High-viscoelastic graft modified chitosan hydrophobic association polymer for enhanced oil recovery

The conventional partially hydrolyzed polyacrylamide (HPAM) is greatly restricted by its single linear molecular structure in oil reservoirs with severe reservoir conditions such as high temperature and high salt. In this article, the chitosan (CS) grafted imidazoline monomer copolymer (CS-g-AM/AA/NIDA) was prepared from N-maleyl CS (N-MCS), acrylamide (AM), acrylic acid (AA), 1-(2-N-acryloylaminoethyl)-2-oleoyl imidazoline (NIDA) by free radical copolymerization. The structure was determined by means of Fourier transform infrared spectroscopy, ¹H nuclear magnetic resonance spectroscopy, scanning electron microscope, thermal gravimetric analysis, and so forth, which confirmed the successful preparation of the copolymer with good thermal stability. Under the same conditions, compared with HPAM and copolymer CS-g-AM/AA, CS-g-AM/AA/NIDA greatly increased the viscosity of the aqueous solution and exhibited excellent shear stability (viscosity retention rate 15.62, 4.91, and 11.54% at 510 s⁻¹), temperature resistance (the viscosity retention rate reached 50.89, 24.50, and 36.59% at 120°C) and salt resistance (14,000 mg/L NaCl: viscosity retention rate up to 17.27, 8.26, and 14.60%). In addition, core flooding experiments showed that oil recovery could be enhanced by up to 8.08% by CS-g-AM/AA/NIDA. As a natural polymer material, CS has hardly been reported for polymer flooding, and it is expected to replace general polymers in tertiary oil recovery.     

Rheology and polymer flooding characteristics of partially hydrolyzed polyacrylamide for enhanced heavy oil recovery

Polymer flooding characteristics of partially hydrolyzed polyacrylamide (HPAM) solution with the addition of NaOH were examined in homogeneous glass‐bead packs. The heavy oil recovery in unconsolidated sandstone formations by applying the alkali‐polymer flooding was observed. Experimental results showed that HPAM solution was sensitive to temperature, salinity, and alkali, finding that alkali‐polymer solutions are more effective in improving viscosity than conventional polymer solutions. The solution of 0.5 wt % NaOH mixed with 1500 ppm HPAM (12 mol % hydrolysis degree) was found to be the optimal choice, which gives rise to the highest viscosity on the rheological characterization. Flood tests using the alkali‐polymer solution showed an increase in oil recovery by 30% over water‐flooding when the water‐cut reached 95%, indicating that alkali‐polymer could be more effective in improving sweep efficiency than polymer flood. © 2012 Wiley Periodicals, Inc. J. Appl. Polym. Sci., 2013     

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.     

Thermoviscosifying polymers based on polyether prepared from inverse emulsion polymerization

Thermoviscosifying polymers are attractive for enhancing oil recovery owing to their exceptional thickening power as temperature increases. However, the polymers reported to date show inadequacies including obligatory high polymer concentration to get the thermothickening ability because of their low molecular weight (MW), and inconvenient post‐treatment due to the high viscosity after manufacturing. To overcome these drawbacks, inverse emulsion polymerization was used here for preparing polyether‐based thermoviscosifying polymers (TVP‐Ps) by grafting acrylic monomers onto triblock copolymers PEO–PPO–PEO. It was found the MW of final products could reach 8 million Daltons, making them thermoviscosifying at 0.2 wt %. The viscosity of polymerized inverse emulsions was as low as 175 mPa·s, leading to direct dispersing. The TVP‐Ps containing Pluronic F127, F108, F68 all exhibited significant thermothickening behaviors in both aqueous solutions and brines, and the critical thermoassociative temperature could be tuned by changing the nature or amount of Pluronics. After aging at 45 °C for 60 days with equal initial viscosity, TVP‐Ps shows 21% higher viscosity retention than the reference polymer without Pluronic, PAMA, and preliminary core flooding test demonstrated TVP‐Ps can get 2.1% higher incremental oil recovery than PAMA. This work paves a new avenue for scaled‐up preparation and potential use of TVP‐Ps. © 2018 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018 , 134, 46696     

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.     

β-Cyclodextrin-functionalized copolymers based on multiple intermolecular forces for enhanced oil recovery

As one of mature enhanced oil recovery (EOR) technologies, polymer flooding has been extensively applied in oilfield. In this study, new hydrophobically associative copolymers were synthesized by free-radical polymerization of acrylamide (AM), acrylic acid (AA), vinyl-modified β-cyclodextrins, and a water-soluble hydrophobic macromonomer (AA-APE-20). Fourier transform infrared, proton-nuclear magnetic resonance, and scanning electron microscopy verified the structure of hydrophobically associative polymers (HDAPAMs). Compared with partially hydrolyzed polyacrylamide (HPAM), multiple intermolecular forces including chelation between ethoxyl (EO) group and Ca²⁺/Mg²⁺, electrostatic bridges between EO groups and carboxyl groups ( COO⁻), hydrogen bonding between EO groups and AM groups ( CONH₂), hydrophobic association among nonyl phenol groups, and host-guest inclusion interaction endowed HDAPAMs favorable temperature-resistance, salt-resistance, and displacement efficiency. It was found that HDAPAMs showed evident temperature-response, salt thickening effect, favorable thixotropy, and viscoelasticity. Compared with HPAM, the core flooding experiments demonstrated that HDAPAMs could further enhance 6.97% to 8.43% oil recovery, even after HPAM flooding used. All the results revealed the EOR potential in HDAPAMs flooding.     

HPAM-g-PEOPPO: Rheological modifiers in aqueous media of high temperature and high ionic strength

Partially hydrolyzed polyacrylamide (HPAM) is widely used as thickener in enhanced oil recovery (EOR), but the high temperature and salinity of oil reservoirs can reduce the viscosity and lead to polymer precipitation. To improve the performance of HPAM in high-salinity and high-temperature environments, the responsive amino-terminated poly(ethylene oxide-co-propylene oxide) (PEOPPO) (EO/PO = 19/03) was grafted onto a HPAM backbone. The copolymers were prepared in water using 1-ethyl-3-[3-(dimethylamino)-propyl]carbodiimide hydrochloride/N-hydroxysuccinimide (EDC/NHS) as activators. Structural characterization was performed by ¹H NMR and Fourier transform infrared (FTIR) and the responsive behavior was investigated by UV–Vis and rheology. Spectroscopic analyses confirmed that copolymers were successfully synthesized. UV–Vis showed that copolymers have combined salt and thermoresponsive character. Rheology in saline medium (ionic strength = 3.75 mol.L⁻¹) revealed that, contrary to unmodified HPAM, HPAM-g-PEOPPO have thermothickening behavior and also higher viscosity than HPAM at 70 °C, suggesting the utilization of these copolymers as rheological modifiers under harsh conditions of temperature and salinity, such as the ones found in EOR applications. © 2019 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019 , 136, 47453.     

塔河油田超稠油水溶性减阻降粘剂的研究与应用

针对塔河稠油高粘及油田地层水高矿化度的特点,研制了耐盐型稠油减阻降粘剂,考察了药剂浓度、矿化度、油水比例以及破乳效果等对稠油降粘效果的影响。结果表明,在A剂加量为3 200 mg/L,B剂加量为800 mg/L,w(油)∶w(水)=6∶4时,降粘剂最佳适用矿化度为9×104mg/L左右,对破乳基本无影响。现场试验结果表明,稠油减阻降粘剂能满足50℃时原油粘度在50×104mPa.s以下的稠油降粘,其对矿化度敏感,最佳矿化度使用范围在7×104~12×104mg/L,耐盐型稠油减阻降粘剂应用于电泵型油井降粘试验效果较好。     

Laboratory study of an anti‐temperature and salt‐resistance surfactant‐polymer binary combinational flooding as EOR chemical

Experimental studies were conducted to enhance the oil recovery by a surfactant‐polymer binary combinational flooding system. The surfactant‐polymer binary combinational flooding was obtained by mixing the surfactants with the poly(AM‐NVP‐AS)‐1 which was an anti‐temperature and salt‐resistance tercopolymer and successfully synthesized via free radical polymerization using acrylamide (AM), N‐vinyl pyrrolidone (NVP), allyl sulfonate (AS) as raw materials. The initiator was redox system including water‐soluble azo compound (AIBA·2HCl) and sodium bisulfite (NaHSO₃). Petroleum carboxylate dodecyl dibasic carbonylic acid sodium (C12DAS) and carboxyl betaine dodecyl dimethyl betaine (C12DB) were selected in this article. Compared with the surfactant‐HPAM, the surfactant‐poly(AM‐NVP‐AS)‐1 binary combinational system showed higher apparent viscosity and lower interfacial tension at high temperature and salinity conditions as the result of a better capacity of anti‐temperature, salt‐resistance, and swept volume. The recovery could enhance over 17% based on the core flooding test under the mineralization of 10,000 mg/L at 65°C. © 2013 Wiley Periodicals, Inc. J. Appl. Polym. Sci., 2014 , 131, 39984.     

Dependence of intrinsic viscosity and molecular size on molecular weight of partially hydrolyzed polyacrylamide

As a typical water-soluble polymer, ultra-high molecular weight (UHMW) partially hydrolyzed polyacrylamide (HPAM) has been widely used in various industries as thickeners or rheology modifiers. However, precise determination of its critical physical parameters such as molecular weight, radius of gyration (R_g) and hydrodynamic radius (R_h) were less documented due to their high viscosity in aqueous solution. In this work, the molecular structure of five UHMW-HPAM samples with different MW was elucidated by ¹H and ¹³C NMR spectroscopy, and their solution properties were characterized by both static and dynamic light scattering. It is found that all the second virial coefficient (A₂) values are positive and approaching zero, indicating of a good solvent of 0.5 M NaCl for UHMW-HPAM. The weight-average molecular weight (M_w) dependence of molecular size and intrinsic viscosity [η] for these series of HPAM polymers with MW ranging from 4.81 to 15.4 × 10⁶ g·mol⁻¹ can be correlated as R_g = 3.52 × 10⁻²M_w^0.51, R_h = 1.97 × 10⁻²M_w^0.51, and [η] = 6.98 × 10⁻⁴ M_w^0.91, respectively. These results are helpful in understanding the relationship between molecular weight and coil size of HPAM polymers in solution, and offer references for quick estimation of molecular weight and screening of commercial UHMW-HPAM polymers for specific end-users.     

Hydrolysis and thermal stability of partially hydrolyzed polyacrylamide in high-salinity environments

Partially hydrolyzed polyacrylamide (HPAM) is the water-soluble polymer most often used in flooding applications in the petroleum industry. However, in aqueous solutions at high temperatures, HPAM undergoes hydrolysis of the lateral amide groups, and the presence of salts in the solution can lead to precipitation of this polymer. Therefore, a method was developed to monitor the thermal stability of HPAM solutions in different saline environments and varying temperatures. The proposed test method involved measurements of intrinsic viscosity as a function of time and determination of the degree of hydrolysis of the HPAM by elemental analysis. The results obtained indicated that the presence of divalent cations (Ca⁺² and Mg⁺²) negatively influenced the intrinsic viscosity of the solutions and in some systems led to precocious precipitation of the polymer in environments with higher concentrations of these cations. The hydrolysis reaction of the amide groups to the acrylate groups of the HPAM chain was significantly affected by rising temperature: at 50 °C, hydrolysis occurred, but not as significantly as at 70, 85, 90, and 95 °C. Hydrolysis up to 84% was observed for solutions processed at 90 °C. The results also indicated limits of hardness for the brine at some temperatures: 1353 ppm for 95 °C and 2867 ppm for 70 °C. For brine containing 13,610 ppm or more of divalent cations, hydrolysis and precipitation of the polymer were not observed at 50 °C. © 2019 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2019 , 136, 47793.     

Experimental research of hydroquinone (HQ)/hexamethylene tetramine (HMTA) gel for water plugging treatments in high‐temperature and high‐salinity reservoirs

Polymer gel, as a water plugging treatment agent, has been successfully used in enhanced oil recovery (EOR) of mature oil fields. A new thermal‐resistance and salt‐tolerance polymer gel was developed based on HPAM and HQ/HMTA under the condition of high‐temperature (100.8 °C) and high‐salinity (up to 19.8 × 10⁴ mg/L and Ca²⁺&Mg²⁺ 0.8 × 10⁴ mg/L). The influence factors of gelling performance and coreflood performances were studied, the microstructure of the gel was observed with the environmental scanning electron microscopy, and gelation mechanism was proposed to illuminate the detailed gelation process. The gelation time decreases and the gel strength increases with the increase of polymer concentration, crosslinker concentration, or temperature. Although shearing had a negative effect on the viscosity of gelling solution, the gel strength, and the stability of gel have not been affected. The gelling solution has a good ability of injection and could selectively flow into high permeable zone. Additionally, the plugging rate increases and stays above 85% with the increase of the permeability or the gel strength. The microstructure of the gel confirms that the gel formed a three‐dimensional network structure. Based on the microstructure and the reaction process of the gel, a possible gelation mechanism is proposed. This study suggests that the gel system can be used in harsh reservoir conditions and the gelation time and gel strength can be controlled with adjusting the formation rate and the concentration of crosslinking agents. © 2016 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2016 , 133, 44359.     

Enhanced oil recovery from high‐salinity reservoirs by cationic gemini surfactants

In order to enhance oil recovery from high‐salinity reservoirs, a series of cationic gemini surfactants with different hydrophobic tails were synthesized. The surfactants were characterized by elemental analysis, infrared spectroscopy, mass spectrometry, and ¹H‐NMR. According to the requirements of surfactants used in enhanced oil recovery technology, physicochemical properties including surface tension, critical micelle concentration (CMC), contact angle, oil/water interfacial tension, and compatibility with formation water were fully studied. All cationic gemini surfactants have significant impact on the wettability of the oil‐wet surface, and the contact angle decreased remarkably from 98° to 33° after adding the gemini surfactant BA‐14. Under the condition of solution salinity of 65,430 mg/L, the cationic gemini surfactant BA‐14 reduces the interfacial tension to 10^?3 mN/m. Other related tests, including salt tolerance, adsorption, and flooding experiments, have been done. The concentration of 0.1% BA‐14 remains transparent with 120 g/L salinity at 50 °C. The adsorption capacity of BA‐14 is 6.3–11.5 mg/g. The gemini surfactant BA‐14 can improve the oil displacement efficiency by 11.09%. © 2017 Wiley Periodicals, Inc. J. Appl. Polym. Sci. 2018 , 135, 46086.     

Progress in research of sulfobetaine surfactants used in tertiary oil recovery

The synthesis of sulfobetaine surfactants and their application in tertiary oil recovery (TOR) are summarized in this paper. The synthesis of sulfobetaine surfactants was classified into three categories of single hydrophobic chain sulfobetaine surfactants, double hydrophobic chain sulfobetaine surfactants and Gemini sulfobetaine surfactants for review. Their application in TOR was classified into surfactant flooding, microemulsion flooding, surfactant/polymer (SP) flooding and foam flooding for review. The sulfonated betaine surfactants have good temperature resistance and salt tolerance, low critical micelle concentration (cmc) and surface tension corresponding to critical micelle concentration (γ_cmc), good foaming properties and wettability, low absorption, ultralow interfacial tension of oil/water, and excellent compatibility with other surfactants and polymers. Sulfobetaine surfactants with ethoxyl structures, hydroxyl and unsaturated bonds, and Gemini sulfobetaine surfactants will become an important direction for tertiary oil recovery because they have better interfacial activity in high-temperature (≥90°C) and high-salinity (≥10⁴ mg/L) reservoirs. Some problems existing in the synthesis and practical application were also reviewed.     

含孪尾结构两性离子共聚物的合成及性能

以丙烯酰胺(AM)、丙烯酸(AA)、N,N-二辛基甲基丙烯酰胺(DLMB)和3-(2-甲基丙烯酰胺丙基二甲胺基)丙磺酸盐(MDPS)为单体,通过自由基共聚,制备了一种含孪尾结构的两性离子共聚物驱油剂(AADM)。对共聚物进行了红外、核磁表征并确认了其结构,热重实验分析了热稳定性,并与部分水解聚丙烯酰胺(HPAM)进行了对比,考察了该共聚物的增黏性、水溶性、抗老化、剪切稀释性、剪切恢复性和耐温抗盐性。结果表明,共聚物AADM具有优异的水溶性和增黏性,在2000 mg/L的质量浓度下可使表观黏度达到466.5 mPa·s;在510s–1的剪切速率下,其表观黏度为60.4 mPa·s;在120℃下,其表观黏度能够达到182.6 mPa·s;在经过30 d的老化实验后其表观黏度为94.6 mPa·s;在15000 mg/L NaCl、2000 mg/L MgCl_2和2000 mg/L CaCl_2溶液中,该共聚物的表观黏度分别为77.8、72.4和68.6 mPa·s。在岩心驱替实验中,共聚物溶液能够将采收率提高7.72%。以上实验结果均优于相同条件下的HPAM,这是因为孪尾结构的引入有效地增强了共聚物的疏水缔合能力,两性离子单体的引入削弱了分子链对盐的敏感度。     

A water‐soluble acrylamide hydrophobically associating polymer: Synthesis,characterization, and properties as EOR chemical

A water‐soluble acrylamide hydrophobically associating terpolymer for polymer flooding was successfully synthesized via free radical polymerization using acrylamide (AM), acrylic acid (AA), and N,N‐divinylnonadeca‐1,10‐dien‐2‐amine (DNDA) as raw materials. The terpolymer was characterized by IR spectroscopy and fluorescence spectra. Compared with partially hydrolyzed polyacryamide (HPAM), the terpolymer showed a stronger link and better dimensional network structure under the environmental scanning electron microscope (ESEM). The results of rheology indicated that the terpolymer (AM‐NaAA‐DNDA) showed an excellent shear‐resistance in high shear rate (1000 s^?1) and remarkable temperature‐tolerance (above 110°C). The salt‐resisting experiment revealed that this terpolymer had a better anti‐salt ability. According to the core flooding test, it could be obtained that oil recovery was enhanced more than 15% under conditions of 2000 mg/L terpolymer in the mineralization of 8000 mg/L at 60°C. © 2012 Wiley Periodicals, Inc. J. Appl. Polym. Sci., 2013     

Effect of micro-aggregation behavior on the salt tolerance of polymer solutions

Polymer solution for oil displacement is mostly used in the middle and late stage of water flooding reservoir development, and reservoir groundwater conditions are often one of the main conditions restricting polymer application. Therefore, it is necessary to develop salt tolerance of polymer solutions with different aggregation behaviors, so as to facilitate the synthesis and optimization of suitable polymer systems. The differences in the micro-aggregation behavior of three polymers with different molecular structures were explored. On this basis, the effects of divalent metal cations on the properties of the polymer solutions were analyzed by assessing the micro-aggregation behavior, apparent viscosity, hydrodynamic size, and shear rheological characteristics. The results showed that the linear partially hydrolyzed polyacrylamide (HPAM) was seriously affected by divalent cations, and the viscosity decreased obviously. The aggregation behavior of the polymer changed by hydrophobic association can enhance the salt tolerance of the solution. The hydrophobically modified partially hydrolyzed polyacrylamide (HMPAM) with “chain beam” aggregation behavior has strong intermolecular connection, which enables it to withstand the content of calcium and magnesium ions of 1100 mg l⁻¹. When the content of calcium and magnesium ions exceeds 600 mg l⁻¹, dendritic hydrophobically associating polymer (DHAP) will destroy the interaction between molecular chains, resulting in the decrease of apparent viscosity and hydrodynamic size. For polymer flooding in high-salinity reservoir, salt tolerant polymer system can be constructed by optimizing molecular weight and hydrophobic group content.     

The performance of polymer solutions in enhanced oil recovery: studies on their rheological,interfacial, and porous media behaviors

Four polymeric solutions based on xanthan, high and low molecular weight sulfonated polyacrylamides, and hydrolyzed polyacrylamide were prepared in aqueous solutions and their behaviors in enhanced oil recovery applications were investigated. The effect of thermal aging on polymer solutions was evaluated through rheological measurement. Pendant drop method was also used for measuring the interfacial tension (IFT) between crude oil and brine containing different polymer solutions. Moreover, the zeta potential of the oil reservoir particles treated with oil and polymer was determined by electrophoresis method in a nano-zeta meter instrument. In addition, sand pack and core flooding setup were used for evaluating the effectiveness of the polymer solutions in porous media. Polymer solutions displayed non-Newtonian behavior in almost the whole range of the shear rate applied; a shear thinning behavior was seen. Furthermore, the aging of polymers in formation water decreased the shear viscosity of all the polymers. The oil/water IFT decreased by the addition of polymers to water. The effect of xanthan polymer on zeta potential value was greater than that of the three acrylamide-based polymers. According to sand pack tests, by increasing the polymer concentration, the incremental oil recovery initially increased up to a polymer concentration of 3,500 ppm and then started to fall. Recovery factor increased from 50 to 65 % using the polymer solution in core flooding experiments. By increasing the injection rate from 0.2 to 3 mL/min, the injected fluid had less time to sweep the pores and consequently the amount of recovered oil decreased.     

The shearing effect on hydrophobically associative water‐soluble polymer and partially hydrolyzed polyacrylamide passing through wellbore simulation device

Hydrolyzed polyacrylamide (HPAM) was the traditional polymer and hydrophobically associative water‐soluble polymer (HAWP) was the new polymer with three‐dimensional network both used to flood to enhance oil recovery. The wellbore area was the most important part before the polymer solution injected into stratum. In this article, the shearing effects of the two polymers were studied by a wellbore simulation device. The viscosities of HPAM and HAWP solutions were both decreased around perforation of wellbore simulation device. Interestingly, viscosity of HAWP recovered from stratum 0.2 m. Until stratum 1.6 m, its viscosity recovered almost 50% of original. The data of intrinsic viscosity showed that the molecular chains of HAWP and HPAM were both degraded without any recovery. The contradiction was further studied by particle size and its microstructure. The mean particle size and particle size distribution data both showed HAWP recovered but HPAM was not. The microstructures of HAWP by atomic force microscopy images further explain the recovery of viscosity. The disassembled molecular chain was self‐assembled into aggregate to newly network by hydrophobes with weaker linking than original solution. While the microstructure of HPAM was thoroughly split up to randomly coil without linking. In addition, the viscoelasticity of HAWP was also recovered to some extent but HPAM was not. All the results proved that HAWP has mobility control ability to displace oil in reservoir even if suffered severely shearing by wellbore. © 2012 Wiley Periodicals, Inc. J. Appl. Polym. Sci., 2013     

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.