Low Salinity Waterflooding Research Articles

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

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

Experimental Study on the Mechanism and Law of Low-Salinity Water Flooding for Enhanced Oil Recovery in Tight Sandstone Reservoirs.

Currently, research surrounding low-salinity water flooding predominantly focuses on medium- to high-permeability sandstone reservoirs. Nevertheless, further investigation is necessary to implement this technique with regard to tight sandstone reservoirs. The present study comprises a series of experiments conducted on the crude oil and core of the Ordos Chang 6 reservoir to investigate the influence of ionic composition on low-salinity water flooding in tight oil reservoirs. The change in wettability on the rock surface was analyzed by using the contact angle experiment. The change in recovery rate was analyzed using a core displacement experiment. The reaction between rock fluids was analyzed using an ion chromatography experiment. Additionally, a nuclear magnetic resonance (NMR) experiment was used to analyze the mobilization law of crude oil and the change in wettability on the scale of the rock core. This led to a comprehensive discussion of the law and mechanism of enhancing the recovery rate via low-salinity water flooding from various perspectives. Experiments show that low-salinity water flooding is an effective technique for enhancing recovery in tight sandstone reservoirs. Altering the ionic composition of injected water can improve the water wettability of the rock surface and enhance recovery. Decreasing the mass concentration of Ca2+ or increasing the mass concentration of SO42- can prompt the ion-exchange reaction on the rock surface and detachment of polar components from the surface. Consequently, the wettability of the rock surface strengthens, augmenting the recovery process. Nuclear magnetic resonance experiments evidence that low-salinity water injection, with ion adjustment, significantly alters the interactions between the rock and fluid in tight sandstone reservoirs. As a result, the T2 signal amplitude decreases significantly, residual oil saturation reduces considerably, and the hydrophilic nature of the rock surface increases.

Scope of Implementation of Low Salinity Nanofluid to Improve Oil Recovery in a Part of the Hapjan Oil Field of Upper Assam Basin

The application of nanoparticles in the field of Enhanced Oil Recovery (EOR) has been an emerging technology in recent years. Earlier studies have shown that the nanofluids containing nanoparticles (NPs) of average size (<100 nm) can enhance the oil recovery through wettability alteration of rock, reduction of mobility ratio, reduction of oil-aqueous solution interfacial tension (IFT), reduction of sand production and improvement of sweep efficiency. Low Salinity Waterflooding (LSW) has been utilized as a promising EOR method in the last two decades. Recent studies have found that nanoparticle-assisted LSW embraces both nanoparticles and ions as EOR agents in the injection brine. This study investigates the scope of implementation of the low salinity nanofluid EOR using silica nanoparticles to improve oil recovery in the Tipam Reservoir Sandstone of the Hapjan Oil Field of Upper Assam Basin, India. The analysis of the reservoir brine, reservoir rock and crude oil shows the presence of divalent cations (Ca2+ and Mg2+), clay minerals (Illite and Smectite) and polar compounds (Asphaltene and Resin) respectively. The presence of the divalent cations, clay minerals and polar compounds in the Crude Oil/Brine/Rock system of a sandstone reservoir is the prerequisite for implementing low salinity nanofluid EOR. The study shows that the low salinity nanofluids can shift the wettability of the rock to a more water-wet state. It is also observed that the silica nanoparticles can increase the nanofluid viscosity and reduce the oil-nanofluid IFT, which can improve the recovery of oil. The experimental results show that the study area has great potential for the low salinity silica nanofluid EOR to improve oil recovery.

Relationship Between Residual Saturations and Wettability Using Pore-Network Modeling

Summary The relationship between residual saturation and wettability is critical for modeling multiphase processes like enhanced oil recovery, CO2 sequestration, and geologic storage of hydrogen. The wetting state of a core is often quantified through Amott indices, which are estimated from the ratio of the saturation fraction that flows spontaneously to the total saturation change that occurs due to spontaneous flow and forced injection. Observations from traditional coreflooding experiments show a minimum in the trends of residual oil saturation (Sor) around mixed-wet conditions. Amott indices, however, provide an average measure of wettability because of their intrinsic dependence on a variety of factors such as the initial oil saturation, aging conditions, rock heterogeneity, etc. Thus, the use of Amott indices could potentially cloud the observed trends of residual saturation with wettability. Using pore-network modeling (PNM), we show that Sor varies monotonically with the contact angle, which is a direct measure of wettability. That is, for fixed initial oil saturation, the Sor decreases monotonically as the reservoir becomes more water-wet (decreasing contact angle). Further, the calculation of Amott indices for the PNM data sets shows that a plot of the Sor vs. Amott indices also shows this monotonic trend, but only if the initial oil saturation is kept fixed. Thus, for the cases presented here, we show that there is no minimum residual saturation at mixed-wet conditions as wettability changes. In this research, we employ a numerical approach to quantify trends of Sor against the traditional definition of wettability. Through the analysis of our numerical work and literature experiments, we find that under isolated conditions (constant initial saturation), linear trends exist between Sor and wettability. This can have important implications for low salinity waterflooding, water-alternating-gas enhanced oil recovery, or CO2 sequestration where the effects of wettability are critical to understand phase trapping.

Experimental Investigation about Oil Recovery by Using Low-Salinity Nanofluids Solutions in Sandstone Reservoirs

Production of crude oil from matured oil reservoirs has major issues due to decreased oil recovery with water channeling; however, the low-salinity water flooding technique is more commonly used to maximize recovery of the remaining oil. In this study, we demonstrated a new hybridization technique of combining low-salinity water and nanofluids; this was achieved by using experiments such as contact angle measurement with water of different salinity levels and nanofluid concentrations, core displacement, and NMR (nuclear magnetic resonance) between low-/high-permeability rock. The trial results demonstrated that the test with KCl-1+NF outperformed those with other compositions by changing the original contact angle from 112.50° to 53.3° and increasing formation production up to 15 cc. In addition, we saw that when 2 PV of KCl-1+NF was injected at a rate of 5 mL/min, the middle pores’ water saturation dropped quickly to 73% and then steadily stabilized in the middle and late stages. Regarding the novel application of the hybridization technique, the insights presented in this paper serve as a helpful resource for future studies in this field.

Hybrid low salinity water and surfactant process for enhancing heavy oil recovery

Combining low salinity water (LSW) with surfactants has an enormous potential for enhancing oil recovery processes. However, there is no consensus about the mechanisms involved, in addition to the fact that several studies have been conducted in model systems, while experiments with rocks and reservoir fluids are scarce. This study presents a core-flooding experiment of LSW injection, with and without surfactant, using the core and heavy oil samples obtained from a sandstone reservoir in southeastern Mexico. The effluents and the crude oil obtained at each stage were analyzed. The study was complemented by tomographic analysis. The results revealed that LSW injection and hybrid process with surfactants obtained an increase of 11.4 percentage points in recovery factor. Various phenomena were caused by LSW flooding, such as changes in wettability and pH, ion exchange, mineral dissolution, detachment of fines and modification of the hydrocarbon profile. In the surfactant flooding, the reduction of interfacial tension and alteration of wettability were the main mechanisms involved. The findings of this work also showed that the conditions believed to be necessary for enhanced oil recovery with LSW, such as the presence of kaolinite or high acid number oil, are not relevant.

How does the presence of an oleic phase influence salt transport during polymer-enhanced low-salinity waterflooding?

Our preceding single-phase experiments demonstrated that polymer enhanced low-salinity waterflooding (PELS) can significantly reduce salt dispersion and improves low-salinity waterflooding (LSWF) performance. In this paper, we extended the research to two-phase fluid flow conditions in the presence of an oleic phase. To assess this quantitatively, a series of two-phase coreflooding experiments using artificial cores were conducted. To eliminate the impact of fluid–fluid and rock–fluid interactions associated with LSWF on salt dispersion, a model, non-polar oleic phase was chosen. The salinity breakthrough results of two-phase corefloods were interpreted using a non-Fickian model based on the Mobile-Immobile Model to infer salt dispersion coefficient. The impact of Partially-Hydrolyzed Polyacrylamide (HPAM) concentration, injection rate, salinity difference, and flooding mode (secondary or tertiary) on salt transport and dispersion through porous media were studied. The results revealed an increase in the salt dispersion coefficient under two-phase conditions by as much as sixfold; taking significantly larger times to displace the high salinity brine. Thus, the optimal HPAM concentration required to effectively suppress mixing was found to be twice (∼400 ppm) as much under the single-phase flow. Reduction of salinity difference also resulted in the reduction of the salt dispersion coefficient by 32%. Moreover, it was observed that in tertiary mode injection where the starting water saturation of the core is higher due to a prior high salinity flooding, the salt dispersion can be increased by more than 21%. These new two-phase results and insights support the possibility of mixing-control under two-phase condition by using PELS and provides a solution to facilitate field implementation.

Interfacial Water-Dictated Oil Adhesion Based on Ion Modulation.

Oil adhesion on ionic surfaces is ubiquitous in organisms and natural environments and is generally determined by surface chemical component and texture. However, when adhesion occurs, water molecules at the solid-liquid interface, acting as a bridge not only influenced by the structure and composition of the solid surface but also interacting with the neighboring oil molecules, play a crucial role but are always overlooked. Herein, we investigate the oil adhesion process on a carboxyl-terminated self-assembled monolayer surface (COOH-SAM) in ionic solutions and observe the interfacial water structure via surface-enhanced Raman scattering (SERS) in this system. It is found that the lower the tetracoordinated water content, the stronger the oil adhesion. Compared to monovalent ions, the strengthened binding of multivalent ions to the COOH-SAM surface makes the interfacial water more disordered, which eventually leads to a stronger oil adhesion. Notably, the amount of oil adhesion decreases with an increase in the thickness of the interfacial water region. The interfacial water-dictated oil adhesion has been demonstrated in capillary to simulate the water-driven oil recovery, providing a molecular-level explanation for enhanced oil recovery from low salinity water flooding and also indicating potential applications in intelligent microfluidic and seawater desalination.

Pore-Scale Imaging of Emulsification of Oil during Tertiary and Secondary Low Salinity Waterflooding in a Reservoir Carbonate

Pore-Scale Imaging of Emulsification of Oil during Tertiary and Secondary Low Salinity Waterflooding in a Reservoir Carbonate

Numerical Investigations of Low-Salinity Water Flooding in a Saline Sandstone Reservoir

Numerical Investigations of Low-Salinity Water Flooding in a Saline Sandstone Reservoir

Fluid-fluid interfacial properties during low salinity waterflooding

Understanding the fluid–fluid interfacial interactions is critical to enhancing oil recovery, underground CO2 storage, and soil remediation. Fluid-fluid interfacial interactions were identified as key parameters to govern fluid–fluid interfacial properties. In this investigation, we aim to evaluate the properties of the oil-brine interface in function of fluid compositions during low salinity waterflooding (LSW). Specifically, the main target is to unravel the oil-brine structure, including orientation of the carboxylic group (–COOH), interfacial structure, and species distribution. We utilized molecular dynamics (MD) simulation to evaluate the species distribution and surface structure at the molecular scale. The MD results showed that the carboxylic group accumulated near the oil-brine interface. The orientation of C=O in the carboxylic group is closer to 90° in the brines with all salinity ranges, which is perpendicular to the oil-brine interface. The accumulation and orientation of the carboxylic group is, however, not sensitive to salinity variations. Furthermore, the oil-brine interfacial area turns to be wider with lowering salinity. Radial distribution function (RDF, g(r)) confirmed that lowering salinity decreases g(r) between –COOH and water and thus looses the affinity of oil to water. This investigation provides insights into the fluid–fluid interfacial properties of LSW at the molecular level.

Studying the effect of surfactant assisted low-salinity water flooding on clay-rich sandstones

Sandstone reservoirs often contain clay particles that can cause damage and reduce permeability during low-salinity water flooding. In this study, the effect of surfactants on fine migration in clay-rich sandstones and its impact on oil recovery was investigated.First, the impact of surfactants on interparticle forces in fine-matrix, fine-fine, and oil-matrix systems was modeled. The results showed that both CTAB (cetyltrimethyl ammonium bromide) and QS (quillaja saponin) cause EDL compaction, weakening the repulsive forces. However, SDS (sodium dodecyl sulfate) and TX (triton X-100) do not affect the EDL. Next, the effect of surfactants on IFT reduction and wettability alteration was experimentally investigated. All surfactants reduced IFT due to the surface excessive concentration mechanism. The wettability alteration experiment illustrated that although QS and CTAB compact EDL around oil and matrix particles leading to attraction force augmentation, they both alter wettability through adsorption on matrix and carboxylic groups present in crude oil, respectively.Surfactant aqueous solutions were then injected into various clay-rich sandstone sanpacks, which resulted in increased oil recovery. However, the mechanisms leading to enhanced oil recovery variedby surfactant type. CTAB increased recovery by 10% through IFT reduction and wettability alteration, while SDS and TX increased recovery by 12% and 9%, respectively, through wettability alteration and extreme fine migration. In contrast, partial fine migration in the QS flooding experiment reached a recovery increase of 18%. Permeability trends through experiments were also recorded. During CTAB injection, permeability did not reduce, while QS aqueous solution reduced rock permeability to 5 mD. SDS and TX reduced the magnitude of permeability to 2 mD.In conclusion, this study demonstrates that surfactants can effectively improve oil recovery in clay-rich sandstones by altering the interparticle forces, reducing IFT, and changing wettability. The results suggest that the type of surfactant used should be carefully selected to achieve the desired recovery increase without affecting the permeability of the reservoir.

Dynamic modelling of reservoir fines retention by mesoporous silica nanofluid to improve oil recovery during low salinity water flooding of a consolidated sandstone

Mesoporous silica (SiO2) nanoparticles (MSNP) was used to stabilize formation fines for increased oil recovery during low salinity water flooding. Likewise, the effect of porous media length on dynamic retention of fines at high temperature reservoir condition was investigated. Breakthrough curves of reservoir fines adsorption by mesoporous SiO2 nanofluid (MSNF) were described using Thomas and Yoon-Nelson models. Similarly, effect of concentration, flow rate, porous media length and temperature on the retention capacity of reservoir fines was modelled using Box Behnken design of experiments. Subsequently, effect of reservoir fines stabilization on oil recovery was evaluated. Formation damage remediation propensity of MSNF was investigated. Finally, the oil recovery mechanisms were determined using the sessile drop contact angle and Wilhelmy plate methods. Experimental results of the dynamic adsorption with coefficient of determination (R2) values between 0.967 and 0.999 signifies that the reservoir fines adsorption by MSNF were well predicted by Thomas and Yoon-Nelson models. Consequently, MSNF stabilized the reservoir fines by attaching onto their surface rather than on the porous media thereby changing the wettability to water-wet, decreasing the contact angle to 16.1°, 17.1° and 20.7° for kaolinite, illite and montmorillonite, respectively. Thus, increasing oil recovery by 22–23% original oil in place.

Pore-Scale Insights into the Nonmonotonic Effect of Injection Water Salinity on Wettability and Oil Recovery in Low-Salinity Waterflooding

Pore-Scale Insights into the Nonmonotonic Effect of Injection Water Salinity on Wettability and Oil Recovery in Low-Salinity Waterflooding

A critical review of carbonate reservoir wettability modification during low salinity waterflooding

The nature of carbonate reservoirs promotes the adsorption of oil onto the rock surface hence making oil recovery a challenge even with the interventions of varied chemical EOR methods. Recently, low salinity water flooding has become of great interest since it is cost-effective and environmentally friendly. Although low salinity waterflooding has been highly investigated in sandstone reservoirs, it is not the same for carbonate reservoirs due to its complexities. Nonetheless, it has been proposed as a favourable technique to mobilise the trapped oil in carbonate reservoirs. Wettability alteration is regarded as the most accepted mechanism for low salinity flooding but has not been well understood making field scale applications doubtful. In this paper, we present a detailed review of the wettability alteration mechanisms in carbonate reservoirs during low salinity waterflooding. Parameters influencing wettability alteration in carbonates and the interactions that occur at the rock/brine/oil interface are also presented. The different methods utilised for wettability measurements during low salinity waterflooding are also reviewed including their drawbacks and advantages and recommendations. This will provide an improved understanding of the low salinity flooding application in carbonate reservoirs.

The impact of grain size heterogeneity on the performance of low-salinity waterflooding in carbonate formations

Low-salinity waterflooding (LSWF) is a proven enhanced oil recovery method for many target fields. The efficiency of this technique depends on both operational factors as well as reservoir settings such as heterogeneity. Micro-scale rock heterogeneity can critically affect the performance of LSWF as it governs the flow path of the injected water, oil-brine-rock contacts and trapping mechanisms, thus sweep efficiency. However, there exist lack of experimental data and detailed understanding of the effect of grain size heterogeneity on LSWF performance. To address this gap, a systematic series of coreflooding experiments were designed using artificial calcite core plugs to investigate the effect of micro-scale heterogeneity, such as grain size and grain heterogeneity, on oil recovery factor by high-salinity waterflooding (HSWF) and LSWF. High salinity formation water, seawater, and diluted seawater were used as injection brines. For this purpose, two relevant grain size ranges (a) from 38 to 75 µm and (b) from 75 to 125 µm were considered to fabricate homogeneous plugs. Heterogeneous core plugs were made by mixing (a) and (b) grain samples. The artificial cores were initialized with the formation brine and crude oil, and aged to restore wettability. Then a set of coreflooding experiments were performed using the mentioned brine samples, in both secondary and tertiary modes by considering a shut-in period.The results reveal that grains size (or micro-scale) heterogeneity has a significant negative impact on both HSWF and LSWF performance and reduces the oil recovery efficiency of HSWF by approximately 15%. This is primarily attributed to the bypassing and entrapment of oil in heterogeneous cores. Moreover, the results show that regardless of the grain size, LSWF in homogeneous plugs result in almost similar recovery factors. The key finding of this study is that LSWF in heterogeneous plugs is more effective and recovers almost 10% more oil compared to HSWF. This is attributed to wettability alteration as indicated by the reduction of water relative permeability endpoint and delay of breakthrough time. The improvement in oil recovery was consistent with the results obtained from the flotation tests and dynamic IFT measurements. However, although LSWF outperforms HSWF in heterogeneous cores, the ultimate recovery factor becomes less in these plugs. Besides, superior performance of secondary flooding was observed compared to tertiary mode for LSWF, especially in cores with heterogeneous grain sizes, leading to almost 10% higher recovery factor.The novel insights gained through this research help identify the proper targets for LSWF in terms of small-scale heterogeneity and can be potentially applied in other water-based EOR techniques.

A Review and Evaluation of Laboratory-to-Field Approach for Low-Salinity Waterflooding Process for Carbonate Reservoirs

A Review and Evaluation of Laboratory-to-Field Approach for Low-Salinity Waterflooding Process for Carbonate Reservoirs

Pore-Scale Insights into In-Situ Mixing Control by Polymer-Enhanced Low-Salinity Waterflooding (PELS)

Pore-Scale Insights into In-Situ Mixing Control by Polymer-Enhanced Low-Salinity Waterflooding (PELS)

Experimental investigation on fluid/fluid and rock/fluid interactions in enhanced oil recovery by low salinity water flooding for carbonate reservoirs

The low salinity water flooding (LSWF) technique has established itself as cost-effective and environment-friendly in nature but its mechanisms are still unclear. Recovery due to LSWF mainly depends on two types of interaction, viz. fluid/fluid and rock/fluid. Despite the significant investigation, there is still no consensus on which interaction mainly governs oil recovery. This study intends to provide essential answers to the aforementioned issues, as well as additional significant insights into the dilution behaviour of Sea Water (SW) to be injected into a carbonate formation with equivalent salinity. A series of experiments were designed to assess both fluid/fluid and rock/fluid interaction thoroughly viz. compatibility test, IFT, interfacial rheology, zeta potential, and contact angle. A comprehensive number of individual and sequential coreflooding were conducted on outcrop cores to quantify the oil recovery potential of optimum salinities and gain more insight into wettability shifts due to LSWF. Rock/fluid and fluid/fluid interfaces showed different optimal conditions for improved oil recovery. Investigation of fluid/fluid interaction showed an optimal salinity of 2dSW as optimal salinity due to IFT reduction and increased viscoelastic properties. Rock/fluid interaction showed an optimal salinity of 10dSW due to enhanced zeta potential and calcite dissolution. Rock/fluid interaction showed an incremental recovery of 14% and fluid/fluid interaction showed an incremental recovery of 7% over simple SW injection. Sequential flooding based on rock/fluid interaction showed an incremental recovery of 16% over simple SW. Oil recovery based on rock/fluid interaction showed the highest recovery as compared to fluid/fluid interaction. Increased interfacial elasticity and calcite dissolution lead to wettability alteration and increased oil recovery due to LSWF. The effectiveness of LSWF depends upon optimum salinity and wettability alteration capability of low salinity slug. Results of this study also indicate that considering only one interaction either rock/fluid or fluid/fluid can lead to erroneous interpretation of LSWF data. Rock/fluid interaction and rock geochemical reactions must be considered while designing the LSWF recipe and low salinity slug should be injected right from the start to reap the benefits of LSWF.

A laboratory investigation of CO2 influence on solvent-assisted polymer flooding for improving viscous oil recovery on Alaska North Slope

In this study, the CO2 influence on enhancing Alaska North Slope (ANS) viscous oil recovery for polymer flooding with assistance of solvents is investigated. Seven coreflooding tests were conducted at reservoir conditions to evaluate ANS viscous oil recovery performance of five solvent-assisted EOR methods including LHS (light hydrocarbon solvent)-alternating-LSW (low salinity water) flooding, CO2-enriched LHS-alternating-LSW flooding, LHS-alternating-LSP (low salinity polymer) flooding, CO2-enriched LHS-alternating-LSP flooding, and CO2-enriched LHS-LSW-LSP flooding. Besides, the CO2 influence on the performance of solvent-assisted EOR methods is investigated. In addition, Constant Composition Expansion (CCE) tests were performed at reservoir temperatue of 85 °F to explore mechanisms of oil recovery improvement with solvent injection in EOR methods of this study. Moreover, water ion analyses of DI-water/natural-sand and DI-water/natural-sand/CO2 systems were carried out to discover the complex reaction between CO2, sand, and LSP solution for better understanding underlying mechanisms of solvent-assisted EOR methods. Coreflooding experiment results demonstrate that five proposed EOR methods all present remarkable production performance with recovery factor ranging from 79.73% to 92.23%. The main EOR mechanisms can be attributed to oil swelling and viscosity reduction effects resulting in the enhancement of microscopic displacement efficiency during solvent flooding and the improvement of macroscopic sweep efficiency of subsequent LSW/LSP flooding resulting from obtaining better mobility control. Considering the recovery factor from the 1st solvent flooding, no obvious improvement was observed with solvent containing CO2. However, higher oil recovery improvement was obtained from the subsequent LSW/LSP flooding of tests using solvent with CO2 than that without CO2, mainly resulting from better mobility control due to the greater viscosity reduction effect by CO2-enriched LHS. Nevertheless, a severe blockage occurred at the production end in the CO2-enriched LHS-alternating-LSP flooding test, which was likely due to the polymer precipitation. CCE test results present that more solvent could be dissolved into the ANS viscous oil by increasing the pressure of the system, which causes greater oil swelling and viscosity reduction effects. The saturation pressure was affected little by adding CO2 in LHS, while the presence of CO2 had a negative impact on oil swelling effect but a positive influence on oil viscosity reduction effect. In addition, water ion analyses results show that, after introducing CO2 to the DI-water/natural-sand system, a great amount of multivalent cations were generated probably due to the dissolution of minerals in the natural sand, which may explain the polymer precipitation. Therefore, the blockage issue at the production end could be solved by injecting LSW as a spacer between CO2-enriched LHS flooding and LSP flooding to reduce the concentration of generated cations.