**1. Introduction**

During the exploitation of oil and gas, some solid particles are deposited on the surfaces of pipelines owing to a decrease in the flow rate and pressure [1]. Under deposit corrosion (UDC) usually occurs and is driven by the differences in the chemistry at the interface between the sediment, the substrate, and the bulk solution. This can cause catastrophic failures, such as a reduction in the equipment's integrity and pipeline perforation, because UDC is difficult to detect [2,3].

Meanwhile, more sour oil and gas fields need to be developed to resolve energy shortages [4]. The dissolution of carbon dioxide produces corrosive carbonic acid, and the hydrolysis of elemental sulfur causes the solution composition to become complex. Elemental sulfur, a yellow powder of S8, is an inorganic sediment generated by the catalytic pyrolysis product of ferrous sulfide under a high temperature and high pressure at the reservoir and deposited due to the reduction in temperature and pressure in the process of fluid production [5]. Zheng et al. [6] proposed that high pressure and temperature were conducive to the formation of polysulfides. Therefore, the chemical equilibrium reaction was changed in a high-temperature and high-pressure environment, and then the decomposition of polysulfides into elemental sulfur and hydrogen sulfide was promoted.

**Citation:** Wang, F.; Li, J.; Qu, C.; Yu, T.; Li, Y.; Zhu, S.; Yang, B.; Cheng, F. Corrosion Mechanism of L360 Pipeline Steel Coated with S8 in CO2-Cl− System at Different pH Values. *Metals* **2021**, *11*, 1975. https://doi.org/10.3390/met11121975

Academic Editor: Renato Altobelli Antunes

Received: 1 November 2021 Accepted: 3 December 2021 Published: 8 December 2021

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In contrast to the general UDC, the corrosion products of sulfur-containing sediments have semiconductor properties, which can not only promote the formation of the concentration cells but also cause galvanic corrosion with metal substrates [7,8]. Furthermore, Cl− with electronegativity is present in the pipeline, which easily adsorbs to the positive metal surface and hinders the formation rate of a passivation film on the surface of the metal [9]. Electrochemical tests showed that the increase in Cl− concentration in the solution could accelerate the anodic dissolution of the metal and the negative shift of the cathode potential [10].

Previous studies have revealed that when the temperature is higher than 60 ◦C, sulfur reacts with water, resulting in serious acidification of the corrosive solution [11]. The existence of the S8 deposition layer, the distribution of ferrous ions, and the concentration of Cl− eventually lead to the heterogeneity of the solution [12]. The corrosion of pipeline steel is a very complex process, which is generally affected by the type of sediment and the internal solution of the pipeline. The hydrolysis of the S8 deposition layer and the dissolution of carbon dioxide acidify the solution. The pH distribution in the pipelines is not uniform, and more H+ is accumulated in the pitting pits. Therefore, the pH distribution at different depths of the pit is heterogeneous, and the pH of the interface between the deposits and the substrate is also different from that of the surface of the bare steel. To maintain electrical neutrality, corrosive Cl− causes the pitting corrosion pits to continue to be excavated downward, which causes fatal damage to the pipeline steel [13]. To mitigate pipeline failure, it is necessary to understand the corrosion mechanism under S8 deposition by adopting effective measuring technologies. Zagal et al. [14] suggested that acid formation caused by sulfur hydrolysis was the main factor controlling corrosion in the presence of S8. Gong et al. [15] argued that with an increase in immersion time, the uniform corrosion rate in the absence of S8 increased slightly, whereas the corrosion rate in the presence of S8 decreased with an increase in immersion time in a supercritical carbon-dioxide-saturated aqueous environment. Zhang et al. [16] studied the galvanic effect between the covered electrode and the bare electrode of mixed sediments in formation water containing CO2 through electrochemical measurements and surface characterization. Therefore, the presence of S8 has a grea<sup>t</sup> influence on the corrosion behavior of oil country tubular goods (OCTG), and the degree of influence is also different. However, few studies have focused on the influence of the deposition of S8 on the corrosion behavior of steel at different pH values.

A wire beam electrode (WBE) provides a new method for monitoring the processes of localized corrosion and estimating the rate of localized corrosion [17]. A WBE can connect the cathode and anode corrosion processes and the cathode and anode areas of the corrosion surface, respectively [18]. Therefore, it can be used to study the anode and cathode processes of localized corrosion cells [19]. Wu et al. [20] used a WBE to study the galvanic corrosion of mild steel under calcium carbonate deposition and potential and galvanic mappings. They found that the polarity of the electrode covered by calcium carbonate changed over time. Chen et al. [21] used a WBE to track the development process of SRB, inducing localized corrosion of 907 steel.

In this study, the effect of the different pH values on the localized corrosion of L360 pipeline steel coated with or without S8 in a 3.5 wt% NaCl solution containing CO2 was studied by a potentiodynamic polarization curve, EIS measurement, and a WBE. The surface morphologies of the corrosion samples were observed by scanning electron microscopy (SEM). After removing the corrosion products, the corrosion morphology of the steel substrate was observed using an OLYMPUS DSX500 optical digital microscope. The composition of the corrosion products was analyzed using X-ray diffraction.

#### **2. Materials and Methods**
