Study on CO₂ Corrosion Behavior of Underground Gas Storage Pipe Columns and Establishment of Corrosion Inhibition System

Abstract

Herein, we take an underground natural gas storage in the Ordos Basin as an example to explore the influence of temperature, CO₂ flow rate, CO₂ partial pressure, and chloride ion concentration on the corrosion rate of N80 and P110 steels in CaCl₂ brine type. Meanwhile, in order to reduce the amount of chemical corrosion inhibitors and improve performance, a novel corrosion inhibitor with a quinoline quaternary ammonium structure named YS-QB was synthesized from 1-methyl-1,2,3,4-tetrahydroisoquinoline, epichlorohydrin, and oleic acid amide propyl dimethylamine. Under normal and high-pressure environments, YS-QB exhibits a superior corrosion inhibition effect to the market product of CX-1. In order to further reduce the amount of corrosion inhibitor and improve the corrosion inhibition effect, orthogonal experiments were conducted to optimize the formula system, and the optimal composite system was finally obtained by forming YS-QB, propargyl alcohol, hexamethylenetetramine, and isopropanol in a mass ratio of 12:1:1:2. At 80 °C, a dosage of 30 mg/L can suppress the CO₂ corrosion rate below 0.076 mm/a, while a dosage of 60 mg/L can suppress the CO₂ corrosion rate below 0.076 mm/a at a high-pressure environment of 120 °C. Combining weightlessness and electrochemical experiments, it is found that the composite corrosion inhibitor performs best when the dosage reached 100 mg/L, and a further increase in the dosage weakens the corrosion inhibition capacity. Based on the polarization curve changes with the dosage of the composite corrosion inhibitor, it can be determined that the final obtained composite corrosion inhibitor system was a cathodic corrosion inhibitor.

1. Introduction

With the rapid development of the economy, residents’ demand for natural gas has been increasing year by year. At the same time, due to regional differences in natural gas supply, underground natural gas storage facilities, serving as a regulating hub for weather resources and used for strategic reserves, are of great significance. Their construction can alleviate the contradiction between natural gas supply and demand and regulate imbalanced supply [1,2,3,4]. Currently, most underground natural gas storage facilities are converted from depleted oil and gas reservoirs. The injected gas sources contain acidic CO₂, with a concentration ranging from approximately 1.89% to 2.18%, which can easily cause CO₂ corrosion of the pipeline strings [5,6,7]. Approximately 25% to 75% of the volume of the underground gas storage capacity is utilized as cushion gas [7,8], which provides pressure for gas extraction and inhibits water flow. CO₂ in a supercritical state, with its dual characteristics of compressibility and high viscosity, serves as a suitable choice for cushion gas in underground gas storage [9,10,11].

The aforementioned circumstances indicate that the primary threat to the safety of underground natural gas storage facilities stems from corrosion caused by the acidic gas CO₂. Taking a gas storage facility in the Ordos Basin as an illustration, the production tubing strings predominantly consist of N80 and P110 materials. Additionally, the formation water predominantly belongs to the CaCl₂ water type, characterized by a relatively high chloride ion concentration. Furthermore, the relatively high CO₂ content in the gas renders the injection and production tubing strings susceptible to corrosion [12,13,14,15]. In comparison with conventional oil and gas wells, gas storage injection and production wells exhibit a distinct feature of “intensive production and injection”, thereby subjecting the injection and production tubing to an alternating load service environment. Simultaneously, acidic associated gas CO₂ and formation water have the potential to corrode the tubing, while excessive gas flow rates during gas production or injection can also erode the tubing. Under the combined influence of various factors, the operational environment of the injection and production tubing is exceedingly harsh, increasing the likelihood of failures such as perforation, rupture, and fracture due to corrosion, ultimately leading to natural gas leakage [16,17,18]. Nevertheless, the safe construction and operation of underground natural gas storage facilities constitute the prerequisite for their development. Mitigating the corrosion of CO₂ on injection and production tubing strings emerges as one of the pivotal tasks in the construction of underground storage facilities. Given the flammable and explosive nature of natural gas, corrosion and leakage of its injection and production tubing can readily trigger severe accidents. Publicly reported incidents of underground natural gas storage accidents, both domestically and internationally, have demonstrated the significant casualties and economic losses they can cause [17,18].

To prevent safety accidents due to corrosion of injection and production pipe columns in underground gas storage, a straightforward yet effective approach remains the establishment of an efficient chemical corrosion inhibitor system. Currently, the oilfield chemical market offers a variety of corrosion inhibitors, with the most classic being the imidazoline-type CO₂ corrosion inhibitor [19,20,21]. The imidazoline-type CO₂ corrosion inhibitor can also be applied in the reservoir stimulation operations such as matrix acidizing and acid fracturing [22,23]. Its field application has proven effective in suppressing corrosion of injection and production tubing, yet there remains considerable potential for enhancing both dosage efficiency and corrosion inhibition effectiveness. This article will concentrate on a specific gas storage facility located in the Ordos Basin, simulating its formation water and stratum environments to investigate the corrosion patterns of N80 and P110 steels under varying conditions, including temperature, CO₂ flow rate, CO₂ partial pressure, and chloride ion concentration. The CO₂ mole ratio in the nature gas of the specific gas storage facility ranges from 0% to 2%, and the pipe pressure is around 20 MPa. The temperature of shallow storage ranges from 55 °C to 80 °C, while that of the deep storage may range from 115 °C to 125 °C. Simultaneously, a novel quinoline quaternary ammonium salt corrosion inhibitor has been designed and synthesized to bolster the inhibitor’s efficacy as a single agent. An optimal composite corrosion inhibition system has been formulated by combining propargyl alcohol, hexamethylenetetramine, and isopropanol, aiming to minimize the inhibitor’s single-agent usage while elevating its corrosion inhibition efficiency.

2. Experiment Part

2.1. Materials

N80 and P110 corrosion coupons used to conduct weight loss experiments, with dimensions of 50 mm × 10 mm × 3 mm, were purchased from Jingdong Industry. Isopropanol, ethyl acetate, and epichlorohydrin of analytical purity were purchased from Chengdu Cologne Chemical Reagent Co., Ltd. (Chengdu, China), and used for the synthesis of corrosion inhibitors. 1-Methyl-1,2,3,4-tetrahydroisoquinoline and oleic acid amide propyl dimethylamine of analytical purity were respectively obtained from Shanghai McLean Biochemical Technology Co., Ltd. (Shanghai, China), and Shanghai Winsono New Materials Co., Ltd. (Shanghai, China), and they both are main materials for the synthesis of corrosion inhibitors. Sodium chloride, potassium chloride, calcium chloride, and magnesium chloride of analytical purity were obtained from Chengdu Cologne Chemical Reagent Co., Ltd., and were used to prepare simulated brines by referring to

Table 1. Water quality of two types of formation water samples from a gas storage facility in Ordos.

Brine Sample	Ion Concentration (mg/L)				Water Type	Mineralization (mg/L)
	K+, Na+	Ca2+	Mg2+	Cl−
#1	986	9289	5987	20,213	CaCl2	36,475
#2	1931	3532	1621	10,863	CaCl2	17,947

. Corrosion inhibitor CX-1 of industrial grade was obtained from the oilfield chemical market to conduct the comparative experiment.

2.2. Methods

2.2.1. Atmospheric Weight Loss Method

Atmospheric weight loss method was used to evaluate the corrosion rate of steel coupons under atmospheric pressure; then, the corrosion behaviors and corrosion inhibitor performance can be primarily assessed. Before the experiment, the steel coupons were cleaned, dehydrated, degreased, and dried in sequence. They were precisely weighed using an electronic balance, and three parallel samples were taken as one group. An amount of 700 mL of corrosive solution was poured into a 1000 mL wild-mouth bottle, and the test coupons were suspended in the solutions; then, the bottles were sealed. High-purity N₂ was used to remove oxygen in the wide-mouthed bottles for 1 h. The bottles were heated to the set temperature, and CO₂ gas at a certain flow rate was injected for a test period of 72 h. After the experiment, the test piece was treated with acid washing solution to remove corrosion products. Then, the test coupons were dehydrated, degreased, and dried, and then weighed to calculate the average weight loss, corrosion rate, and corrosion inhibition rate. The calculation formulas for corrosion rate and corrosion inhibition rate are shown in Equations (1) and (2):

$$V={\displaystyle \frac{8.75\times {10}^4\times \Delta W}{\rho \times s\times t}}$$

(1)

$$\eta ={\displaystyle \frac{V_0-V}{V_0}}$$

(2)

Among them, ΔW is the average weight loss of the sample before and after corrosion, g; ρ is the density of the steel coupon, g/cm³; t is the corrosion time, h; V₀ and V are the corrosion rates before and after adding the corrosion inhibitor, mm/a.

Referring to the industry standard “Recommended Indicators and Analysis Methods for Water Quality of Clastic Rock Reservoir Injection” (SY/T5329-2012) [24], the corrosion rate of 0.076 mm/a is used as the judgment standard. Exceeding this value does not meet the engineering requirements.

2.2.2. Pressurized Weight Loss Method

A high-temperature and high-pressure reactor was used to conducted pressurized weight loss so as to simulate the real environment in downhole conditions, which is pressurized with N₂ gas. The CO₂ valve was adjusted to control the partial pressure of CO₂. The test period was 72 h. After the experiment, the corrosion rate and corrosion inhibition rate were calculated using Formulas (1) and (2).

2.2.3. Electrochemical Test

An electrochemical test was conducted to obtain the Nyquist plot and polarization curve under different corrosion inhibitor dosages in order to analyze the corrosion type of CO₂ and effect of corrosion inhibitor dosage on performance. A Reference 3000 electrochemical workstation (Gamry, Warminster, PA, USA) was used to evaluate the efficiency of corrosion inhibitors and explore their mechanism of action, and a classic three-electrode system was employed. Electrochemical impedance testing was conducted by soaking in corrosive media with and without corrosion inhibitors for 1 h, and the inhibitors were evaluated based on the electrochemical Nyquist plot and polarization curve.

2.2.4. Synthesis of Corrosion Inhibitors

A ring-opening reaction of epichlorohydrin [25,26] was conducted to obtain the intermediate through the reaction of epichlorohydrin and 1-methyl-1,2,3,4-tetrahydroisoquinoline. Then, the quaternization reaction of chlorine and tertiary amine was conducted to obtain the target product of YS-QB.

A total of 200 mL of isopropanol was poured into a 500 mL flask, and 14.7 g of 1-methyl-1,2,3,4-tetrahydroisoquinoline and 9.25 g of epichlorohydrin were dissolved in isopropanol. Then, the flask was moved in an oil bath at 52 °C, with magnetic stirring and reflux for 5 h. After the reaction, the isopropanol solution of the intermediate was obtained, and the reaction process is described in Scheme 1.

Subsequently, 36.6 g of oleic acid amide propyl dimethylamine was dissolved in 100 mL of isopropanol, and the solution was poured into the flask and mixed with the intermediate. The flask was placed in an 80 °C oil bath, stirred with a magnetic stirrer, and refluxed for 12 h. After the reaction, the isopropanol was removed by vacuum rotary evaporation, and the reaction process is described in Scheme 2. The crude product obtained after rotary evaporation was recrystallized 2–3 times with ethyl acetate to obtain a pure product.

2.2.5. Molecular Structure Characterization

A Bruker AVANCE III HD 400 NMR spectrometer (Bruker, Fällanden, Switzerland) was used to analyze the ¹H NMR spectrum of the molecular structure. A Nicolet 6700 Fourier transform infrared spectrometer (Thermo Scientific, Waltham, MA, USA) was used to test the Fourier transform infrared spectra of the molecular structure, and the KBr pellet method was used to prepare samples.

3. Results and Discussion

3.1. Study on the Corrosion Behavior of N80 and P110 Steels in CO₂ Environment

3.1.1. Effect of Temperature on Corrosion of N80 and P110 Steels

(1)

Under atmospheric pressure

Under normal pressure, N80 and P110 coupons were immersed in simulated formation brine #1 and #2, respectively, and CO₂ was injected into a wild-mouth bottle at a flow rate of 2 mL/min. Static corrosion rates were tested at 20 °C, 40 °C, 60 °C, 80 °C, and 95 °C. The test results are shown in Figure 1. Under normal pressure conditions, it was observed that the corrosion rate of N80 and P110 coupons increased slightly within the temperature range from 20 °C to 60 °C under various conditions. However, when the temperature exceeded 60 °C, both N80 and P110 steel coupons exhibited a significant increase in CO₂ corrosion rate in different simulated formation brines. The corrosion rate of coupons in #1 simulated formation brine was notably higher than that in #2 simulated formation brine. This is attributed to the significantly higher concentration of chloride ions in #1 simulated formation bine sample, which can enhance the CO₂ corrosion rate to some extent.

Additionally, due to the slightly higher non-metallic content in P110 material, the overall CO₂ corrosion rate of P110 steel coupons is higher than that of N80 steel coupons. This is because CO₂ corrosion conforms to the electrochemical corrosion mechanism. In addition, non-metallic elements in iron (such as carbon, silicon, etc.) can form impurity phases, and there is a potential difference between these impurity phases and the iron matrix, which forms the primary battery and leads to electrochemical corrosion. In aqueous environments, these impurity phases act as anodes and the iron matrix acts as a cathode, forming primary cell reactions that accelerate the corrosion rate of iron. Referring to the industry standard “Recommended Indicators and Analysis Methods for Water Quality of Clastic Rock Reservoir Injection” (SY/T5329-2012) [24], P110 steel has a corrosion rate higher than 0.076 mm/a when the temperature reaches 40 °C in the two high-salinity simulated brine samples under normal pressure, which does not meet industrial requirements. Under the same conditions, the corrosion rates of P110 in #1 brine and #2 brine are 0.101 mm/a and 0.087 mm/a, respectively, and the corrosion rates of N80 materials also start to exceed 0.076 mm/a at 60 °C, which means the corrosion rates of both N80 and P110 materials do not meet industrial requirements when the temperature is greater than or equal to 60 °C.

(2)

Under high temperature and high pressure

To further explore the corrosion rate of CO₂ on pipe steel in high-temperature environments, this study employed a high-pressure reactor to assess the CO₂ corrosion rate of N80 and P110 steel coupons within the temperature range of 110 °C to 160 °C. The CO₂ partial pressure was maintained at 0.2 MPa, and the test results are depicted in Figure 2. As the temperature increases, the corrosion rate of N80 and P110 steel coupons rises significantly more than that observed under normal pressure conditions. Due to their non-metallic content, the corrosion rate of P110 steel coupons exceeds that of N80 steel coupons under identical conditions. Additionally, the high chloride ion concentration in simulated formation brine #1 results in a higher corrosion rate for steel coupons immersed in it, compared with those in simulated formation brine #2. Regardless of the steel material, whether N80 or P110, when the temperature is 110 °C or higher and the CO₂ partial pressure is 0.2 MPa, the CO₂ corrosion rate in both simulated formation brines significantly exceeds the industry standard (SY/T5329-2012) of 0.076 mm/a [24]. Therefore, the establishment of a CO₂ corrosion inhibition system under high temperature and high pressure is necessary for the safety of underground natural gas storage.

3.1.2. Effect of CO₂ Flow Rate and Partial Pressure on Steel Corrosion

(1)

Effect of CO₂ flow rate on steel corrosion

Under normal pressure at 60 °C, the corrosion rates of N80 and P110 steel coupons were tested under various CO₂ flow rates, with the results illustrated in Figure 3. Overall, the increase amplitude in corrosion rates of N80 and P110 steel coupons in two simulated formation brines decreases with the increase in CO₂ flow rate, eventually stabilizing. This is attributed to the limited solubility of CO₂ in water under normal pressure, with the dissolution of CO₂ maintaining a dynamic equilibrium with the corrosion of the steel coupon surface by carbonic acid. The corrosion rate of P110 in both simulated formation brines is higher than that of N80. At a CO₂ flow rate of 1 mL/min, its corrosion rate approaches 0.076 mm/a, reaching 0.075 mm/a and 0.069 mm/a, respectively. Additionally, the corrosion rate of steel coupons in simulated formation brine #1 is notably higher than that in simulated formation brine #2, highlighting that a higher chloride ion concentration promotes metal surface corrosion at any CO₂ flow rate.

(2)

Effect of CO₂ partial pressure on steel corrosion

Under pressurized conditions, the impact of CO₂ partial pressure at 120 °C on the corrosion rate of steel coupons in two simulated formation brines was tested. Considering that the pressure in pipe columns ranges from 10 to 30 MPa and the nature gas compression factor (Z) is around 0.98 under 120 °C, CO₂ partial pressure can be calculated through Formula (3) according to Dalton’s law of partial pressure, and the CO₂ partial pressure ranges from 0.2 MPa to 0.6 MPa as the mole ratio of CO₂ in nature gas is 2%:

$$P_{{\mathrm{CO}}_2}=P\times Z\times X_{{\mathrm{CO}}_2}$$

(3)

Among them, P_CO2 is the partial pressure of CO₂, MPa; P is the total pressure of gas, MPa; X_CO2 is the mole ratio of CO₂.

The CO₂ partial pressure ranged from 0.2 MPa to 0.6 MPa under 120 °C, and the test results are illustrated in Figure 4. The results indicate that the corrosion rate of steel coupons in simulated formation brine #1 is higher than that in simulated formation brine #2. Overall, as the CO₂ partial pressure increases, the rate of corrosion rises more significantly. This is attributed to the fact that a higher CO₂ partial pressure facilitates the dissolution of CO₂ in water, thereby intensifying the corrosion of metal surfaces.

3.1.3. The Influence of Chloride Ion Concentration on the Corrosion of Steels

By controlling the dosage of sodium chloride and the concentration of chloride ions, the influence of chloride ion concentration on the corrosion rate of N80 and P110 steel under normal and high-pressure environments was investigated. The influence of chloride ion concentration on the corrosion rate of steel coupons under normal pressure and a 60 °C environment with CO₂ flow rate controlled at 2 mL/min is shown in Figure 5. During the process of increasing the chloride ion concentration from 2000 mg/L to 10,000 mg/L, the corrosion rate of steel coupons increased significantly. When the chloride ion concentration exceeded 10,000 mg/L, as the chloride ion concentration further increased, the increase amplitude in corrosion rate of steel coupons decreased and then the corrosion rate began to decline. When the Cl⁻ concentration is low, the conductivity of the solution gradually increases with its concentration, promoting charge transfer. At the same time, Cl⁻ hydrolyzes with Fe²⁺ to form a complex, promoting the activation and dissolution of the metal anode. As the Cl⁻ concentration gradually increases, the amount adsorbed on the metal surface gradually increases, partially replacing the depolarizing agents such as H⁺ and HCO₃⁻ adsorbed on the metal surface. Especially when the Cl⁻ concentration is high, it will excessively occupy the cathode active sites on the metal surface, suppress the cathode reaction, and thus reduce the corrosion rate [12].

Under the condition of a high pressure of 120 °C and CO₂ partial pressure of 0.5 MPa, the effect of chloride ion concentration on corrosion rate was tested, as shown in Figure 6. The overall pattern is consistent with that under normal pressure; that is, the corrosion rate first increases and then decreases with the increase in chloride ion concentration.

3.2. Molecular Structural Characterization

The structure of YS-QB was characterized by the FT-IR and ¹HMR spectrum. Figure 7 exhibits the FT-IR spectrum of YS-QB. The peaks at 485.3 cm⁻¹, 623.2 cm⁻¹, 725.3 cm⁻¹, 852.2 cm⁻¹, 886.2 cm⁻¹, and 956.8 cm⁻¹ correspond to the bending vibration absorption on the quinoline structure. The peaks at 2912.1 cm⁻¹, 2852.5 cm⁻¹, and 2731.6 cm⁻¹ correspond to the stretch vibration absorption associated with C-H, -CH₃, and -CH₂-. The absorption peaks caused by the amide N-H stretching and bending vibrations are at 3443.3 cm⁻¹ and 1548.3 cm⁻¹. The absorption peaks at 3559.6 cm⁻¹ and 1319.3 cm⁻¹ are caused by the -OH stretching and bending vibrations. The absorption peak at 1589.2 cm⁻¹ corresponds to the stretching vibration peak of C=O on amide.

Figure 8 shows the ¹H NMR spectrum of YS-QB. The chemical shift and peak area integral value: (a) 0.858 (t, 3H, CH₃CH₂), (b) 1.331 (m, 2OH, CH₃(CH₂)₆CH₂CH=CHCH₂(CH₂)₈), (c) 1.587 (s, 2H, CH₂CH₂C=O), (d) 1.98 (m, 6H, CH₂CH=CHCH₂, CH₂CONH), (e) 2.19 (s, 2H, CH₂CH₂NH), (f) 2.28 (m, 3H, CH₃CH), (g) 2.88 (s, 2H, CCH₂CH₂), (h) 3.10 (t, 2H, CH₂NCH), (i) 3.23 (s, 6H, 2N+CH₃), (j) 3.39 (s, 2H, CH₂CH₂N+), (k) 3.67 (s, 2H, CH₂NHCO), (l) 3.83 (s, 4H, CH₂CHOHCH₂), (m) 4.18 (s, 2H, CH₂CHOHCH₂, CCHN), (n) 4.31 (s, 1H, CH₂CHOHCH₂), (o) 5.31 (s, 2H, CH=CH), (p) 6.60 (s, 2H, 2CHCHC), (q) 7.78 (s, 2H, CHCHCHCH), (r) 8.03 (br, 1H, CONH).

3.3. Establishment of Composite Corrosion Inhibition System

3.3.1. Performance of Single Corrosion Inhibitors

The performance of the synthesized quinoline quaternary ammonium structure corrosion inhibitor YS-QB and that of the imidazoline corrosion inhibitor CX-1 purchased from the oilfield chemical market were compared by testing corrosion rate. The comparative results of different single agents tested under atmospheric pressure of 80 °C and CO₂ flow rate of 2 mL/min are shown in Figure 9. Overall, when the dosage of a single agent is within the range of 20 mg/L to 60 mg/L, the decrease amplitude in steel corrosion rate and the increase amplitude in corrosion inhibition rate are significant with increasing dosage. Within the range of 60 mg/L to 100 mg/L, the decrease amplitude in steel corrosion rate and the increase in corrosion inhibition rate are relatively gentle as the dosage increases. When the dosage is increased to 120 mg/L, the corrosion rate of the steel coupon increases, indicating a deterioration in the corrosion inhibition effect. At the same time, in order to meet the industry standard (SY/T5329-2012) [24] for a corrosion rate of less than 0.076 mm/a under an atmospheric pressure of 80 °C, the amount of CX-1 purchased in the market needs to reach 60 mg/L. However, the quinoline quaternary ammonium salt structure (YS-QB) synthesized in this article only requires 40 mg/L to achieve a corrosion rate of less than 0.076 mm/a for two types of steel coupons.

Under a high pressure of 120 °C, the effect of two single-agent dosages on corrosion rate is basically consistent with that under normal pressure, and the results are shown in Figure 10. However, if the corrosion rate meets the industry standard (SY/T5329-2012) [24] (less than 0.076 mm/a), the dosage of CX-1 in the market product needs to be 100 mg/L, while the dosage of YS-QB, a quinoline quaternary ammonium salt corrosion inhibitor, needs to be 80 mg/L. The synergistic effect of the quinoline structure, quaternary ammonium salt structure, and oleic acid hydrophobic chain endows the YS-QB corrosion inhibitor with good single-agent corrosion inhibition effect. However, in order to further reduce application costs and improve economic benefits, YS-QB can be compounded with propargyl alcohol, hexamethylenetetramine, and isopropanol to form a liquid corrosion inhibitor formula with better corrosion inhibition effect and simple on-site operation through intermolecular synergistic effect.

3.3.2. Optimization of Composite Corrosion Inhibitor System

A four-factor four-level L16 (4⁴) orthogonal experiment was used to optimize the proportions of YS-QB, propargyl alcohol, hexamethylenetetramine, and isopropanol. The factor and level design are shown in

Table 2. Factor and level design.

	Factor	YS-QB	Propargyl Alcohol	Hexamethylenetetramine	Isopropanol
Level
L1		3	0.5	0.5	1
L2		4	1	1	2
L3		5	1.5	1.5	3
L4		6	2	2	4

.

The overall dosage of the four components was set at 30 mg/L, and the corrosion rate of N80 steel coupon in # 1 simulated formation brine was tested under normal pressure of 80 °C and high pressure of 120 °C. The CO₂ flow rate under normal pressure was 2 mL/min, and the CO₂ partial pressure under high pressure was 0.2 MPa. The test results are listed in

Table 3. L16 (4⁴) orthogonal experimental results.

No.	YS-QB	Propargyl Alcohol	Hexamethylenetetramine	Isopropanol	Corrosion Rate (mm/a)
					80 °C	120 °C
1	3	0.5	0.5	1	0.101	0.216
2	3	1	1	2	0.140	0.253
3	3	1.5	1.5	3	0.152	0.268
4	3	2	2	4	0.171	0.259
5	4	0.5	1	3	0.106	0.183
6	4	1	0.5	4	0.113	0.198
7	4	1.5	2	1	0.098	0.172
8	4	2	1.5	2	0.123	0.201
9	5	0.5	1.5	4	0.0912	0.168
10	5	1	2	3	0.0903	0.152
11	5	1.5	0.5	2	0.0732	0.132
12	5	2	1	1	0.0602	0.119
13	6	0.5	2	2	0.0519	0.0929
14	6	1	1.5	1	0.0432	0.0903
15	6	1.5	1	4	0.0563	0.0958
16	6	2	0.5	3	0.0581	0.0981

.

Analysis of orthogonal experiment results is shown in

Table 4. Analysis of orthogonal experiment results.

	Average/Range	YS-QB	Propargyl Alcohol	Hexamethylenetetramine	Isopropanol
80 °C Corrosion rate (mm/a)	K1	0.141	0.0875	0.0863	0.0756
	K2	0.110	0.0966	0.0906	0.0970
	K3	0.0787	0.0949	0.102	0.102
	K4	0.0524	0.103	0.103	0.108
	R	0.0886	0.0155	0.0167	0.0324
120 °C Corrosion rate (mm/a)	K1	0.249	0.165	0.161	0.149
	K2	0.189	0.173	0.163	0.170
	K3	0.143	0.167	0.182	0.175
	K4	0.0943	0.169	0.169	0.180
	R	0.155	0.008	0.021	0.031

. The order of the influence of the proportion of the four components on the corrosion inhibition effect is YS-QB > isopropanol > hexamethylenetetramine > propargyl alcohol, whether under 80 °C or 120 °C. The proportion of propargyl alcohol and hexamethylenetetramine has the same impact on the corrosion inhibition effect under a normal pressure environment. The optimal ratio selected based on the average and range values of each level is 12:1:1:2. Under this ratio, the four components exhibit excellent synergistic effects.

After determining that the optimal ratio of YS-QB, hexamethylenetetramine, propargyl alcohol, and isopropanol in the composite system was 12:1:1:2, the composite system was prepared according to the ratio, and the effect of the composite system dosage on the corrosion inhibition of N80 and P110 steel coupons was tested under a normal pressure of 80 °C and high pressure of 120 °C. The water sample used in the experiment was simulated formation brine # 1, with a CO₂ flow rate of 2 mL/min under normal pressure and a CO₂ partial pressure of 0.2 MPa under high pressure. The test results are shown in Figure 11.

Under atmospheric pressure and 80 °C conditions, when the dosage of the composite system is 30 mg/L, the corrosion rate of the steel coupon can meet the industry standard (SY/T5329-2012) [24], which is less than 0.076 mm/a. Under high pressure and 120 °C, the dosage of the composite system can reach the standard at 60 mg/L. Compared with the application of YS-QB single agent, the dosage of YS-QB was reduced by 43.75%, indicating that YS-QB single agent not only has good corrosion inhibition effect, but also has a more effective corrosion inhibition effect in synergy with hexamethylenetetramine, propargyl alcohol, and isopropanol.

Therefore, using the composite system mentioned above with the dosage of 30 mg/L at 80 °C and 60 mg/L at 120 °C is an optimal solution to avoid the fast and severe CO₂ corrosion.

3.3.3. Electrochemical Test

• Electrochemical impedance spectroscopy (EIS)

The corrosion behavior of N80 carbon steel electrode in solutions with different concentrations of composite corrosion inhibitors was studied through EIS testing. From the Nyquist plots, it can be intuitively seen that, under different dosages of composite corrosion inhibitors, the capacitance arc is almost semi-circular. Regarding the Nyquist plots, the diameter of the capacitance arc semicircle indicates the impedance of charge transfer during metal dissolution. The larger the diameter of semicircle, the greater the charge transfer impedance and the better the corrosion inhibition effect.

The AC impedance spectrum measured after 60 min of CO₂ corrosion environment in simulated formation water at 60 °C under normal pressure is shown in Figure 12. As the amount of composite corrosion inhibitor increases to 100 mg/L, the diameter of the capacitance arc semicircle increases, reflecting an increasingly enhanced charge transfer impedance ability. That is, as the amount of composite corrosion inhibitor increases, the corrosion inhibition effect is better. However, when the dosage of composite corrosion inhibitor was increased to 120 mg/L, the diameter of the capacitance arc semicircle decreased, indicating a decrease in the ability to transfer charges and resist corrosion, which is consistent with the results of the previous weight loss experiment.

The polarization curves were used to analyze the corrosion inhibition mechanism of the composite corrosion inhibitor and verify the effect of the dosage of composite corrosion inhibitor on the corrosion inhibition effect. Figure 13 shows the polarization curves measured after 60 min in a CO₂ corrosion environment formed by #1 simulated formation brine at normal pressure of 60 °C. It can be found that, with the change of the dosage of the composite corrosion inhibitor, only the cathodic curve corrosion current density changes, indicating that the corrosion inhibitor system is a cathodic-type corrosion inhibitor. During the process of increasing the dosage of composite corrosion inhibitor from 0 to 100 mg/L, the cathodic curve corrosion current density continued to decrease, indicating that the corrosion inhibition effect increased with the increase in dosage. However, when the dosage was increased to 120 mg/L, the cathodic curve corrosion current density increased, indicating a weakened corrosion inhibition ability, consistent with the previous AC impedance spectroscopy test.

4. Conclusions

The corrosion behavior of CO₂ on N80 and P110 steel in two kinds of simulated reservoir brines of a gas storage facility in the Ordos Basin was studied. At the same time, a quinoline quaternary ammonium salt corrosion inhibitor YS-QB was designed and synthesized, and the optimal composite corrosion inhibitor system was established by adding propargyl alcohol, hexamethylenetetramine, and isopropanol through an L16 (4⁴) orthogonal experiment.

(1)

Under normal pressure and CO₂ flow rate of 2 mL/min, the corrosion rate of N80 and P110 varies slightly within the temperature range of 20 °C–60 °C, and the corrosion rate meets the industry standard requirements (less than 0.076 mm/a). When the temperature is higher than 60 °C, the corrosion rate changes more with increasing temperature, and the corrosion rate of N80 and P110 steel coupons starts to exceed 0.076 mm/a from 60 °C onwards. When the pressure is high and the CO₂ partial pressure is 0.2 MPa, the corrosion rate changes significantly as the temperature increases from 110 °C to 160 °C.

(2)

Due to the high salinity and chloride ion concentration of the simulated formation brine in #1, the corrosion rate of the steel coupon in it is relatively high. Meanwhile, under the same conditions, the corrosion rate of the P110 steel coupon is higher than that of the N80 steel coupon.

(3)

Under normal pressure and 60 °C, there is a positive correlation between CO₂ flow rate and steel corrosion rate. However, when the CO₂ flow rate is higher than 3 mL/min, the increase in steel corrosion rate is relatively small and tends to stabilize. Under high pressure, as the partial pressure of CO₂ increases, the increase in corrosion rate becomes greater, which is due to the increased solubility of CO₂ under high pressure. Regarding the influence of chloride ion concentration, whether in normal or high-pressure environments, the corrosion rate shows a pattern of first increasing and then decreasing with the increase in chloride ion concentration.

(4)

After ¹H NMR and infrared spectroscopy characterization, it was confirmed that the quinoline quaternary ammonium salt corrosion inhibitor YS-QB was successfully synthesized, and its corrosion inhibition effect was superior to the existing imidazoline corrosion inhibitor CX-1 in the market. Under 80 °C and 120 °C, the YS-QB single agent dosage was 40 mg/L and 80 mg/L, respectively, which can make the steel corrosion rate meet industry standards.

(5)

The optimal ratio of YS-QB, propargyl alcohol, hexamethylenetetramine, and isopropanol was optimized by the orthogonal experiment to be 12:1:1:2. The formula formed by this ratio can meet the industry standard for steel corrosion rate when added at 30 mg/L and 60 mg/L under 80 °C and 120 °C, respectively. Under both conditions, the amount of YS-QB added is 43.75% less. Therefore, using the composite system mentioned above with the dosage of 30 mg/L at 80 °C and 60 mg/L at 120 °C is an optimal solution to avoid fast and severe CO₂ corrosion, which can improve the corrosion inhibiting performance and lower dosage.

(6)

Both the impedance spectrum and polarization curve confirm that the composite formula has the best corrosion inhibition effect when the dosage is 100 mg/L. Continuing to increase the dosage weakens the corrosion inhibition effect. At the same time, the polarization curve also confirms that the composite corrosion inhibitor system is a cathodic corrosion inhibitor.