Low Salinity Water Injection Research Articles

Preliminary experimental study of low salinity effect on organic polar compounds desorption in Hassi Messaoud field-Algeria

Low salinity water (LSW) injection is a well-recognized enhanced oil recovery method that has proved to increase oil recovery. Despite its simple implementation and low cost, no experimental investigations have been reporting its application in Algeria’s oil fields. The present work investigates the impact of LSW injection and identifies the role of organic polar compounds on oil trapping in Hassi Messaoud oil field. The study involves adsorption/desorption experiments using acid/amine organic polar compounds dissolved in non-polar refined oil while employing rock drilling cuttings. Subsequent validation of desorption data is performed by employing crude oil in both Amott tests and micro-model displacement tests using various water salinity ranges. It was evident that at water salinities ranging from 1000 to 2000 ppm, the interfacial tension decreased to 10−2 mN/m, leading to favorable rock wetting behavior and increased oil recovery of 9.18% and 20.07% for amine and acid compounds, respectively. The wettability alteration mechanism was proposed as the main contributor since the actual interfacial tension of natural surfactant might not significantly impact oil recovery. The implementation of LSW injection in Algerian fields presents fresh prospects for future enhanced oil recovery projects.

Experimental study of the effect of oil polarity on smart waterflooding in carbonate reservoirs

This study investigates the influence of oil polarity on interfacial tension (IFT), contact angle, oil recovery, and effluent pH in smart water and Low-salinity water injection. The results indicate that the interaction between the hydration shell of ions and the polar components (PCs) of oil is crucial. Increasing oil polarity enhances the potential for interaction with the hydration shell of ions, leading to reduced IFT, altered wettability, and improved oil recovery; which could be boosted by the contribution of a higher number of anions in the smart water bulk through the enhancement of their interaction with the PCs (especially acidic components) of oil. The study demonstrates that increasing the SO42− concentration in seawater increased oil recovery for oils with higher acid component content, as indicated by total acid number values of 0.87, 0.99, and 1.32 mgKOH/g, the tertiary oil recovery factors for these oils were 61.10%, 69.82%, and 87.09%, respectively. The effluent pH results align with the findings of contact angle and oil recovery, confirming the dominant influence of anions on oil recovery. The interaction between the PCs of oil and the hydration shell of ions is thus highlighted as a critical factor in the observed outcomes.

Potential of polymer’s viscosity and viscoelasticity for accessible oil recovery during low salinity polymer flooding in heterogeneous carbonates

Despite the usual improvement in sweep efficiency during polymer flooding, the polymer’s viscoelastic characteristics were reported to contribute to residual oil recovery in sandstone reservoirs at high flux conditions. In carbonate reservoirs, besides high-salinity, high-temperature, and non-water-wet nature, heterogeneity is a key variable that may impair the viscoelastic fluid flow in the porous media and recovery performance. However, no attempts were made to study the polymer’s viscoelastic influence on residual oil recovery in heterogeneous carbonate formations and the objective of this paper is to systematically examine the recovery performance of high molecular weight viscoelastic sulfonated polymer (AN-125-SH) in comparison to viscous xanthan gum polymer with the low salinity injection water of 5957 ppm total dissolved solids (TDS) in heterogeneous outcrop carbonate rocks at fluxes ranging from shear thinning to shear thickening using the combination of bulk shear rheometry, NMR, single-phase in-situ studies and two-phase core flooding experiments.Nuclear magnetic resonance (NMR) imaging ensured that the chosen cores are characterized with similar pore-size distribution. The steady-shear rheological experiments showed that 2500 ppm AN-125-SH polymer exhibits a lower viscosity at the lower shear rate and an early shear thickening (indicating higher non-linear viscoelasticity) than 2000 ppm xanthan gum. Then single-phase flow experiments are conducted using two polymer systems to determine the desired flux rates before the eventual multi-rate two-phase core flood experiments. Core flooding results revealed following an extensive secondary water flooding, at the shear thinning flux of 4 ft/day, 2000 ppm high viscous xanthan gum injection leads to an incremental recovery factor of 8.3 % with the generated pressure gradient of 20.48 psi/ft compared to 3.6 % recovery obtained using 2500 ppm AN 125-SH polymer with a pressure gradient of 16.2 psi/ft. However, at shear thickening fluxes of 20 ft/day and 30.5 ft/day, the higher elastic polymer enhanced the recovery by 3.3 % and 1.2 %, respectively. Conversely, the less elastic xanthan gum showed minimal to no incremental recovery at these fluxes.The novel findings of this work convey that the viscosity of xanthan gum provides a comparative advantage over the viscoelasticity of synthetic sulfonated polymers on oil recovery at relatively low fluxes in the studied heterogeneous formation at low salinity conditions.

Enhanced oil recovery and mitigating challenges in sandstone oil reservoirs employing EDTA chelating agent/ seawater flooding

While low salinity water (LSW) holds promise for improving oil recovery, its implementation is comparatively costly due to the substantial volumes of fresh water required to dilute seawater (SW). Additionally, concerns arise regarding potential issues related to LSW, including fines migration in sandstone reservoirs and scale formation in carbonate reservoirs. Chelating agents can be introduced into undiluted SW to bind with metal ions, thereby lowering its salinity. This approach mimics the behavior of LSW injection while overcoming associated challenges. This study involves measuring oil/injected solution interfacial tension (IFT), evaluating sandstone surface wettability alteration, along with conducting different sand pack flooding scenarios using Ethylenediaminetetraacetic acid (EDTA) chelating agent. The aim was to comprehend the EDTA oil recovery mechanisms and determine the optimal concentration of EDTA that minimizes chemical consumption while maximizing oil recovery. The findings indicated that incorporating 5 wt% EDTA into SW significantly reduced IFT from 29.52 mN/m to 4.75 mN/m, making the oil nearly miscible in the solution. Moreover, wettability tests confirmed that a minimum EDTA concentration of 5 wt% is required to shift wettability from oil-wet to strongly water-wet conditions. Sand pack flooding experiments, on the other hand, further demonstrated that this optimized fluid system can potentially recover an additional 16.1 % of oil following SW flooding. Finally, inductively coupled plasma (ICP) analysis revealed a notable increase in metal ion concentration during EDTA flooding, indicating enhanced leaching of metals from the sandstone surface and improved wettability characteristics.

LOW SALINITY WATER INJECTION EVALUATION AND MATURE FIELD DEVELOPMENT AT ANGGORO SHALLOW SAND, SANGASANGA FIELD

AbstractAnggoro's shallow sand was perforated at well ANG-1033 (D4-N1 layer). Oil production in this well increased from an average of 15 BOPD to 170 BOPD. That the perforated layer was affected by low salinity water injection (salinity < 3000 ppm). Evaluation of water injection sweep efficiency was carried out using the Dykstra-Parson method, vertical efficiency of about 0.3, area efficiency of 0.7, and displacement efficiency of 0.3. The Estimated Ultimate Recovery (EUR) of this well provides is 197 MBbls with an additional RF of around 20 %. This increase is due to the low salinity water injection sweep mechanism that occurs. The clay content plays an important role in the mechanism that occurs in this layer, these mechanisms fines migration, increase in pH, multi ion exchange, double layer effect, and salting in which these mechanisms result in increased oil recovery. Seeing the production results from the D4-N1 layer and oil production in this layer can still be maximized, in the future this layer can be developed with several programs such as reactivation, workover, and development drilling.Keywords: Low salinity water injection, shallow layer, efficiency

A review of scale inhibitor methods during modified smart water injection

AbstractEnhancing oil recovery (EOR) through water flooding methods, including smart water injection, low salinity water injection, polymer injection, and surfactant injection has become a pivotal strategy for enhancing productivity. Despite their promising outcomes, these methods often encounter challenges such as scaling formation and deposition, impacting reservoir permeability and production rates. A comprehensive understanding of scaling formation is crucial for effective implementation of these methods. This article explores various scaling types prevalent in the field, examining key parameters (temperature, pressure, and pH) that influence scaling formation. Additionally, it presents a diverse range of inhibitors employing both chemical and mechanical methods to mitigate and prevent scaling, thus safeguarding reservoir performance. The efficiency of inhibitors is scrutinized concerning chemical composition and performance maintenance under different temperature and pressure conditions. This study serves as a valuable resource for researchers, engineers, and industry experts involved in the oil industry and reservoir management. By elucidating scaling mechanisms, delineating consequences, and offering extensive solutions, it enhances comprehension and provides a foundation for improving oil recovery strategies. The findings of this study contribute to a better understanding of scaling mechanisms, providing insights that can be applied to optimize oil recovery processes, mitigate reservoir challenges, and improve overall reservoir management strategies.

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.

Salt-acid-surfactant synergistic effects on interfacial characteristics of water/oil systems: A molecular dynamics simulation study

Low salinity water injection with surfactants is one of the standard approaches in enhanced oil recovery (EOR). This method relies on the interaction of surfactants and ions at oil/water interfaces to reduce the interfacial tensions. However, the details of the mechanisms governing the synergistic effects of these components are still debatable. In this study, molecular dynamic (MD) simulations have been employed to investigate the challenging interactions of chemicals and saline water at a molecular scale. The model oil phase used in this study was defined as a mixture of toluene and decane. In addition, the synergistic materials are NaCl, sodium dodecyl ethoxy sulfate (AES), and decanoic acid.The results of density profiles, planar distribution maps, and PMF calculations imply that the acid molecules in the oil phase act as surfactants and form micelles. A few water molecules are also transferred to the oil phase to form water-acid micelles at high surfactant concentrations. Consequently, the number of acid components in the interfacial area is decreased; hence, the IFT reduction is alleviated. The results showed that micelle formation was decreased by adding ions to the aqueous phase. RDF profiles indicate that surfactant-acid interaction improves by adding ions to the water phase. The higher surfactant-acid interactions keep the polar hydrocarbon molecules near the interface and prevent them from moving to the hydrocarbon phase. This study also highlights the vital role of surfactant-acid interactions in the arrangements and orientations of surface-active materials. Orientation analysis indicates that salts in water and hydrophobic acids synergize to orient surfactants parallel to the interface. These facts signify that the surfactant-acid interaction is one of the main factors that critically affect the water–oil interfacial behavior.

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.

A comprehensive evaluation of the effect of key parameters on the performance of DTPA chelating agent in modifying sandstone surface charge

Despite the positive aspects of low salinity water (LSW), this technique is relatively expensive and unavailable in some countries. Furthermore, potential problems associated with LSW such as scale precipitation in carbonate reservoirs and fine migration in sandstone reservoirs raise concerns. Chelating agents have the ability to chelate metal ions from solution, effectively reducing the salinity of seawater (SW) and mimicking the behavior of LSW. However, they mitigate the challenges associated with LSW injection. This study focuses on how the Diethylenetriaminepentaacetic acid (DTPA) chelating agent performs in modifying rock surface charge. The impact of concentration, brine salinity, potential determining ions (PDIs), oil presence, Fe3+ ions, and solution pH on the effectiveness of DTPA in altering rock surface charge was evaluated. Furthermore, wettability alteration and sand pack flooding tests were conducted to study the effect of DTPA on rock wettability and oil recovery. Results of wettability alteration, zeta potential, sand pack flooding experiments and ion concentration analysis are reported in this paper. The results showed that reducing salinity, increasing DTPA concentration, and raising solution pH changed rock wettability from oil-wetness towards water-wetness. The presence or absence of PDIs in the solution did not affect the performance of DTPA. However, by tripling the concentration of these ions in the solution, the performance of DTPA in changing rock surface charge was impaired. Based on the wettability alteration and zeta potential experiments, 5 wt% DTPA was determined as the optimum concentration. Subsequent flooding experiments revealed that injecting 5 wt% DTPA chelating agents into the sandstone sand pack after SW injection increased oil recovery from 48 % to 68.3 %. The analysis of ion concentrations also revealed a significant increase in the amount of calcium ions during the DTPA flooding, indicating the chelation of metal ions from both rock and solution and improving the wettability conditions.

Simulation study of affecting parameters during low salinity water injection in carbonate reservoirs: from core to field scale

Over the last decade, economic and environmental factors have led to low salinity water injection (LSWI) becoming one of the most important improved oil recovery methods. Although many results have been obtained from laboratory tests, only a few papers have been published regarding the modeling and simulating LSWI in carbonate reservoirs compared to sandstone reservoirs. This paper investigated the most affecting parameters on oil recovery during LSWI at the core and field scale. The published work focused more on the effective parameters related to ultimate oil recovery using LSWI. However, important parameters affecting the oil recovery rate were not investigated. We compared how important parameters affected the ultimate oil recovery factor and ultimate oil recovery rate. According to the results of this study, the salinity of injected water and curvature of oil relative permeability were the most important factors on the ultimate oil recovery factor. By reducing both of these parameters, more increment oil was recovered. By increasing the injection rate of water, the curvature of the water relative permeability, wettability, and the endpoint of oil relative permeability, the oil recovery rate also increased. Furthermore, threshold capillary pressure and the endpoint of relative permeability of water had inverse effects on oil recovery. Injecting low salinity water into the reservoir will change its wettability. As a result, it will change the properties of the reservoir and increase the production from the reservoir, resulting in more oil being produced. LSWI resulted in an increase of oil recovery factor of 5% and 11% respectively after 25 and 58 years in this case.

Low-Salinity Polymer Flood for Enhanced Oil Recovery in Low-Permeability Carbonates

Summary Low-salinity waterflooding and brine ion modification, in general, can improve displacement efficiency in initially oil-wet reservoirs if it can alter wettability, but it is often a slow process. Polymer flooding usually does not improve displacement efficiency (without significant viscoelasticity) but enhances sweep efficiency. The main objective of this work is to study the synergy between ion modification and polymer flooding for low-permeability carbonate rocks. High-salinity high-temperature reservoirs often need a sulfonated polymer for thermal stability in the high-salinity brine, but a low-salinity water (LSW) injection at that temperature can use a common hydrolyzed polyacrylamide (HPAM) polymer. The second objective of this study is to compare the performance of these two polymer injections. With the proper preparation method, two polymers (HPAM and AN132) with the molecular weight of approximately 6 MDa were successfully injected into the oil-aged carbonate rocks with the absolute permeability of 10–20 md. A low-salinity polymer (LSP) flood was carried out using HPAM prepared in diluted seawater (with added sulfate concentrations). High-salinity polymer (HSP) floods increased the oil recovery in tight cores by 4–5% original oil in place (OOIP) due to higher pressure gradient. Low-salinity corefloods (with added sulfate ions) produced little incremental oil in a few pore volumes (PVs) of injection, but the combination of sulfated low-salinity brine and polymer improved the oil recovery by 8–10% OOIP in less than 1.5 PV. It is shown for the first time that the low-salinity brine with additional sulfate and negatively charged HPAM polymer changed the wettability of the originally oil-wet carbonate rock to water-wet. The synergy between polymer and wettability alteration can recover oil from bypassed pores and shorten the time for oil recovery.

Rock wettability and interfacial tension improvement by exposure time effect in modified water injection process coupled with silica nanoparticles

New approaches to low salinity water (LSW) injection methods, such as LSW/surfactant, LSW/polymer, and LSW/nanofluid flooding, have been studied for oil reservoirs. Numerous researchers discussed the mechanisms related to enhanced oil recovery (EOR) efficiency and highlighted the significant impact of the wettability alteration and interfacial tension (IFT) reduction. This work studied the effect of exposure time on the wettability alteration and IFT in the LSW/nanoparticle (LSWN) flooding. Contact angle tests investigated rock wettability over a series of different times. A pendant drop tensiometer was used to measure the IFT. By coreflood apparatus, waterflood tests were also conducted, considering the effect of soaking time. Laboratory results showed that the involved mechanisms are time-dependent. More water-wet conditions and higher oil recovery were obtained under longer soaking time. In addition, the positive effect of LSWN was observed in tertiary flooding tests. The results also indicate that the effect of water-soluble oil compounds should be considered in measuring wettability and IFT.

Enhanced oil recovery prioritization based on feasibility criteria using intuitionistic fuzzy multiple attribute decision making: a case study in an oil reservoir

Decision-making is among the main concerns in management discussions. This applied research is about a Multiple Criteria Decision Making problem since the decision-making process is drawn upon quantitative and qualitative criteria under uncertain conditions. This study was conducted for an oil reservoir consisting of nine criteria and eight alternatives. To form the network structure and recognize the relationships between the criteria, alternatives, and criteria weights, the Fuzzy Analytic Network Process (FANP) was used. Moreover, the Interval Valued Intuitionistic Fuzzy-TODIM (IVIF-TODIM) technique prioritized the alternatives. A case study was applied to demonstrate and show the suitability of the suggested method. The study’s objective is to prioritize enhanced oil recovery (EOR) methods based on the feasibility criteria using the FANP and IVIF-TODIM techniques. This issue is required to implement the research because not all the EOR methods are implemented practically. They should be prioritized and chosen based on the budget, available infrastructures, and other important factors. The important issue is the manager’s decision to choose the best method by considering different indicators. This method is a tool for better decision-making. Using these techniques, low salinity water injection was selected as the best and most effective and feasible method.

Prediction of electrostatic properties of reservoir rock in low salinity water injection into carbonate reservoirs

Geochemical modeling along with chemical reactions is one of the challenges in modeling of low salinity water injection. The most important issue in the geochemical model is to determine the correct electrical charge distribution model and its tuning parameters. The composition of the rock as well as the candidate water used is effective in determining the type of model and its parameters, so that the tuning parameters are determined based on the history of zeta potential experiments. In this study, in order to determine the correct model of electrical charge distribution and its tuning parameters in carbonate rock samples, first, equilibrium samples of Candidate water with crushed rock are subjected to static zeta potential tests. Then, the diffuse electrical double layer model is used to determine the electrical charge of the rock/water and water/oil surfaces and to predict the zeta potential. In the following, by adjusting the tuning parameters of the model to match the prediction results of the model with the history of the laboratory data, the density of the carbonate rock surface, the equilibrium constants and the kinetics of the governing reactions are determined. The obtained results show that the range of error in zeta potential prediction by the model compared to the laboratory data is from 2 to 20%, which is within the acceptable range of the performance of electrical charge distribution models. Moreover, it could be observed that the error of prediction using DLM model is significantly less than the conventional models (CD-MUSIC and BSM) for different candidate water. Finally, the effect of calculated zeta potential changes is used to calculate the contact angle changes of low salinity water injection based on the coupling of DLVO theory and geochemical model. The results of the study prove that the prediction error is less than 5% compared to the results of the static wettability tests. Based on this, according to the good match between the model and the laboratory results, it is possible to determine the properties of surface sites in surface complexation models of carbonate samples using the proposed approach and the subsequent tuning data of the geochemical model.

Effects of salinity alternation on relative permeability and capillary pressure as determined from steady-state-transient test

This paper aims the development of a new laboratory method for the simultaneous determination of phase relative permeability (Kr) and capillary pressure (Pc) for low salinity (LS) waterflooding. The proposed method is based on the so-called steady-state-transient (SSTT) method that uses steady-state and transient coreflood data, which allows calculating Kr and Pc from the same coreflood. A novel mathematical modelling is developed to determine Kr and Pc for two-phase multicomponent transports, where these parameters also depend on component concentrations, i.e. kr(s,c) and pc(s,c).Two sister cores from the same outcrop are used for the SSTT and wettability measurement experiments. The SSTT is performed using a sequence of HS injection → core re-initialization → LS injection to enable comparison of Kr and Pc curves for the same initial conditions. The modelling resultsusing a well-posed inverse algorithm - indicate a significant decrease in relative permeability for water, an insignificant increase in relative permeability for oil, a slight reduction in residual oil saturation, and a negligible downward shift in the Pc curve after LS water injection. This is explained by the formation damage caused by the mobilization of fine particles and the consequent pore-scale flow diversion due to pore plugging.

Application of Nanoparticles to Enhanced Oil Recovery

Due to the disadvantages of traditional EOR methods, such as low sweep efficiency, formation damage and poor environmental protection, nanotechnology has attracted great attention in improving oil recovery due to its cost-effectiveness and environmental protection. Common types of nanoparticles that can play an effective role in enhancing oil recovery include oxides of aluminum, zinc, magnesium, iron, zirconium, nickel, tin and silicon. At home and abroad in this paper, the different types of nanomaterials research progress on the reservoir and production technology are introduced in detail, involving nanoparticles in effect on the viscosity of heavy oil and hydraulic fracturing technology, heat recovery technology, low salinity water injection technology and steam foam flooding technology and changing wettability, to reduce the oil/water interfacial tension and so on the basis of theoretical research and application situation. Scholars at home and abroad have carried out a lot of experiments and numerical simulations on the role of nanoparticles in enhancing oil recovery, as well as the required concentration and action conditions, and elaborated on the mechanism of nanoparticle enhanced oil recovery. In this paper, the latest research progress in this field at home and abroad is reviewed, and the key problems and development direction in the application of nanotechnology are pointed out.

A mechanistic study of low salinity water-based nanoparticle-polymer complex fluid for improved oil recovery in sandstone reservoirs

Low salinity water flooding has gained tremendous attention in these days due to its cost-effectiveness and environment-friendly nature. Fine tuning of physico-chemical properties of low saline water by addition of suitable chemicals and nanoparticle (NP) can increase the oil recovery significantly because of synergistic effects. In this study, an attempt has been made to explore the benefit of adding nanoparticle and polymer into low salinity water (LSW) for increased oil recovery. Two complex chemical slugs were prepared with formation water (FW) and LSW as base fluids consisting of different concentrations of polymer and NP. The target viscosity for maximum sweep efficiency was estimated through the total minimum relative mobility concept. The rheological studies of the complex chemical slugs revealed that the addition of NP into polymer solution increased the viscosity significantly because of formation of macromolecular structure. It has been observed that a lower concentration of polymer is required to reach the target viscosity in LSW than FW. The benefits of low salinity effects over high saline formation water are evidenced by the reduction of interfacial tension (IFT), which is further reduced by addition of NP. A low IFT is always desirable for enhanced oil recovery. Contact angle showed a decreasing trend with FW, LSW and Nano fluid solutions respectively but presence of polymer in the slugs shows reverse effect on contact angle. LSW showed higher recovery as compared to FW in secondary recovery stage due to different reported mechanisms. Injection of LSW based complex fluid showed incremental recovery of 13.3 % of OOIP as compared to LSW and 22.0 % of OOIP as compared to conventional FW flooding in secondary stage. Synergistic effect of NP and polymer to form a complex macromolecular structure through hydrogen bonding and low salinity effect led to the improved oil recovery.”

A Numerical Study of Tertiary Oil Recovery by Injection of Low-Salinity Water

The injection of Low Salinity Water (LSWI) as an Enhanced Oil Recovery (EOR) method has recently attracted a lot of attention. Extensive research has been conducted to investigate and identify the positive effects of LSWI on oil recovery. In order to demonstrate the impact of introducing low salinity water into a reservoir, simulations on the ECLIPSE 100 simulator are being done in this work. To simulate an actual reservoir, an easy static model was made. In order to replicate the effects of injecting low salinity water and normal salinity, or seawater, the reservoir is three-phase with oil, gas, and water. It has one injector and one producer. Five cases were suggested to investigate the effect of low salinity water injection with different concentrations and the period of injection. The low salinity injection period varied from twenty-five years in case one and reduced five years in each case until reached to five years in final case. Higher oil recovery factor obtained in case one with injection time twenty-five years and lower recovery factor for case five with injection time of low salinity water injection five years. Lower water concentration gives higher oil recovery for all cases where this study investigated the effect of low-salinity water flooding as slug injection. From the five cases presented, field oil recovery factor (FOE), field oil production rate (FOPR), field oil production total (FOPT), field pressure (FP), and field water cut (FWCT) were observed. Oil recovery is 56.6 percent in high salinity water flooding (HSWF), and 71.8 percent in low salinity water flooding (LSWF) for 0 percent salt concentration and 62.40 percent for 20 percent salt concentration as in case one.

A Review of Wettability Alteration by Spontaneous Imbibition Using Low-Salinity Water in Naturally Fractured Reservoirs

Analysis of fluid flow in naturally fractured reservoirs (NFRs), as a highly heterogeneous and complex system, requires a detailed study of the fracture-matrix interactions. The main process of fluid movement between the fracture and matrix is spontaneous imbibition (SI), which can occur in co/countercurrent fluid flow states. In addition, most carbonate rocks are fractured and non-water-wet, which can lead to low oil recovery. Wettability greatly affects the performance of the SI process. Injection of water or chemicals can be insufficient because fluids mostly pass through highly permeable fractures and lead to early breakthrough. Therefore, the wettability alteration mechanism should be applied in NFRs, and low-salinity water (LSW) injection is considered an effective enhanced oil recovery (EOR) approach. In this review, experimental and numerical studies of co/counter-imbibition are analyzed to show the importance of investigating the fracture-matrix interactions. In addition, the review shows the wettability effect on imbibition in fractured rocks. The review of experimental studies of LSW imbibition in fractured carbonates shows the possibilities for implementing an EOR method. However, the wettability alteration process during SI using LSW has not yet been studied, and no simulation models of co/countercurrent flows have yet been provided. Based on this review, more experimental studies are recommended to duplicate co/countercurrent imbibition using LSW. Advanced techniques such as CT scanning, MRI, and NTI can be used to reveal fluid distribution. Using experimental data, numerical models can be developed to characterize dynamic wettability alteration during co/countercurrent imbibition.