## 1 Introduction  
Heavy oil resources are abundant and widely distributed in the United States, Canada, Venezuela, Russia and China. Due to the high viscosity of heavy oil, water flooding is not a good way to develop heavy oil resources. The main methods include steam flooding, steam huff and puff and steam-assisted gravity drainage (SAGD). Many researchers have shown that thermal recovery is not advisable in deep heavy oil reservoirs. This is due to serious heat loss from formation and the wellbore, the low dryness of steam injection, the limited heating range and the poor development effect [1; 2; 3; 4]. For deep heavy oil reservoirs, other methods need to be considered [5; 6; 7]. Polymer flooding is one chemical EOR method used to improve macroscopic oil sweep efficiency and hinder the fingering phenomena that occur due to highly permeable regions and the water cut [8; 9; 10]. At present, polymer flooding has achieved good development results in many heavy oil blocks, such as Pelican Lake [11; 12], Mooney, Seal [13], Marmul [14; 15; 16], Bohai [17] and Medicine Hat [18]. The viscosity of the underground crude oil in the experimental area of the Pelican Lake oilfield is 1200-1800 mPa s. Since polymer flooding was implemented in 2005, the oil recovery in the experimental block has increased by 20% [11; 12]. In 1956, Marmul oilfield was discovered in the south of Oman. The viscosity of crude oil is 80-110 mPa-s, and polymer flooding has achieved good development results. The oil recovery following polymer flooding is 46% [14; 15; 16]. The average viscosity of crude oil in Bohai oilfield is 70 mPa\(\cdot\)s. After the success of a test, polymer flooding was carried out with four injection and six production methods in 2005. The water cut decreased by 10% after polymer flooding, and the crude oil production per well increased by 1.77 \(\times\) 10\({}^{4}\) m\({}^{3}\)[17]. Thus, it can be seen that polymer flooding can effectively enhance oil recovery in heavy oil reservoirs. Hydrolyzed polyacrylamide (HPAM) has been used for the most oilfield projects because of its low cost and great viscoelasticity. It can increase the viscosity of the displacing phase while reducing the water/oil mobility ratio so as to enlarge the swept volume [19; 20; 21]. However, the hydrolysis reaction of HPAM is very rapid, and its stability is poor in high-temperature and high-salinity reservoirs. The carboxyl group produced by hydrolysis is easy to precipitate with large amounts of Ca\({}^{2+}\) and Mg\({}^{2+}\), which destroys the formation conditions and reduces the temperature resistance and salinity tolerance of the polymer; thus, it cannot meet the requirements of high-temperature and high-salinity reservoirs [22; 23; 24; 25; 26; 27]. In order to improve the properties of HPAM, much research has been undertaken on changing the chemical structure of HPAM in the process of polymer flooding [24; 25; 26; 27; 28]. Researchers have mainly focused on replacing various AM moieties in the main chain. The properties of the copolymers can be optimized by adding different functional groups to HPAM to obtain better stability. Polymers containing sulfonate groups are expected to offer higher stability in solution and are tolerant to high salinity [29]. In 1986, Evani first proposed the concept of hydrophobically associating water-solute polymer (HAWPs), and they were successfully synthesized through the association of hydrophobic groups in aqueous solution. HAWP is a functional polymer polymerized by two types of monomers, hydrophilic and hydrophobic, under the action of the initiator and the temperature [30]. Due to the hydrophobic groups, there are intramolecular and intermolecular associations in the aqueous solution system. At a certain polymer concentration, similarly to the micelles formed by surfactants above their critical micelle concentration, the hydrophobic groups in these polymers aggregate through intermolecular hydrophobic interaction and tend to associate in aqueous solution [31].