Surfactant Polymer Flooding Research Articles

Study on interfacial tension, wettability and viscosity in different salinities of synthesized a new polymeric surfactant for improving oil recovery

Over 50% of the original oil in place (OOIP) is immobile or trapped in the reservoir. Therefore, today, more efficient methods have been introduced in the tertiary oil recovery sector as a scheme of enhanced oil recovery (EOR). Due to the decline of conventional hydrocarbon reserves, polymers are increasingly used in EOR methods, such as surfactant-polymer (SP) and alkaline-surfactant-polymer (ASP) flooding. SP flooding has a complex formulation and design, leading to undesirable phase separation if improperly mixed. Polymeric surfactants are a promising alternative to SP flooding. They consist of hydrophobic groups attached to hydrophilic polymers, which help to improve the mobility ratio and reduce interfacial tension (IFT). This paper examines the rheological and synthesis properties of a new polymeric surfactant produced through bond co-polymerization reaction using different hydrolyzed polyacrylamide (HPAM) ratios and a zwitterion hydrophobic group. The synthesized hydrophobically modified zwitterionic polyacrylamide (HMZPAM) was characterized by FTIR and HMNR analysis. HMZPAM performed better than other substances in IFT, viscosity, wettability, oil recovery, and resistance to different one and two-valence cations. The results indicate that HPAM reduced the IFT to 13.65, while HMZPAM reduced it to 0.441 mN/m. Wettability change evaluated on a rock carbonate/crude oil/HMZPAM system that changed the water-wet state of the primary oil-wet rock carbonate to strongly water-wet state as wettability change measurements showed a decrease in contact angle from 62.76 to 21.23 degree. Comparative studies on the effectiveness of HPAM and HMZPAM were also conducted according to the measurement of viscosity and shear rate in the presence of salt, which indicates the higher shear rate and viscosity of HMZPAM. Core flooding tests revealed that HMZPAM resulted in better additional recovery due to microscopic displacement, resulting in a total oil recovery of 84%, compared to 48% of residual oil saturation for HPAM. Also, salts decreased oil recovery in HPAM injection but increased oil recovery in HMZPAM injection.

Emulsion formation and stability of surfactant–polymer flooding

Emulsification plays a pivotal role in the process of enhanced oil recovery, especially in chemical flooding. Surfactant–polymer flooding is a promising technique with significant potential for improving oil recovery in medium and high permeability oilfields in China. Emulsification has emerged as one of the key mechanisms facilitating oil recovery in surfactant–polymer flooding. This study aimed to assess the effects of surfactant structure and concentration, polymer, oil–water ratio, clay content, and injection rate on the formation of different emulsion types and their stabilities. The assessment was conducted based on the actual conditions of surfactant–polymer flooding in the Qizhong area of the Xinjiang oilfield. The findings revealed that KPS-1 (petroleum sulfonate) demonstrated superior emulsifying and solubilizing abilities for crude oil compared to BS-18 (betaine), whereas BS-18 exhibited better emulsifying stability. KPS, which was a combination system of KPS-1 and BS-18, displayed favorable emulsifying ability. However, the emulsifying stability of the three surfactants decreased in the presence of HPAM (hydrolyzed polyacrylamide). The oil–water ratio primarily influenced the morphology of the emulsion. When the oil–water ratio exceeded 6:4, a water-in-oil emulsion was formed, and the viscosity of the emulsion reached its maximum at an oil–water ratio of 7:3. Moreover, clay demonstrated a significantly high ability to emulsify, resulting in the formation of emulsions with increased viscosity and robust stability. Regarding the injection rate, effective emulsification occurred when the injection rate reached 1 m/d, while emulsions with high viscosity were observed at an injection rate of 7 m/d.

Non-thermal recovery of a viscous oil with a surfactant-polymer process

The goal of this work is to improve recovery of a viscous oil reservoir at 70 °C using a non-thermal process. Polymer floods can improve sweep efficiency, but leave behind a residual oil saturation. A surfactant-polymer flood has the potential to improve both the sweep as well as the displacement efficiency. Phase behavior experiments with the viscous oil, water and surfactants were conducted to identify surfactants. 1D and 2D sandpack displacements were conducted to evaluate the efficacy of the process. Phase behavior experiments showed Winsor type I behavior with a low interfacial tension using a single surfactant, but not ultralow tension. Water flood recovered about 50% OOIP and reduced the oil saturation to about 45% in 1D floods. The subsequent SP flood increased the cumulative oil recovery to 99% in sandpacks when the viscosity of chemical slugs exceeded the oil viscosity. When the permeability decreased (as in a Bentheimer core), the oil recovery decreased to about 86%. Secondary SP floods also recovered most of the oil and faster than tertiary floods. Reduction of polymer concentration (and viscosity to about 1/4th of the oil viscosity) reduced the oil recovery, especially in 2D sandpack floods. Decrease in interfacial tension increased the requirement of polymer concentration to maintain flood front stability. This flood demonstrates the effectiveness of Winsor type I SP formulation for viscous oil, high permeability reservoirs. Such a SP process would reduce the carbon footprint of viscous oil recovery compared to that of thermal processes.

3-D Modelling and Simulation of a Reservoir for Surfactant-Polymer Flooding Using Eclipse Software

Surfactant-polymer flooding is a tertiary enhanced oil recovery method used to recover oil that remained in the reservoir after the primary and secondary oil recovery mechanisms. Predicting the pressure in the reservoir is important for oil production as pressure changes with time. A suitable approach to achieve this task is to derive fluid flow equation based on the reservoir characteristics and solve them numerically which provide the solution to the mathematical fluid flow model (diffusivity equation). In this study, 3-D reservoir was modelled using Eclipse software. The fluid flow equations in a porous media were derived based on the simulated model and the reservoir conditions. Numerical solution using implicit formulation to solve the mathematical fluid flow model (diffusivity equation) was investigated by developing Python codes using Jupyter library to ascertain the pressure distribution for the reservoir and imported into Eclipse simulator. Simulation was carried out using surfactant-polymer and reservoir properties to determine the oil recovery. The results of the study showed that pressure increases with time as oil production continued, and water saturation decreased for the grid-cells of the reservoir. Waterflooding had oil recovery of 38.0% and water-cut of 59.0%, while surfactant flooding had oil recoveries of 42.0%, 46.5%, 49.0% and water-cut of 57.0%, 51.0%, 46.3%. In addition, polymer flooding had oil recoveries of 44.3%, 48.4%, 54.0% and water-cut of 50.0%, 45.0% and 33.0% respectively at different concentrations of 0.3%wt. 0.4%wt. and 0.5%wt.

Development of surfactant formulation for high-temperature off-shore carbonate reservoirs.

The residual oil left behind after water flooding in petroleum reservoirs can be mobilized by surfactant formulations that yield ultralow interfacial tension (IFT) with oil. However, finding ultralow IFT surfactant formulations is difficult for high-temperature, off-shore, carbonate reservoirs. These reservoirs are often water-flooded with seawater (with a lot of divalent ions), which is often incompatible with many surfactants at high temperatures. The goal of this research is to develop a surfactant formulation for an off-shore carbonate reservoir at 100°C previously flooded by seawater. Surfactant-oil-brine phase behavior was studied for formulations, starting from a single surfactant to mixtures of surfactants and a co-solvent. Mixtures of three surfactants and one co-solvent were needed to produce ultralow IFT formulations for the oil of interest. The surfactant system with polymer mobility control was tested in crushed reservoir rock packs. The cumulative oil recovery was >99% for the surfactant-polymer (SP) flood with an optimal salinity gradient. The constant salinity SP floods with seawater increased oil recovery significantly beyond the water flood (cumulative oil recovery >91%), even though the recovery was lower than that of the optimal salinity gradient SP flood. Our experimental work demonstrates the effectiveness of the surfactant formulation for a high-temperature carbonate reservoir at seawater salinity.

Study on the Mobilization Mechanisms of Microscopic Residual Oil in High-Water-Cut Sandstone Reservoirs

As mature oilfields enter the high-water-cut development stage, significant amounts of residual oil remain trapped underground. To enhance the effectiveness of tertiary oil recovery, it is crucial to understand the distribution and mobilization patterns of this residual oil. In this study, polydimethylsiloxane (PDMS) was used to create a microscopic oil displacement model, which was observed and recorded using a stereomicroscope. The experimental images were extracted, analyzed, and quantitatively evaluated, categorizing the microscopic residual oil in the high-water-cut sandstone reservoirs of Dagang Oilfield into cluster-like, pore surface film-like, corner-like, and slit-like types. Polymer–surfactant composite flooding (abbreviated as SP flooding) effectively mobilized 47.16% of cluster-like residual oil and 43.74% of pore surface film-like residual oil, with some mobilization of corner-like and slit-like residual oil as well. Building on SP flooding, dual-mobility flooding further increased the mobilization of cluster-like residual oil by 12.37% and pore surface film-like residual oil by 3.52%. With the same slug size, dual-mobility flooding can reduce development costs by 16.43%. Overall, dual-mobility flooding offers better development prospects.

Study on Surfactant-Polymer Flooding after Polymer Flooding in High-Permeability Heterogeneous Offshore Oilfields: A Case Study of Bohai S Oilfield.

Polymer flooding is an effective development technology to enhance oil recovery, and it has been widely used all over the world. However, after long-term polymer flooding, a large number of oilfields have experienced a sharp decline in reservoir development efficiency. High water cut wells, serious dispersion of residual oil distribution and complex reservoir conditions all bring great challenges to enhance oil recovery. In this study, the method of enhancing oil recovery after polymer flooding was studied by taking the S Oilfield as an example. A surfactant-polymer system suitable for high-permeability heterogeneous oilfields was developed, comprising biogenic surfactants and polymers. Microscopic displacement experiments were conducted using cast thin sections from the S Oilfield, and nuclear magnetic resonance was employed for core displacement experiments. Numerical simulation experiments were also conducted on the S Oilfield. The results show that the enhanced oil recovery mechanism of the surfactant-polymer system is to adjust the flow direction, expand the swept volume, emulsify crude oil and reduce interfacial tension. Surfactant-polymer flooding proves to be effective in improving recovery efficiency, significantly reducing the time of flooding and further enhancing the strong swept area. The nuclear magnetic resonance results indicate a high amplitude of passive utilization of residual oil during the surfactant-polymer flooding stage, highlighting the enormous potential for an increased recovery ratio. Surfactant-polymer flooding emerges as a more suitable technique to enhance oil recovery in the post polymer-flooding stage in high-permeability heterogeneous oilfields.

SURFACTANT–POLYMER FLOODING: GEOCHEMICAL MONITORING OF THE PROPERTIES OF FORMATION FLUIDS AT THE IMPACT AREA

Chemical flooding methods improve oil extraction after standard waterflooding processes. Chemical EOR methods modify different properties of fluids and/or rock to mobilize the remaining oil. It is expected that the residual oil will be different in properties than conventional. A new technology is presented to study a surfactant–polymer flooding, based on a periodic sampling and measuring properties of oil and water during 15 months. The study area is a terrigenous reservoir with 3 chemical injection wells and 16 production wells. High-precision mass spectrometry methods were carried out on each sample, which made it possible to evaluate the effectiveness of ongoing work on chemical flooding. At each sampling date, 2D reservoir model was built to track these changes in the study area. It is shown that the composition of the water has changed - highly permeable channels were closed and formation waters were involved in the production. The properties of oil have also changed - depending on the site of impact, there are areas with more degraded oil in production after the injection of chemicals. Geochemical monitoring shows the redistribution of filtration flow directions in the reservoir volume.

Forecasting the efficiency of waterflooding, thermal and chemical enhanced oil recovery methods in Bobrikovian reservoirs

The development of reserves contained viscous and highly viscous oil poses one of the major challenges in modern reservoir engineering. The poor performance of conventional waterflooding prompts the application of enhanced oil recovery (EOR) methods, of which thermal and chemical EOR are considered the most efficient. Reservoir simulation is a powerful tool for evaluating EOR performance. Serial runs of a history-matched model of a Bobrikovian reservoir are used to evaluate the incremental oil production due to each EOR technique and formulate the efficiency limits of the process performance criteria. In contrast to previous studies that evaluated EOR applications using reservoir simulation modeling, an entirely new quality model is derived through automatic history matching performed by solving an inverse problem. Another novel feature is the automated selection of the optimum field development scenario given a user-defined objective function. Evaluating the performance of hot water injection in a Bobrikovian reservoir suggests that this technology yields positive effects when the injected water temperature ranges from 50 °C to 90 °C. The surfactant–polymer flooding method is also investigated. The largest incremental oil production with a constant surfactant concentration of 0.5% is observed for a polyacrylamide concentration of 0.25%, which can be attributed to a water cut reduction due to plugging the well-drained and flushed reservoir zones. The greatest incremental oil production is achieved when injecting 1.5% surfactant and 0.25% polyacrylamide. The highest efficiency per ton of injected chemicals is obtained when injecting 0.5% polyacrylamide and 0.10% surfactant. Keywords: High-viscosity oil; EOR; thermal methods; surfactant-polymer flooding; reservoir simulation; history matching; injection simulation scenario.

Research on Microbial Community Structure in Different Blocks of Alkaline–Surfactant–Polymer Flooding to Confirm Optimal Stage of Indigenous Microbial Flooding

The microbial communities associated with alkaline–surfactant–polymer (ASP)-flooded reservoirs have rarely been investigated. In this study, high-throughput sequencing was used to analyse the indigenous microbial communities in two different blocks, the water flooding after the alkaline–surfactant–polymer flooding block and the alkaline–surfactant–polymer flooding block, and to ascertain the optimal stage for the implementation of indigenous microbial oil recovery technology. The different displacement blocks had significant effects on the indigenous microbial community at the genus level according to an alpha diversity analysis and community composition. In water flooding after alkaline–surfactant–polymer flooding, the dominant genus of Pseudomonas exceeded 30%, increasing to 52.1% in alkaline–surfactant–polymer flooding, but alpha diversity decreased. Through a co-occurrence network analysis, it was found that the complexity of the water flooding after alkaline–surfactant–polymer flooding was higher than that of alkaline–surfactant–polymer flooding. This means that the water flooding ecosystem after alkaline–surfactant–polymer flooding was more stable and less susceptible to external environmental influences. In addition, there were significant differences in the functional redundancy of microbial communities in different blocks. In summary, the optimal stage for implementing local microbial oil recovery technology may be water flooding after alkaline–surfactant–polymer flooding.

Experimental Investigation of the Effect of Surfactant–Polymer Flooding on Enhanced Oil Recovery for Medium Crude Oil

High technical and financial risks are involved in exploring and exploiting new fields; hence, greater focus has placed on the development of environmentally friendly, cost-effective, and enhanced oil recovery (EOR) options for existing fields. For reservoirs producing high-density crudes and those with high interfacial tensions, water flooding is usually less effective due to density differences—hence the advent of polymer and surfactant flooding. For cost-effective and eco-friendly EOR solutions, a biopolymer and a surfactant synthesized from Jatropha seeds are used in this study to determine their effectiveness in increasing the oil recovery during core flooding analysis. The experiment involved an initial water flooding that served as the base cases of three weight percentages of polymers and polymeric surfactant solutions. The results for the polymer flooding of 1 wt%, 1.5 wt%, and 2 wt% showed an incremental oil recovery in comparison to water flooding of 16.8%, 17%, and 26%, while the polymeric surfactant mixtures of 5 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded 16.5%, 22.3%, and 28.8%, and 10 wt% of surfactant and 1 wt%, 1.5 wt%, and 2 wt% of a polymer recorded incremental oil recoveries of 20%, 32.9%, and 38.8%, respectively.

Characterization of the Solution Properties of Sodium Dodecylsulphate Containing Alkaline–Surfactant–Polymer Flooding Media

Alkaline–surfactant–polymer (ASP) flooding by means of which alkali additives, surfactant and polymer are inserted as the same slug is one of the most favourable worldwide focuses of Chemical Enhanced Oil Recovery (cEOR) research and field trials, due to the individual synergy of the three chemical components. To develop efficient oil recovery chemicals, it is essential to fully understand the mechanism behind ASP flooding. Nonetheless, there are hardly any studies reporting a systematic characterization of the ASP process. Thus, the present paper focuses on modelling this process in a laboratory by the use of an anionic surfactant—sodium dodecyl sulphate (SDS) in alkaline–polymer media—which is composed of a commercial water-soluble polymer (Flopaam AN125SH®, SNF Floerger, Andrézieux-Bouthéon, France) and alkali compounds (NaOH and Na2CO3). The samples were characterized using rheometry, dynamic light scattering (DLS), infrared spectroscopy (IR) and measurement of inferfacial tension (IFT) between the samples and rapeseed oil. In accordance with the experimental results, surprisingly lower IFT values were recorded between the alkaline–polymer solutions and rapeseed oil than the samples which contained SDS. Increasing polymer and sodium chloride concentration caused a decrease (from 0.591 mN/m to 0.0486 mN/m) in IFT between the surfactant containing samples and rapeseed oil. The IR measurements confirmed that the surfactant was not detected in the oil phase in the absence of NaOH and Na2CO3. The effects of SDS on the viscosity of the mixtures were also investigated, as viscosity is a considerably important parameter in processes using polymers.

Decarbonization of Alkali–Surfactant–Polymer Flooding Enhanced Oil Recovery Process with Hydrogen under Uncertainty

Decarbonization of Alkali–Surfactant–Polymer Flooding Enhanced Oil Recovery Process with Hydrogen under Uncertainty

Effect of the Surfactant Type on the Demulsification of the W/O Crude Oil Emulsion Produced by Surfactant-Polymer Flooding.

At present, there are many works on the influences of partially hydrolyzed polyacrylamide (HPAM) and surfactant on the stability and treatment of O/W emulsion produced by surfactant-polymer (SP) flooding. However, there are few related reports on the effects of HPAM and surfactant on the demulsification of W/O crude oil emulsion produced by SP flooding. Especially, there is no report on the effect of the surfactant type. In this paper, sodium dodecyl sulfate (SDS), octylphenol polyoxyethylene ether (OP-10), and alkyl C16-18 hydroxypropyl sulfobetaine (HSB1618) were selected as representatives of the anionic surfactant, nonionic surfactant, and zwitterionic surfactant, respectively. Demulsification experiments and interface behavior experiments were conducted to investigate their influences on the demulsification performance of a demulsifier D1. The results showed that the order of the negative effect of the surfactant type on dehydration speed and the dehydration rate of D1 was HPAM + OP-10 > HPAM + HSB1618 > HPAM + SDS. There is no difference in the effect of three surfactants on the conformation adjustment of D1 at the W/O interface, but the properties of the composite W/O interface formed by them and D1 were different. The coalescence time was longest when there were HPAM and OP-10 in water, while the lg(G 1'/G demulsifier')/lgG 1' was the smallest, which led to the most difficult demulsification of W/O emulsion. This work can guide surfactant selection during SP flooding from the perspective of produced fluid treatment.

Surfactant–Polymer Flooding: Chemical Formula Design and Evaluation for High-Temperature and High-Salinity Qinghai Gasi Reservoir

The Gasi reservoir in the Qinghai oilfield is a typical high-temperature and high-salinity reservoir, with an average temperature and average salinity of 70.0 °C and 152,144 mg/L, respectively. For over 30 years since 1990, water flooding has been the primary method for enhancing oil recovery. Recently, the Gasi reservoir has turned into a mature oilfield. It possesses a high water cut of 76% and a high total recovery rate of 47%. However, the main developing enhanced oil recovery (EOR) technology for the development of the Gasi reservoir in the next stage is yet to be determined. Surfactant–polymer (SP) flooding, which can reduce the oil–water interfacial tension and increase the viscosity of the water phase, has been widely applied to low-temperature and low-salinity reservoirs across China in the past few decades, but it has rarely been applied to high-temperature and high-salinity reservoirs such as the Gasi reservoir. In this study, the feasibility of SP flooding for high-temperature and high-salinity reservoirs was established. Thanks to the novel surfactant and polymer products, an SP flooding formula with surfactants ZC-2/B2 and polymer BRH-325 was proposed for Gasi. The formula showed a low interfacial tension of 10−2 mN/m and a high viscosity of 18 MPa·s in simulated reservoir conditions. The oil displacement experiment demonstrated that this formula can enhance the oil recovery rate by 26.95% upon water flooding at 64.64%. This study provides a feasible EOR candidate technology for high-temperature and high-salinity reservoirs, as exemplified by the Qinghai Gasi reservoir.

Early warning methods of chemical agent channeling in polymer–surfactant flooding reservoirs

AbstractIn the chemical flooding process, the premature breakthrough of chemical agents in production wells results in a large waste of chemical agents and increases the volume and processing difficulty of the produced fluids. The early warning method of chemical agent channeling can predict the strength of agent channeling in advance. The practice of chemical flooding shows that the production performance can be used for early warning of chemical agent channeling. In this paper, we analyze the relationship between cumulative oil production and cumulative polymer production of production wells in polymer–surfactant flooding. Three types of curves according to the enhanced oil production characteristics of chemical flooding, including convex type, S‐type, and concave type. We use the drop speed of the water–oil ratio and the rapid‐decline speed of water cut as early warning indicators to predict the channeling coefficient. A Latin hypercube experimental design method is used to design a polymer–surfactant flooding scheme with the main control factors of the channeling coefficient and early warning indicators. Numerical simulation is used to calculate samples of the channeling coefficient and early warning indicators under various conditions. The drop speed of the water–oil ratio reference value model and the rapid‐decline speed of the water cut reference value model are determined with a multiple regression method. A prediction model for the chemical agent channeling coefficient is established using the deviation coefficient of an early warning index. The method is applied in the Ng54‐61 polymer–surfactant flooding pilot area in the west of the Gudong Seventh District, Shengli Oilfield, China, and the error between the predicted result and the actual value is less than 10%. This research is helpful in taking effective antichanneling measures and improving the oil recovery degree of chemical flooding reservoirs.

Surfactant-polymer flood with seawater for a high temperature carbonate reservoir

Developing ultralow tension surfactant formulations for carbonate reservoirs at high temperatures (> 100 °C) in the presence of hard brine is challenging. The target carbonate reservoir had been flooded with seawater and changing of the injection brine (softening or low salinity) for enhanced oil recovery was considered expensive. Seawater was presumed to be the injection brine for this study. The goal of this research work was to develop an ultralow tension surfactant-polymer (SP) formulation with seawater for this carbonate reservoir at 115 °C and to evaluate core floods with and without salinity gradient. Phase behavior was studied for many surfactants and ultralow IFT formulations were identified with the optimal salinity near the seawater salinity. SP core floods were conducted in reservoir sand packs at 115 °C; a novel 2-oven technique was used to collect the effluent with no wax formation and minimal hydrocarbon vaporization. The residual oil saturation was reduced to less than 1% in floods with salinity gradient and about 5% in constant salinity floods (at seawater salinity). The novelty of the work lies in developing SP formulations with seawater at a high temperature and studying the effect of salinity gradient. This process can be considered for many off-shore fields which have been waterflooded with seawater.

Relationship between polymer-surfactant interaction and micellar solubilization revealed by NMR spectroscopy

Micellar solubilization is considered as a key factor affecting the recovery efficiency in chemically enhanced oil recovery (cEOR). However, it is poorly understood how polymers in surfactant-polymer (SP) flooding influences the micellar solubilization. Guar gum (GG) and hydroxyethyl cellulose (HEC) are two important and widely used polysaccharide polymers. In this work, the effect of GG and HEC on the solubilization of a crude oil model compound methyl benzoate (MB) in anionic sodium dodecyl sulfate (SDS) micelles and the underlying mechanism were explored at the molecular scale by NMR spectroscopy. GG and HEC slightly increased the MB solubility in SDS micelles but did not change the solubilization capacity. No correlation peak was observed to demonstrate the attractive interaction between polymer and SDS. After examination, there is weak electrostatic repulsion between HEC/GG and SDS, which made the polymer independent from SDS micelles and was unable to participate in the formation of micelles to alter micellar structure and solubilization behavior. Although the solubility of MB was slightly increased, this increase should originate from weak molecular interactions between polymers, surfactants and hydrophobic molecules, including hydrogen bonding, van der Waals forces and hydrophobic interactions, etc. In summary, without strong electrostatic attraction between polymer and surfactant, the solubilization of polymers and the solubilization of micelles proceed independently, resulting in that the solubilization capacity of SDS micelles was not improved.

In-situ emulsification in low-tension surfactant/polymer systems: Impacts on enhanced oil recovery

The flow of two immiscible liquids in porous media can lead to fluid mixing, resulting in emulsions—where one phase is dispersed as droplets in the other. In reservoir rocks, natural surfactants and polar molecules, like asphaltenes, can promote oil–water emulsion formation. During chemically enhanced oil recovery processes (CEOR) such as surfactant, alkali, or surfactant-alkali flooding, in-situ emulsification is often seen as key to enhancing frontal stability and facilitating the piston-like displacement of oil by water. However, this work reports a minimal effect of in-situ emulsification on oil production during surfactant-polymer (SP) flooding. Experimental studies show this by injecting prepared emulsions into a multi pressure-tap core holder and examining emulsion formation in one reservoir core before moving it into a second core for oil displacement. This helps us understand the specific role of emulsions in oil mobilization. Factors like surfactant concentration, interfacial tension, and the timing of introducing the surfactant-polymer solution do influence the intensity of in-situ emulsification. Yet, the incremental oil recoveries show no significant differences. Through similar experiments, it is observed that ultra-low interfacial tension (IFT) in our surfactant-polymer system is the primary mechanism for oil mobilization. The slight increase in pressures suggests that in-situ emulsification has a limited role in increasing flow resistance during the ultra-low IFT SP flood process, potentially not improving the swept volume. This research can guide the development of systematic approaches to analyze the effects of in-situ emulsification on oil mobilization and evaluate chemical flooding processes.

A New Adaptive Implicit Method for Multicomponent Surfactant-Polymer Flooding Reservoir Simulation

Summary In the oil industry, chemicals can improve oil production by mobilizing trapped and bypassed oil. Such processes are known as chemical-enhanced oil recovery (CEOR). Surfactants and polymers are important chemicals used in CEOR with different mechanisms to improve oil recoveries, such as reduction in residual saturation, oil solubilization, and mobility control. However, both surfactant and polymer may increase the cost of oil production, making optimizing these processes essential. Reservoir simulators are tools commonly used when performing such field optimization. The simulation of surfactant flooding processes has been historically performed with the implicit pressure explicit composition (IMPEC) approach. The injection of surfactants requires modeling the brine/oil/microemulsion phase behavior along with other processes, such as capillary desaturation and retention. The microemulsion phase behavior and the complex relative permeability behavior can lead to convergence issues when using fully implicit (FI) schemes. Only recently, the FI approach has been efficiently applied to simulate this process using new modeling. The adaptive implicit method (AIM) can combine the benefits of the FI and IMPEC approaches by dynamically selecting the implicitness level of gridblocks in the domain. This work presents a new AIM in conjunction with recently developed models to mitigate discontinuities in the microemulsion relative permeabilities and phase behavior. The approach presented here considers the stability analysis method as a switching criterion between IMPEC and FI. To the best of our knowledge, the approach presented here is the first AIM to consider the brine/oil/microemulsion three-phase flow in its conception. The new approach uses the finite volume method in conjunction with Cartesian grids as spatial discretization and is applied here for field-scale problems. The new approach is tested for polymer flooding and surfactant-polymer (SP) flooding for problems with several active cells ranging from about a hundred thousand to almost a million. The AIM approach was compared with the FI and IMPEC approaches and displayed little variation in the computational performance despite changes in the timestep size. The AIM also obtained the fastest performance for all cases, especially for SP flooding cases. Furthermore, the results here suggest that the gap in performance between the AIM and FI seems to increase as the number of gridblocks increases.