Corrosion Mechanism Analysis of L360QS Steel Gas Gathering Pipeline

Literature Overview

This paper, published in Corrosion and Protection (2025, Vol. 46, No. 3), authored by Wang Liang and colleagues from Southwest Petroleum University and the PetroChina Pipeline Research Institute, investigates the corrosion failure of an L360QS steel gas gathering pipeline. The study employs a systematic approach combining field inspection, chemical composition verification, microstructural analysis, and corrosion product characterization using scanning electron microscopy (SEM) and energy-dispersive X-ray spectroscopy (EDS). The work is supported by Southwest Petroleum University extracurricular open experiment projects and the Sichuan Provincial Natural Science Foundation, reflecting a strong academic-industrial collaboration in pipeline integrity research.

Core Technical Findings

The authors confirmed that the L360QS steel pipeline met the required chemical composition specifications, with a microstructure consisting of ferrite and bainite. This is consistent with the typical microstructural design of L360-grade line pipe, where the controlled rolling and air-cooling process produces a predominantly acicular ferrite/bainite matrix that balances strength and toughness. The key finding concerns the corrosion mechanism: the internal surface corrosion layer was identified as a typical product of a coexisting H₂S/CO₂ corrosion system.

Corrosion Product Characterization

The study concluded that H₂S was the dominant corrosive agent. In the early corrosion stage, a protective FeS film formed on the pipeline surface. However, the combined action of CO₂, Cl⁻, Ca²⁺, and Mg²⁺ ions progressively degraded this FeS film, facilitating the formation of FeCO₃ corrosion products. This two-stage corrosion evolution is particularly significant for gas gathering pipelines in carbonate reservoirs where both H₂S and CO₂ are present.

Engineering Implications for Pipeline Integrity

From a pipeline integrity management perspective, this study highlights several critical points. First, the presence of dissolved salts (Ca²⁺, Mg²⁺, Cl⁻) in the produced water accelerates the breakdown of protective corrosion films, a phenomenon well-documented in the NACE MR0175/ISO 15156 framework for sour service materials. Second, the FeS-to-FeCO₃ transition represents a degradation of surface protection, as FeCO₃ is generally less adherent and less protective than FeS. Third, the L360QS designation indicates a steel grade specifically designed for sour service (QS suffix), yet the corrosion still occurred, suggesting that either the operating conditions exceeded design assumptions or that the corrosion resistance of the grade was insufficient for the actual field environment.

Discussion on Corrosion Mechanism and Mitigation

The study's identification of H₂S as the dominant corrosive agent aligns with established electrochemical corrosion theory. In sour service, the corrosion process proceeds through the reduction of H₂S at the cathodic sites, generating H₂ and HS⁻ ions, while the anodic dissolution of iron produces Fe²⁺ ions. The Fe²⁺ and HS⁻ react to form FeS, which initially provides a degree of surface protection. However, the degradation of this film by Cl⁻ (which penetrates and disrupts the sulfide layer) and by the buffering action of CO₂ (which maintains a low pH environment) is a well-known challenge in sour gas gathering systems.

From a materials engineering standpoint, the L360QS steel's ferrite-bainite microstructure is generally considered to offer good resistance to sulfide stress cracking (SSC) and hydrogen-induced cracking (HIC) when properly heat-treated. However, the study does not explicitly address whether hydrogen embrittlement or cracking was observed, which would be a critical consideration for pipeline integrity. In my experience with sour service pipelines, the combination of H₂S and CO₂ corrosion frequently leads to a pitting-dominated damage pattern, where localized breakdown of the protective film creates deep pits that can rapidly propagate to wall-thickness loss.

For mitigation, several engineering measures come to mind. First, the use of corrosion inhibitors (film-forming organic inhibitors for CO₂ and sulfide scavengers for H₂S) should be evaluated for the specific operating conditions. Second, the pipeline's internal coating system should be verified for integrity, as coating defects at welds and girth joints are common initiation sites for corrosion. Third, the operating parameters—particularly temperature, pressure, and gas composition—should be reviewed against the NACE MR0175 material selection guidelines to ensure the L360QS grade remains within its applicable range.

Study Insights and Practical Recommendations

This study provides valuable field-based evidence of how multi-component corrosion environments interact to degrade sour service pipelines. The two-stage corrosion product evolution (FeS to FeCO₃) is a critical finding that should inform corrosion monitoring strategies. In practice, pipeline operators should not rely solely on the presence of FeS as evidence of adequate protection, as the study demonstrates that this film can be progressively degraded. Regular inline inspection (ILI) with corrosion mapping capability, combined with laboratory analysis of retrieved coupons, is essential for accurate assessment of corrosion progression.

The study also underscores the importance of considering the complete chemical environment rather than focusing on a single corrosive agent. The synergistic effect of CO₂, Cl⁻, Ca²⁺, and Mg²⁺ on FeS film degradation is a reminder that corrosion management must be holistic. For future work, I would recommend extending the investigation to include quantitative corrosion rate measurements, hydrogen permeation tests, and accelerated corrosion testing under simulated field conditions to establish more precise design life predictions for L360QS pipelines in similar environments.

In summary, this study offers a well-documented case analysis of H₂S-dominated corrosion in L360QS sour service pipelines, revealing the critical role of multi-ion interactions in corrosion product evolution and providing actionable insights for pipeline integrity management in carbonate reservoir gas gathering systems.