Surfactant Polymer Flooding Research Articles

Nanomaterials for scaling prevention in alkaline–surfactant–polymer flooding: A review

Nanomaterials for scaling prevention in alkaline–surfactant–polymer flooding: A review

Synergistic SmartWater based surfactant polymer flooding for enhanced oil recovery in carbonates

SmartWater flooding has been recognized as an efficient and practical technology to synergize with different enhanced oil recovery methods for increasing oil recovery. This article aims to investigate the beneficial synergy effect between the SmartWater and surfactant-polymer (SP) flooding for carbonate reservoirs. Both zeta potential and contact angle measurements revealed that a favorable wettability alteration was induced with SmartWater. Coreflooding experiments were performed using preserved carbonate core samples at reservoir conditions. Results demonstrated that SP flooding combined with SmartWater achieved higher oil recovery with less chemical consumption when compared to conventional SP flooding.

Silicate Scaling Formation: Impact of pH in High-Temperature Reservoir and Its Characterization Study

Silicate scaling tends to form and be aggravated during high pH Alkaline Surfactant Polymer (ASP) floods and this silicate scale deposition affects oil production. Hence, it is important to examine the conditions that lead to silicate scale forming. The severity of the silicate scaling reaction, the type and morphology of silica/silicate scale formed in an experimental ASP flood were studied for pH values 5, 8.5, and 11, whilst the temperature was kept constant at 90 ℃. In addition, the impact of calcium ion was studied and spectroscopic analyses were used to identify the extent of scaling reaction, morphology type and the functional group present in the precipitates. This was performed using imagery of the generated precipitates. It was observed that the silica/silicate scale is most severe at the highest pH and Ca:Mg molar ratios examined. Magnesium hydroxide and calcium hydroxide were observed to precipitate along with the silica and Mg-silicate/Ca-silicate scale at pH 11. The presence of calcium ions altered the morphology of the precipitates formed from amorphous to microcrystalline/crystalline. In conclusion, pH affects the type, morphology, and severity of the silica/silicate scale produced in the studied scaling system. The comprehensive and conclusive data showing how pH affects the silicate scaling reaction reported here are vital in providing the foundation to further investigate the management and prevention of this silicate scaling. Copyright © 2022 by Authors, Published by BCREC Group. This is an open access article under the CC BY-SA License (https://creativecommons.org/licenses/by-sa/4.0)

Optimization of surfactant-polymer formulations for improving oil production

This study investigated the optimal concentration of an anionic surfactant (APA-H1) and a sulfonated polyacrylamide (SPAM-A5) formulation for SP flooding at high temperature high salinity conditions. IFT, viscosity and oil production rate in micromodel tests of the formulation were evaluated from 200 to 2000 ppm in high salinity water at 90 °C. Results showed by injecting 1000 ppm APA-H1 and 1,500 ppm SPAM-A5 with ∼10−4 mN/m IFT and 5.4 cP viscosity, the highest incremental oil production was 27%, which were not improved by increasing chemical concentrations. The work reveals there exists an optimal range of surfactant polymer concentrations in SP flooding.

Experimental studies of surfactant-polymer flooding: An application case investigation

A great deal of oil field is currently produced using water flooding and the water cut has reached a high level, which requires enhanced oil recovery (EOR) techniques to improve the recovery. Surfactant-polymer (SP) flooding is the combination of surfactant flooding and polymer flooding. The polymer is added to increase the viscosity and viscoelasticity of the fluid while the surfactant is included to decrease the oil–water interfacial tension and change the wettability. Although the mechanism of SP flooding has been deeply investigated, the application of SP flooding on a specific oil field requires the selection of optimal SP system. Therefore, for the first time, we performed a series of experiments to determine the optimal SP system for high water-cut oil field. In the injection capability experiment, we observe that the SP system is injected into the core with less resistance compared with single polymer solution. In the flooding experiment, regardless of the polymer types, the improvement of recovery becomes significant when the injected PVs increases. SP flooding shows the higher improvement of recovery compared with single polymer flooding or surfactant flooding. Based on the performance of recovery improvement, we recommend the optimal SP system for the studied case is the combination of DQ-TSRP01 polymer and surfactant. The optimal injection parameters of this SP system are 1500 mg/L polymer concentration, 0.3 injection PV and the injection timing of 96% water cut. The finding of this study can help for better understanding of the application of SP flooding in high water-cut oil field production.

The results of single well chemical tracer tests to assess the effectiveness of surfactant-polymer exposure at the Kholmogorskoye field

Methods of enhanced oil recovery in general and surfactant-polymer flooding in particular are considered as tertiary methods for the development of mature oil fields in Western Siberia, with the potential to increase oil recovery to 60-70% of the initial geological reserves.
 To select an effective mixture of surfactants and polymer for surfactantpolymer flooding, laboratory tests were carried out in which the thermal stability, phase behaviour, interfacial tension and rheology of the formulations were tested. Filtration experiments were also carried out to optimize the volumes of injected fringes and the concentrations of reagents in them. At the final stage, single well chemical tracer tests (SWCTT) were carried out to assess the effectiveness of surfactant-polymer flooding on two wells of the Kholmogorskoye field. In order to investigate different technical and economic models of surfactant-polymer exposure, SWCTT tests were conducted with the same surfactant, but with a different design. The results of the SWCTT tests showed that the residual oil saturation in the affected area after injection of the surfactant-polymer solution decreased by about 11% compared to water flooding, which is about a third of the residual oil after flooding. The tested surfactant showed acceptable efficiency under suboptimal temperature conditions, which is favorable for the use of the selected surfactant-polymer composition for neighboring deposits and formations with different reservoir temperatures, but similar water composition.
 In general, the results of the conducted field tests correlate with the results of the main laboratory experiments for the selected surfactant.

Performance evaluation of deep eutectic solvent for surfactant polymer flooding

Surfactant polymer (SP) flooding is among the most efficient and widely accepted chemical enhanced oil recovery (EOR) processes which involves slug injection containing a polymer and surfactant. This work is aimed at understanding the effect of different deep eutectic solvents (DESs) as an additive for EOR. For this, two different DES have been synthesized, having different hydrogen bond donors and acceptors and their effect on EOR was investigated. The results show that the addition of DESs as surfactant additives significantly improves flooding performance. The addition of DES1 and DES2 at critical micelle concentration (CMC) reduced the surface tension of water by 47% and 43%, respectively. The interfacial tension was drastically reduced upon the addition of DES. Also, DES molecules were found to affect the micellization concentration of surfactants. The addition of 1000 ppm of DES1 and DES2 reduced the CMC of surfactant by 17% and 9% respectively. In addition, DESs reduced the surfactant adsorption by 34% and 22% for DES1 and DES2, respectively. These results show that prepared DESs are highly efficient and outperformed the conventional [C12mim][Cl] and [C4mim][PF6] ionic liquids. The addition of DESs further enhanced the cumulative oil recovery for surfactant polymer flooding.

Factors influencing oil recovery by surfactant–polymer flooding in conglomerate reservoirs and its quantitative calculation method

This study aims to clarify the factors influencing oil recovery of surfactant–polymer (SP) flooding and to establish a quantitative calculation model of oil recovery during different displacement stages from water flooding to SP flooding. The conglomerate reservoir of the Badaowan Formation in the seventh block of the Karamay Oilfield is selected as the research object to reveal the start-up mechanism of residual oil and determine the controlling factors of oil recovery through SP flooding experiments of natural cores and microetching models. The experimental results are used to identify four types of residual oil after water flooding in this conglomerate reservoir with a complex pore structure: oil droplets retained in pore throats by capillary forces, oil cluster trapped at the junction of pores and throats, oil film on the rock surface, isolated oil in dead-ends of flow channel. For the four types of residual oil identified, the SP solution can enhance oil recovery by enlarging the sweep volume and improving the oil displacement efficiency. First, the viscosity-increasing effect of the polymer can effectively reduce the permeability of the displacement liquid phase, change the oil–water mobility ratio, and increase the water absorption. Furthermore, the stronger the shear drag force of the SP solution, the more the crude oil in a porous medium is displaced. Second, the surfactant can change the rock wettability and reduce the absorption capacity of residual oil by lowering interfacial tension. At the same time, the emulsification further increases the viscosity of the SP solution, and the residual oil is recovered effectively under the combined effect of the above two factors. For the four start-up mechanisms of residual oil identified after water flooding, enlarging the sweep volume and improving the oil displacement efficiency are interdependent, but their contribution to enhanced oil recovery are different. The SP flooding system primarily enlarges the sweep volume by increasing viscosity of solution to start two kinds of residual oil such as oil droplet retained in pore throats and isolated oil in dead-ends of flow channel, and primarily improves the oil displacement efficiency by lowing interfacial tension of oil phase to start two kinds of residual oil such as oil cluster trapped at the junction of pores and oil film on the rock surface. On this basis, the experimental results of the oil displacement from seven natural cores show that the pore structure of the reservoir is the main factor influencing water flooding recovery, while the physical properties and original oil saturation have relatively little influence. The main factor influencing SP flooding recovery is the physical and chemical properties of the solution itself, which primarily control the interfacial tension and solution viscosity in the reservoir. The residual oil saturation after water flooding is the material basis of SP flooding, and it is the second-most dominant factor controlling oil recovery. Combined with the analysis results of the influencing factors and reservoir parameters, the water flooding recovery index and SP flooding recovery index are defined to further establish quantitative calculation models of oil recovery under different displacement modes. The average relative errors of the two models are 4.4% and 2.5%, respectively; thus, they can accurately predict the oil recovery of different displacement stages and the ultimate reservoir oil recovery.

The Effect of Alkaline on the Properties of Combination Flooding Agent During Long Distance Migration in Daqing Oilfield

Abstract Combination flooding, which performs well on both sweep efficiency and displacement efficiency, is being extensively utilized in Daqing Oilfield. Surfactant-polymer (SP) flooding and alkaline-surfactant-polymer (ASP) flooding are two of the most used combination flooding techniques. According to the findings, alkaline lowers the oil-water interfacial tension and reduces the other component’s adsorption. Nevertheless, alkaline also has negative effects like scaling and cost increasing. Therefore, the use of alkaline in combination flooding is still disputed. In order to clarify the role of alkaline on combination flooding, SP and ASP flooding comparative tests are conducted with typical formula in Daqing Oilfield. A 3000-centimeter long model is built to simulate long distance migration for the property change study. During the flooding, fluid samples are obtained along the model, and the properties of the samples such as viscosity, interfacial tension (IFT), and components concentration are measured. According to the findings, the 3.60 percent higher recovery rate caused by ASP flooding compared to SP flooding is primarily due to the near inlet area. In ASP flooding, alkaline reduces polymer and surfactant near inlet dynamic retention by 20.16% and 13.43%, respectively, when compared to SP flooding. Besides, alkaline also maintains viscosity at a higher level and IFT at a lower level in the first third of the well spacing in ASP flooding. Consequently, the effects of alkaline are noticeable in the near inlet area and fade as distance increase.

Application of a novel amphiphilic polymer for enhanced offshore heavy oil recovery: Mechanistic study and core displacement test

A molecular modified polyacrylamide with Gemini surfactant monomers, named as HA1, was evaluated in this paper as an alternative to enhance the offshore heavy oil recovery. The physical properties of HA1 solution including apparent viscosity, rheological properties, static adsorption, interfacial activities (IFT, interfacial visco-elasticity and contact angle), emulsification ability, as well as oil recovery capacity were comprehensively investigated. Our results indicate that due to the hydrophobic and Gemini surfactant monomers on the acrylamide backbone, this novel amphiphilic polymer possesses more advanced functions than conventional polymers. HA1 demonstrates pronounced aqueous-phase viscosifying ability by forming 3D network in solution when the concentration is above CAC. In addition, the IFT, interfacial visco-elasticity and contact angle response illustrate that HA1 interacts strongly with the oil-phase which gives rise to its significant interfacial activity. Thereby, HA1 is able to reduce the heavy oil viscosity by emulsifying oil into water phase even at relatively low water content (20%) and also avoids dehydration difficulty by reducing the oil-brine interfacial rigidity. Furthermore, the asphaltene morphology change due to HA1 observed by SEM and AFM proves that HA1 can disperse the asphaltene aggregates in the crude oil, leading to a direct reduction of the heavy oil viscosity. At last, the coreflooding in an artificially synthesized triple-layered porous media shows that HA1 gives rise to an additional oil recovery of 27.04%, at the optimum concentration of 1600 ppm, by improving sweep efficiency, microscopic efficiency and dispersion of the asphaltene aggregates. Therefore, the potential of HA1 to enhance heavy oil recovery is comparable to traditional multi-component polymer-surfactant flooding. Since HA1 is single-component, it can also mitigate incompatibility issues like chromatography separation and surfactant-polymer interactions. Overall, this new self-assembly system shows potential for applications in heavy oil recovery.

Creation of a Hydrodynamic Digital Model of a Laboratory Core Experiment of Surfactant Polymer Impact on Oil Recovery, in Order to Determine Parameters for Further Full-Scale Simulation

The work aimed to solve the problem of determining, validating, and transferring model parameters of flooding using chemical enhanced oil recovery (EOR) from a core experiment to a full-scale hydrodynamic model. For this purpose, a digital hydrodynamic model describing the process of oil displacement by the surfactant and polymer solution on the core is created and the digital model is matched to achieve convergence with the historical data. This approach allows the uncertainties associated with the limited number of experiments to be removed to fully describe the parameters of the chemical surfactant polymer flooding model and form a database that could subsequently be replicated at various field sites, having the composition of reservoir fluids and distribution of rock composition in the core material as the basis. Besides, the digital model allows for verification of physical and chemical properties of surfactants and polymers, values of the adsorption of chemical agents on rocks, and the behavior of relative permeability in the hydrodynamic model of EOR before making predictions on the full-scale model and to improve the quality of forecast cases.

Determination of relative permeability curve under combined effect of polymer and surfactant

Relative permeability of surfactant-polymer (SP) flooding is determined by an inversion method based on numerical simulation and unsteady-state coreflooding experiment. Compared with the common methods, this method is more time-saving and simpler than steady-state method, and considers more physicochemical properties (adsorption and diffusion) of SP than unsteady-state method based on Buckley-Leverett theory. It is also more applicable to reservoir engineering than pore-scale simulation. After the reliability is confirmed, the superiority of the method is strongly proved by studying the influence of adsorption and diffusion of SP on relative permeability. Comparing relative permeability with and without effect of adsorption and diffusion of SP, the findings show adsorption and diffusion of SP significantly reduce the average inversion error of relative permeability curve from 11.9 to 3.7 for oil and from 10.7 to 1.8 for water. On this basis, the variations of SP-flooding relative permeability under the effect of polymer and surfactant are discussed in turn. In the existing researches, the quantitative characterization of variation of SP-flooding relative permeability curves is limited by curve crossing and endpoint saturation changes. In this work, normalized relative permeability is introduced to eliminate the adverse effect caused by curve crossing and endpoint saturation changes. The findings show that although the rise of aqueous-phase viscosity reduces water relative permeability, it has little effect on normalized water relative permeability. Normalized oil and water relative permeability increase in logistic functions with the decrease of IFT in semi-logarithmic plot. Water relative permeability at residual oil endpoint decreases linearly as aqueous-phase viscosity increases, and increases exponentially as IFT decreases in semi-logarithmic plot. Ultimately, the functional models based on normalized relative permeability and cubic B-spline are built through multiple regression, which can calculate relative permeability of SP flooding in term of IFT and aqueous-phase viscosity.

Application of Polymers for Chemical Enhanced Oil Recovery: A Review.

Polymers play a significant role in enhanced oil recovery (EOR) due to their viscoelastic properties and macromolecular structure. Herein, the mechanisms of the application of polymeric materials for enhanced oil recovery are elucidated. Subsequently, the polymer types used for EOR, namely synthetic polymers and natural polymers (biopolymers), and their properties are discussed. Moreover, the numerous applications for EOR such as polymer flooding, polymer foam flooding, alkali–polymer flooding, surfactant–polymer flooding, alkali–surfactant–polymer flooding, and polymeric nanofluid flooding are appraised and evaluated. Most of the polymers exhibit pseudoplastic behavior in the presence of shear forces. The biopolymers exhibit better salt tolerance and thermal stability but are susceptible to plugging and biodegradation. As for associative synthetic polyacrylamide, several complexities are involved in unlocking its full potential. Hence, hydrolyzed polyacrylamide remains the most coveted polymer for field application of polymer floods. Finally, alkali–surfactant–polymer flooding shows good efficiency at pilot and field scales, while a recently devised polymeric nanofluid shows good potential for field application of polymer flooding for EOR.

Functional characteristics and dominant enhanced oil recovery mechanism of polymeric surfactant

There are more than 40% remaining oil trapped in the reservoir in the mature oilfield even after second and tertiary recovery processes. High performance chemical agent was required for the trapped oil further mobilization. Polymeric surfactant was synthesized by grafting the active ground into the polymer skeleton. It has the advantages of surfactant polymer (SP) flooding and overcome the chromatographic separation during SP flooding. However, it is still unclear how the supramolecular molecular structure of polymeric surfactant affects its properties. Two kinds of polymeric surfactants named HB and HD with different molecular structures were characterized in this paper. Their molecular structure, static properties and enhanced oil recovery (EOR) efficiency were examined and compared via a series of experiments. The results showed that HD was dominated by amide group with hydrophobic association structure, and exhibited the supramolecular characteristics of space network; while HB mainly consisted by ring groups, showing a straight chain structure. HD featured with a better thickening, shear-resistance and salt-resistance ability, while HB can easily emulsify oil. In the microfluidic and three parallel core flooding experiments, HD both presented a higher recovery factor due to its good mobility control performance. Cluster remaining oil obviously declined and film-liked remaining oil slightly increased during HB and HD flooding stage. The incremental oil recovery of HD after water flooding was 26.6%, which was 5.5% higher than that of HB. This work indicates the molecular structure of spatial network is preferred in the design of polymer molecular structure towards EOR in the heterogeneous reservoir.

Xanthan gum-added natural surfactant solution of Chuback: A green and clean technique for enhanced oil recovery

Enhanced oil recovery (EOR) is one of the most important branches of petroleum engineering. For this purpose, the surfactant flooding method remains one of the primary methods because of the prospects of wettability adjustment and a decrease in oil-water interfacial tension (IFT). However, environmental load and high costs make synthetic organic surfactants flooding inefficient and uneconomical under certain conditions. A new natural surfactant, viz. Chuback, was introduced in this study because natural surfactants are environmentally benign, nonhazardous, and cost-effective. The effects of adding bio-based xanthan gum (XG) and increasing the salinity on the wettability adjustment, IFT, rheological behaviors, and core flooding characteristics were investigated in terms of the performance of the designed surfactant-polymer flooding system. The results showed that Chuback is very efficient in wettability alteration from an oil-wet state to a water-wet state with an increase in the oil droplet contact angle in the carbonate (from 16.71° to 60.52°) and sandstone (from 8.87° to 50.1°) rock cores. In addition to the 28.6% higher oil recovery in the carbonate core, effective IFT reduction of 74%, and almost optimum mobility ratio (M = 1.01), Chuback exhibited excellent improvement in its rheological properties in the presence of XG, even under high-salinity conditions; its effect was comparable to that of commonly used synthetic surfactants. Thus, in this study, we successfully determined the application of Chuback as a suitable candidate for EOR purposes.

SmartWater based synergistic technologies for enhanced oil recovery

Enhanced oil recovery (EOR) technologies based on chemicals and solvents require significant volume of source injection materials, and have limited applicability in difficult environments and harsh reservoir conditions. Synergizing injection water compositions in terms of salinity and ionic content (SmartWater) with existing recovery methods can become a game changer to overcome these limitations.The main objective is to explore the synergistic effects of SmartWater as a potential optimization avenue for achieving more efficient and economic EOR applications. To achieve this objective, a range of multiscale experimental data from macro- to core-scale were analyzed to demonstrate and quantify the benefits of water chemistry synergies with different recovery methods. The multiscale experimental data analyzed comprised of polymer rheology, contact angles, core floods, foam stability and rheology, besides evaluating the zeta potential results obtained from surface complexation modeling (SCM).The dilute concentrations of polymer ranging from 250 to 500 ppm in SmartWater increased the injection water viscosities by 2 to 4 times to provide better mobility control for light oil recovery. The tailored water chemistry reduced the polymer consumption requirements by one-third (from 3000 ppm to 2000 ppm) and increased the oil recovery by 5–7% in polymer flooding processes used for viscous oil recovery. Synergizing water chemistry with surfactant-polymer flooding resulted in an incremental oil recovery of about 4% besides lowering the surfactant and polymer concentrations by 50% (from 2000 ppm to 1000 ppm). SmartWater has also been found to synergistically combine with carbonated waterflooding to increase the CO2 dissolved volumes by 25–30% for effectively lowering the pH and develop favorable wettability alterations towards water-wet conditions. The tailored water chemistry increased the foam stabilities by resulting in 2–3 times higher foam half-lifes in addition to raising the foam apparent viscosities by 1.5 times. SmartWater foams also increased the pressure drops in porous media by 50% to confirm higher foam apparent viscosities and more resistance to gas flow.The benefits of different SmartWater based synergistic EOR technologies demonstrated in this study can be significant. They can deliver higher oil recoveries in addition to lowering the volume requirements of different EOR agents such as chemicals and gas. These findings will have a practical impact to result in more practical, efficient and economical EOR projects in the field.

Application of α-MnO2 nanoparticles for residual oil mobilization through surfactant polymer flooding.

Injection of surfactant and polymer slug is among the most effective chemical enhanced oil recovery processes. The only problem encountered with the surfactant polymer (SP) flooding is the loss of surface-active agents that reduce the efficiency of surfactants in the chemical slug. Various attempts to modify SP flooding have been made previously so that the surfactant loss due to adsorption could be reduced. Nanoparticles (NPs) are one of the most effective ways of reducing surfactant adsorption as surfactant particles are held in the liquid phase by nanoparticles, resulting in lower surfactant losses due to adsorption. However, the high cost of the NPs limits their use on the field scale. To encounter this problem, the present study focuses on the application of the manganese dioxide NPs, synthesized through a green route that is economically viable. These NPs are found to be cost-effective as compared to commercially available NPs as well as the synthesis of these NPs does not require the use of toxic chemicals. The 1000ppm NPs effectively reduced the surfactant adsorption by 46%. The surface tension was lowered from 29.4 to 26.1 mN/m when 1000ppm NPs were applied to 2500ppm surfactant solution. Also, the nanoparticles were found to increase the viscosity of the chemical slug by increasing the solid particles present in the slug. The sand pack flooding experiments were carried out to assess the crude oil mobilization ability of the NPs assisted SP flooding. The oil recovery was found to increase from 5% of the original oil in place, resulting in ~ 75% of the crude oil recovery, which was only ~ 70% when NPs were not introduced into the system.

Polymer-Surfactant Flooding in Low-Permeability Reservoirs: An Experimental Study.

Chemical flooding technology has been widely applied in medium- and high-permeability reservoirs. However, it is rarely applied in low-permeability reservoirs, which is mainly limited by reservoir physical properties, chemical agents, injection capacity, and so forth. In this paper, a novel chemical formula used in low-permeability reservoirs was developed. In response to the low-permeability reservoir geological characteristics, fluid properties, and water flooding development of the target block, some experimental studies and field project studies of polymer–surfactant flooding were carried out. The surfactant structure and polymer molecular weight were determined from laboratory experiments. The polymer–surfactant binary system was synthesized. It had good injectivity in low-permeability reservoirs, and its oil recovery efficiency increased over 10% in the laboratory experiment. The result was higher than that of single chemical flooding. After field implementation, initial results have been achieved with an increase in injection pressure. The chemical formula can effectively alleviate intra-layer and inter-layer contradictions in the reservoir. The project has increased oil output by 77,700 t and the recovery factor by 3.5%. The experience and lessons were of great significance for the development of chemical flooding in high-temperature, high-salinity, and low-permeability reservoirs.

Predicting the surfactant-polymer flooding performance in chemical enhanced oil recovery: Cascade neural network and gradient boosting decision tree

Surfactant-polymer flooding is one of the most important enhanced oil recovery (EOR) techniques, which refers to the injection of surfactant slugs and polymer drives. Two crucial decision-making parameters in EOR operations are net present value (NPV) and oil recovery factor (RF). Herein, various intelligent models, based on multilayer perceptron (MLP), cascade neural network (CNN), radial basis function (RBF), neural networks as well as support vector regression (SVR), and decision tree (DT) algorithms are proposed toward estimating these two parameters with respect to polymer drive size, surfactant slug size, the salinity of polymer drive, Kv/Kh ratio, surfactant concentration, and polymer concentration in polymer drive and surfactant slug. The results exhibited the outperformance of the CNN model trained with the Levenberg Marquardt algorithm in forecasting the RF and NPV with average absolute errors of 0.66% and 1.95%, respectively. Moreover, the results of the sensitivity analysis reflected that the most effective inputs on the predicted value of RF were surfactant concentration and surfactant slug size, while surfactant concentration and polymer concentration in surfactant slug could considerably affect the NPV model’s output. Lastly, the outlier detection analysis revealed that the employed data is valid and only two points were detected as outliers.

New fully implicit formulations for the multicomponent surfactant-polymer flooding reservoir simulation

The injection of chemicals such as polymers, surfactants, and alkali into oil reservoirs are referred to chemical enhanced oil recovery (CEOR) and can significantly increase the recovery of oil. Polymer increases water viscosity, yielding better mobility control, which reduces the amount of oil bypassed. Surfactants reduce capillary forces by lowering the interfacial tension, allowing the recovery of trapped oil that is normally left behind in conventional waterflooding. Despite the strong appeal that these two techniques offer, the injection of chemicals is expensive, and proper field optimization is required to ensure a robust recovery design. Such optimization can be carried out with the help of a reservoir simulator, a numerical tool capable of emulating the multiphase flow in the reservoir rock. Most attempts to develop chemical flooding reservoir simulators have faced challenges due to the particular nonlinearities of the physicochemistry for modeling CEOR. Therefore, most simulators reported in the literature use the IMPEC (implicit pressure, explicit concentrations) approach, which suffers from time-step restrictions, or fully implicit approaches that do not cover the whole range of the microemulsion (ME) phase behavior. This work presents new models and fully implicit approaches for surfactant-polymer flooding considering all important phase behavior types and dependency on salinity, assuming no gas is present and that the brine, oil, and microemulsion phases are slightly compressible. The oil phase is modeled as a single component phase but multiple components (i. e. surfactant, anions, polymer) are transported in aqueous and surfactant-rich microemulsion phases, therefore making this a multicomponent model. This paper presents three different fully implicit approaches to solve the flow and transport equations, along with new relative permeability models that smooth and minimize discontinuities at phase changes, thereby improving the convergence of the Newton scheme. The first scheme uses pressure and concentrations as primary variables, while the second is based on natural variables, and the third one considers a mixed variable scheme. These schemes are compared with an IMPEC approach, and the different numerical models are compared in terms of oil recovery, production rates, saturation profiles, CPU time, Newton iterations, and linear solver iterations. The new formulations were implemented into the University of Texas at Austin Chemical Flooding Reservoir Simulator (UTCHEM-RS), a variation of the well-established UTCHEM. It was observed that the fully implicit (FI) approaches have a better computational performance than the IMPEC approach for polymer flooding, while the FI global variables presented a better computational performance for field-scale surfactant-polymer flooding through the increase of the time-step. Accuracy was observed to deteriorate with the increasing of time-step, although it had minor effects on the oil recovery. However, the results suggests that caution must be taken when selecting the time-step.