Investigation of Polymer Adsorption on Rock Surface of Highly Saline Reservoirs

Blocking or reducing water production from oil wells is a serious problem in oil industry. Two types of polymers, namely, polyacrylamide (PAA) and polysaccharides (xanthan) have been investigated in this paper. The viscosity of both polymer solutions was first evaluated at different salinities, shear rates and concentrations. Afterwards, the solutions were injected into core samples to examine the adsorption on the rock surface by calculating the resistance factor as well as the residual resistance factor. Also, the effect of the injection rate of the polymer solutions has been studied. The results show that xanthan solution is tolerant of high salinity (20 %), while PAA solution is very sensitive to salt. Both polymer solutions show a pseudoplastic flow as a function of the shear rate. The core sample experiments show that both polymer solutions suffer a reduction in the adsorption rate with salinity increase. However, xanthan shows acceptable values even with a salinity up to 20 % and a temperature of 60 °C. Therefore, xanthan can be recommended to shut off water in high salinity and high temperature reservoirs. It was also found that the lower the injection rate the higher the adsorption on the rock surface.     

交联聚合物溶液在孔隙介质中的流动与滞留行为

在内径为40 mm、长度为1500 mm的填充砂管中,在线测量了由部分水解聚丙烯酰胺和柠檬酸铝所形成的交联聚合物溶液在填充砂孔隙介质中的流动和滞留特性,考察了交联聚合物溶液的流动形态及流动速度对孔隙封堵位置的影响。结果表明,交联聚合物溶液在孔隙介质中的流动过程中,经过多次压力脉动最终导致一种局部性的非均匀封堵;随着流动线速度的增加,封堵位置与交联聚合物注入口间的距离呈非线性增大;对应于封堵现象的发生,可能存在一个临界注入量,只有当交联聚合物溶液的注入量大于该临界值时,才会对孔隙介质产生封堵作用。     

Thermoviscosifying polymer used for enhanced oil recovery: rheological behaviors and core flooding test

Polymer flooding represents one of the most efficient processes to enhance oil recovery, but the poor thermostability and salt tolerance of the currently used water-soluble polymers impeded their use in high temperature and salinity oil reservoirs. Thermoviscosifying polymers (TVPs) whose viscosity increases upon increasing temperature and salinity may overcome the deficiencies of most water-soluble polymers. A novel TVP was studied in comparison with traditional partially hydrolyzed polyacrylamide (HPAM) in synthetic brine regarding their rheological behaviors and core flooding experiments under simulated high temperature and salinity oil reservoir conditions (T: 85 °C, and total salinity: 32,868 mg/L, [Ca²⁺] + [Mg²⁺]: 873 mg/L). It was found that with increasing temperature, both apparent viscosity and elastic modulus of the TVP polymer solution increase, while those of the HPAM solutions decrease. Such a difference is attributed to their microstructures formed in aqueous solution, which were observed by cryogenic transmission electron microscopy. Core flow tests at equal conditions showed an oil recovery factor of 13.5 % for the TVP solution versus only 2.1 % for the HPAM solution.     

The investigation of a new moderate water shutoff agent: Cationic polymer and anionic polymer

Cationic polymers and anionic polymers were selected as a moderate water shutoff agent for water production control. Due to the adsorption of polymers on the sand surface, the adsorption capacity under static condition, in porous media, and adsorption morphology on mica were investigated through starch–cadmium iodide method, core flow test, and atomic force microscopy measurement. The adsorption quantity on the sand surface increased with the high polymer concentrations and long adsorption time. With the increase of temperature and shearing time, the adsorption capacity slightly decreased. In addition, the adsorption capacity under water wettability condition was significantly larger than that under oil wettability condition. Alternate injection of cationic polymer and anionic polymer caused larger adsorption capacity in the core test. An adsorption multilayer was formed through alternate adsorption of cationic polymer and anionic polymer confirmed by atomic force microscopy. The visual simulation experiment was also conducted to illustrate adsorption and enhanced oil recovery mechanism. The polymers preferentially entered the high permeability zone and adsorbed on the sand surface, thus enhanced oil recovery. Furthermore, alternate injection of cationic and anionic polymers as a moderate water shutoff agent was successfully applied for water production control in oilfield test. © 2013 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2014 , 131, 39462.     

Intrinsic viscosity,rheological property,and oil displacement of hydrophobically associating fluorinated polyacrylamide

The surface‐active polymer (FPAM) was synthesized by free‐radical polymerization of acrylamide (AM), 2‐acrylamido‐2‐methyl‐1‐propane sulfonic acid (AMPS) and N ‐dodecyl‐N ‐perfluoro octane sulfonyl acrylamide (AMPD), which was prior prepared by reacting dodecylamine, perfluoro‐1‐octanesulfonyl fluoride, and acryloyl chloride. Parameters affecting the intrinsic viscosity ([η]) and apparent viscosity (η) of FPAM, such as reaction temperature, AMPD concentration, AMPS concentration, monomer concentration, initiator concentration, and pH were examined. Apparent viscosity and interfacial tension (IFT) of FPAM solution were evaluated. Subsequently, temperature tolerance and shear tolerance were investigated by comparing with hydrolyzed polyacrylamide (HPAM), and results indicated that the FPAM displayed better performances than HPAM. FPAM can reduce the IFT between crude oil/water, and the IFT values are around at 2.91 and 3.9 mN m^?1 corresponding to FPAM and HPAM/FC‐118. The sandpack model oil displacement experiment showed that water flooding can further increase the oil recovery to 15.01% (FPAM), compared with 9.26% oil recovery for HPAM, and 10.99% oil recovery for HPAM/FC‐118. The glass micromodel techniques for studying enhanced oil recovery get a good result and provide a useful reference for understanding the displacement behaviors in polymer flood process. It could be concluded that the introduction of fluorinated groups in the polymer chain was helpful in enhancing the oil displacement efficiency. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2017 , 134 , 44672.     

Viscoelastic Surfactants with High Salt Tolerance,Fast‐Dissolving Property,and Ultralow Interfacial Tension for Chemical Flooding in Offshore Oilfields

Injected chemical flooding systems with high salinity tolerance and fast‐dissolving performance are specially required for enhancing oil recovery in offshore oilfields. In this work, a new type of viscoelastic‐surfactant (VES) solution, which meets these criteria, was prepared by simply mixing the zwitterionic surfactant N‐hexadecyl‐N,N‐dimethyl‐3‐ammonio‐1‐propane sulfonate (HDPS) or N‐octyldecyl‐N,N‐dimethyl‐3‐ammonio‐1‐propane sulfonate (ODPS) with anionic surfactants such as sodium dodecyl sulfate (SDS). Various properties of the surfactant system, including viscoelasticity, dissolution properties, reduction of oil/water interfacial tension (IFT), and oil‐displacement efficiency of the mixed surfactant system, have been studied systematically. A rheology study proves that at high salinity, 0.73 wt.% HDPS/SDS‐ and 0.39 wt.% ODPS/SDS‐mixed surfactant systems formed worm‐like micelles with viscosity reaching 42.3 and 23.8 mPa s at a shear rate of 6 s^?1, respectively. Additionally, the HDPS/SDS and ODPS/SDS surfactant mixtures also exhibit a fast‐dissolving property (dissolution time <25 min) in brine. More importantly, those surfactant mixtures can significantly reduce the IFT of oil–water interfaces. As an example, the minimum of dynamic‐IFT (IFT_min) could reach 1.17 × 10^?2 mN m^?1 between the Bohai Oilfield crude oil and 0.39 wt.% ODPS/SDS solution. Another interesting finding is that polyelectrolytes such as sodium of polyepoxysuccinic acid can be used as a regulator for adjusting IFT_min to an ultralow level (<10^?2 mN m^?1). Taking advantage of the mobility control and reducing the oil/water IFT of those surfactant mixtures, the VES flooding demonstrates excellent oil‐displacement efficiency, which is close to that of polymer/surfactant flooding or polymer/surfactant/alkali flooding. Our work provides a new type of VES flooding system with excellent performances for chemical flooding in offshore oilfields.     

Investigation of Interfacial Tension Reduction,Wettability Alteration,and Oil Recovery Using a New Non-ionic Oil-Based Surfactant from Gemini Surfactants Family Coupled with Low-Salinity Water: Experimental Study on Oil-Wet Carbonate Rock

Low-salinity surfactant (LSS) flooding is a combined enhanced oil recovery (EOR) technique that increases oil recovery (OR) by altering the rock surface wettability and reducing oil–water interfacial tension (IFT). In this study, optimum concentrations of several types of salt in distilled water were obtained on the basis of IFT experiments for the preparation of low-salinity water (LSW). Then, a new oil-based natural surfactant (Gemini surfactant, GS) was combined with LSW to investigate their effects on IFT, wettability, and OR. Experimental results showed that LSW is capable of reducing IFT and contact angle, but the synergy of GS and the active ions Mg²⁺, Ca²⁺, and SO₄²⁻ in LSW was more effective on IFT reduction and wettability alteration. The combination of 1000 ppm MgSO₄ and 3000 ppm GS led to a decrease in contact angle from 134.82° to 36.98° (oil-wet to water-wet). Based on core flooding tests, LSW injection can increase OR up to 71.46% (for LSW with 1000 ppm MgSO₄), while the combination of GS and LSW, as LSS flooding, can improve OR up to 84.23% (for LSS with 1000 ppm MgSO₄ and 3000 ppm GS). Therefore GS has great potential to be used as a surfactant for EOR.     

Novel fluorinated surfactants for enhanced oil recovery in carbonate reservoirs

Novel surfactant‐polymer (SP) formulations containing fluorinated amphoteric surfactant (surfactant‐A) and fluorinated anionic surfactant (surfactant‐B) with partially hydrolyzed polyacrylamide (HPAM) were evaluated for enhanced oil recovery applications in carbonate reservoirs. Thermal stability, rheological properties, interfacial tension, and adsorption on the mineral surface were measured. The effects of the surfactant type, surfactant concentration, temperature, and salinity on the rheological properties of the SP systems were examined. Both surfactants were found to be thermally stable at a high temperature (90 °C). Surfactant‐B decreased the viscosity and the storage modulus of the HPAM. Surfactant‐A had no influence on the rheological properties of the HPAM. Surfactant‐A showed complete solubility and thermal stability in seawater at 90 °C. Only surfactant‐A was used in adsorption, interfacial tension, and core flooding experiments, since surfactant‐B was not completely soluble in seawater and therefore was limited to deionized water. A decrease in oil/water interfacial tension (IFT) of almost one order of magnitude was observed when adding surfactant‐A. However, betaine‐based co‐surfactant reduced the IFT to 10^?3 mN/m. An adsorption isotherm showed that the maximum adsorption of surfactant‐A was 1 mg per g of rock. Core flooding experiments showed 42 % additional oil recovery using 2.5 g/L (2500 ppm) HPAM and 0.001 g/g (0.1 mass%) amphoteric surfactant at 90 °C.     

Laboratory Studies to Determine Suitable Chemicals to Improve Oil Recovery from Garzan Oil Field

Garzan oil field is located at the south east of Turkey. It is a mature oil field and the reservoir is fractured carbonate reservoir. After producing about 1% original oil in place (OOIP) reservoir pressure started to decline. Waterflooding was started in order to support reservoir pressure and also to enhance oil production in 1960. Waterflooding improved the oil recovery but after years of flooding water breakthrough at the production wells was observed. This increased the water/oil ratio at the production wells. In order to enhance oil recovery again different techniques were investigated. Chemical enhanced oil recovery (EOR) methods are gaining attention all over the world for oil recovery. Surfactant injection is an effective way for interfacial tension (IFT) reduction and wettability reversal. In this study, 31 different types of chemicals were studied to specify the effects on oil production. This paper presents solubility of surfactants in brine, IFT and contact angle measurements, imbibition tests, and lastly core flooding experiments. Most of the chemicals were incompatible with Garzan formation water, which has high divalent ion concentration. In this case, the usage of 2-propanol as co-surfactant yielded successful results for stability of the selected chemical solutions. The results of the wettability test indicated that both tested cationic and anionic surfactants altered the wettability of the carbonate rock from oil-wet to intermediate-wet. The maximum oil recovery by imbibition test was reached when core was exposed 1-ethly ionic liquid after imbibition in formation water. Also, after core flooding test, it is concluded that considerable amount of oil can be recovered from Garzan reservoir by waterflooding alone if adverse effects of natural fractures could be eliminated.     

Acidic Heavy Oil Recovery Using a New Formulated Surfactant Accompanying Alkali–Polymer in High Salinity Brines

The strength of a newly formulated surfactant with an alkali and polymer (AS/ASP) to improve an acidic heavy oil recovery was laboratory evaluated by various flooding experiments. The comparative role of the parameters like chemical nature, surface wettability, salinity, temperature and injection scheme were explored at high temperature and pressure on Berea sandstone rocks. According to the results the anionic surfactant is capable of providing proper oil displacement under high salinity conditions around 15 wt%. Continuous monitoring of differential pressure response and effluents’ state clearly represented the formation of an emulsified oil in high saline solutions with both alkali and surfactant. Adding sodium metaborate to the surfactant solution reduced the interfacial tension (IFT) to ultra low values and decreased the surfactant emulsion generation capability at higher salinities. Besides, adding Flopaam AN113SH to the chemical slug increased the residual oil removal owing to lower mobility ratios. So, while high capillary number and an emulsion phase were generated by the A/S slug phases, adding polymer could further enhance the performance of these chemicals. On the other hand, chemical flooding through the oil-wet medium resulted in shorter break through time, lower differential pressure, finer emulsion formation, and lower oil recovery in comparison to the similar water-wet cases.     

聚合物驱油技术综述

综述了目前石油开采过程中常见的聚合物驱油剂种类,包括耐高温耐盐聚合物驱油剂、生物聚合物(黄原胶)、交联聚合物、疏水缔合聚合物、星形聚合物、两性聚合物等;以此为基础介绍了四种聚合物驱技术类型,包括热驱、混相驱、化学驱和微生物采油;并简单介绍了聚合物驱油技术在油田开发过程中所带来的负面矛盾及目前的主要解决方法。     

Effect of microscopic aggregation behavior on polymer shear resistance

The study of polymer aggregation behavior effect on shear resistance shed light on the synthesis of antishear polymer for oil displacement and enhances the application effect of polymer flooding. The effects of mechanical degradation on the properties of polymer solutions were studied by using partially hydrolyzed polyacrylamide (HPAM), hydrophobically modified HPAM (HMPAM), and dendritic hydrophobic associative polymers (DHAP), which are characterized by “granular,” “chain,” and “cluster” aggregation behavior, respectively. The results show that mechanical shearing can dramatically reduce the performance of polymer solution. The shearing resistance can be effectively enhanced by improving the polymer aggregation behavior. After being strongly sheared, hydrophobically associating polymers can still partially restore its network through hydrophobic association, therefore rebuild the solution viscosity. For DHAP, the broken molecular chains distribute more evenly in solution after shearing. In addition, the strength of reconstructed network structure of DHAP is better than that of HMAPM, which implies a better shear resistance. Furthermore, the hydrophobic association of linear polymers will increase their static adsorption on quartz sand. Meanwhile, DHAP with stronger spatial structure has less static adsorption, which is beneficial to maintain a higher polymer concentration in solution. © 2019 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019 , 137, 48670.     

Rheological investigation of xanthan gum–chromium gelation and its relation to enhanced oil recovery

Xanthan gum–water solutions with polymer concentrations 0.05–1% w/w and chromium ion content 30–1200 ppm were being gelled at temperatures from 25 to 90°C. A control deformation test (CD test) at a constant shear rate 0.05 s^?1 was performed for all the specimens. Shear moduli of elasticity and in some cases yield stresses and yield strains were determined from these tests. The energy of activation E_a = 93 ± 6 kJ/mol was obtained. The dependence of the gelation rate on the ionic concentration followed a power law with a coefficient of 1.8. There was relatively small dependence of the gelation rate on the xanthan gum concentration. Surprisingly, the maximum obtainable moduli at complete gelation do not depend on xanthan gum concentration in the range 0.2–1% w/w and are about 2400 Pa. The number of the bound chromium ions per monomer unit of xanthan gum is changed from 0.64 to 0.16 for the above measured concentrations of the polymer. High moduli gels on the base of the lower concentrations of xanthan gum were practically not recoverable after mechanical destruction. The assumption was made that the main reason for the profile modification of the flow for enhanced oil recovery in porous media is the yield stress of the gels. The smaller capillaries can even be closed if the yield stress is higher than the maximum shear stress existing in the capillary. © 2006 Wiley Periodicals, Inc. J Appl Polym Sci 103: 160–166, 2007     

Preparation and performance study of functional polymer with self demulsifying

In polymer flooding, the residual polymer in the produced fluid can increase the stability of crude oil emulsion, thereby negatively affecting the demulsification process. Therefore, a polymer that has no effect on the stability of crude oil emulsion is required. Herein, a polymerizable monomer with a demulsification function (MD) was synthesized and then copolymerized with acrylamide, acrylic acid, and 2-acrylamide-2-methylpropane sulfonic acid to prepare a novel copolymer (self-demulsifying polymer, PDM). The dissolution time, solution viscosity, shear resistance, static adsorption on quartz sand, and the effect on the crude oil emulsion stability of PDM were compared with those of regular polyacrylamide (PAM). Experimental results showed that owing to the steric hindrance effect of MD, the molecular weight of PDM was lower than that of PAM. Both polymers exhibited satisfactory solubility, solution viscosity, shear resistance, and static adsorption, which can meet the requirements of polymer for use in oil displacement. However, in contrast to PAM, PDM had no negative effect on the crude oil emulsion stability. This study provides a new solution to the problem of increased crude oil emulsion stability in polymer flooding.     

Flow characteristics of three enhanced oil recovery polymers in porous media

This article presents an experimental study aiming to explore the relationship among rheological properties, flow characteristics in porous media, and enhanced oil recovery (EOR) performance of three typical EOR polymers. The results suggest that xanthan gum exhibits a very pronounced shear‐thinning behavior, which is probably also the reason explaining its moderate adsorption extent within porous media (thickness of adsorbed layer, e = 3.1 μm). The advanced viscoelastic properties coupled with the less adsorption extent compared to the hydrophobically modified copolymer (HMSPAM) allow xanthan gum to establish a “piston‐like” displacement pattern and lead up to 49.4% original oil in place (OOIP) of the cumulative oil recovery during polymer flooding. Regarding HMSPAM, the significant permeability reduction of the porous media induced by multilayer adsorption (e = 5.6 μm) results in much higher drive forces (ΔP) in the extended waterflooding stage, which further raises the cumulative oil recovery by 18.5% OOIP. In general, xanthan gum and HMSPAM totally produced 84% OOIP which is 15% higher than the extensively used EOR polymer, hydrolyzed polyacrylamide (HPAM), under the same experimental conditions. © 2014 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2015 , 132, 41598.     

Propagation of Surfactant-Dispersed Multiwalled Carbon Nanotubes in Porous Media

Understanding the transport of carbon nanotubes in porous media is essential to their applications in subsurface reservoirs, e.g., delivering catalysts or chemicals to targeted formations. In this study, a series of laboratory experiments are conducted to explore the transport of surfactant-dispersed multiwalled nanotubes (MWNT) in different porous media in flow-through columns at elevated electrolyte levels. Noncovalent bonding of ethoxylated alcohols adsorbed on the MWNT surface provides them with outstanding dispersion stability and excellent transport properties in a crushed-limestone sand pack. Superior transport performance in silica sand is obtained with binary nonionic–anionic surfactant formulations, which provide both steric repulsion and electrostatic repulsion between nanoparticle–nanoparticle and nanoparticle–sand surface. The mobility of MWNT suspensions are further investigated in the exposure to multiphase flow, e.g., with residual oil present, or coinjected with air into the sand pack. Coinjecting surfactant-dispersed MWNT suspensions with air (i.e., MWNT-stabilized foams) has hardly any impact on their propagation; retention in the sand pack remains quite low. With the presence of oil in the sand pack, the transport of MWNT suspensions is highly dependent on the type of surfactants used as the dispersant. For surfactants that achieved modest interfacial tension (IFT) reduction, the injected MWNT suspension bypasses the oil phase, and little impact on retention is observed. When the dispersant surfactant is also adjusted for an ultralow IFT condition, greater MWNT retention in the porous medium is observed because surfactants detach from the MWNT surface and aggressively partition to the oil/water interface, allowing the MWNT to flocculate and become deposited in the porous medium.     

Superior enhancement of imbibition recovery by novel surfactant mixtures with a large hydrophobic group combined with nanosilica

Low interfacial tension (IFT) drainage and imbibition are effective methods for improving oil recovery from reservoirs that have low levels of oil or are tight (i.e., exhibit low oil permeability). It is critical to prepare a high efficient imbibition formula. In this work, a novel 2,4,6-tris(1-phenylethyl)phenoxy polyoxyethylene ether hydroxypropyl sodium sulfonate (TPHS) surfactant was synthesized and evaluated for imbibition. Its structure was confirmed by Fourier transform infrared spectroscopy and the interfacial tension (IFT) of the crude oil/0.07% TPHS solution was 0.276 mN/m. When 0.1 wt% TPHS was mixed with 0.2 wt% alpha olefin sulfonate (AOS), the IFT was lowered to 6 × 10⁻² mN/m. The synergy between nanoparticles (NPs) and TPHS/AOS mixed surfactant was studied by IFT, contact angle on sandstone substrates, zeta potential, and spreading dynamics through microscopic methods. The results show that the surfactant likely adsorbs to the NP surface and that NP addition can help the surfactant desorb crude oil from the glass surface. With the addition of 0.05 wt% SiO₂ NPs (SNPs), the imbibition oil recovery rate increased dramatically from 0.32%/h to 0.87%/h. The spontaneous imbibition recovery increased by 4.47% for original oil in place (OOIP). Compared to flooding by TPHS/AOS surfactant solutions, the oil recovery of forced imbibition in the sand-pack increased by 12.7% OOIP, and the water breakthrough time was delayed by 0.13 pore volumes (PV) when 0.05% SNPs were added. This paper paves the way for enhanced oil recovery in low-permeability sandstone reservoirs using novel TPHS/AOS surfactants and SNPs.     

Rheological properties of new polymer compositions for sand consolidation and water shutoff in oil wells

The rheological properties of some newly developed polymer compositions have been investigated with and without crosslinking. These polymer compositions were developed as a water shutoff and sand consolidation treatment agents for producing oil and gas wells. The effects of several variables on the rheology of the compositions were evaluated over a wide range of temperatures (25–110°C), shear rates (0–500 s^?1), brine percentages (0–15%), crosslinker types and concentrations (0–3%), and polymer concentrations (6–50%). It was found that increasing the shear rate from 0 s^?1 to 100 s^?1 caused shear thinning and reduction of the viscosity of the dilute solutions (6–13%) from 25 cP to ～ 3 cP at 80°C. In contrast, for the concentrated solutions (20–50%), the viscosity dropped slightly in the shear rate range 0–10 s^?1, and subsequently decreased more slowly up to shear rates of 500 s^?1. The viscosities of all polymer solutions dropped by a factor of 2 as the brine concentration increased from 0% to 15%. Finally, aging time coupled with shear rates and higher percentages of crosslinkers accelerate the buildup of viscosity and gelation time of the polymer compositions. For concentrated solutions, shear rates ranging within 0–200 s^?1 accelerated gelation time from 9.75 h to 2–3 h, when they were sheared at 80°C. The polymeric solutions exhibited Newtonian, shear‐thinning (pseudo‐plastic), and shear‐thickening (dilatant) behavior, depending on the concentration, shear rate, and other constituents. In most cases, the rheological behavior could be described by the power law. © 2007 Wiley Periodicals, Inc. J Appl Polym Sci 2007     

聚合物驱在提高油气采收率上的应用与进展

介绍了聚合物驱油原理,概括了聚合物驱所采用的聚合物品类,介绍了疏水缔合聚合物、两性聚合物及梳形聚合物的特点和发展概况,分析了提高采收率的系列方法。在新型驱油剂的研制过程中,要满足其苛刻的使用条件,开发出耐井下高温,不易在电解质溶液中被剪切破坏的高分子量聚合物驱油剂。     

Viscosity behavior and surface and interfacial activities of hydrophobically modified water‐soluble acrylamide/N‐phenyl acrylamide block copolymers

In this study, the viscosity behavior and surface and interfacial activities of associative water‐soluble polymers, which were prepared by an aqueous micellar copolymerization technique from acrylamide and small amounts of N‐phenyl acrylamide (1.5 and 5 mol %), were investigated under various conditions, including the polymer concentration, shear rate, temperature, and salinity. The copolymer solutions exhibited increased viscosity due to intermolecular hydrophobic associations, as the solution viscosity of the copolymers increased sharply with increasing polymer concentration, especially above a critical overlap concentration. An almost shear‐rate‐independent viscosity (Newtonian plateau) was also displayed at high shear rates, and typical non‐Newtonian shear‐thinning behavior was exhibited at low shear rates and high temperatures. Furthermore, the copolymers exhibited high air–water and oil–water interfacial activities, as the surface and interfacial tensions decreased with increasing polymer concentration and salinity. © 2003 Wiley Periodicals, Inc. J Appl Polym Sci 89: 2290–2300, 2003