This paper presents the viscosifying and oil recovery efficiencies of a novel high-molecular-weight ternary polyampholyte (TPA), composed of 80 mol.% acrylamide (AAm) (a nonionic monomer), 10 mol.% 2-acrylamido-2-methyl-1-propanesulfonic acid sodium salt (AMPS) (an anionic monomer), and 10 mol.% (3-acrylamidopropyl) trimethylammonium chloride (APTAC) (a cationic monomer), in various high-salinity brines as compared to the efficiency of hydrolyzed poly(acrylamide) (HPAM), which is the most commonly used polymer in oil production. The results show that, in a range of salinity from 200 to 300 g∙L⁻¹, the viscosity of the TPA solution is rather high and relatively stable, whereas that of HPAM severely decreases. The ability of TPA to increase its viscosity in extremely high salinity brines is explained by the antipolyelectrolyte effect, resulting in the unfolding of macromolecular chains of charge-balanced polyampholytes at a quasi-neutral state, which occurs due to the screening of the electrostatic attraction between oppositely charged moieties. The novelty of this research is that, in high-salinity reservoirs, the amphoteric terpolymer Aam-AMPS-APTAC may surpass HPAM in oil displacement capability.

In our previous papers [1, 2] we considered the behavior of linear and crosslinked polyampholytes based on fully charged anionic monomer — 2-acrylamido-2-methyl-1-propanesulfonic acid sodium salt (AMPS) and cationic monomer — (3-acrylamidopropyl)trimethylammonium chloride (APTAC) in aqueous-salt solutions, swelling and mechanical properties. In the present paper we report the applicability of salt tolerant amphoter-ic terpolymers composed of AMPS, APTAC and acrylamide (AAm) in enhanced oil recovery (EOR). The amphoteric terpolymers of different compositions, particularly [AAm]:[AMPS]:[APTAC] = 50:25:25; 60:20:20; 70:15:15; 80:10:10 and 90:5:5 mol.% were prepared by free-radical polymerization, identified and their viscosifying ability with respect to reservoir saline water (salinity is 163 g⋅L-1) at 60 °C was tested. It was found that due to polyampholytic nature, the AAm-AMPS-APTAC terpolymers exhibited improved viscosifying behavior at high salinity water. As a result, the appropriate salt tolerant sample [AAm]:[AMPS]:[APTAC] = 80:10:10 mol.% was selected for polymer flooding experiments. Polymer flood-ing experiments on high permeable sand pack model demonstrated that only 0.5 % oil was recovered by am-photeric terpolymer. While injection of polyampholyte solution into preliminarily water flooded core sample resulted in the increase of oil recovery up to 4.8–5 %. These results show that under certain conditions the amphoteric terpolymers have a decent oil displacement ability.

High molecular weight amphoteric terpolymer based on a nonionic monomer, acrylamide (AAm), an anionic monomer, 2-acrylamido-2-methyl-1-propanesulfonic acid sodium salt (AMPS), and a cationic monomer, (3-acrylamidopropyl) trimethylammonium chloride (APTAC), was prepared using free-radical copolymerization in an aqueous solution and characterized by ¹H NMR, FTIR, GPC, DLS, zeta potential and viscometry. The polymer was shown to be viscosifying, and therefore can be utilized as a polymer flooding agent in the high salinity and temperature conditions of oil reservoirs. Injection of 0.25 wt.% of amphoteric terpolymer, dissolved in 200-300 g∙L^-1 brine, into high and low permeability sand pack models demonstrated that the oil recovery factor (ORF) increases by up to 23-28% in comparison with saline water flooding. This is explained by an increase in the viscosity of brine solution due to disruption of intra- and interionic contacts between oppositely charged AMPS and APTAC moieties, demonstrating the antipolyelectrolyte effect. In high saline water, the anions and cations of salts screen the electrostatic attraction between positively and negatively charged macroions, resulting in expansion of the macromolecule. This phenomenon leads to an increase in the viscosifying effect on the brine solution, thus decreasing the mobility factor (M), which is defined as the ratio of displacing phase mobility (water) to displaced phase mobility (oil).

The viscosity and the oil recovery ability of high molecular weight amphoteric terpolymer (ATP) were tested in different brines and compared with hydrolyzed poly(acrylamide) (HPAM) which is traditionally used in enhanced oil recovery (EOR). The results show that ATP provides higher viscosity at brine salinity ranging from 200 to 300 g∙L-1. This may give ATP an advantage over HPAM in high salinity reservoirs, which are abundant in Kazakhstan. Moreover, comparative polymer flooding experiments were carried out by injecting 0.25 wt.% ATP and HPAМ dissolved in 200 g∙L-1 brine into sand packs. The HPAМ flooding in high perme-ability (1.77 Darcy) sand pack leads to the increase of the oil recovery factor (ORF) by 18.5 % after 1 PV of brine injection. On the other hand, the injection of ATP into the low permeability (0.6 Darcy) sand pack re-sults in the ORF increase by 28.5 %. The obtained results show that ATP has the potential to become an al-ternative to HPAM in 200 g∙L-1 and higher brine salinity reservoirs.

Background: Due to its high efficiency, polymer flooding has been widely used in the fields of Kazakhstan. However, under conditions of high water salinity, high concentrations of polymers are needed to ensure the design viscosity of the solutions, therefore, polymers are needed that, at concentrations not exceeding 0.10.2%, will increase the viscosity of water up to 2050 cP when the formation water salinity is above 200 g/ l. Aim: The purpose of this work is to study the salt- and heat-resistant properties of a linear polyampholyte based on acrylamide, an anionic monomer sodium salt of 2-acrylamido-2-methyl-1-propanesulfonic acid - and a cationic monomer (3-acrylamidopropyl) trimethylammonium chloride and substantiate its applicability in oil production. Materials and methods: We used water with a salinity of 200300 g/l, as well as oils with viscosities of 60, 138, and 420 cP. To simulate a porous medium, bulk sand models and aerated concrete with high porosity were chosen. Hydrolyzed polyacrylamide with a molecular weight of 17 million Da and a ternary polyampholyte with a molecular weight of 2.9 million Da were used as polymers. To compare the effectiveness of these polymers under conditions of high salinity, experiments were carried out to measure the dynamic viscosity and oil displacement efficiency. Results: It is shown that the injection of a 0.25% solution of triple polyampholyte dissolved in water with a salinity of 200 g/l into sand models increases the oil displacement efficiency by 2328% compared to the injection of formation water. Under identical conditions, the injection of a hydrolyzed polyacrylamide solution resulted in an increase in the oil displacement efficiency by only 18%. Conclusion: Triple polyampholyte based on acrylamide derivatives has superior oil displacement properties compared to hydrolyzed polyacrylamide in high salinity reservoirs. The results of laboratory experiments can draw the attention of oil and gas industry specialists and subsoil users to new developments by the staff of the Institute of Polymer Materials and Technologies in terms of scaling up synthetic polyampholytes and conducting pilot tests.