Journal articles on the topic 'Polymer fluid'
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Liang, Feng, Ghaithan Al-Muntasheri, Hooisweng Ow, and Jason Cox. "Reduced-Polymer-Loading, High-Temperature Fracturing Fluids by Use of Nanocrosslinkers." SPE Journal 22, no. 02 (October 5, 2016): 622–31. http://dx.doi.org/10.2118/177469-pa.
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Summary In the quest to discover more natural-gas resources, considerable attention has been devoted to finding and extracting gas locked within tight formations with permeability in the nano- to microdarcy range. The main challenges associated with working in such formations are the intrinsically high-temperature and high-pressure bottom conditions. For formations with bottomhole temperatures at approximately 350–400°F, traditional hydraulic-fracturing fluids that use crosslinked polysaccharide gels, such as guar and its derivatives, are not suitable because of significant polymer breakdown in this temperature range. Fracturing fluids that can work at these temperatures require thermally stable synthetic polymers such as acrylamide-based polymers. However, such polymers have to be used at very-high concentrations to suspend proppants. The high-polymer concentrations make it very difficult to completely degrade at the end of a fracturing operation. As a consequence, formation damage by polymer residue can reduce formation conductivity to gas flow. This paper addresses the shortcomings of the current state-of-the-art high-temperature fracturing fluids and focuses on developing a less-damaging, high-temperature-stable fluid that can be used at temperatures up to 400°F. A laboratory study was conducted with this novel system, which comprises a synthetic acrylamide-based copolymer gelling agent and is capable of being crosslinked with an amine-containing polymer-coated nanosized particulate crosslinker (nanocrosslinker). The laboratory data have demonstrated that the temperature stability of the crosslinked fluid is much better than that of a similar fluid lacking the nanocrosslinker. The nanocrosslinker allows the novel fluid system to operate at significantly lower polymer concentrations (25–45 lbm/1,000 gal) compared with current commercial fluid systems (50–87 lbm/1,000 gal) designed for temperatures from 350 to 400°F. This paper presents results from rheological studies that demonstrate superior crosslinking performance and thermal stability in this temperature range. This fracturing-fluid system has sufficient proppant-carrying viscosity, and allows for efficient cleanup by use of an oxidizer-type breaker. Low polymer loading and little or no polymer residue are anticipated to facilitate efficient cleanup, reduced formation damage, better fluid conductivity, and enhanced production rates. Laboratory results from proppant-pack regained-conductivity tests are also presented.
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Cao, Xiao Chun, Yi Qin, Yan Na Zhao, and Kun Ke. "Basic Performance Research of Polymer Intercalation Clay." Advanced Materials Research 578 (October 2012): 183–86. http://dx.doi.org/10.4028/www.scientific.net/amr.578.183.
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Using the preliminary research of the polymer properties, the different between the physical and chemical properties of new polymer-clays nanometer composites and clay have been studied. Different polymers are used to evaluate experiment. Based on a large number of lab experiments, the changes of rheological property and API filtration property of polymer-clay drilling fluids nanometer composites are studied. The results show that clay particles could become smaller and the composites drilling fluid have the role of controlling loss and enhancing cake quality. The prepared composites could be used to solve the technical problems in drilling fluid.
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Dery Nagre, Robert, Lin Zhao, and Isaac Kwesi Frimpong. "Polymer-FLR for Mud Fluid Loss Reduction." Chemistry & Chemical Technology 12, no. 1 (March 21, 2018): 79–85. http://dx.doi.org/10.23939/chcht12.01.079.
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Boyer, Séverine A. E., Takeshi Yamada, Hirohisa Yoshida, and Jean-Pierre E. Grolier. "Modification of molecular organization of polymers by gas sorption: Thermodynamic aspects and industrial applications." Pure and Applied Chemistry 81, no. 9 (August 19, 2009): 1603–14. http://dx.doi.org/10.1351/pac-con-08-11-09.
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In polymer science, gas–polymer interactions play a central role for the development of new polymeric structures for specific applications. This is typically the case for polymer foaming and for self-assembling of nanoscale structures where the nature of the gas and the thermodynamic conditions are essential to control. An important applied field where gas sorption in polymers has to be documented through intensive investigations concerns the (non)-controlled solubilization of light gases in the polymers serving, for example, in the oil industry for the transport of petroleum fluids. An experimental set-up coupling a vibrating-wire (VW) detector and a pVT technique has been used to simultaneously evaluate the amount of gas entering a polymer under controlled temperature and pressure and the concomitant swelling of the polymer. Scanning transitiometry has been used to determine the interaction energy during gas sorption in different polymers; the technique was also used to determine the thermophysical properties of polymers submitted to gas sorption. The role of the pressurizing fluid has been documented in terms of the influence of pressure, temperature, and nature of the fluid.
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LaGrone, C. C., S. A. Baumgartner, and R. A. Woodroof. "Chemical Evolution of a High- Temperature Fracturing Fluid." Society of Petroleum Engineers Journal 25, no. 05 (October 1, 1985): 623–28. http://dx.doi.org/10.2118/11794-pa.
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Abstract Reservoirs with bottomhole temperatures (BHT's) in excess of 250 deg. F [121 deg. C] and permeabilities of less than 1.0 md are commonly encountered in drilling and completing geothermal and deep gas wells. Successful stimulation of these wells often requires the use of massive hydraulic fracturing (MHF) treatments. Fracturing fluids chosen for these large treatments must possess shear and thermal stability at high BHT'S. The use of conventional fracturing fluids has been limited traditionally to wells with BHT's of 250 deg. F [121 deg. C] or less. Above 250 deg. F [121 deg. C], high polymer concentrations and/or large fluid volumes are required to maintain effective fluid viscosities in the fracture. However, high polymer concentrations lead to high friction pressures, high costs, and high gel residue levels. The large fluid volumes also increase significantly the cost of the treatment. Greater understanding of fracturing fluid properties has led to the development of a crosslinked fracturing fluid designed specifically for wells with BHT's above 250 deg F [121 deg C). The specialized chemistry of this fluid combines a high-ph hydroxypropyl guar gum (HPG) solution with a high-temperature gel stabilizer and a proprietary crosslinker. The fluid remains stable at 250 to proprietary crosslinker. The fluid remains stable at 250 to 350 deg. F [121 to 177 deg. C] for extended periods of time under shear. This paper describes the rheologial evaluations used in the systematic development of this fracturing fluid. In field applications, this fracturing fluid has been used to stimulate successfully wells with BHT's ranging from 250 to 540 deg. F [121 to 282 deg C). Case histories that include pretreatment and posttreatment production data are presented. Introduction Temperatures exceeding 250 deg F [121 deg C) and permeabilities less than 1.0 md are frequently encountered in permeabilities less than 1.0 md are frequently encountered in deep gas and geothermal wells. Successful economic completion of these wells requires that long, conductive fractures with optimal proppant distribution be created. Ultimately, the amount of production from these formations depends on the propped fracture length created. One successful stimulation technique used to create these long fractures is MHF. In these treatments, the fracturing fluids are often exposed to shear in the fracture for prolonged periods of time at high temperatures. Thus the fracturing fluids must exhibit extended shear and thermal stability at the high BHT'S. In addition, the fracturing fluid must not leak off rapidly into the formation, or the fracture may not be extended to the desired length. Many early treatments were limited by fracturing fluids that lost viscosity rapidly at high BHT's because of excessive thermal and/or shear degradation. Creation of a narrow fracture width, excessive fluid loss to the formation, and insufficient proppant transport resulted from the use of these low viscosity fluids. The solution to conventional fracturing fluid deficiencies was to develop a more efficient fracturing fluid (low polymer concentrations) with greater viscosity retention under shear at high temperatures, better fluid-loss control, and lower friction pressures. Generally, the components that make up crosslinked fracturing fluids include a polymer, buffer, gel stabilizer, and crosslinker. Each of these components is critical to the development of the desired fracturing fluid properties. The role of polymers in fracturing fluids is to properties. The role of polymers in fracturing fluids is to provide fracture width, to suspend proppants, to help provide fracture width, to suspend proppants, to help control fluid loss to the formation, and to reduce friction pressure in the tubular goods. Guar gum and cellulosic pressure in the tubular goods. Guar gum and cellulosic derivatives are the most common types of polymers used in fracturing fluids. The cellulosic derivatives are residue-free and thus help minimize fracturing fluid damage to the formation. However, the cellulosic derivatives are difficult to disperse because of their rapid rate of hydration. Guar gum and its derivatives are easily dispersed but produce some residue when broken. Buffers are used in conjunction with polymers so that the optimal pH for polymer hydration can be attained. When the optimal pH is reached, the maximal viscosity yield from the polymer is more likely to be obtained. The most common example of fracturing fluid buffers is a weak-acid/weak-base blend, whose ratios can be adjusted to that the desired ph is reached. However, some of these buffers dissolve slowly, particularly at cooler temperatures. Gel stabilizers are added to polymer solutions to inhibit chemical degradation. Examples of gel stabilizers used in fracturing fluids include methanol and various inorganic sulfur compounds. Other stabilizers are useful in inhibiting the chemical degradation process, but many interfere with the mechanism of crosslinking. The sulfur containing stabilizers possess an advantage over methanol, which is flammable, toxic, and expensive. SPEJ P. 623
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Lu, Hongwei, and Jiankang Wang. "Current Research and Patents of Polymer Foaming." Recent Patents on Mechanical Engineering 13, no. 3 (August 26, 2020): 280–90. http://dx.doi.org/10.2174/2212797613666200320100642.
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Background: Since the rapid development of polymers in the 1920’s, polymer products have become a necessary part of people's lives. Supercritical fluid technology was gradually introduced in this field. With the emergence of new technologies, methods, and equipment, the supercritical fluid technology has rapidly developed in the field of polymers and displayed a broad application perspective. Objective: The research progress of supercritical fluid-assisted polymer foaming, including equipment improvement, polymer composition ratio, and foaming process, and the influence of these processes on polymer foaming materials is reviewed here. Methods: Patents and research progress of supercritical fluid assisted polymer foams were reviewed. The advantages and disadvantages of various patents are analyzed in terms of cell structure, mechanical properties, surface quality, processing performance, and cost. Results: The foaming equipment and the manufacturing process of polymer foaming materials were retrospected, in order to improve the quality and application prospect of foaming composites. Conclusion: The preparation technology of supercritical fluid polymer foams has attracted wide attention. In recent years, patented technology has enabled us to use the supercritical fluid polymer foaming materials. There are some problems in the supercritical fluid foaming in terms of mechanical properties, cell structure, cell size, and processing technology, therefore, more equipment and patents are needed to solve these problems in the future.
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Liu, Tianle, Ekaterina Leusheva, Valentin Morenov, Lixia Li, Guosheng Jiang, Changliang Fang, Ling Zhang, Shaojun Zheng, and Yinfei Yu. "Influence of Polymer Reagents in the Drilling Fluids on the Efficiency of Deviated and Horizontal Wells Drilling." Energies 13, no. 18 (September 9, 2020): 4704. http://dx.doi.org/10.3390/en13184704.
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Improving the efficiency of well drilling process in a reservoir is directly related to subsequent well flow rates. Drilling of deviated and horizontal wells is often accompanied by an increase in pressure losses due to flow resistance caused by small size of the annular space. An important role in such conditions is played by the quality of borehole cleaning and transport capacity of drilling fluid, which is directly related to the rheological parameters of the drilling fluid. The main viscosifiers in modern drilling fluids are polymer reagents. They can be of various origin and structure, which determines their features. This work presents investigations that assess the effect of various polymers on the rheological parameters of drilling fluids. Obtained data are evaluated taking into account the main rheological models of fluid flow. However, process of fluid motion during drilling cannot be described by only one flow model. Paper shows experimentally obtained data of such indicators as plastic viscosity, dynamic shear stress, non-linearity index and consistency coefficient. Study has shown that high molecular weight polymer reagents (e.g., xanthan gum) can give drilling fluid more pronounced pseudoplastic properties, and combining them with a linear high molecular weight polymer (e.g., polyacrylamide) can reduce the value of the dynamic shear stress. Results of the work show the necessity of using combinations of different types of polymer reagents, which can lead to a synergetic effect. In addition to assessing the effect of various polymer reagents, the paper presents study on the development of a drilling fluid composition for specific conditions of an oil field.
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Almubarak, Tariq, Jun Hong Ng, Hisham A. Nasr–El–Din, Khatere Sokhanvarian, and Mohammed AlKhaldi. "Dual-Polymer Hydraulic-Fracturing Fluids: A Synergy Between Polysaccharides and Polyacrylamides." SPE Journal 24, no. 06 (July 19, 2019): 2635–52. http://dx.doi.org/10.2118/191580-pa.
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Summary As exploration for oil and gas continues, it becomes necessary to produce from deeper formations, and to meet the challenge of low permeability and higher temperatures. Unconventional shale formations are addressed with slickwater fracturing fluids, owing to the shale's unique geomechanical properties. On the other hand, conventional formations require crosslinked fracturing fluids to properly enhance productivity. Guar and its derivatives have a history of success in crosslinked hydraulic–fracturing fluids. However, they require higher polymer loading to withstand higher–temperature environments. This leads to an increase in mixing time and additive requirements. Most importantly, as a result of high polymer loading, they do not break completely and thus generate residual–polymer fragments that can plug the formation and significantly reduce fracture conductivity. In this work, a new hybrid dual–polymer hydraulic–fracturing fluid was developed. The fluid consists of a guar derivative and a polyacrylamide–based synthetic polymer. Compared with conventional fracturing fluids, this new system is easily hydrated, requires fewer additives, can be mixed “on the fly,” and is capable of maintaining excellent rheological performance at low polymer loadings. The polymer mixture solutions were prepared at a total polymer concentration of 20 to 40 lbm/1,000 gal at volume ratios of 2:1, 1:1, and 1:2. The fluids were crosslinked with a metallic crosslinker and broken with an oxidizer at 300°F. Testing focused on crosslinker/polymer–ratio analysis to effectively lower loading while maintaining sufficient performance to carry proppant at this temperature. A high–pressure/high–temperature (HP/HT) rheometer was used to measure viscosity, storage modulus, and fluid–breaking performance. An HP/HT aging cell and HP/HT see–through cell were used for proppant settling. Fourier–transform infrared (FTIR) spectroscopy, Cryo scanning electron microscopy (Cryo–SEM), and an HP/HT rheometer were also used to understand the interaction. Results indicated that the dual–polymer fracturing fluid was able to generate stable viscosity at 300°F and 100 s−1 as well as generate a higher viscosity compared with the individual–polymer fracturing fluid. Also, properly understanding and tuning the crosslinker to the polymer ratio generated excellent performance at 20 lbm/1,000 gal. The two polymers formed an improved crosslinking network that enhanced proppant–carrying properties. This fluid also demonstrated a clean and controlled breaking performance with an oxidizer. Extensive experiments were pursued to evaluate the new dual–polymer system for the first time. This system exhibited a positive interaction between the polysaccharide and polyacrylamide families and generated excellent rheological properties. The major benefit of using a mixed–polymer system is reduced polymer loading. Lower loading is highly desirable because it reduces material cost, eases field operation, and potentially lowers damage to the fracture face, proppant pack, and formation.
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Sugihardjo, Sugihardjo. "Polymer Properties Determination For Designing Chemical Flooding." Scientific Contributions Oil and Gas 34, no. 2 (March 14, 2022): 127–37. http://dx.doi.org/10.29017/scog.34.2.799.
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Waterflooding became the standard practice in many reservoirs formation in petroleum industries, the strengths and weaknesses of the methods were quite well established. In particular, the inefficiency of the waterflood oil displacement mechanism as a result of either an unfavorable mobility ratio or heterogeneity was largely identified. Therefore, chemicals injections as the improvement displacement processes had been proposed to support petroleum industries to recover the production of oil. Chemical injection normally consists of alkaline, surfactant, and polymer (ASP). They could be injected as standalone fluid or mixture of fluids; it depends upon the injection fluid design appropriate for particular field. Polymer solution could be prepared for mixtures of injection fluid and or as chase fluid injection which is injected behind surfactant or ASP. The main function of polymer solution primarily is to viscosity the injection water as a mobility control. This work is proposed to determine the important polymer properties which are suitable for mobility control in such EOR plan in the particular field. This field is sandstone reservoir with oil gravity of 23 to 26oAPI and viscosity of 3cp at 90oC. Two kinds of polymers have been chosen such as: HPAM-1 and HPAM-2 and subject to be tested for the properties characteristic. Intensive works have been done to evaluate the bulk polymer properties at laboratory scale which include rheology, filtration, thermal stability, retention/adsorption, and injectivity or permeability reduction tests. The results indicated that HPAM-1 polymer is suitable for injection fluid design for Zone-B while HPAM-2 for Zone-A.
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Akhavan, J., K. Slack, V. Wise, and H. Block. "Coating of Polyaniline with an Insulating Polymer to Improve the Power Efficiency of Electrorheological Fluids." International Journal of Modern Physics B 13, no. 14n16 (June 30, 1999): 1931–39. http://dx.doi.org/10.1142/s0217979299001983.
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Currents drawn under high fields often present practical limitations to electrorheological (ER) fluids usefulness. For heavy-duty applications where large torques have to be transmitted, the power consumption of a ER fluid can be considerable, and for such uses a current density of ~100μ A cm -2 is often taken as a practical upper limit. This investigation was conducted into designing a fluid which has little extraneous conductance and therefore would demand less current. Selected semi-conducting polymers provide effective substrates for ER fluids. Such polymers are soft insoluble powdery materials with densities similar to dispersing agents used in ER formulations. Polyaniline is a semi-conducting polymer and can be used as an effective ER substrate in its emeraldine base form. In order to provide an effective ER fluid which requires less current polyaniline was coated with an insulating polymer. The conditions for coating was established for lauryl and methyl methacrylate. Results from static yield measurements indicate that ER fluids containing coated polyaniline required less current than uncoated polyaniline i.e. 0.5μ A cm -2. The generic type of coating was also found to be important.
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Bizhani, M., and E. Kuru. "Particle Removal From Sandbed Deposits in Horizontal Annuli Using Viscoelastic Fluids." SPE Journal 23, no. 02 (December 19, 2017): 256–73. http://dx.doi.org/10.2118/189443-pa.
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Summary This paper presents results of an experimental study on how fluid viscoelastic properties would influence the particle removal from the sandbed deposited in horizontal annuli. Water and two different viscoelastic fluids were used for bed-erosion experiments. The particle-image-velocimetry (PIV) technique was used to measure the local fluid velocity at the fluid/sandbed interface, allowing for accurate estimation of the fluid-drag forces and the turbulence stresses. It was found that polymer fluids needed to exert higher level drag forces (than those of water) on the sandbed to start movement of the particles. Results have also shown that, at the critical flow rate of bed erosion, the polymer fluids yielded higher local fluid velocities and turbulent stresses than those of water. Moreover, the local velocity measurements by means of the PIV technique and the resultant bed-shear-stress calculations indicated that enhancing polymer concentration under the constant flow rate should also enhance the drag forces acting on the sandbed. However, these improved fluid hydrodynamic forces did not result in any improvement in the bed erosion. Therefore, the mechanism causing the delay in the bed erosion by polymer additives could not be explained by any decrease in the local fluid velocity and the turbulence. The primary reason for the delayed bed erosion by the polymer fluids was suggested to be linked to their viscoelastic properties. Two possible mechanisms arising from the elastic properties of the polymer fluids that hinder bed erosion were further discussed in the paper. The stress tensor of the viscoelastic-fluid flow was analyzed to determine the normal stress differences and the resultant normal fluid force acting on the particles at the fluid/sandbed interface. The normal force induced by the normal stress differences of the viscoelastic fluid was identified as one of the possible causes of the delayed bed erosion by these types of fluids.
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Hosseini-Kaldozakh, Seyed, Ehsan Khamehchi, Bahram Dabir, Ali Alizadeh, and Zohreh Mansoori. "Experimental Investigation of Water Based Colloidal Gas Aphron Fluid Stability." Colloids and Interfaces 3, no. 1 (March 3, 2019): 31. http://dx.doi.org/10.3390/colloids3010031.
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Today, the drilling operators use the Colloidal Gas Aphron (CGA) fluids as a part of drilling fluids in their operations to reduce formation damages in low-pressure, mature or depleted reservoirs. In this paper, a Taguchi design of experiment (DOE) has been designed to analyse the effect of salinity, polymer and surfactant types and concentration on the stability of CGA fluids. Poly Anionic Cellulose (PacR) and Xanthan Gum (XG) polymers are employed as viscosifier; Hexadecyl Trimethyl Ammonium Bromide (HTAB) and Sodium Dodecyl Benzene Sulphonate (SDBS) have been also utilized as aphronizer. Moreover, bubble size distributions, rheological and filtration properties of aphronized fluids are investigated. According to the results, the polymer type has the highest effect, whereas the surfactant type has the lowest effect on the stability of CGA drilling fluid. It was also observed that increasing salinity in CGA fluid reduces the stability. Finally, it should be noted that the micro-bubbles generated with HTAB surfactant in an electrolyte system, are more stable than SDBS surfactant.
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Liu, Yin Qing, Shi Jun Guo, and Hai Qing Cui. "The Research of Vertical Pipe Flow Rules of Polymer Drive Pump Wells Recovery Liquid." Advanced Materials Research 807-809 (September 2013): 2612–15. http://dx.doi.org/10.4028/www.scientific.net/amr.807-809.2612.
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As polymer flooding in Daqing oil field with the further exploitation,the polymer content in the flooding produced fluids and the produced fluid flow characteristics of polymer are all constant change. The rheology of produced fluids is changed too, it obviously shows non-newtonian fluid properties. About the concentric axis of non-newtonian fluid flow rules of the air the ring,it is becoming more and more important for producted crude oil in Daqing polymer flooding oilfield. This paper built a indoor device that used for the research of Polymer flooding pumping Wells recovery liquid vertical pipe flow rules,had a deep research on flow rules and rheology of Polymer flooding pumping Wells recovery liquid that was coming from Xingbei development zone of Daqing oilfield in the tubing wellbore.
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S, Gerry, Bayu D. Prasetiyo, and Tomi Erfando. "Parameter Analysis of Polymer on Sandstone Reservoir in Indonesia: An Experimental Laboratory Study." Scientific Contributions Oil and Gas 45, no. 2 (January 9, 2023): 95–101. http://dx.doi.org/10.29017/scog.45.2.1185.
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Polymers are often used to increase oil recovery by improving sweeping efficiency. The screening was carried out as a first step in evaluating the test parameters of several polymers of the Hydrolyzed Polyacrylamide (HPAM) type in fluid and sandstone reservoir rocks. The test was carried out using a reservoir fluid classified as light oil (35°API) and at a reservoir temperature (60°C). The HPAM polymers used are A1, F1, F2, F3, and P1 polymers. The test parameters carried out on these 5 types of polymer (A1, F1, F2, F3 dan P1) include a compatibility test for formation water. The rheology polymer test includes concentration vs Tres, and shear rate vs viscosity which aims to determine the type of polymer solution being tested is a non-Newtonian or pseudoplastic fluid group. Thermal stability test of polymer for 60 days to determine the stability of the polymer solution and whether it is degraded or stable. Filtration testing with criteria FR value 1.2, screen factor test, and adsorption testing using the static method with a standard limit of adsorption value 400 µg/gr and polymer injectivity test. From these tests, scoring (range 0-100) was carried out to determine polymer candidates in polymer flooding testing. The F1 polymer candidate for the sandstone reservoir was obtained with a score of 82.25. From the scoring results, the selected F1 polymer candidate has a concentration value of 2000 ppm. For thermal degradation, the polymer F1 2000 ppm experienced degradation of 15.5%. The results of the F1 2000 ppm polymer static adsorption test were 54.8 µg/gr. With the RRF = 1 value indicating rock permeability after injection of polymer F1 2000 ppm, it tends not to experience plugging due to injection of polymer solution.
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Ying, Chunye, Xinli Hu, Peng Xia, and Haiyan Zhang. "Design and Evaluation of a Polymer Support Fluid in a Soil–Rock Mixture." Polymers 14, no. 7 (March 30, 2022): 1402. http://dx.doi.org/10.3390/polym14071402.
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Soil–rock mixtures are commonly encountered in the construction of bored piles. Conventional bentonite support fluids have disadvantages, such as more significant environmental impacts, more complex mixing, bigger site footprint, weaker foundation performance, and overall low economies. The present study conducted a comprehensive investigation of partially hydrolyzed polyacrylamide (PHPA) polymer fluids, an alternative to bentonite ones, to drill into a soil-limestone mixture. The fluid flow pattern, aging behavior, and the influence of finer silty clay on polymer fluid were explored. The test results showed that polymer fluids were reasonably well fitted to the power-law model and were a good alternative to the conventional bentonite ones. In terms of their aging behavior, the remaining active viscosity of the polymer was at least 70% after a prolonged aging time of up to 30 days, showing the effective on-site use of polymer fluids. The mixing of silty clay significantly reduced the apparent viscosity of polymer fluids, with 10% silty clay causing a viscosity reduction of 76%, indicating the importance of fluid control in drilling these materials. A polymer formula, water + 0.08%PHPA + 0.1~0.5%Na2CO3, was proposed and was verified by drilling into a soil–limestone mixture. The polymer fluids led to small radial displacements around the boreholes with a high drilling quality. This work would be helpful for consultants and contractors designing and constructing bored piles in soil and rock mixtures utilizing polymer fluids.
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Hatzikiriakos, Savvas G. "Slip mechanisms in complex fluid flows." Soft Matter 11, no. 40 (2015): 7851–56. http://dx.doi.org/10.1039/c5sm01711d.
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The classical no-slip boundary condition of fluid mechanics is not always a valid assumption for the flow of several classes of complex fluids including polymer melts, their blends, polymer solutions, microgels, glasses, suspensions and pastes.
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Guo Kun-Kun, Qiu Feng, Zhang Hong-Dong, and Yang Yu-Liang. "Polymer anchored fluid membrane." Acta Physica Sinica 55, no. 1 (2006): 155. http://dx.doi.org/10.7498/aps.55.155.
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Kikic, I. "Polymer–supercritical fluid interactions." Journal of Supercritical Fluids 47, no. 3 (January 2009): 458–65. http://dx.doi.org/10.1016/j.supflu.2008.10.016.
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Boger, D. V. "Model polymer fluid systems." Pure and Applied Chemistry 57, no. 7 (January 1, 1985): 921–30. http://dx.doi.org/10.1351/pac198557070921.
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Zhao, Zhenhua, Sinan Chen, Fengshan Zhou, and Zhongjin Wei. "Gel Stability of a Calcium Bentonite Suspension in Brine and Its Application in Water-Based Drilling Fluids." Gels 8, no. 10 (October 10, 2022): 643. http://dx.doi.org/10.3390/gels8100643.
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With the development of the oil industry and the increasingly complex drilling environment, the performance of drilling fluids has to be constantly improved. In order to solve the problem of bentonite dispersion and hydration in a saline medium, a drilling fluid additive with good performance and acceptable cost was sought. The effects of several water-soluble polymers, such as cellulose polymers, synthetic polymers and natural polymers, on the rheology and gel suspension stability of calcium-based bentonite were compared in this study. Among the examined polymers, the xanthan gum biopolymer (XC) was the least negatively affected in the saline medium used. However, its high price limits its industrial application in oil and gas drilling fluids. In this study, a salt-tolerant polymer, modified plant gum (MVG), was prepared by a cross-linking modification of a natural plant gum, which is abundant and cheap. Then, a salt-tolerant polymer mixture called SNV was prepared, composed of the salt-resistant natural polymer MVG and the biopolymer XC. The salt tolerance and pulping ability of SNV and common water-soluble polymers were evaluated and compared. We then selected the most suitable Herschel–Bulkley model to fit the rheological curve of the SNV–bentonite aqueous suspension system. SNV improved the rheological properties of the calcium-based bentonite slurry and the dispersion stability of bentonite. In an SNV concentration of 0.35%, the apparent viscosity (AV) of the base slurry increased from 2 mPa·s to 32 mPa·s., and the low shear reading value at 3 rpm increased from 0 dia to 5 dia. This could greatly improve the viscosity and cutting carrying capacity of the bentonite drilling fluid. The bentonite drilling fluid prepared with SNV could be directly slurried with brine and even seawater; this means that when drilling in ocean, coastal saline water and high-salinity-surface saline water areas, the slurry preparation cost and preparation time can be conveniently reduced.
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Panwar, Pawan, Paul Michael, Mark Devlin, and Ashlie Martini. "Critical Shear Rate of Polymer-Enhanced Hydraulic Fluids." Lubricants 8, no. 12 (November 25, 2020): 102. http://dx.doi.org/10.3390/lubricants8120102.
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Many application-relevant fluids exhibit shear thinning, where viscosity decreases with shear rate above some critical shear rate. For hydraulic fluids formulated with polymeric additives, the critical shear rate is a function of the molecular weight and concentration of the polymers. Here we present a model for predicting the critical shear rate and Newtonian viscosity of fluids, with the goal of identifying a fluid that shear thins in a specific range relevant to hydraulic pumps. The model is applied to predict the properties of fluids comprising polyisobutene polymer and polyalphaolefin base oil. The theoretical predictions are validated by comparison to viscosities obtained from experimental measurements and molecular dynamics simulations across many decades of shear rates. Results demonstrate that the molecular weight of the polymer plays a key role in determining the critical shear rate, whereas the concentration of polymer primarily affects the Newtonian viscosity. The simulations are further used to show the molecular origins of shear thinning and critical shear rate. The atomistic simulations and simple model developed in this work can ultimately be used to formulate polymer-enhanced fluids with ideal shear thinning profiles that maximize the efficiency of hydraulic systems.
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Huang, Jingting, Liqiong Chen, Shuxuan Li, Jinghang Guo, and Yuanyuan Li. "Numerical Study for the Performance of Viscoelastic Fluids on Displacing Oil Based on the Fractional-Order Maxwell Model." Polymers 14, no. 24 (December 8, 2022): 5381. http://dx.doi.org/10.3390/polym14245381.
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In the study of polymer flooding, researchers usually ignore the genetic stress properties of viscoelastic fluids. In this paper, we investigate the process of viscoelastic fluid flooding the remaining oil in the dead end. This work uses the fractional-order Maxwell in the traditional momentum equation. Furthermore, a semi-analytic solution of the flow control equation for fractional-order viscoelastic fluids is derived, and the oil-repelling process of viscoelastic fluids is simulated by a secondary development of OpenFOAM. The results show that velocity fractional-order derivative α significantly affects polymer solution characteristics, and increasing the elasticity of the fluid can significantly improve the oil repelling efficiency. Compared to the Newtonian fluid flow model, the fractional order derivative a and relaxation time b in the two-parameter instanton equation can accurately characterize the degree of elasticity of the fluid. The smaller the a, the more elastic the fluid is and the higher the oil-repelling efficiency. The larger the b, the less elastic the fluid is and the lower the cancellation efficiency. Moreover, the disturbance of the polymer solution to the dead end is divided into two elastic perturbation areas. The stronger the elasticity of the polymer solution, the higher the peak value of the area in the dead end and the higher the final oil displacement efficiency.
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Ahuja, Vishal Raju, Jasper van der Gucht, and Wim Briels. "Large Scale Hydrodynamically Coupled Brownian Dynamics Simulations of Polymer Solutions Flowing through Porous Media." Polymers 14, no. 7 (March 31, 2022): 1422. http://dx.doi.org/10.3390/polym14071422.
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Large scale simulations of polymer flow through porous media provide an important tool for solving problems in enhanced oil recovery, polymer processing and biological applications. In order to include the effects of a wide range of velocity and density fluctuations, we base our work on a coarse-grain particle-based model consisting of polymers following Brownian dynamics coupled to a background fluid flow through momentum conserving interactions. The polymers are represented as Finitely Extensible Non-Linear Elastic (FENE) dumbbells with interactions including slowly decaying transient forces to properly describe dynamic effects of the eliminated degrees of freedom. Model porous media are constructed from arrays of parallel solid beams with circular or square cross-sections, arranged periodically in the plane perpendicular to their axis. No-slip boundary conditions at the solid–fluid interfaces are imposed through interactions with artificial particles embedded within the solid part of the system. We compare the results of our simulations with those of standard Smoothed Particle Hydrodynamics simulations for Newtonian flow through the same porous media. We observe that in all cases the concentration of polymers at steady state is not uniform even though we start the simulations with a uniform polymer concentration, which is indicative of shear-induced cross-flow migration. Furthermore, we see the characteristic flattening of the velocity profile experimentally observed for shear-thinning polymer solutions flowing through channels as opposed to the parabolic Poiseuille flow profile for Newtonian fluids.
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Hirpa, Mehmet Meric, Sumanth Kumar Arnipally, and Ergun Kuru. "Effect of the Particle Size on the Near-Wall Turbulence Characteristics of the Polymer Fluid Flow and the Critical Velocity Required for Particle Removal from the Sand Bed Deposited in Horizontal Wells." Energies 13, no. 12 (June 18, 2020): 3172. http://dx.doi.org/10.3390/en13123172.
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Water-based polymer drilling fluids are commonly used for drilling long horizontal wells where eliminating the drilling fluid-related formation damage and minimizing the environmental impact of the drilling fluids are the main concerns. An experimental study was conducted to investigate the turbulent flow of a polymer fluid over a stationary sand bed deposited in a horizontal pipeline. The main objectives of the study were to determine the effects of sand particle size on the critical velocity required for the onset of the bed erosion and the near-wall turbulence characteristics of the polymer fluid flow over the sand bed. Industrial sand particles having three different size ranges (20/40, 30/50, 40/70) were used for the experiments. The particle image velocimetry (PIV) technique was used to determine instantaneous local velocity distributions and near-wall turbulence characteristics (such as Reynolds stress, axial and turbulence intensity profiles) of the polymer fluid flow over the stationary sand bed under turbulent flow conditions. The critical velocity for the onset of the particle removal from a stationary sand bed using a polymer fluid flow was affected by the sand particle size. The critical velocity required for the particle removal from the bed deposits did not change monotonously with the changing particle size. When polymer fluids were used for hole cleaning, the particle size effect on the critical velocity varied (i.e., critical velocity increased or decreased) depending on the relative comparison of the sand particle size with respect to the thickness of the viscous sublayer under turbulent flow condition.
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Abbas, Ghulam, Sonny Irawan, Khalil Rehman Memon, and Javed Khan. "Application of cellulose-based polymers in oil well cementing." Journal of Petroleum Exploration and Production Technology 10, no. 2 (November 22, 2019): 319–25. http://dx.doi.org/10.1007/s13202-019-00800-8.
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AbstractCellulose-based polymers have been successfully used in many areas of petroleum engineering especially in enhanced oil recovery drilling fluid, fracturing and cementing. This paper presents the application of cellulose-based polymer in oil well cementing. These polymers work as multifunctional additive in cement slurry that reduce the quantity of additives and lessen the operational cost of cementing operation. The viscosity of cellulose polymers such as hydroxyethyl cellulose (HEC), carboxymethylcellulose (CMC) and hydroxypropyl methylcellulose (HPMC) has been determined at various temperatures to evaluate the thermal degradation. Moreover, polymers are incorporated in cement slurry to evaluate the properties and affect in cement slurry at 90 °C. The API properties like rheology, free water separation, fluid loss and compressive strength of slurries with and without polymer have been determined at 90 °C. The experimental results showed that the viscosity of HPMC polymer was enhanced at 90 °C than other cellulose-based polymers. The comparative and experimental analyses showed that the implementation of cellulose-based polymers improves the API properties of cement slurry at 90 °C. The increased viscosity of these polymers showed high rheology that was adjusted by adding dispersant which optimizes the rheology of slurry. Further, improved API properties, i.e., zero free water separation, none sedimentation, less than 50 ml/30 min fluid loss and high compressive strength, were obtained through HEC, CMC and HPMC polymer. It is concluded that cellulose-based polymers are efficient and effective in cement slurry that work as multifunctional additive and improve API properties and cement durability. The cellulose-based polymers work as multifunctional additive that reduces the quantity of other additives in cement slurry and ultimately reduces the operational cost of cementing operation. The comparative analysis of this study opens the window for petroleum industry for proper selection of cellulose-based polymer in designing of cement slurry.
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WOODCOCK, JAMES D., JOHN E. SADER, and IVAN MARUSIC. "On the maximum drag reduction due to added polymers in Poiseuille flow." Journal of Fluid Mechanics 659 (July 27, 2010): 473–83. http://dx.doi.org/10.1017/s0022112010003083.
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The addition of elastic polymers to turbulent liquids is known to produce significant drag reduction. In this study, we prove that the drag in pipe and channel flows of an unforced laminar fluid constitutes a lower bound for the drag of a fluid containing dilute elastic polymers. Further, the addition of elastic polymers to laminar fluids invariably increases drag. This proof does not rely on the adoption of a particular constitutive equation for the polymer force, and would also be applicable to other similar methods of drag reduction, which are also achieved by the addition of certain particles to a flow. Examples of such methods include the addition of surfactants to a flowing liquid and the presence of sand particles in sandstorms and water droplets in cyclones.
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Talmon, Yeshayahu. "Cryo-TEM of amphiphilic polymer and amphiphile/polymer solutions." Proceedings, annual meeting, Electron Microscopy Society of America 51 (August 1, 1993): 876–77. http://dx.doi.org/10.1017/s0424820100150216.
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To achieve complete microstructural characterization of self-aggregating systems, one needs direct images in addition to quantitative information from non-imaging, e.g., scattering or Theological measurements, techniques. Cryo-TEM enables us to image fluid microstructures at better than one nanometer resolution, with minimal specimen preparation artifacts. Direct images are used to determine the “building blocks” of the fluid microstructure; these are used to build reliable physical models with which quantitative information from techniques such as small-angle x-ray or neutron scattering can be analyzed.To prepare vitrified specimens of microstructured fluids, we have developed the Controlled Environment Vitrification System (CEVS), that enables us to prepare samples under controlled temperature and humidity conditions, thus minimizing microstructural rearrangement due to volatile evaporation or temperature changes. The CEVS may be used to trigger on-the-grid processes to induce formation of new phases, or to study intermediate, transient structures during change of phase (“time-resolved cryo-TEM”). Recently we have developed a new CEVS, where temperature and humidity are controlled by continuous flow of a mixture of humidified and dry air streams.
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Ushida, Akiomi, Shuichi Ogawa, Tomiichi Hasegawa, and Takatsune Narumi. "OS23-1 Pseudo-Laminarization of Dilute Polymer Solutions in Capillary Flows(Thermo-fluid dynamics(1),OS23 Thermo-fluid dynamics,FLUID AND THERMODYNAMICS)." Abstracts of ATEM : International Conference on Advanced Technology in Experimental Mechanics : Asian Conference on Experimental Mechanics 2015.14 (2015): 278. http://dx.doi.org/10.1299/jsmeatem.2015.14.278.
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Pinho de Aguiar, Kelly Lúcia Nazareth, Luiz Carlos Magalhães Palermo, and Claudia Regina Elias Mansur. "Polymer viscosifier systems with potential application for enhanced oil recovery: a review." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 76 (2021): 65. http://dx.doi.org/10.2516/ogst/2021044.
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Due to the growing demand for oil and the large number of mature oil fields, Enhanced Oil Recovery (EOR) techniques are increasingly used to increase the oil recovery factor. Among the chemical methods, the use of polymers stands out to increase the viscosity of the injection fluid and harmonize the advance of this fluid in the reservoir to provide greater sweep efficiency. Synthetic polymers based on acrylamide are widely used for EOR, with Partially Hydrolyzed Polyacrylamide (PHPA) being used the most. However, this polymer has low stability under harsh reservoir conditions (High Temperature and Salinity – HTHS). In order to improve the sweep efficiency of polymeric fluids under these conditions, Hydrophobically Modified Associative Polymers (HMAPs) and Thermo-Viscosifying Polymers (TVPs) are being developed. HMAPs contain small amounts of hydrophobic groups in their water-soluble polymeric chains, and above the Critical Association Concentration (CAC), form hydrophobic microdomains that increase the viscosity of the polymer solution. TVPs contain blocks or thermosensitive grafts that self-assemble and form microdomains, substantially increasing the solution’s viscosity. The performance of these systems is strongly influenced by the chemical group inserted in their structures, polymer concentration, salinity and temperature, among other factors. Furthermore, the application of nanoparticles is being investigated to improve the performance of injection polymers applied in EOR. In general, these systems have excellent thermal stability and salinity tolerance along with high viscosity, and therefore increase the oil recovery factor. Thus, these systems can be considered promising agents for enhanced oil recovery applications under harsh conditions, such as high salinity and temperature. Moreover, stands out the use of genetic programming and artificial intelligence to estimate important parameters for reservoir engineering, process improvement, and optimize polymer flooding in enhanced oil recovery.
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Abbas, Ghulam, Sonny Irawan, Sandeep Kumar, and Ahmed A. I. Elrayah. "Improving Oil well Cement Slurry Performance Using Hydroxypropylmethylcellulose Polymer." Advanced Materials Research 787 (September 2013): 222–27. http://dx.doi.org/10.4028/www.scientific.net/amr.787.222.
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At present, high temperature oil wells are known as the most problematic for cementing operation due to limitations of polymer. The polymers are significantly used as mutlifunctional additives for improving the properties of cement slurry. At high temperature, viscosity of polymer decreases and unable to obtained desired properties of cement slurry. It becomes then major cause of fluid loss and gas migration during cementing operations. Thus, it necessitates for polymers that can able to enhance viscosity of slurry at elevated temperatures. This paper is aiming to study Hydroxypropylmethylcellulose (HPMC) polymer at high temperature that is able to increase the viscosity at elevated temperature. In response, experiments were conducted to characterize rheological properties of HPMC at different temperatures (30 to 100 °C). Then it was incorporated as multifunctional additive in cement slurry for determining API properties (fluid loss, free water, thickening time and compressive strength). It was observed that HPMC polymer has remarkable rheological properties that can have higher viscosity with respect to high temperatures. The best concentration of HPMC was found from 0.30 to 0.50 gallon per sack. This concentration showed minimal fluid loss, zero free water, high compressive strength and wide range of thickening time in cement slurry. The results signified that HPMC polymer is becoming multifunctional additive in cement slurry to improve the API properties of cement slurry and unlock high temperature oil wells for cementing operations.
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Graham, Michael D. "Polymer turbulence with Reynolds and Riemann." Journal of Fluid Mechanics 848 (June 1, 2018): 1–4. http://dx.doi.org/10.1017/jfm.2018.353.
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Models of flowing complex fluids such as polymer solutions often use a conformation tensor that reflects the state of the fluid microstructure. In polymer solutions, this quantity measures the orientation and stretching of the molecules, and reflects the fact that the squared length of a polymer molecule must be positive. By exploiting results from differential geometry and continuum mechanics, Hameduddin et al. (J. Fluid Mech., vol. 842, 2018, pp. 395–427) introduce a new approach for analysing the conformation tensor that respects this positivity constraint. With this approach, they present computational results for turbulent flow of a polymer solution that exhibits turbulent drag reduction, showing that the new measures of polymer stretching afforded by their approach lend insights not available in traditional methods.
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Li, Wen Ting. "Flow Behavior of Polymer Viscoelastic Fluid in Complex Channel." Advanced Materials Research 774-776 (September 2013): 379–82. http://dx.doi.org/10.4028/www.scientific.net/amr.774-776.379.
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A finite volume method for the numerical solution of viscoelastic flows is given. The flow of a differential Phan-Thien-Tanner (PTT) fluid through an abrupt expansion-contraction channel has been chosen as a prototype example. Through the results of numerical simulations, the contours of velocity and stream function are drawn. Numerical results show that the viscoelasticity of polymer solutions is the main factor influencing the sweep efficiency. With increasing elasticity, the flowing area in the channel is enlarged significantly, thus the area with immobile zones becomes smaller, the microcosmic sweep efficiency increases. The visco-elastic nature of the displacing polymer fluids can ingeneral improve the displacement efficiency in pores compared to using Newtonian fluids. This conclusion should be useful in selecting polymer fluids and designing polymer flooding operations.
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Chen, Dilin, Jie Li, Haiwen Chen, Lai Zhang, Hongna Zhang, and Yu Ma. "Electroosmotic Flow Behavior of Viscoelastic LPTT Fluid in a Microchannel." Micromachines 10, no. 12 (December 15, 2019): 881. http://dx.doi.org/10.3390/mi10120881.
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In many research works, the fluid medium in electroosmosis is considered to be a Newtonian fluid, while the polymer solutions and biological fluids used in biomedical fields mostly belong to the non-Newtonian category. Based on the finite volume method (FVM), the electroosmotic flow (EOF) of viscoelastic fluids in near-neutral (pH = 7.5) solution considering four ions (K+, Cl−, H+, OH−) is numerically studied, as well as the viscoelastic fluids’ flow characteristics in a microchannel described by the Linear Phan-Thien–Tanner (LPTT) constitutive model under different conditions, including the electrical double layer (EDL) thickness, the Weissenberg number (Wi), the viscosity ratio and the polymer extensibility parameters. When the EDL does not overlap, the velocity profiles for both Newtonian and viscoelastic fluids are plug-like and increase sharply near the charged wall. Compared with Newtonian fluid at Wi = 3, the viscoelastic fluid velocity increases by 5 times and 9 times, respectively, under the EDL conditions of kH = 15 and kH = 250, indicating the shear thinning behavior of LPTT fluid. Shear stress obviously depends on the viscosity ratio and different Wi number conditions. The EOF is also enhanced by the increase (decrease) in polymer extensibility parameters (viscosity ratio). When the extensibility parameters are large, the contribution to velocity is gradually weakened.
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Furusho, Junji, and Naoyuki Takesue. "Research and Development of Functional Fluid Mechatronics, Rehabilitation Systems, and Mechatronics of Flexible Drive Systems." Journal of Robotics and Mechatronics 28, no. 1 (February 18, 2016): 5–16. http://dx.doi.org/10.20965/jrm.2016.p0005.
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[abstFig src='/00280001/01.jpg' width=""260"" text='PLEMO-P3 Developed by Furusho Lab at Osaka Univ.' ]We conducted many research and development activities on functional fluid mechatronics, rehabilitation systems, and servo drive systems. In this review, studies on the development of magnetorheological fluid devices, electrorheological effects of liquid crystalline polymers on one-sided pattern electrodes, and vibration control using control theory and liquid crystalline polymer are introduced. In addition, applications of rehabilitation systems for upper and lower extremities employing functional fluids for individuals suffering from stroke, cerebellar ataxia, and Guillain-Barre syndrome are also introduced.
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CAI, W. H., F. C. LI, and H. N. ZHANG. "DNS study of decaying homogeneous isotropic turbulence with polymer additives." Journal of Fluid Mechanics 665 (October 19, 2010): 334–56. http://dx.doi.org/10.1017/s0022112010003939.
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In order to investigate the turbulent drag reduction phenomenon and understand its mechanism, direct numerical simulation (DNS) was carried out on decaying homogeneous isotropic turbulence (DHIT) with and without polymer additives. We explored the polymer effect on DHIT from the energetic viewpoint, i.e. the decay of the total turbulent kinetic energy and energy distribution at each scale in Fourier space and from the phenomenological viewpoint, i.e. the alterations of vortex structures, the enstrophy and the strain. It was obtained that in DHIT with polymer additives the decay of the turbulent kinetic energy is faster than that in the Newtonian fluid case and a modification of the turbulent kinetic energy transfer process for the Newtonian fluid flow is observed due to the release of the polymer elastic energy into flow structures at certain small scales. Besides, we deduced the transport equations of the enstrophy and the strain, respectively, for DHIT with polymer additives. Based on the analyses of these transport equations, it was found that polymer additives depress both the enstrophy and the strain in DHIT as compared to the Newtonian fluid case, indicating the inhibition effect on small-scale vortex structures and turbulence intensity by polymers.
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YANG, SHU-QING, and G. DOU. "Turbulent drag reduction with polymer additive in rough pipes." Journal of Fluid Mechanics 642 (December 11, 2009): 279–94. http://dx.doi.org/10.1017/s002211200999187x.
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Friction factor of drag-reducing flow with presence of polymers in a rough pipe has been investigated based on the eddy diffusivity model, which shows that the ratio of effective viscosity caused by polymers to kinematic viscosity of fluid should be proportional to the Reynolds number, i.e. u∗R/ν and the proportionality factor depends on polymer's type and concentration. A formula of flow resistance covering all regions from laminar, transitional and fully turbulent flows has been derived, and it is valid in hydraulically smooth, transitional and fully rough regimes. This new formula has been tested against Nikuradse and Virk's experimental data in both Newtonian and non-Newtonian fluid flows. The agreement between the measured and predicted friction factors is satisfactory, indicating that the addition of polymer into Newtonian fluid flow leads to the non-zero effective viscosity and it also thickens the viscous sublayer, subsequently the drag is reduced. The investigation shows that the effect of polymer also changes the velocity at the top of roughness elements. Both experimental data and theoretical predictions indicate that, if same polymer solution is used, the drag reduction (DR) in roughened pipes becomes smaller relative to smooth pipe flows at the same Reynolds number.
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Li, Bing, and Steven M. Abel. "Shaping membrane vesicles by adsorption of a semiflexible polymer." Soft Matter 14, no. 2 (2018): 185–93. http://dx.doi.org/10.1039/c7sm01751k.
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The adsorption of polymers onto fluid membranes is a problem of fundamental interest in biology and soft materials, in part because the flexibility of membranes can lead to nontrivial coupling between polymer and membrane configurations.
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Othman, Amro, Mohammed AlSulaimani, Murtada Saleh Aljawad, Shiv Shankar Sangaru, Muhammad Shahzad Kamal, and Mohamed Mahmoud. "The Synergetic Impact of Anionic, Cationic, and Neutral Polymers on VES Rheology at High-Temperature Environment." Polymers 14, no. 6 (March 13, 2022): 1145. http://dx.doi.org/10.3390/polym14061145.
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Hydraulic fracturing operations target enhancing the productivity of tight formations through viscous fluid injection to break down the formation and transport proppant. Crosslinked polymers are usually used for desired viscoelasticity of the fracturing fluid; however, viscoelastic surfactants (VES) became a possible replacement due to their less damaging impact. To design a fracturing fluid with exceptional rheological and thermal stability, we investigated mixing zwitterionic VES with carboxymethyl cellulose (CMC), hydroxyethylcellulose (HEC), or a poly diallyl dimethylammonium chloride (DADMAC) polymers. As a base fluid, calcium chloride (CaCl2) solution was prepared with either distilled water or seawater before adding a polymer and the VES. A Chandler high-pressure, high-temperature (HPHT) viscometer was used to conduct the viscosity measurements at a shear rate of 100 1/s. It has been found that adding 1% CMC polymer to 9% (v/v) VES increases the viscosity more compared to 10% (v/v) VES at reservoir temperatures of 143.3 °C. On the other hand, adding only 1.0% of HEC to 9% (v/v) VES doubled the viscosity and proved more effective than adding CMC. HEC, nevertheless, reduced the system stability at high temperatures (i.e., 148.9 °C). Adding DADMAC polymer (DP) to VES increased the system viscosity and maintained high stability at high temperatures despite being exposed to saltwater. CaCl2 concentration was also shown to affect rheology at different temperatures. The improved viscosity through the newly designed polymer can reduce chemical costs (i.e., reducing VES load), making it more efficient in hydraulic fracturing operations.
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Zhou, Jiajia, and Masao Doi. "Derivation of Two-Fluid Model Based on Onsager Principle." Entropy 24, no. 5 (May 17, 2022): 716. http://dx.doi.org/10.3390/e24050716.
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Using the Onsager variational principle, we study the dynamic coupling between the stress and the composition in a polymer solution. In the original derivation of the two-fluid model of Doi and Onuki the polymer stress was introduced a priori; therefore, a constitutive equation is required to close the equations. Based on our previous study of viscoelastic fluids with homogeneous composition, we start with a dumbbell model for the polymer, and derive all dynamic equations using the Onsager variational principle.
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BOFFETTA, GUIDO, ANDREA MAZZINO, STEFANO MUSACCHIO, and LARA VOZELLA. "Rayleigh–Taylor instability in a viscoelastic binary fluid." Journal of Fluid Mechanics 643 (January 15, 2010): 127–36. http://dx.doi.org/10.1017/s0022112009992497.
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The effects of polymer additives on Rayleigh–Taylor (RT) instability of immiscible fluids is investigated using the Oldroyd-B viscoelastic model. Analytic results obtained exploiting the phase-field approach show that in polymer solution the growth rate of the instability speeds up with elasticity (but remains slower than in the pure solvent case). Numerical simulations of the viscoelastic binary fluid model confirm this picture.
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Ismail, Abdul Razak, Radzuan Junin, Issham Ismail, and Mohd Fauzi Hamid. "The Effectiveness of Cationic and Polymer Inhibitors on Shale." Advanced Materials Research 1125 (October 2015): 205–9. http://dx.doi.org/10.4028/www.scientific.net/amr.1125.205.
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Maintaining the borehole stability while drilling oil and gas wells is a major problem when drilling through water sensitive formation. Drilling using oil-based drilling fluid is the most effective solution to control shale. Due to the increasing environmental constraints on the use of mineral oil-based drilling fluid system, expensive research has been studied to optimize oil well operations and minimize drilling cost using new water-based drilling fluid system. In this study, the effectiveness of three commonly used shale inhibitors were tested, where cationic polymer and KLA-Gard are cationic type inhibitors and PHPA is polymer type inhibitor. Two types of shale samples were used in this study, both were taken from Malaysia. Each shale sample represents different degree in swelling and dispersion characteristic. The testing procedures were employed for the shale reactivity evaluation, inhibitors’ performance evaluation, rheology and filtration loss effect evaluation as well as the character of the recovered shale from dispersion test. Result showed that the cationic type inhibitor is suitable to be used for swelling shale. For disperse shale, polymer type inhibitor is the best selection to be added in the drilling fluid system. The combination of cationic inhibitor used along with the polymer inhibitor showed reduction in dispersion and swelling tendency. It is also found that the cationic inhibitors showed well compatibility with other polymers in the ionic solution. Cationic inhibitors do not affect the rheology and filtration loss properties but polymer inhibitors affect these properties.
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Brattekås, Bergit, Martine Folgerø Sandnes, Marianne Steinsbø, and Jacquelin E. Cobos. "A Systematic Investigation of Polymer Influence on Core Scale Wettability Aided by Positron Emission Tomography Imaging." Polymers 14, no. 22 (November 21, 2022): 5050. http://dx.doi.org/10.3390/polym14225050.
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Polymers have been used as viscosifying agents in enhanced oil recovery applications for decades, but their influence on rock surface wettability is rarely discussed relative to its importance: wettability largely controls fluid flow in porous media and changes in wettability may significantly influence subsequent system performance. This paper presents a two-part systematic investigation of wettability alteration during polymer injection into oil-wet limestone. The first part of the paper determines wettability and wetting stability on the core scale. The well-established Amott–Harvey method is used, and five full cycles performed with repeated spontaneous imbibition and forced displacements. Wettability alterations are measured in a polymer/oil system, to determine polymer influence on wettability, and evaluated towards simpler brine/oil and glycerol/oil systems, to determine reproducibility and uncertainty related to the method and fluid/rock system. Polymer injection into oil-wet limestone core plugs is shown to repeatedly and reproducibly reverse the core wettability towards water-wet. Wettability changed both quicker and towards stronger water-wet conditions with polymer solution as the aqueous phase compared to brine and glycerol. The second part of the paper attempts to explain the observed behavior; by utilizing in situ imaging by Positron Emission Tomography, an emerging imaging technology within the geosciences. High resolution imaging provides insight into fluid flow dynamics during water and polymer injections, identifying uneven displacement fronts and significant polymer adsorption.
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Hirpa, Mehmet Meric, and Ergun Kuru. "Hole Cleaning in Horizontal Wells Using Viscoelastic Fluids: An Experimental Study of Drilling-Fluid Properties on the Bed-Erosion Dynamics." SPE Journal 25, no. 05 (June 18, 2020): 2178–93. http://dx.doi.org/10.2118/199636-pa.
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Summary An experimental study was conducted to determine the influence of fluid elastic properties on the critical velocity, frictional pressure drops, and the turbulent-flow characteristics of polymer-fluid flow over a sand bed deposited in a horizontal pipe. Fluids were prepared using a special technique, which allowed for the alteration of fluid elastic properties while keeping the shear viscosity constant. By conducting experiments under controlled conditions, we were able to quantify the individual effect of the fluid elasticity (independent from shear viscosity) on the critical flow rate for bed erosion and the turbulent-flow characteristics of polymer-fluid flow over the stationary sand bed. Results showed that higher critical velocities were required for the onset of the bed erosion when we use the fluid with higher elasticity.
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Graham, Michael D. "Fluid Dynamics of Dissolved Polymer Molecules in Confined Geometries." Annual Review of Fluid Mechanics 43, no. 1 (January 21, 2011): 273–98. http://dx.doi.org/10.1146/annurev-fluid-121108-145523.
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Wilk-Zajdel, Klaudia, Piotr Kasza, and Mateusz Masłowski. "Laboratory Testing of Fracture Conductivity Damage by Foam-Based Fracturing Fluids in Low Permeability Tight Gas Formations." Energies 14, no. 6 (March 23, 2021): 1783. http://dx.doi.org/10.3390/en14061783.
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In the case of fracturing of the reservoirs using fracturing fluids, the size of damage to the proppant conductivity caused by treatment fluids is significant, which greatly influence the effective execution of hydraulic fracturing operations. The fracturing fluid should be characterized by the minimum damage to the conductivity of a fracture filled with proppant. A laboratory research procedure has been developed to study the damage effect caused by foamed and non-foamed fracturing fluids in the fractures filled with proppant material. The paper discusses the results for high quality foamed guar-based linear gels, which is an innovative aspect of the work compared to the non-foamed frac described in most of the studies and simulations. The tests were performed for the fracturing fluid based on a linear polymer (HPG—hydroxypropyl guar, in liquid and powder form). The rheology of nitrogen foamed-based fracturing fluids (FF) with a quality of 70% was investigated. The quartz sand and ceramic light proppant LCP proppant was placed between two Ohio sandstone rock slabs and subjected to a given compressive stress of 4000–6000 psi, at a temperature of 60 °C for 5 h. A significant reduction in damage to the quartz proppant was observed for the foamed fluid compared to that damaged by the 7.5 L/m3 natural polymer-based non-foamed linear fluid. The damage was 72.3% for the non-foamed fluid and 31.5% for the 70% foamed fluid, which are superior to the guar gum non-foamed fracturing fluid system. For tests based on a polymer concentration of 4.88 g/L, the damage to the fracture conductivity by the non-foamed fluid was 64.8%, and 26.3% for the foamed fluid. These results lead to the conclusion that foamed fluids could damage the fracture filled with proppant much less during hydraulic fracturing treatment. At the same time, when using foamed fluids, the viscosity coefficient increases a few times compared to the use of non-foamed fluids, which is necessary for proppant carrying capacities and properly conducted stimulation treatment. The research results can be beneficial for optimizing the type and performance of fracturing fluid for hydraulic fracturing in tight gas formations.
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Wang, Gang, Honghai Fan, Guancheng Jiang, Wanjun Li, Yu Ye, Jitong Liu, Xiangji Kong, Zhao Zhong, and Feng Qian. "Rheology and fluid loss of a polyacrylamide-based micro-gel particles in a water-based drilling fluid." Materials Express 10, no. 5 (May 1, 2020): 657–62. http://dx.doi.org/10.1166/mex.2020.1687.
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In this paper, the cross-linked micro-gel polymer between acrylamide (AM) and N, N-Methylenebisacrylamide (MBA) was synthesized by dispersion polymerization. The initiator and crosslinking agent concentration were used to control the particle size of micro-gel polymer. The filtration property and mechanism of micro-gel were investigated comprehensively. The characteristics of micro-gel were checked by means of Fourier transform infrared spectroscopy, thermogravimetry, transmission electron microscopy, and particle size distribution, respectively. The results indicated that the cross-linked micro-gel polymer exhibited several outstanding merits, such as thermal stability (up to 200 °C), filtration control and rheological property. Microstructure analysis and particle size distribution examinations showed that the scale of micro-gel polymer was micro, which is in accord with design. Rheological tests demonstrated that the nonlinear structure of micro-gel polymer showed less impact on the apparent viscosity. The anti-high temperature property of micro-gel polymer was better than poly anioniccellulose (PAC) and asphalt widely applied in drilling fluid for anti-high temperature fluid-loss additive. As a result, the cross-linked micro-gel polymer had great potential to be applied in high temperature water-based mud.
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Wang, Sheng Peng, Xian Zheng Zhao, Bo Cai, and Shen Hua. "Study of New Ultra-Temperature Polymer Fracturing Fluid Material." Advanced Materials Research 1061-1062 (December 2014): 283–86. http://dx.doi.org/10.4028/www.scientific.net/amr.1061-1062.283.
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Nowadays, hydraulic fracturing has become the mainly treatment in low permeability reservoirs.Niudong buried-hill was located in the Baxian Sag of the Bohai Bay Basin. The charactristers of this natural reservoirs are summarized as :low porosity and ultra-low permeability ;complex storage types and complex fracture break and with ultra high temperature (200-210°C) ,In the past, 150°C fracturing fluid system was used in order to solve fluid fracturing efficiency low, quick acid rock reaction.Field test shown that it can’t meet target of greatly improve the output. So it is necessary to develop a novel fluid system to achieve high-efficient stimulation. Therefore, this paper invented a new high temperature resistant ternary anionic thickener, and launched some fracturing fluid performance evaluation.The novel high-temperature fracturing fliud provides a new material to stimulate ultra-high temperature, ultra deep formation to help maximize recovery efficiency. it has important strategic significance for exploration promotion of ultra-high reservoirs .
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Zhu, Lingyue, Jing Dong, Wei Jiang, Dandan Yuan, Hong Jiang, Chao Yan, and Baohui Wang. "Screening Study on Rheological Behavior and Phase Transition Point of Polymer-containing Fluids produced under the Oil Freezing Point Temperature." Open Chemistry 17, no. 1 (December 31, 2019): 1442–48. http://dx.doi.org/10.1515/chem-2019-0158.
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AbstractFor an increasing implementation of the low-temperature transportation in oilfield, it is urgent priority initially to study the physical and chemical properties to provide the vital technical support for the low-temperature transport of the polymer flooding. In this paper, the rheological behavior of polymer-containing fluid produced from the Daqing polymer flood were first studied for an adaptation of transportation under the oil’s freezing point temperature. The experiments progressed with different temperature, shear rate, water content and polymer concentration which have great impacts on the viscosity of the fluids produced aiming to find the phase transportation point for the application of the low-temperature transportation. It was displayed that a significant discontinuity in the viscosity occurs at some range of water content. Before the phase transition point, presented in W/O (water-in-oil) emulsion, the viscosity was lifted with the increase of the water content while after the phase transition point, forming the O/W (oil-in-water) type emulsion, the viscosity was dropped with an increase of water content. The phase transition points strongly depend on the polymer concentration in the fluids Produced. It was demonstrated that the phase transition points of polymer-containing fluids were 65%, 70%, 50%, 50% and 50%, corresponding to the polymer concentrations of 315mg/L, 503mg/L, 708mg/L, 920mg/L and 1053mg/L, respectively. The characteristics are attributed to the viscous polymer. The fluidity of the fluid produced was decreased with the increase of polymer concentration.
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Yang, Bo, Jincheng Mao, Jinzhou Zhao, Yang Shao, Yang Zhang, Zhaoyang Zhang, and Qingye Lu. "Improving the Thermal Stability of Hydrophobic Associative Polymer Aqueous Solution Using a “Triple-Protection” Strategy." Polymers 11, no. 6 (June 1, 2019): 949. http://dx.doi.org/10.3390/polym11060949.
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Because of their high viscoelasticity, Hydrophobic Associative Water-Soluble Polymers (HAWSPs) have been widely used in many industrial fields, especially in oilfield flooding and fracturing. However, one major problem which limits the wide applications of HAWSPs is their weak resistance to high temperatures. Once the temperature increases over 100 °C, the viscosity of the fracturing fluid decreases rapidly, because high temperatures reduce fluid viscosity by oxidizing the polyacrylamide chains and weakening the association of hydrophobic groups. To improve the high temperature resistance of one HAWSP, a triple-protection strategy was developed. First, rigid N-vinyl-2-pyrrolidone moiety was introduced into the polymer chains. Second, an environmentally-friendly deoxidizer, carbohydrazide, was selected to prevent polymer oxidization by scavenging dissolved oxygen. Results showed that both the rigid groups and the deoxidizer improved the temperature resistance of the polymer and helped it maintain high viscosity under high temperature and shear rate. Using these two protection strategies, the resistant temperature of the polymer could reach 160 °C. However, the polymer network still got severely damaged at further elevated temperatures. Therefore, as the third protection strategy, the pre-added high temperature responsive crosslinking agent was applied to form new networks at elevated temperatures. The results have shown that the optimized polymer solution as a kind of fracturing fluid showed good temperature resistance up to 200 °C.
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Tahir, Muhammad, Rafael E. Hincapie, Nils Langanke, Leonhard Ganzer, and Philip Jaeger. "Coupling Microfluidics Data with Core Flooding Experiments to Understand Sulfonated/Polymer Water Injection." Polymers 12, no. 6 (May 28, 2020): 1227. http://dx.doi.org/10.3390/polym12061227.
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The injection of sulfonated-modified water could be an attractive application as it results in the formation of a mechanically rigid oil-water interface, and hence, possible higher oil recovery in combination with polymer. Therefore, detailed experimental investigation and fluid-flow analysis into porous media are required to understand the possible recovery mechanisms taking place. This paper evaluates the potential influence of low-salt/sulfate-modified water injection in oil recovery using a cross-analyzed approach of coupled microfluidics data and core flooding experiments. Fluid characterization was achieved by detailed rheological characterization focusing on steady shear and in-situ viscosity. Moreover, single and two-phase micromodels and core floods experiments helped to define the behavior of different fluids. Overall, coupling microfluidics, with core flooding experiments, confirmed that fluid-fluid interfacial interaction and wettability alteration are both the key recovery mechanisms for modified-water/low-salt. Finally, a combination of sulfate-modified/low-salinity water, with polymer flood can lead to ~6% extra oil, compared to the combination of polymer flood with synthetic seawater (SSW). The results present an excellent way to make use of micromodels and core experiments as a supporting tool for EOR processes evaluations, assessing fluid-fluid and rock-fluid interactions.