A Numerical Investigation of Low Salinity Polymer Flooding Effects from a Geochemical Perspective

2021 ◽  
Author(s):  
Omar Chaabi ◽  
Emad W. Al-Shalabi ◽  
Waleed Alameri
Keyword(s):  
Aqueous Phase ◽  
Oil Recovery ◽  
Reactive Transport ◽  
History Matching ◽  
Solution Chemistry ◽  
Related Effect ◽  
Exchange Reactions ◽  
Two Phase ◽  
Low Salinity ◽  
Geochemical Reactions

Abstract Low salinity polymer (LSP) flooding is getting more attention due to its potential of enhancing both displacement and sweep efficiencies. Modeling LSP flooding is challenging due to the complicated physical processes and the sensitivity of polymers to brine salinity. In this study, a coupled numerical model has been implemented to allow investigating the polymer-brine-rock geochemical interactions associated with LSP flooding along with the flow dynamics. MRST was coupled with the geochemical software IPhreeqc. The effects of polymer were captured by considering Todd-Longstaff mixing model, inaccessible pore volume, permeability reduction, polymer adsorption as well as salinity and shear rate effects on polymer viscosity. Regarding geochemistry, the presence of polymer in the aqueous phase was considered by adding a new solution specie and related chemical reactions to PHREEQC database files. Thus, allowing for modeling the geochemical interactions related to the presence of polymer. Coupling the two simulators was successfully performed, verified, and validated through several case studies. The coupled MRST-IPhreeqc simulator allows for modeling a wide variety of geochemical reactions including aqueous, mineral precipitation/dissolution, and ion exchange reactions. Capturing these reactions allows for real time tracking of the aqueous phase salinity and its effect on polymer rheological properties. The coupled simulator was verified against PHREEQC for a realistic reactive transport scenario. Furthermore, the coupled simulator was validated through history matching a single-phase LSP coreflood from the literature. This paper provides an insight into the geochemical interactions between partially hydrolyzed polyacrylamide (HPAM) and aqueous solution chemistry (salinity and hardness), and their related effect on polymer viscosity. This work is also considered as a base for future two-phase polymer solution and oil interactions, and their related effect on oil recovery.

scholarly journals Enhanced Wettability Modification and CO2 Solubility Effect by Carbonated Low Salinity Water Injection in Carbonate Reservoirs

2017 ◽  
Vol 2017 ◽  
pp. 1-10 ◽  
Author(s):  
Ji Ho Lee ◽  
Kun Sang Lee
Keyword(s):  
Oil Recovery ◽  
Saline Water ◽  
Water Injection ◽  
Carbonate Reservoirs ◽  
Viscosity Reduction ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Geochemical Reactions ◽  
Salinity Water ◽  
Low Salinity Water Injection

Carbonated water injection (CWI) induces oil swelling and viscosity reduction. Another advantage of this technique is that CO2 can be stored via solubility trapping. The CO2 solubility of brine is a key factor that determines the extent of these effects. The solubility is sensitive to pressure, temperature, and salinity. The salting-out phenomenon makes low saline brine a favorable condition for solubilizing CO2 into brine, thus enabling the brine to deliver more CO2 into reservoirs. In addition, low saline water injection (LSWI) can modify wettability and enhance oil recovery in carbonate reservoirs. The high CO2 solubility potential and wettability modification effect motivate the deployment of hybrid carbonated low salinity water injection (CLSWI). Reliable evaluation should consider geochemical reactions, which determine CO2 solubility and wettability modification, in brine/oil/rock systems. In this study, CLSWI was modeled with geochemical reactions, and oil production and CO2 storage were evaluated. In core and pilot systems, CLSWI increased oil recovery by up to 9% and 15%, respectively, and CO2 storage until oil recovery by up to 24% and 45%, respectively, compared to CWI. The CLSWI also improved injectivity by up to 31% in a pilot system. This study demonstrates that CLSWI is a promising water-based hybrid EOR (enhanced oil recovery).

FORTESCUE RESERVOIR DEVELOPMENT AND RESERVOIR STUDIES

1985 ◽  
Vol 25 (1) ◽  
pp. 95
Author(s):  
S.T. Henzell ◽  
H.R. Irrgang ◽  
E.J. Janssen ◽  
R.A.H. Mitchell ◽  
G.O. Morrell ◽  
...  
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Three Dimensional ◽  
Two Phase ◽  
Aquifer System ◽  
Southeastern Australia ◽  
Drainage Patterns ◽  
Stock Tank ◽  
Well Pattern ◽  
Gippsland Basin

The Fortescue field in the Gippsland Basin, offshore southeastern Australia is being developed from two platforms (Fortescue A and Cobia A) by Esso Australia Ltd. (operator) and BHP Petroleum.The Fortescue reservoir is a stratigraphic trap at the top of the Latrobe Group of sediments. It overlies the western flank of the Halibut and Cobia fields and is separated from them by a non-net sequence of shales and coals which form a hydraulic barrier between the two systems. Development drilling into the Fortescue reservoir commenced in April 1983 with production coming onstream in May 1983. Fortescue, with booked reserves of 44 stock tank gigalitres (280 million stock tank barrels) of 43° API oil, is the seventh major oil reservoir to be developed in the offshore Gippsland Basin by Esso/BHP.In mid-1984, after drilling a total of 20 exploration and development wells, and after approximately one year of production, a detailed three-dimensional, two-phase reservoir simulation study was performed to examine the recovery efficiency, drainage patterns, pressure performance and production rate potential of the reservoir.The model was validated by history matching an extensive suite of Repeat Formation Test (RFT)* pressure data. The results confirmed the reserves basis, and demonstrated that the ultimate oil recovery from the reservoir is not sensitive to production rate.This result is consistent with studies on other high quality Latrobe Group reservoirs in the Gippsland Basin which contain undersaturated crudes and receive very strong water drive from the Basin-wide aquifer system. With the development of the simulation model during the development phase, it has been possible to more accurately define the optimal well pattern for the remainder of the development.* Mark of Schlumberger

A compositional formulation for multiphase multicomponent reactive transport modelling of highly coupled systems

2020 ◽  
Author(s):  
Nicolas Seigneur ◽  
K. Ulrich Mayer
Keyword(s):  
Water Resources ◽  
Reactive Transport ◽  
Transport Processes ◽  
Coupled Systems ◽  
Phase Flow ◽  
Reactive Transport Modelling ◽  
Two Phase ◽  
Transport Modelling ◽  
Geochemical Reactions ◽  
Contaminant Hydrology

<p>In certain reactive transport applications, strong coupling between geochemical reactions and hydrodynamics exists. Dissolution and precipitation of minerals, such as the conversion between gypsum and anhydrite [1] or the precipitation of nesquehonite during CO<sub>2</sub> sequestration [2], as well as gas bubble formation [3] are geochemical processes which modify the multiphase flow dynamics, with direct feedback on reactive transport processes. In addition, heat generation induced by sulphide mineral oxidation can lead to significant increases in temperature [4], impacting flow, transport and geochemical reactions. In these instances, commonly used reactive transport modelling approaches, which rely on decoupling flow and reactive transport processes, have limitations. For density dependent or two-phase flow problems in the presence of a gas phase, the coupling between flow and reactive transport can be accounted for through a Picard iterative approach [3,5,6]. However, this approach is computationally expensive, involving the solution of nonlinear problems multiple times during each timestep, and convergence properties are often poor. More recently, a weak explicit coupling approach was developed to capture the impact of chemistry on flow by integrating water as a component and perform a volume balance calculation [7]. In the current work, a compositional approach is implemented into MIN3P-THCm, in which the flow variables (pressure, density) are expressed based on mass variables. Hence, this global implicit approach does not require solving the flow problem, but instead integrates groundwater flow processes directly into the reactive transport equations. We show that this approach yields very similar results to the commonly used approaches for single and two-phase flow. Finally, we show that, in highly coupled systems, not considering these coupled effects may lead to significant errors in simulating system evolution, highlighting the benefits of the newly developed approach.</p><p> </p><p>[1] Jowett, Cathles & Davis (1993). AAPG Bulletin, 77(3), 402-413.</p><p>[2] Harrison, Dipple, Power & Mayer (2015). Geochimica et cosmochimica Acta, 148, 477-495.</p><p>[3] Amos and Mayer (2006). Journal of contaminant hydrology, 87(1-2), 123-154.</p><p>[4] Lefebvre, Hockley, Smolensky & Gélinas (2001). Journal of contaminant hydrology, 52(1-4), 137-164.</p><p>[5] Henderson, Mayer, Parker, & Al (2009). Journal of contaminant hydrology, 106(3-4), 195-211.</p><p>[6] Sin, Lagneau and Corvisier (2017). Advances in Water Resources, 100, 62-77.</p><p>[7] Seigneur, Lagneau, Corvisier & Dauzères (2018). Advances in Water Resources 122, 355-366.</p>

A Robust Geochemical Simulator To Model Improved-Oil-Recovery Methods

SPE Journal ◽  
2016 ◽  
Vol 21 (01) ◽  
pp. 55-73 ◽  
Author(s):  
Haishan Luo ◽  
Emad W. Al-Shalabi ◽  
Mojdeh Delshad ◽  
Krishna Panthi ◽  
Kamy Sepehrnoori
Keyword(s):  
Oil Recovery ◽  
Magnesium Ions ◽  
Improved Oil Recovery ◽  
Low Salinity ◽  
Geochemical Reactions ◽  
Newton Raphson ◽  
Calcium And Magnesium ◽  
Sacrificial Agent ◽  
Raphson Method ◽  
Calcium And Magnesium Ions

Summary The interest in modeling geochemical reactions has increased significantly for different improved-oil-recovery processes such as alkali/surfactant/polymer (ASP) flood, low-salinity waterflood, and ethylenediaminetetraacetic acid (EDTA) injection as a sacrificial agent in hard brine. Numerical simulation of multiphase flow coupled with geochemical reactions is challenging because of complex and coupled aqueous, aqueous/solid, and aqueous/oleic reactions. These reactions have significant impact upon oil recovery, and hence a robust geochemical simulator is important. UTCHEM (2000) is a chemical-flooding reservoir simulator with geochemical-modeling capability. Nevertheless, one major limitation in the geochemical-reactive engine of UTCHEM is assuming the activities of reactive species is equal to unity. In fact, the activity coefficients are strongly nonlinear functions of the ionic strength of solution. One approach to tackle this deficiency was to couple UTCHEM (flow and transport) with IPhreeqc (a geochemical reactive engine) (Kazemi Nia Korrani et al. 2013). However, the simulator proved to be computationally expensive. Therefore, it is desirable to improve the geochemical- reactive engine within UTCHEM. This paper presents the improvement of the geochemical-reactive engine in UTCHEM including implementing different activity-coefficient models for different reactive species, cation-exchange reactions, and numerical convergence. Certain unknown concentrations are eliminated from the elemental mass-balance equations and the reaction equations to reduce the computational burden. The Jacobian matrix and right-hand side of the linear-system equation in the Newton-Raphson method are updated accordingly in the Newton-Raphson method for performing the batch-reaction calculation. A low-salinity-waterflood case is presented to validate the updated UTCHEM against PHREEQC (Parkhurst and Appelo 1999) and UTCHEM-IPhreeqc. The simulation studies indicated that the updated geochemical simulator succeeds in tackling the inaccuracy concerned in the original UTCHEM. Also, the updated version is more efficient compared with PHREEQC and UTCHEM-IPhreeqc with the same degree of accuracy. The updated geochemical simulator is then applied to model an ASP coreflood in which EDTA is used as a sacrificial agent to chelate calcium and magnesium ions. The experimental data of pH, oil recovery, and pressure drop were successfully history matched with predictions of the effluent concentrations of calcium and magnesium ions. A synthetic 3D ASP pilot case is successfully simulated considering effects of acid equilibrium reaction constant on oil recovery.

scholarly journals Mysteries behind the Low Salinity Water Injection Technique

2014 ◽  
Vol 2014 ◽  
pp. 1-11 ◽  
Author(s):  
Emad Waleed Al-Shalabi ◽  
Kamy Sepehrnoori ◽  
Gary Pope
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
History Matching ◽  
Water Injection ◽  
Residual Oil ◽  
Oil Saturation ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Low salinity water injection (LSWI) is gaining popularity as an improved oil recovery technique in both secondary and tertiary injection modes. The objective of this paper is to investigate the main mechanisms behind the LSWI effect on oil recovery from carbonates through history-matching of a recently published coreflood. This paper includes a description of the seawater cycle match and two proposed methods to history-match the LSWI cycles using the UTCHEM simulator. The sensitivity of residual oil saturation, capillary pressure curve, and relative permeability parameters (endpoints and Corey’s exponents) on LSWI is evaluated in this work. Results showed that wettability alteration is still believed to be the main contributor to the LSWI effect on oil recovery in carbonates through successfully history matching both oil recovery and pressure drop data. Moreover, tuning residual oil saturation and relative permeability parameters including endpoints and exponents is essential for a good data match. Also, the incremental oil recovery obtained by LSWI is mainly controlled by oil relative permeability parameters rather than water relative permeability parameters. The findings of this paper help to gain more insight into this uncertain IOR technique and propose a mechanistic model for oil recovery predictions.

Geochemical Modeling of Hybrid Surfactant and Engineered Water Injections in Carbonate Reservoirs under Harsh Conditions

SPE Journal ◽  
2021 ◽  
pp. 1-25
Author(s):  
Ahmed Adila ◽  
Emad W. Al-Shalabi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Ion Concentration ◽  
Wettability Alteration ◽  
Surfactant Flooding ◽  
Exchange Reactions ◽  
Concentration Data ◽  
Data Set ◽  
Hybrid Surfactant ◽  
Harsh Conditions

Summary Engineered water injection (EWI) has gained popularity as an effective technique for enhancing oil recovery. Surfactant flooding is also a well-established chemical enhanced-oil-recovery (EOR) technique in the petroleum industry. The hybrid surfactant flooding/EWI (surfactant/EWI) technique has been studied experimentally and showed promising results. However, there are very limited numerical applications on the hybrid surfactant/EWI technique in carbonates in the literature. Also, the studies applied under harsh conditions of high temperature and high salinity are even fewer. In this study, a numerical-simulation model is developed and used to investigate the hybrid effect of surfactant/EWI in carbonates under harsh conditions. This developed model was validated by history matching a recently conducted surfactant coreflood in the secondary mode of injection. Oil recovery, pressure drop, and surfactant-concentration data were used. The surfactant-flooding model was then coupled with a geochemical model that captures different reactions involved during EWI. The geochemical reactions considered include aqueous, dissolution/precipitation, and ion-exchange reactions. The proposed model has been further validated by history matching another experimental data set. Furthermore, different simulation scenarios were considered, including waterflooding, surfactant flooding, EWI, and the hybrid surfactant/EWI technique. For the case of EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial-tension (IFT) reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that for the hybrid surfactant/EWI, wettability alteration is considered as the controlling mechanism where surfactant boosts oil-recovery rate through increasing oil relative permeability while EWI reduces residual oil. Moreover, the simulation runs showed that the hybrid surfactant/EWI is a promising technique for enhancing oil recovery from carbonates under harsh conditions. Also, hybrid surfactant/EWI results in a more water-wetting rock condition compared with that of EWI alone, which leads to lower injectivity, and hence, lower rate of propagation for ion-concentration waves. The hybrid surfactant/EWI outperformed other injection techniques followed by EWI, then surfactant flooding, and finally waterflooding. This work gives more insight into the application of hybrid surfactant/EWI on enhancing oil recovery from carbonates. The novelty is further highlighted through applying the hybrid surfactant/EWI technique under harsh conditions. In addition, the findings of this study can help in better understanding the mechanism behind enhancing oil recovery using the hybrid surfactant/EWI technique and the important parameters needed to model its effect on oil recovery.

Geochemical Modeling of Petrophysical Alteration Effect on CO2 Injectivity in Carbonate Rocks

2021 ◽  
Author(s):  
Fabio Bordeaux Rego ◽  
Shayan Tavassoli ◽  
Esmail Eltahan ◽  
Kamy Sepehrnoori
Keyword(s):  
Oil Recovery ◽  
Chemical Equilibrium ◽  
Carbonate Rocks ◽  
Reactive Transport ◽  
History Matching ◽  
Geochemical Modeling ◽  
Mineral Dissolution ◽  
Co2 Injection ◽  
Carbon Dioxide Injection ◽  
Gravity Segregation

Abstract Carbon dioxide injection into sedimentary formations has been widely used in enhanced oil recovery (EOR) and geological-storage projects. Several field cases have shown an increase in water injectivity during CO2 Water-Alternating-Gas (WAG) projects. Although there is consensus that the rock-fluid interaction is the main mechanism, modeling this process is still challenging. Our main goal is to validate a physically based model on experimental observations and use the validated model to predict CO2 injectivity alteration based on geochemical reactions in carbonate rocks. In this paper, we present a new method for CO2 reactive transport in porous media and its impact on injectivity. We hypothesize that if CO2 solubilizes in the connate water, then it induces a shift in chemical equilibrium that stimulates mineral dissolution. Consequently, porosity and permeability will increase, and cause alterations to well injectivity. We develop a predictive model to capture this phenomenon and validate the model against available data in the literature. We use UTCOMP-IPhreeqc, which is a fully coupled fluid-flow and geochemical simulator to account for rock/hydrocarbon/water interactions. In addition, we perform several experiments to test CO2/water slug sizes, mineralogy assembly, injected brine composition, and gravity segregation combined with the effect of heterogeneity. Coreflood simulations using chemical equilibrium and kinetics indicate mineral dissolution at reservoir conditions. The results suggest that the intensity of rock dissolution depends on formation mineralogy and brine composition as carbonate systems work as buffers. Additionally, we show that prolonged CO2 and brine injection induces petrophysical alteration close to the injection region. Our field-scale heterogeneous reservoir simulations show that permeability alteration calculated based on Carman-Kozeny correlation and wormhole formulation had the same results. Furthermore, we observed that water injectivity increased by almost 20% during subsequent cycles of CO2-WAG. This finding is also supported by the Pre-Salt carbonate field data available in the literature. In the case of continuous CO2 injection, the carbonate dissolution was considerably less severe in comparison with WAG cases, but injectivity increased due to unfavorable CO2 mobility. With the inclusion of gravity segregation, we report that the injectivity doubles in magnitude. The simulations show more extensive dissolution at the upper layers of the reservoir, suggesting that preferential paths are the main cause of this phenomenon. The ideas presented in this paper can be utilized to improve history-matching of production data and consequently reduce the uncertainty inherent to CO2-EOR and carbon sequestration projects.

Sequential Coupling of Geochemical Reactions With Reservoir Simulations for Waterflood and EOR Studies

SPE Journal ◽  
2012 ◽  
Vol 17 (02) ◽  
pp. 469-484 ◽  
Author(s):  
Lingli Wei
Keyword(s):  
Water Chemistry ◽  
Oil Recovery ◽  
Reactive Transport ◽  
Produced Water ◽  
Mineral Dissolution ◽  
Individual Species ◽  
Chemical Changes ◽  
Injection Water ◽  
Geochemical Reactions ◽  
The Impact

Summary Many waterflood projects now experience significant amounts of water cut, with more water than hydrocarbon flowing between the injectors and producers. In addition to the impact on water viscosity and density that results from using different injection-water sources during a field's life, water chemistry itself may impact oil recovery, as demonstrated by recent research on low-salinity water-injection schemes. It is also known that water chemistry has a profound impact on various chemical enhanced-oil-recovery (EOR) processes. Moreover, the effectiveness and viability of such EOR schemes is strongly dependent on reservoir-brine and injection-water compositions. In particular, the presence of divalent cations such as Ca+2 and Mg+2 has a significantly adverse effect for chemical EORs. Using new developments in reservoir simulation, this paper outlines a method to couple geochemical reactions in a reservoir simulator in black-oil and compositional modes suitable for large-scale reservoir models for waterflood and EOR studies. The new multicomponent reactive-transport modeling capability considers chemical reactions triggered by injection water and/or injected reactive gases such as CO2 and H2S, including mineral dissolution and precipitation, cation exchange, and surface complexation. For waterflood-performance assessment, the new modeling capability makes possible a more-optimum evaluation of petrophysical logs for well intervals where injection-water invasion is suspected. By modeling transport of individual species in the aqueous phase from injectors to producers, reservoir characterization can also be improved through the use of these natural tracers, provided that the compositions of the actual produced water are used in the history matching. The simulated water compositions in producers can also be used by production chemists to assess scaling and corrosion risks. For CO2 EOR studies, we illustrate chemical changes inside a reservoir and in the produced water before and after CO2 breakthrough, and discuss geochemical monitoring as a potential surveillance tool. Alkaline-flood-induced water chemical changes and calcite precipitation are also presented to illustrate applicability for chemical EOR with the new simulation capability.

A Novel Method To Model Low-Salinity-Water Injection in Carbonate Oil Reservoirs

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1154-1166 ◽  
Author(s):  
Emad W. Al-Shalabi ◽  
Kamy Sepehrnoori ◽  
Mojdeh Delshad ◽  
Gary Pope
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Carbonate Rocks ◽  
History Matching ◽  
Water Injection ◽  
Low Salinity ◽  
Low Salinity Water ◽  
Salinity Water ◽  
Low Salinity Water Injection

Summary There are few low-salinity-water-injection (LSWI) models proposed for carbonate rocks, mainly because of incomplete understanding of complex chemical interactions of rock/oil/brine. This paper describes a new empirical method to model the LSWI effect on oil recovery from carbonate rocks, on the basis of the history matching and validation of recently published corefloods. In this model, the changes in the oil relative permeability curve and residual oil saturation as a result of the LSWI effect are considered. The water relative permeability parameters are assumed constant, which is a relatively fair assumption on the basis of history matching of coreflood data. The capillary pressure is neglected because we assumed several capillary pressure curves in our simulations in which it had a negligible effect on the history-match results. The proposed model is implemented in the UTCHEM simulator, which is a 3D multiphase flow, transport, and chemical-flooding simulator developed at The University of Texas at Austin (UTCHEM 2000), to match and predict the multiple cycles of low-salinity experiments. The screening criteria for using the proposed LSWI model are addressed in the paper. The developed model gives more insight into the oil-production potential of future waterflood projects with a modified water composition for injection.

Geochemical Modeling of Hybrid Surfactant and Engineered Water Injections in Carbonate Reservoirs under Harsh Conditions

2021 ◽  
Author(s):  
Ahmed Adila ◽  
Emad W. Al-Shalabi ◽  
Waleed AlAmeri
Keyword(s):  
Oil Recovery ◽  
History Matching ◽  
Water Injection ◽  
Petroleum Industry ◽  
Wettability Alteration ◽  
Surfactant Flooding ◽  
Exchange Reactions ◽  
Concentration Data ◽  
Hybrid Surfactant ◽  
Harsh Conditions

Abstract Engineered water injection (EWI) has gained popularity as an effective technique for enhancing oil recovery. Surfactant flooding is also a well-established and commercially-available technique in the petroleum industry. In this study, a numerical simulation model is developed and used to investigate the hybrid effect of surfactant-EWI in carbonates. This developed model was validated by history-matching a recently conducted surfactant coreflood in the secondary mode of injection. Oil recovery, pressure drop, and surfactant concentration data were utilized. The surfactant flooding model was then coupled with a geochemical model that captures different reactions during engineered water injection. The geochemical reactions considered include: aqueous, dissolution/precipitation, and ion- exchange reactions. Also, different simulation scenarios were considered including waterflooding, surfactant flooding, engineered water injection, and the hybrid surfactant-EWI technique. For the case of EWI, wettability alteration was considered as the main mechanism underlying incremental oil recovery. However, both wettability alteration and interfacial tension reduction mechanisms were considered for surfactant flooding depending on the type of surfactant used. The results showed that for the hybrid surfactant-EWI, wettability alteration is considered as the controlling mechanism where surfactant boosts oil recovery rate through increasing oil relative permeability while EWI reduces residual oil. Moreover, the simulation runs showed that the hybrid surfactant-EWI is a promising technique for enhancing oil recovery from carbonates under harsh conditions. The hybrid surfactant-EWI outperformed other injection techniques followed by EWI, then surfactant flooding, and least waterflooding. This work gives more insight into the application of hybrid surfactant-EWI on enhancing oil recovery from carbonates.

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