Surfactant–Polymer Flooding: Chemical Formula Design and Evaluation for High-Temperature and High-Salinity Qinghai Gasi Reservoir

Abstract

The Gasi reservoir in the Qinghai oilfield is a typical high-temperature and high-salinity reservoir, with an average temperature and average salinity of 70.0 °C and 152,144 mg/L, respectively. For over 30 years since 1990, water flooding has been the primary method for enhancing oil recovery. Recently, the Gasi reservoir has turned into a mature oilfield. It possesses a high water cut of 76% and a high total recovery rate of 47%. However, the main develo** enhanced oil recovery (EOR) technology for the development of the Gasi reservoir in the next stage is yet to be determined. Surfactant–polymer (SP) flooding, which can reduce the oil–water interfacial tension and increase the viscosity of the water phase, has been widely applied to low-temperature and low-salinity reservoirs across China in the past few decades, but it has rarely been applied to high-temperature and high-salinity reservoirs such as the Gasi reservoir. In this study, the feasibility of SP flooding for high-temperature and high-salinity reservoirs was established. Thanks to the novel surfactant and polymer products, an SP flooding formula with surfactants ZC-2/B2 and polymer BRH-325 was proposed for Gasi. The formula showed a low interfacial tension of 10⁻² mN/m and a high viscosity of 18 MPa·s in simulated reservoir conditions. The oil displacement experiment demonstrated that this formula can enhance the oil recovery rate by 26.95% upon water flooding at 64.64%. This study provides a feasible EOR candidate technology for high-temperature and high-salinity reservoirs, as exemplified by the Qinghai Gasi reservoir.

1. Introduction

The Gasi reservoir, located in Qinghai Province in western China, is a typical high-temperature and high-salinity reservoir. The temperature of the reservoir ranges from 60.8 °C to 78.7 °C, and its proportion of total dissolved solids (TDS) ranges from 151,000 to 170,000 mg/L [1]. The Gasi reservoir has experienced more than 30 years of water flooding, starting in 1990. At present, the reservoir has turned into a mature oilfield, with a comprehensive water cut of 76% and a recovery rate of 47% [2]. The water flooding can no longer serve the aim of oil recovery, and, therefore, develo** new technologies for the Gasi reservoir is an important research topic. Surfactant–polymer (SP) flooding is an enhanced oil recovery (EOR) technology [3,4] that has been successfully applied to conventional low-temperature (<70 °C), low-salinity (<10,000 mg/L) reservoirs [5,6,7], while its feasibility in high-temperature and high-salinity reservoirs, such as Gasi, has not been revealed [2]. The mechanism of SP flooding is reducing oil–water interfacial tension and increasing water phase viscosity. Because of the high-temperature and high-salinity characteristics of the Gasi reservoir, the conventional SP flooding formula cannot meet the technical requirements. Therefore, designing an SP flooding system specifically tailored for high-temperature and high-salinity environments is a crucial technical challenge. To improve the feasibility of SP flooding in the Gasi reservoir, this study proposed and evaluated a novel SP formula as a potential candidate for EOR.

There are many limits that make it difficult for conventional surfactants and polymers to be applied in high-temperature and high-salinity environments. Under high-temperature and high-salinity conditions, the currently prevalent sulfonate surfactants become precipitates with divalent ions (Ca²⁺, Mg²⁺) in water, and high TDS levels can also trigger phase separation phenomena [8]. Conventional polymers, such as partially hydrolyzed polyacrylamide (HPAM), undergo self-hydrolysis or degradation under high-temperature conditions [9]. The presence of divalent cations (Ca²⁺, Mg²⁺) further accelerates this decomposition process [10]. Monovalent cations (Na⁺, K⁺) present in brine can shield the electrostatic repulsion among the carboxylate charges along the HPAM chains, causing polymer chain coils to collapse [11].

Researchers have made some efforts in order to make polymers and surfactants available under high-temperature and high-salinity conditions. To solve the problem of surfactant precipitation, the selected surfactant needs to possess stronger hydrophilicity. In order to maintain the balance between hydrophilicity and lipophilicity, surfactants with stronger hydrophilic head groups require longer hydrophobic tail chains. Extended surfactants have been introduced as a solution to this issue [12]. These surfactants are characterized by the inclusion of intermediate polarity groups situated between the hydrophobic tail and the hydrophilic head group [13]. This unique molecular structure allows the surfactant molecules to extend more effectively into both oil and water phases, thereby enhancing their interfacial activity [14]. In particular, surfactants featuring alkoxy chains, such as EO and PO, have demonstrated improved tolerance to high-temperature and high-salinity environments, as evidenced by several laboratory studies and pilot tests [15,16,17]. Regarding polymers, research efforts have focused on increasing the viscosity of polymer solutions, which is primarily achieved by increasing the molecular weight of the polymers [18,19]. A higher molecular weight contributes to a larger hydrodynamic volume of polymer molecules, resulting in an elevated viscosity of the polymer solution. However, high-molecular-weight polymers can cause reservoir plugging or blocking, making it difficult to inject polymer solutions [20,21]. To develop a polymer suitable for high-temperature and high-salinity conditions with good injectivity, current research predominantly utilizes acrylamide as a foundational monomer and introduces functional monomers to increase viscosity under these challenging conditions [22]. In the study conducted by David B. et al. [23], acrylamide was used as the base monomer, and methylpropane sulfonic acid groups were introduced into the polymer chain. By replacing the carboxyl group with a hydrophilic group, the precipitation produced by the polymer and the divalent ion is reduced. In the study by Li et al. [24], large-volume side groups were introduced into the polymer chain using compounds containing N,N-dimethylformamide to increase the rigidity of the polymer chains, thereby enhancing their performance under high-temperature and high-salinity conditions. Based on the previous ideas, we designed a polymer constructed from acrylamide-based copolymers containing N,N-dimethylformamide and sulfonic acid groups. This study selected extended surfactants as well as acrylamide-based polymers containing N,N-dimethylformamide and sulfonic acid groups as the main research contents (Figure 1).

In this study, we conducted a comprehensive investigation on the screening and optimization of SP flooding formula specifically designed for the Gasi reservoir. Through a series of experiments, including viscosity tests, thermal stability tests, interfacial tension tests, emulsification stability tests, and oil displacement tests, we explored the efficacy of SP flooding methods in enhancing oil recovery in high-temperature and high-salinity reservoirs. The findings of this research provide a technical basis for the application of SP flooding in high-temperature and high-salinity reservoirs.

2. Materials and Methods

2.1. Materials

2.1.1. Polymer Samples

Polymers including HPAM-21, BRH-325, BRH-A, and BRH-D are shown in

Table 1. Characteristics of polymer samples.

Name	Component	Manufacturer
HPAM-21		RIPED (Bei**g, China)
BRH-325		RIPED (Bei**g, China)
BRH-A		RIPED (Bei**g, China)
BRH-D		RIPED (Bei**g, China)

. The component of the polymer was drawn using KingDraw software version 3.0.2 (KingDraw Business Corp., Qingdao, China).

2.1.2. Surfactant Samples

Surfactants including A3, B2, B3, and ZC-2 are shown in

Table 2. Characteristics of surfactant samples.

Surfactant	Component	Purity	Manufacturer
A3	C8-4PO-10EO Sulfate	C.P.	Changzhou Haohua Chemical Co., Ltd. (Changzhou, China)
B2	C10-4PO-5EO Sulfate	C.P.	Changzhou Haohua Chemical Co., Ltd. (Changzhou, China)
B3	C10-4PO-10EO Sulfate	C.P.	Changzhou Haohua Chemical Co., Ltd. (Changzhou, China)
ZC-2	Petroleum Sulfonate	40%	Qinghai Oilfield Company (Qinghai, China)

.

2.1.3. Oil Samples

The simulated oil used in the experiment was a mixture of kerosene and dehydrated crude oil provided by Qinghai Oilfield, which was intended to simulate the viscosity of crude oil under actual formation conditions. The simulated oil had a density of 0.825 g/cm³ and a viscosity of 6.5 MPa·s at 70 °C.

2.1.4. Core Samples

The porosity and water phase permeability were measured in a laboratory and simulated the permeability and porosity characteristics of the Gasi reservoir. The properties of the cores are shown in

Table 3. Characteristics of cores.

No.	Length (cm)	Diameter (cm)	Porosity (%)	Permeability (μm2)
1	9.899	2.495	26.116	94.6
2	9.980	2.504	27.373	96.0

.

2.1.5. Water

The water used in this study was simulated formation water, which simulated the salinity of the produced water from the Gasi reservoir. The properties of the simulated formation water are shown in

Table 4. Composition of simulated formation water for experiment.

Concentration (mg/L)					Total Salinity (mg/L)
Na+	Ca2+	Mg2+	Cl−	SO42−
56,908.8	912.5	248.9	86,856.5	5641.1	152,144

.

2.2. Experimental Methods

2.2.1. Viscosity Measurement

Viscosity measurements were performed with a Brookfield DV-2T digital viscometer, with a ULA0 rotor type, at a speed of 6 rpm. The polymer solution was heated to 70 °C to simulate the temperature of the Gasi reservoir. After the temperature was stabilized for 15 min, the viscosity of the sample was measured.

2.2.2. Long-Term Stability Measurement

The polymer solution was deoxygenated by nitrogen for 60 min, and the solution was put into several glass bottles. Then, the bottles were transferred to a vacuum box for secondary deoxygenation. The upper air of the glass bottle was removed, and the glass bottle was sealed and placed in a 78 °C oven. A bottle of polymer solution was taken out every 30 days for a viscosity test.

2.2.3. Interfacial Tension Measurement

The interfacial tension between the surfactant solution and crude oil was measured using a spinning-drop interfacial tensiometer (Model CNG701, Shengwei, Bei**g, China). The surfactant solution was injected into a glass tube as the outer phase, and about 2 μL of oil was injected into the glass tube as the inner phase. The internal diameter of the glass tube was 2 mm. All experiments were operated at a rotating velocity of 5000 r/min. The measurement results were recorded following a stabilization period of 2 h.

2.2.4. Emulsion Stability Measurement

In this experiment, 4 mL of n-alkanes and 4 mL of the surfactant solution (0.3 wt%) were added in a small glass vial. The mixture was then homogenized for 30 s at a speed of 13,000 r/min using a homogenizer. Subsequently, the homogenized mixture was transferred into a 10 mL test tube. The volume of each phase was recorded constantly over 30 days.

For the purpose of evaluation, the emulsification stability was characterized by the oil separation ratio [25], as follows:

$$f_o=\frac{V_1-V_2}{V_1}$$

$f_o$ indicates the oil separation ratio, %; $V_1$ is the initial volume of oil, mL; and $V_2$ is the volume of emulsified oil, mL.

2.2.5. Oil Displacement Measurement

The oil displacement experiment for the SP flooding system was designed according to the analytical method for the alkali–surfactant–polymer flooding system (Chinese standard SY/T 6424-2014) [26]. It had the following steps:

Saturation with water: The core was dried and saturated with simulated brine, and the pore volume was calculated using the gravimetric method. The saturation was performed at room temperature (25 °C).

Saturation with oil: The core was heated to the reservoir temperature of 70 °C for 24 h. Then, the oil was used to displaced the water at an injection rate of 0.1 mL/min until the oil content in the fluid was more than 98%. Then, the core was kept at the reservoir temperature of 70 °C for 48 h.

Water flooding: Simulated formation brine was used to displace the oil at an injection rate of 0.1 mL/min. Water flooding was stopped when the water content at the outlet reached 98%.

Chemical flooding: A chemical flooding slug of 0.5 PV was injected at an injection rate of 0.1 mL/min.

Subsequent waterflooding: Simulated formation water was used to displace the oil at an injection rate of 0.1 mL/min. Subsequent water flooding was stopped when the water content at the outlet reached 98%.

The temperature of the core displacement experiment was maintained at 70 °C. The injection rate was 0.1 mL/min, and an overburden pressure of 15 MPa was applied to prevent bypass. During the experiment, pressure, oil production, water production, and total fluid production were promptly recorded to accurately calculate the incremental oil production and water cut of chemical flooding.

3. Results and Discussion

3.1. Polymer Selection

3.1.1. Viscosity

The viscosity of several polymers was measured including partially hydrolyzed polyacrylamide HPAM-21, salt-resistant polymer BRH-325, BRH-A, and BRH-D. All polymers were dissolved with simulated formation water. The viscosity measurements were performed at reservoir temperatures.

The curves illustrated in Figure 2 show the variations in polymer viscosity with concentration. For all polymers, as expected, the viscosity increased with increasing concentration. At the concentration of 2000 mg/L, the viscosity of BRH-325 was higher than that of other polymers and was 58% higher than that of HPAM. Therefore, BRH-325 was selected as the polymer for the SP flooding formula. Based on the balance between performance and cost, the BRH-325 solution, at the concentration of 2000 mg/L, was selected as the polymer formula for subsequent research.

3.1.2. Long-Term Stability

For high-temperature and high-salinity reservoir conditions, long-term stability is a major parameter. In oilfield development, SP flooding agents were usually buried underground for months or even years. Polymers, as major components of the SP flooding formula, usually find it difficult to maintain viscosity over such a long period of time, especially under high-temperature and high-salinity conditions. Therefore, we developed a long-term stability test to evaluate whether the polymer can maintain its viscosity over time.

The experimental results showed that the viscosity of BRH-325 was 58% higher than that of HPAM after a 90-day long-term test, with the viscosity retention rate of BRH-325 at 81.1%, significantly better than that of HPAM with only 35.6%. This comparison showed the excellent performance of BRH-325 under high-temperature and high-salinity conditions, thereby confirming its suitability for applications under such conditions (Figure 3).

3.2. Surfactant Selection

3.2.1. Interfacial Tension

In this study, several types of surfactants were selected to evaluate the interfacial tension between a surfactant solution and crude oil. The concentration of surfactants was 0.3%, and the evaluated surfactants included petroleum sulfonate ZC-2 and extended surfactants B2, B3, and A3. In addition, these two types of surfactants formed ZC-2/B2, ZC-2/B3, and ZC-2/A3 at a ratio of 8:2.

The results showed that mixed surfactants exhibited an excellent ability to reduce interfacial tension, reaching a level of 10⁻² mN/m within the temperature range of 50 °C–90 °C. This indicated a synergistic effect between extended surfactants and petroleum sulfonates. Based on the interfacial tension, we determined that ZC-2/B2 should be used as the formula for subsequent research (Figure 4).

In the process of surfactant flooding, there is a considerable loss of surfactant due to retention in the cores [27], so we designed experiments to study the interfacial tension performance at different concentrations. In this study, the interfacial tension of surfactant ZC-2 and ZC-2/B2 at different concentrations was investigated. The results are presented in Figure 5.

The experimental results showed that, for ZC-2, in the concentration range of 0.05–0.3%, the interfacial tension can be maintained at 10⁻² mN/m only in temperature ranges below 70 °C. In contrast, ZC-2/B2 exhibited higher temperature tolerance, maintaining an interfacial tension of 10⁻² mN/m from 50 °C to 90 °C at the corresponding concentration. This surfactant formula has wider operating windows for both temperature and concentration, which enhances its applicability in a wider range of reservoirs, and it is thus of great significance to improving the efficiency and practicability of actual oil production.

3.2.2. Emulsion Stability Test

In addition to reducing interfacial tension, emulsification is also a crucial mechanism in the oil recovery process. Through effective emulsification, emulsifiers can mix the oil and water phases to form stable emulsions, making it easier to drive out crude oil. To fully understand the emulsification performance of surfactants, a series of experiments were designed and conducted.

Both curves shown in Figure 6 tracked the change in the oil separation ratio with time. In the system using ZC-2, the oil separation ratio reached 100% at the beginning, indicating that the emulsion quickly broke down after formation, thus showing that the ZC-2 system failed to establish a stable emulsion structure, which may be due to the limited inherent emulsifying ability of ZC-2. In contrast, the ZC-2/B2 surfactant showed better emulsion stability, forming an emulsion with an initial oil separation ratio of 1.4% on day 0. The oil separation ratio gradually increased to 30.99% by day 30. For B2, the oil separation ratio was 8.03% at day 30. These results showed that the B2 surfactant had the best emulsion stability, which verified the emulsifying properties of extended surfactants under high-temperature and high-salt conditions. B2, an extended surfactant with a unique structure, can be further extended into the oil phase and water phase. This effect leads to a higher interaction of the surfactant–water and surfactant–oil, resulting in higher emulsion stability [28]. The ZC-2/B2 surfactant improved its emulsifying properties by adding B2. Based on the balance between performance and cost, we chose ZC-2/B2 as the surfactant for SP formulation.

Figure 7 shows the effects of different surfactant concentrations on the emulsification performance of the system. It can be found that the oil separation ratio of the ZC-2 surfactant at all concentrations was 100%. The ZC-2/B2 surfactant system had an oil separation ratio of 40.83% within 30 days at the concentration of 0.2%, and the oil separation ratio at a concentration of 0.3% was 30%. The results showed that, compared with ZC-2 alone, the ZC-2/B2 formula demonstrated enhanced emulsion stability, especially at higher concentrations.

Figure 8 shows the oil separation ratios after 10 days under different salinity concentrations. In low-salinity concentrations, both ZC-2 and composite surfactant systems showed relatively low oil separation ratios, less than 10%. It is worth noting that when the salinity rose to 15%, there was a significant difference: the oil separation ratio of ZC-2 increased sharply to 93%, while the oil separation ratio of ZC-2/B2 was 8%. The turning point of the 15% salinity level was particularly related to the salinity of the Qinghai Oilfield. Under the condition of high salinity (>15 mg/L), the emulsification effect of the ZC-2/B2 system was obviously better than that of the ZC-2 system, which reflected the applicability of the ZC-/B2 system in high-salinity environments.

3.3. Polymer–Surfactant Compatibility Test

In reservoir development, it is very important to carefully consider the compatibility between polymers and surfactants when designing SP formulas. Surfactants can affect the viscosity of polymers, the addition of polymers will also affect the interfacial properties of surfactants, and the negative effects will reduce the efficiency of the EOR process. Therefore, in the formula design process, the compatibility of polymers and surfactants should be fully considered to ensure that the final formula does not experience performance loss. A compatibility experiment was designed in order to solve this problem. Figure 9 describes the interfacial tension test for the surfactant and the SP formula, while Figure 10 shows the viscosity test for the polymer and the SP formula.

The experimental results showed that the interfacial tension of the SP formula was lower than that of the ZC-2/B2 surfactant alone in the temperature range of 50–80 °C. In contrast to the ZC-2/B2 surfactant, the SP flooding formula decreased interfacial tension from 7 × 10⁻² mN/m to 1 × 10⁻² mN/m at 70 °C. In addition, the viscosity of the SP formulation was higher than that of the BRH-325 polymer throughout the entire temperature range. The viscosity of the SP flooding formula increased by 14% compared with that of the BRH-325 polymer at 70 °C. These findings confirmed the good compatibility between the surfactants and polymers used in this study and proved the feasibility of polymers and surfactants in the SP formula.

3.4. Oil Displacement Test

Core oil displacement experiments were conducted to assess the efficacy of the SP flooding formula. The dynamic oil recovery curves shown in Figure 11 and Figure 12 compare the performance of ZC-2 with that of the SP formula under simulated reservoir conditions. The red lines indicated the timing of chemical flooding injection and the timing of stop** injection. The experimental outcomes showed that ZC-2 demonstrated an 8.4% increase in recovery rate. In contrast, the SP oil displacement formula enhanced the recovery rate by 26.95%, thereby confirming its superior oil displacement capabilities. As expected, SP flooding had a higher oil recovery. The addition of polymer increased its viscosity under reservoir conditions, thus increasing the sweep efficiency of the displacement fluid and greatly improving the oil recovery. The heterogeneity of sandstone reservoirs highlighted the advantages of binary compound flooding. Therefore, compared with single-surfactant flooding, SP flooding showed significant advantages in enhancing oil recovery.

During the oil displacement experiment, we recorded the changes in injection pressure and back pressure with time. The changes in pressure during the oil displacement process of the ZC-2 and SP formulations is shown in Figure 13 and Figure 14, respectively. It can be seen that the pressure fluctuation of the ZC-2 formulation was small. After the chemical flooding slug injection, there was a slight pressure drop of about 0.5 MPa. The injection pressure after SP formulation injection increased by about 2.5 MPa. This verified the oil displacement mechanism of the surfactant and SP formula. The surfactant can reduce the oil–water interfacial tension, making it easier for oil to flow out of pores, thereby reducing the relative permeability of oil and resulting in a decrease in injection pressure. The polymer was added to the oil displacement process of the SP formula, which increased the viscosity of the water phase, expanded the sweep efficiency of the displacement fluid, and improved the recovery rate, causing the injection pressure to rise during the displacement process.

4. Conclusions

In this paper, an SP flooding formula comprising surfactant ZC-2/B2 and polymer BRH-325 was proposed for the high-temperature and high-salinity Gasi reservoir. ZC-2/B2 was formulated by combining extended surfactant B2 and petroleum sulfonate ZC-2. The interfacial tension between the ZC-2/B2 solution and oil was maintained at the level of 10⁻² mN/m at temperatures ranging from 50 °C to 90 °C and at a salinity level of 152,144 mg/L. Moreover, the emulsion formed by oil and the ZC-2/B2 solution exhibited an oil separation ratio of 30.99% after 30 days, demonstrating that the surfactant ZC-2/B2 was able to reduce interfacial tension and form stable emulsions in challenging reservoir environments. BRH-325 was selected as the polymer for the SP flooding formula due to its superior viscosity and long-term stability. At a concentration of 0.2%, the BRH-325 polymer solution achieved a viscosity of 18.13 MPa·s under simulated reservoir conditions, exceeding that of the partially hydrolyzed polyacrylamide HPAM-21 by 58%. Furthermore, BRH-325 demonstrated excellent long-term stability, maintaining a viscosity retention rate above 80% during a 90-day long-term stability test at 70 °C. The synergistic effects between the selected polymer and surfactant were evaluated. In contrast to the ZC-2/B2 surfactant, the SP flooding formula decreased interfacial tension from 7 × 10⁻² mN/m to 1 × 10⁻² mN/m, and the viscosity of the SP flooding formula increased by 14% compared with that of the BRH-325 polymer. The oil displacement experiment also verified that the SP flooding formula could improve the oil recovery rate by 26.95% upon water flooding at 64.64% in the simulated conditions of the Qinghai Gasi reservoir. The principle of SP flooding is verified by the pressure change in the displacement process. The oil displacement efficiency is improved by reducing the interfacial tension, and the sweep efficiency is increased by increasing the viscosity of the displacement fluid. The results of this study confirm that SP flooding is a viable and promising technology for the EOR process in high-temperature and high-salinity reservoirs, such as the Qinghai Gasi reservoir.