scholarly journals MICROEMULSION FLOODING MECHANISM FOR OPTIMUM OIL RECOVERY ON CHEMICAL INJECTION

2018 ◽  
Vol 40 (2) ◽  
pp. 85-90
Author(s):  
Yani Faozani Alli ◽  
Edward ML Tobing ◽  
Usman Usman
Keyword(s):  
Oil Recovery ◽  
Mobility Control ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Viscosity ◽  
Oil Saturation ◽  
Remaining Oil ◽  
Tertiary Oil Recovery

The formation of microemulsion in the injection of surfactant at chemical flooding is crucial for the effectiveness of injection. Microemulsion can be obtained either by mixing the surfactant and oil at the surface or injecting surfactant into the reservoir to form in situ microemulsion. Its translucent homogeneous mixtures of oil and water in the presence of surfactant is believed to displace the remaining oil in the reservoir. Previously, we showed the effect of microemulsion-based surfactant formulation to reduce the interfacial tension (IFT) of oil and water to the ultralow level that suffi cient enough to overcome the capillary pressure in the pore throat and mobilize the residual oil. However, the effectiveness of microemulsion flooding to enhance the oil recovery in the targeted representative core has not been investigated.In this article, the performance of microemulsion-based surfactant formulation to improve the oil recovery in the reservoir condition was investigated in the laboratory scale through the core flooding experiment. Microemulsion-based formulation consist of 2% surfactant A and 0.85% of alkaline sodium carbonate (Na2CO3) were prepared by mixing with synthetic soften brine (SSB) in the presence of various concentration of polymer for improving the mobility control. The viscosity of surfactant-polymer in the presence of alkaline (ASP) and polymer drive that used for chemical injection slug were measured. The tertiary oil recovery experiment was carried out using core flooding apparatus to study the ability of microemulsion-based formulation to recover the oil production. The results showed that polymer at 2200 ppm in the ASP mixtures can generate 12.16 cP solution which is twice higher than the oil viscosity to prevent the fi ngering occurrence. Whereas single polymer drive at 1300 ppm was able to produce 15.15 cP polymer solution due to the absence of alkaline. Core flooding experiment result with design injection of 0.15 PV ASP followed by 1.5 PV polymer showed that the additional oil recovery after waterflood can be obtained as high as 93.41% of remaining oil saturation after waterflood (Sor), or 57.71% of initial oil saturation (Soi). Those results conclude that the microemulsion-based surfactant flooding is the most effective mechanism to achieve the optimum oil recovery in the targeted reservoir.

scholarly journals Modification of Xanthan Gum for a High-Temperature and High-Salinity Reservoir

Polymers ◽  
2021 ◽  
Vol 13 (23) ◽  
pp. 4212
Author(s):  
Mohamed Said ◽  
Bashirul Haq ◽  
Dhafer Al Shehri ◽  
Mohammad Mizanur Rahman ◽  
Nasiru Salahu Muhammed ◽  
...  
Keyword(s):  
High Temperature ◽  
Oil Recovery ◽  
Xanthan Gum ◽  
Elevated Temperatures ◽  
High Salinity ◽  
Residual Oil ◽  
Core Flooding ◽  
Nacl Solution ◽  
The Core ◽  
Tertiary Oil Recovery

Tertiary oil recovery, commonly known as enhanced oil recovery (EOR), is performed when secondary recovery is no longer economically viable. Polymer flooding is one of the EOR methods that improves the viscosity of injected water and boosts oil recovery. Xanthan gum is a relatively cheap biopolymer and is suitable for oil recovery at limited temperatures and salinities. This work aims to modify xanthan gum to improve its viscosity for high-temperature and high-salinity reservoirs. The xanthan gum was reacted with acrylic acid in the presence of a catalyst in order to form xanthan acrylate. The chemical structure of the xanthan acrylate was verified by FT-IR and NMR analysis. The discovery hybrid rheometer (DHR) confirmed that the viscosity of the modified xanthan gum was improved at elevated temperatures, which was reflected in the core flood experiment. Two core flooding experiments were conducted using six-inch sandstone core plugs and Arabian light crude oil. The first formulation—the xanthan gum with 3% NaCl solution—recovered 14% of the residual oil from the core. In contrast, the modified xanthan gum with 3% NaCl solution recovered about 19% of the residual oil, which was 5% higher than the original xanthan gum. The xanthan gum acrylate is therefore more effective at boosting tertiary oil recovery in the sandstone core.

scholarly journals Experimental Investigation of Chemical Flooding Using Nanoparticles and Polymer on Displacement of Crude Oil for Enhanced Oil Recovery

2020 ◽  
Vol 2020 ◽  
pp. 1-10
Author(s):  
Imran Akbar ◽  
Hongtao Zhou ◽  
Wei Liu ◽  
Muhammad Usman Tahir ◽  
Asadullah Memon ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Petroleum Industry ◽  
Chemical Flooding ◽  
Polymer Gel ◽  
Core Flooding ◽  
High Concentration ◽  
Remaining Oil ◽  
Water Cut

In the petroleum industry, the researchers have developed a new technique called enhanced oil recovery to recover the remaining oil in reservoirs. Some reservoirs are very complex and require advanced enhanced oil recovery (EOR) techniques containing new materials and additives in order to produce maximum oil in economic and environmental friendly manners. In this work, the effects of nanosuspensions (KY-200) and polymer gel HPAM (854) on oil recovery and water cut were studied in the view of EOR techniques and their results were compared. The mechanism of nanosuspensions transportation through the sand pack was also discussed. The adopted methodology involved the preparation of gel, viscosity test, and core flooding experiments. The optimum concentration of nanosuspensions after viscosity tests was used for displacement experiments and 3 wt % concentration of nanosuspensions amplified the oil recovery. In addition, high concentration leads to more agglomeration; thus, high core plugging takes place and diverts the fluid flow towards unswept zones to push more oil to produce and decrease the water cut. Experimental results indicate that nanosuspensions have the ability to plug the thief zones of water channeling and can divert the fluid flow towards unswept zones to recover the remaining oil from the reservoir excessively rather than the normal polymer gel flooding. The injection pressure was observed higher during nanosuspension injection than polymer gel injection. The oil recovery was achieved by about 41.04% from nanosuspensions, that is, 14.09% higher than polymer gel. Further investigations are required in the field of nanoparticles applications in enhanced oil recovery to meet the world's energy demands.

Enhanced Oil Recovery by Flooding With Dilute Aqueous Chemical Solutions

1981 ◽  
Vol 103 (4) ◽  
pp. 285-290 ◽  
Author(s):  
K. I. Kamath ◽  
S. J. Yan
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Laboratory Data ◽  
Recovery Process ◽  
Immiscible Displacement ◽  
Residual Oil ◽  
Oil Viscosity ◽  
Recovery Mechanism ◽  
Tertiary Oil Recovery ◽  
Hydrolyzed Polyacrylamide

The theory of enhanced oil recovery by surfactant flooding (micellarpolymer and “low-tension” floods) is based on three premises: that the chemical slug is 1) less mobile than the crude oil, 2) miscible with the reservoir fluids (oil and brine), and 3) stable over long periods of time (years) in the reservoir environment. We report here a rather simple process in which none of these expensive and exacting requirements have to be met. In this process, relatively small amounts of “EOR-active” substances present in certain petroleum-based sulfonates are found to recover 15–20 percent of the residual oil from waterflooded Berea sandstone cores. The chemicals are injected in the form of slugs of their aqueous solutions. If the chemical slugs are followed with similar slugs of additives such as partially hydrolyzed polyacrylamide, acrylamide monomer, urea, EDTA, or anions such as P2O7‴‴‴‴ and PO4‴‴‴, the oil recovery is increased 30–40 percent of the in-place residual oil. The concentrations of the “active” sulfonate and additive in their respective slugs appear to be of the order of 500 ppm or less. Extrapolation of the laboratory data to field conditions indicate that chemical requirements for the recovery of a barrel of tertiary oil are about 0.5–2 lb of sulfonate and a like amount of additive. The main features of the displacement process are: 1) Oil recovery is independent of oil viscosity in the tested range of 0.4–100 cps. 2) The process is essentially an immiscible displacement in which oil recovery depends on the amount of active chemical in the slug and not its concentration. 3) Tertiary oil is produced in the form of a clean “oil bank” and the buildup of a residual oil saturation at the producing end of linear cores occurs during the flood. From the data on hand, it is apparent that the oil recovery mechanism differs basically in character from the conventional Buckley-Leverett-type immiscible displacement. The low level concentrations of sulfonate and additive involved, and the independence of oil recovery with respect to oil viscosity suggest that the recovery mechanism is possibly actuated by certain specific functional groups in the structure of the EOR-active molecule or its anion, and of the additive. The results hold great potential for developing a simple and economical tertiary oil recovery process that can recover, very substantially, more oil (light as well as moderately viscous) than is now considered possible by conventional chemical floods.

Competing Roles of Interfacial Tension and Surfactant Equivalent Weight in the Development of a Chemical Flood

1982 ◽  
Vol 22 (04) ◽  
pp. 472-480 ◽  
Author(s):  
S.L. Enedy ◽  
S.M. Farouq Ali ◽  
C.D. Stahl
Keyword(s):  
Interfacial Tension ◽  
Crude Oil ◽  
Oil Recovery ◽  
Salt Concentration ◽  
Surfactant Concentration ◽  
Evolutionary Process ◽  
Chemical Flooding ◽  
Equivalent Weight ◽  
Residual Oil ◽  
Tertiary Oil Recovery

Abstract This investigation focused on developing an efficient chemical flooding process by use of dilute surfactant/polymer slugs. The competing roles of interfacial tension (IFT) and equivalent weight (EW) of the surfactant used, as well as the effect of different types of preflushes on tertiary oil recovery, were studied. Volume of residual oil recovered per gram of surfactant used was examined as a function of these variables and slug size. Tertiary oil recovery increased with an increase in the dilute surfactant slug size and buffer viscosity. However, low IFT does not ensure high oil recovery. An increase in surfactant EW used actually can lead to a decrease in oil recovery. Tertiary oil recovery was also sensitive to preflush type. Reasons for the observed behavior are examined in relation to the surfactant properties as well as to adsorption and retention. Introduction Two approaches are being used in development of surfactant /polymer-type chemical floods:a small-PV slug of high surfactant concentration, ora large-PV slug of low surfactant concentration. This study deals with the latter-i.e., dilute aqueous slugs (with polymer added in many cases) containing less than or equal 2.0 wt% sulfonates and about 0. 1 wt% crude oil. Because the dilute slug contains little of the dispersed phase, an aqueous surfactant slug usually is unable to displace the oil miscibly; however, residual brine is miscible with the slug if the inorganic salt concentration is not excessive. The dilute, aqueous petroleum sulfonate slug lowers the oil/water IFT. overcoming capillary forces. This process commonly is referred to as locally immiscible oil displacement. Objectives The objective of this work was to develop an efficient dilute surfactant/polymer slug for the Bradford crude with a variety of sulfonate combinations. Effects of varying the slug characteristics such as equivalent weight, IFT, salt concentration, etc. on tertiary oil recovery were examined. Materials and Experimental Details The petroleum sulfonates and the dilute slugs used in this study are listed in Tables 1 and 2, respectively. The crude oil tested was Bradford crude 144 degrees API (0.003 g/cm3), 4 cp (0.004 Pa.s)]. The polymer solutions were prefiltered and driven by brines of various concentrations (0.02, 1.0, and 2.0% NACl). In many cases, the polymer was added to the slug. Conventional coreflood equipment described in Ref. 3 was used. Berea sandstone cores (unfired) 2 in, (5 cm) in diameter and 4 ft (1.3 m) in length were used for all tests, with a new core for each test. Porosity ranged from 19.3 to 21.0%, permeability averaged 203 md, and the waterflood residual oil saturation averaged 33.1%. IFT's were measured by the spinning drop method. Viscosities were measured with a Brookfield viscosimeter and are reported here for 6 rpm (0.1 rev/s). The dilute slugs containing polymer exhibited non-Newtonian behavior. Without polymer the behavior was Newtonian. Sulfonate concentration in the oleic phase was determined by an infrared spectrophotometer, while the concentration in the aqueous phase was measured by ultraviolet (UV) absorbance analysis. Discussion of Results Slug development in this investigation was an evolutionary process. Dilute slugs were developed and core tested in a sequential manner (Table 2). Slugs 100 through 200 yielded insignificant ternary oil recoveries (largely because of excessive adsorption and retention), but the results helped determine improvements in slug compositions and in the overall chemical flood. This paper gives results for the more efficient slugs only. SPEJ P. 472^

Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field

2012 ◽  
Vol 15 (05) ◽  
pp. 541-553 ◽  
Author(s):  
Prabodh Pathak ◽  
Dale E. Fitz ◽  
Kenneth P. Babcock ◽  
Richard J. Wachtman
Keyword(s):  
Data Acquisition ◽  
Oil Recovery ◽  
Tracer Tests ◽  
Carbonate Reservoir ◽  
Core Analysis ◽  
Residual Oil ◽  
Oil Saturation ◽  
West Texas ◽  
Remaining Oil ◽  
Data Acquisition Program

Summary The technical success of an enhanced oil recovery (EOR) project depends on two main factors: first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters must be estimated before embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil. There are many methods for determining the oil saturation (Chang et al. 1988; Pathak et al. 1989), and these include core analysis, well-log analysis, log/inject/log (LIL) procedures (Richardson et al. 1973; Reedy 1984), and single-well chemical tracer tests (SWCTT) (Deans and Carlisle 1986). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. No single method achieves the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place (OIP) is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the ROS in the reservoir. This paper presents the results from a fieldwide data acquisition program conducted in a west Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in west Texas has been producing for more than the past 75 years, and the producing mechanisms have included primary recovery, secondary waterflooding, and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process, and it was imperative to evaluate the oil saturation in the lower, previously undeveloped zones. This paper briefly outlines the production history, reservoir description, and reservoir management of the Means field, but this paper concentrates on the residual oil zone (ROZ) that underlies the main producing zone (MPZ) and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS: core analysis, LIL tests, and SWCTT tests.

scholarly journals Numerical Simulation and Optimization of Enhanced Oil Recovery by the In Situ Generated CO2Huff-n-Puff Process with Compound Surfactant

2016 ◽  
Vol 2016 ◽  
pp. 1-13 ◽  
Author(s):  
Yong Tang ◽  
Zhengyuan Su ◽  
Jibo He ◽  
Fulin Yang
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
History Matching ◽  
Injection Rate ◽  
Thermal Recovery ◽  
Chemical Flooding ◽  
Core Flooding ◽  
Daily Production ◽  
Simulation And Optimization

This paper presents the numerical investigation and optimization of the operating parameters of the in situ generated CO2Huff-n-Puff method with compound surfactant on the performance of enhanced oil recovery. First, we conducted experiments of in situ generated CO2and surfactant flooding. Next, we constructed a single-well radial 3D numerical model using a thermal recovery chemical flooding simulator to simulate the process of CO2Huff-n-Puff. The activation energy and reaction enthalpy were calculated based on the reaction kinetics and thermodynamic models. The interpolation parameters were determined through history matching a series of surfactant core flooding results with the simulation model. The effect of compound surfactant on the Huff-n-Puff CO2process was demonstrated via a series of sensitivity studies to quantify the effects of a number of operation parameters including the injection volume and mole concentration of the reagent, the injection rate, the well shut-in time, and the oil withdrawal rate. Based on the daily production rate during the period of Huff-n-Puff, a desirable agreement was shown between the field applications and simulated results.

Characterization of Surfactants Using a Scaling Law Interpretation of Coreflood Residual Oil Saturation Profiles

1983 ◽  
Vol 23 (03) ◽  
pp. 511-518
Author(s):  
L.A. Davis ◽  
T.N. Tyler ◽  
D.F. Brost ◽  
H.K. Haskin
Keyword(s):  
Microwave Absorption ◽  
Oil Recovery ◽  
Scaling Law ◽  
Linear Scaling ◽  
Chemical Flooding ◽  
Residual Oil ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Saturation Profiles

Abstract The characterization of surfactant candidates for a given reservoir can be improved by the use of linear coreflood residual-oil-saturation profiles measured along the core after chemical flooding. A surfactant formulation's functional relation of oil recovery to slug size can be calculated from a single coreflood with the assumption of a relaxed scaling law. A volumetric linear scaling approach is developed from laboratory coreflood data. Residual-oil-saturation profiles measured in reservoir material with a microwave absorption instrument support this approximate scaling relation. Analysis of 32 linear surfactant-slug corefloods is presented as additional verification. The limits of this scaling law are defined, with emphasis on the role of mixing and dispersion. The procedure for using saturation profiles to calculate oil recovery as a function of slug size is developed and a test case is presented. A recovery relation derived from a single coreflood saturation profile is compared with that determined by multiple conventional corefloods. Introduction Many techniques and instruments are now available for noninvasive measurement of oil/brine saturations along linear cores during secondary and tertiary displacement experiments, these are reviewed briefly in Ref. 1. The most popular recent method is based on the microwave absorption properties of water. Such saturation- profile measurements provide much more information on a given chemical-flood experiment than can be collected merely from effluent material balance. This abundance of data can be used in two ways: to determine relations that would otherwise have to be developed laboriously from many separate conventional corefloods and to develop predictive capability for estimating surfactant- flood performance in new situations. Both applications are possible as an outgrowth of the concept of volumetric linear scaling for chemical flooding proposed by Parsons and Jones. This relaxed scaling technique is supported by the data of Ref. 6 and a wide variety of conventional and scanned corefloods presented in this work. A process can be defined as volumetrically linearly scalable if the fluid compositions and saturations at any point in the matrix at any time are functions only of the PV of fluids injected relative to that point with respect to the injection point. This can be stated simply for a single slug of surfactant: a given-PV slug of surfactant will produce the same compositions and saturation distributions in a core of any physical shape and size. Moreover, a 0. 10-PV slug injected into a 2-m core will produce the same composition and saturation distribution in the first meter of that core as would be produced over the entire length of a 1-m core that had seen a 0.20-PV slug. This is a trivial-but not an obvious-view of the recovery process. Limitations to this relative-sizing concept are discussed in the following paragraph. SPEJ P. 511^

scholarly journals Performance Evaluation of Thermal Enhanced Oil Recovery by In-situ Combustion

2018 ◽  
Vol 7 (2.20) ◽  
pp. 52
Author(s):  
D Sairam ◽  
G Reshma ◽  
Arjun P ◽  
Y Deepu
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Injection Well ◽  
Production Well ◽  
Oil Viscosity ◽  
Thermal Methods ◽  
In Situ Combustion ◽  
Oil Saturation ◽  
1D Model

Thermal methods of enhanced oil recovery and especially the in-situ combustion known to the efficient methods among the known enhanced oil recovery methods. In this method heat is added to the reservoir to reduce the oil viscosity. So, that it can be more efficiently driven to the producing well. However the experimental analysis of ISC to understand its operation is known to be expensive. Therefore we have developed a 1D model using STARS module of CMG where in we have Cartesian grid. To this we have given and given i, j, k values. Later porosity, Temperature and initial pressures are given. For setting the well we have used injector and producer. After checking errors we have validated the model. It is evident from the performance plots that the temperature along the core is a function of the gas injected and the oil saturation. However the as the temperature moves along the reservoir from injection well the oil saturation is observed to decrease in the vicinity of the well and start to build away from the injection well towards the production well. This is work provides a platform to understands the combustion propagation and its role in improving the oil recoveries  

Investigation into the Functions of Alkali and Surfactant in Chemical Flooding for Enhanced Heavy-Oil Recovery

2012 ◽  
Vol 524-527 ◽  
pp. 1816-1820 ◽  
Author(s):  
Ji Jiang Ge ◽  
Hai Hua Pei ◽  
Gui Cai Zhang ◽  
Xiao Dong Hu ◽  
Lu Chao Jin
Keyword(s):  
Oil Recovery ◽  
Heavy Oil ◽  
Chemical Flooding ◽  
Surfactant Flooding ◽  
Core Flooding ◽  
Sweep Efficiency ◽  
Water Emulsion ◽  
Tertiary Oil Recovery ◽  
Fingering Phenomena ◽  
Oil In Water Emulsion

In this study, a comparative study of alkaline flooding and alkali-surfactant flooding were conducted for Zhuangxi heavy oil with viscosity of 325 mPa•s at 55 °C. The results of core flooding tests show that the tertiary oil recovery of alkali-surfactant flooding are lower than those of alkaline-only flooding, in spite of the coexistence of the surfactant and alkali can reduce the IFT between the heavy oil and aqueous phase to an ultralow level. Further flood study via glass-etching micromodel tests demonstrates that injected alkaline-only solution can penetrate into the oil phase and creates some discontinuous water droplet inside the oil phase that tend to lower the mobility of the injected water and lead to the improvement of sweep efficiency. While for alkali-surfactant flooding, heavy oil is easily emulsified in brine by an alkaline plus very dilute surfactant formula to form oil-in-water emulsion, and then entrained in the water phase. Therefore, viscous fingering phenomena occur during the alkali-surfactant flooding, resulting in relatively lower sweep efficiency.

Evaluating Efficiency of Surfactant-Polymer Flooding with Single Well Chemical Tracer Tests at Kholmogorskoye Field

2021 ◽  
Author(s):  
Mikhail Bondar ◽  
Andrey Osipov ◽  
Andrey Groman ◽  
Igor Koltsov ◽  
Georgy Shcherbakov ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Promising Result ◽  
Tracer Tests ◽  
Polymer Flooding ◽  
Water Flooding ◽  
Residual Oil ◽  
Core Flooding ◽  
Oil Saturation ◽  
Chemical Eor ◽  
Single Well

Abstract EOR technologies in general and surfactant-polymer flooding (SP) in particular is considered as a tertiary method for redevelopment of mature oil fields in Western Siberia, with potential to increase oil recovery to 60-70% OOIP. The selection of effective surfactant blend and a polymer for SP flooding a complex and multi-stage process. The selected SP compositions were tested at Kholmogorskoye oilfield in September-December 2020. Two single well tests with partitioning chemical tracers (SWCTT) and the injectivity test were performed. The surfactant and the polymer for chemical EOR were selecting during laboratory studies. Thermal stability, phase behavior, interfacial tension and rheology of SP formulation were investigated, then a prospective chemical design was developed. Filtration experiments were carried out for optimization of slugs and concentrations. Then SWCTT was used to evaluated residual oil saturation after water flooding and after implementation of chemical EOR in the near wellbore areas. The difference between the obtained values is a measure of the efficiency of surfactant-polymer flooding. Pandemic restriction shifted SWCTT to the period when temperature dropped below zero and suitable for winter conditions equipment was required. Two SWCTT were conducted with same surfactant, but different design of slugs in order to prove technical and economic models of SP-flooding. Long-term polymer injectivity was accessed at the third well. Oil saturation of sandstone reservoir after the injection of a surfactant-polymer solution was reduced about 10% points which is around one third of the residual oil after water flooding. Results were compared with other available data such as well logging, lab core flooding experiments, and hydrodynamic simulation. Modeling of SWCTT is ongoing, current interpretation confirms the increase the oil recovery factor after SP-flooding up to 20-25%, which is a promising result. Temperature model of the bottom hole zone was created and verified. The model predicts that temperature of those zones essentially below that average in the reservoir, which is important for interpretation of tracer test and surfactant efficiency. The tested surfactant showed an acceptable efficiency at under-optimum conditions, which is favorable for application of the SP formulation for neighboring field and layers with different reservoir temperatures, but similar water composition. In general, the results of the conducted field tests correlate with the results of the core experiments for the selected surfactant

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