluid because of the excess salt desorbed from the rock surface into the aqueous solution. Such a delay in wettability alteration is important when considering an appropriate slug size for the low-salinity slug. Finally, we observed that dispersion had little effect on the ultimate oil recovery during wettability alteration as compared to reaction kinetics.

Experimental Investigation on the Pore-Scale Mechanism of Improved Sweep Efficiency by Low-Salinity Water Flooding Using a Reservoir-on-a-Chip.

Low-salinity water flooding, known as an environmentally friendly and efficient oil recovery technology, has attracted the attention of several researchers all over the world. However, its field application is suffering restrictions because of the ambiguous mechanisms of the oil recovery by controlling the salinity. In this study, a water flooding microfluidic experiment was conducted to investigate the pore-scale mechanism of enhanced sweep efficiency by low-salinity water flooding. This experiment used a reservoir-on-a-chip that preserved the real rock properties and morphological features. Crude oil–water–rock contact angle experiments by altering water salinity were conducted to investigate the mechanism of the improvement of sweep efficiency by low-salinity water flooding. The experiment results show that unlike high-salinity water flooding, low-salinity water flooding improves its sweep efficiency from wettability alteration. Specifically, in the microfluidic model, it clearly shows that the pore-scale sweep efficiency is improved by reducing the salinity of injected water. Low-salinity water can invade the pores that cannot be reached by high-salinity water and displace the remaining oil after high-salinity water flooding. In the altering water salinity contact angle experiments, the contact angles decrease from 91.05° (neutral-wet) to 64.41° (water-wet) as the water salinity decreases from 46.58 to 2.31 g/L. The wettability of the rock surface changes from oil or neutral-wet to water-wet and induces the imbibition process, during which the hydrophilic pores absorb the low-salinity water into the smaller pores where the high-salinity water cannot invade. This investigation provides a further in situ and pore-scale evidence of improved sweep efficiency and wettability alteration by low-salinity water flooding and a possible reference to solve the difficulty in upscaling fluid flow behavior from microfluidics to reservoir rocks.

Influence of carbonate impurities on smartwater effect: Evaluation of wettability alteration process by geochemical simulation

Low salinity water flooding (LSWF) has been considered as a promising technique for enhanced oil recovery (EOR). The wettability alteration towards a more water-wet state is recognised as the main mechanism for the positive LSWF effect. Electrokinetic interactions occurring at crude oil/brine and rock/brine interfaces affect the wettability alteration. Most of the studies reported in the existing knowledge considered synthetic calcite to understand the electrokinetics of natural carbonate with brines. The mineral impurities present in natural carbonate could influence the electrokinetics and subsequently wettability alteration. In this study, the surface complexation model, thermodynamic equilibrium model, and extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory were combined to evaluate the effect of impurities (dolomite and anhydrite) in natural carbonate on wettability alteration. The surface complexation modelling parameters were first estimated by fitting the calculated zeta potential to that of measured value in various brines and then validated in smartwater. The thermodynamic equilibrium of impurities is largely insensitive to crude oil/brine interface properties. However, the calculated carbonate/brine surface or zeta potential changed from positive to negative with anhydrite equilibrium in the brines containing Ca2+ or Mg2+ ions. The attractive or repulsive forces between crude oil and carbonate were estimated from disjoining pressure using extended DLVO theory and compared with measured adhesion forces. The computed disjoining pressure was used as an indicator to evaluate wettability alteration. It is found that brine with SO42- ions can result in highest water-wet condition, followed by smartwater (brine with Ca2+, Mg2+, and SO42-) and brine with either Ca2+ ions or Mg2+ ions. The de-ionic (DI) water is unfavourable for wettability alteration. The effect of impurities equilibrium and the crude oil surface site densities on the disjoining pressure were also discussed.

Efficiency of enhanced oil recovery by original and low salinity waterflooding treatment

The article presents the results of research on the possibility of increasing the recovery factor of oil fields by implementing the waterflooding treatment as one of the most common enhanced oil recovery method. Based on the interpretation of data from the core flow tests, an attempt was made to characterize the displacement process using original reservoir brine and waters with lower salinity level. Additionally, the relation between the type of wettability of the rock and recovery factor was investigated. Original reservoir fluids that were characterized in terms of their basic rheological parameters were used for research purposes. The rock material consisted of 16 samples of Cambrian sandstones. The initial scope of work concerned the petrophysical characteristics of the cores, including the determination of their basic parameters, such as absolute gas permeability, porosity and pore volume. Based on the determined values of permeability, the available samples were grouped which made it possible to perform test sets for pairs with the most similar filtration parameters in the next stages of the research. Further work included the performance of relative permeability analyses and the determination of the value of the mobility factor for the oil – reservoir water system in order to determine the type of wettability of the rock and the potential efficiency of the oil displacement process. The main element of the research was the simulation of the waterflooding process carried out in two parts – the first with the use of the original reservoir water (corresponding to the secondary recovery methods) and the second with the use of low-salinity waters (the third recovery methods) in two variants of the mineralization level. Based on the obtained data of the displaced oil, for each of the displacement medium recovery factor curve were constructed and compared with the determined type of wettability of the rock.

Interplay Between Ca2+, Mg2+, and SO42– Ions and Their Influence on the Zeta-Potential of Limestone during Controlled-Salinity Waterflooding

Substantially enhanced oil recoveries from carbonate reservoirs have been accredited to the modification of ionic content and salinity of the injection water and subsequent alteration of reservoir rock wettability toward more water-wet. Modification of surface charges at rock/oil/water interfaces is believed to be the main mechanism that controls the process of wettability alteration. This paper presents a systematic zeta-potential measurement study that investigates the individual and relative impacts of Ca2+, Mg2+, and SO42– ions on a limestone rock from the Middle East. The main target of the study is to understand the impact of each potential determining ion individually and in the presence of another ion for insightful explanations of the overall impact of injection water during ionically controlled waterflooding in carbonate reservoirs. The novelty of the current study is the comprehensive investigation of the interplay between potential determining ions and the resultant impact on limestone surface charges. Different modified brines were prepared based on the ionic composition of Arabian Gulf seawater, which is the main source of injection water in the region. Model oil, containing carboxylic acid, was used to represent the oil phase in aging procedures. Interactions at the rock/oil/water interfaces were assessed using zeta-potential measurements of unaged and aged limestone particles. The results show that Ca2+, Mg2+, and SO42– are potential determining ions that can alter surface charges of unaged and aged limestone. SO42– ions were found to have a profound impact on the generation of negative surface charges on limestone as well as in suppressing the preferential ability of Ca2+ and Mg2+ ions to generate positive surface charges. Results also showed that limestone possesses negative surface charges when conditioned in unmodified seawater and twice diluted seawater. Comparing the obtained results from this study with the literature suggests that similarities in the mineralogical composition of carbonates rocks do not necessarily reflect in similar electrokinetic behavior, even under the same experimental conditions. Moreover, this study shows that the zeta-potential of limestone is not linearly correlated with decreased salinity. Furthermore, it is shown that conditioning limestone in sequentially diluted seawater will result in an increase in the magnitude of the negative charges up to twice diluted seawater, after which the magnitude of the negative surface charges will start to decrease. This finding suggests that a different mechanism is responsible for the modification of carbonate surface charges during late stages of sequential low-salinity waterflooding than the mechanism that controls the modification of surface charges during early stages of the process.

The non-linear effect of oil polarity on the efficiency of low salinity waterflooding: A pore-level investigation

Oil polarity is an important property impacting the efficiency of low salinity waterflooding (LSWF). It directly affects fluid/fluid and rock/fluid interactions, controlling the interfacial properties and forces. However, the current findings in the literature on the effect of concentration of polar components on oil recovery by LSWF are contradictory. Therefore, the main objective of this paper is to investigate how the type of non-polar fractions and the concentration of acidic polar oil constituents change the trapped oil saturation at the pore-scale during LSWF. In this regard, we conducted a series of microfluidics LSWF experiments in both secondary and tertiary modes, using clay-free glass micromodels of representative elementary volume (REV) size. Both model oils and crude oil were tested. The polarity of model oils was manipulated by introducing different amounts of oleic acid into the samples. In addition, the contact angle under dynamic salinity alteration (CA-DSA), interfacial tension (IFT), and oil/brine zeta-potential were measured as a function of oil polarity for a detailed understanding of the pore-scale results.Based on the results, polar acidic fraction increases both the oil-wetting tendency under high salinity (HS) condition and the degree of wettability alteration under low salinity (LS) condition. Increasing the concentration of the polar components in the model oils resulted in reducing oil/brine IFT by 7–9 mN/m in HS and 8–12 mN/m in LS. As the IFT was reduced, the sweep efficiency of both HS and LS flooding was improved, which can be ascribed to the reduction of capillary trapping. However, the change of IFT by change of salinity was minor; thus, it cannot be considered a primary mechanism of LSWF. The ultimate oil recovery from HS and LS injection steps was highest when crude oil was used than using the most polar model oil. In the absence of polar components, no incremental oil recovery during LSWF was observed regardless of the molecular weight of the model oil. The efficiency of LSWF with all the polar oils was higher in the secondary injection than in the tertiary mode, as also reported in core-scale studies.The main novel insight from the study is that the oil recovery factor by LSWF is logarithmically correlated with the oil polarity. The measured zeta-potential at the oil/brine interface also confirms a logarithmic correlation between the oil/brine interface potential and the concentration of polar components in the oil samples. This highlights that the bulk concentration of polar groups and their respective concentration at the oil/brine interface are not linearly related. Therefore, the acid number alone cannot predict the concentration of polar components at the interface and is not recommended to be used for screening potent oils.