Pipelines for the transmission of oil and gas are the safest and most efficient way to transfer hydrocarbons between locations. Unfortunately, and although rare, pipeline failures do occur. The potential of leakage has severe environmental consequences: oil spills, air pollution, water contamination, habitat destruction, and more.
Such ruptures can include corrosion (both internal and external); mechanical problems such as material, design, or construction issues; third-party activities that were either accidental or intentional; operational problems; and acts of nature.
Oil and gas fluids in pipelines normally contain small quantities of carbon dioxide (CO2) and hydrogen sulfide (H2S). They are byproducts of the geological decomposition of organic matter and are extracted alongside the oil and/or natural gas. These gases readily dissolve in water, lower the pH by forming carbonic and sulfuric acids, and can cause significant corrosion or cracking of carbon steel—a common pipeline material of construction.
One of the primary causes or contributing factors of pipeline corrosion failures is the presence of hydrogen sulfide. The maximum allowable H2S in gas pipelines is 4 parts per million (ppm) or 0.25 grains per 100 standard cubic feet. However, with greater domestic crude production, H2S content in pipelines is dramatically increasing. In this article, we’ll focus on H2S-associated corrosion-type failures and the requisite mitigation/prevention strategies.
The primary contributors to corrosion-related failures in the oil and gas industry. Source: Sustainability/MDPI
H₂S: The Hazards to Human Health
Although H₂S-related corrosion doesn’t account for most corrosion-related failures in the oil and gas industry, it is one of the most severe forms. This is due to its potential for sudden, catastrophic failures in critical infrastructure. Such failures’ economic and environmental impacts are evident, but injuries and loss of human life are ultimately the most extreme consequences.
Hydrogen is well known as a colorless, flammable, explosive, and highly toxic gas. At low doses, it has a characteristic “rotten-egg” smell, but one cannot rely on this as an indicator of its presence. Depending on the concentration level, duration of exposure, and other factors, H₂S’s effects on people can range from headaches and respiratory irritation to convulsions and death.
Historically, the industry has seen many tragedies related to hydrogen sulfide. In the United States alone, public records of H2S incidents in pipeline and similar sectors date back to the 1980s.
Cases of Notable Fatalities: a 3-Year Snapshot
- October 2024: An hours-long toxic gas leak was reported at an oil refinery in Deer Park, Texas. During this time, 43,500 pounds of highly toxic H2S was released, which was more than 800 times the hourly emission limit for the dangerous gas. Contract workers had been performing maintenance on site when the accident occurred. Exposure to the gas killed two of them and injured dozens more. The incident also put surrounding communities at risk; as a result, a shelter-in-place order was initiated for two neighboring cities, and part of a nearby state highway was temporarily closed.
- February 2023: An employee was found unresponsive at an oil and gas well site in Watford City, North Dakota. This site was known to have H2S present in the air at times. A coworker pulled the employee from the area, contacted emergency services, and performed CPR while waiting for them to arrive. He reported that the employee had foam in his mouth and that blood was coming out of the employee’s mouth when he performed CPR. The employee also had chemical burns and was transported to the hospital, where he was pronounced dead. He had been overcome by high levels of flammable gases, including potential hydrogen sulfide overexposure.
- June 2022: Two employees died while working at a remote oil and gas services site in Loco Hills, New Mexico. Upon investigation, H2S gas was detected at levels between 3 parts per million (ppm) and 5 ppm, which is not lethal. However, it wasn’t possible to estimate what the H2S levels were at the time the employees were killed.
The scene of a large gas main explosion in San Francisco, California, in 2019. Such incidents have lasting impacts on the surrounding communities. (Source: colloidial/iStock)
What Does Hydrogen Sulfide Do to Pipelines?
The H2S-induced processes that lead to corrosion failure, infrastructure damage, and eventually human fatalities (as demonstrated in the previous section) are not simple. Hydrogen sulfide poses serious threats to pipeline integrity primarily through corrosion and cracking. The degradation of pipeline materials through these two mechanisms is explained in more detail below.
Corrosion Caused by H₂S
The extent and type of corrosion is defined by the CO2/H2S ratio:
- When the CO2/H2S ratio is <20, the hydrocarbon is defined as sour. Sour corrosion is dominated by the formation of a protective, continuous, and semi-conductive iron sulfide (FexSy) scale. However, these scales can be locally disrupted by galvanic currents between defects and the surrounding scale, resulting in localized pitting attacks. Additional localized corrosion caused by under-deposit corrosion can be produced.
- A CO2/H2S ratio of >500 for the hydrocarbon is classified as being sweet. Under these conditions, corrosion tends to be uniform. With the presence of water and oxygen, carbonic acid can form and corrode the metal. Depending on the acid gas, water chemistry, temperature, and flow conditions, the corrosion rate can be over 10 mm/y.
- When the CO2/H2S ratio is between 20 to 500, the corrosion tends to be uniform. The uniform corrosion rate can be lower than for sweet hydrocarbons because of the co-precipitation of iron carbonate (FeCO3) and non-continuous FexSy scales.
Internal corrosion of pipelines. (Source: Aleksandar Tasevski / iStock)
Other H2S-Related Factors Influencing Pipeline Corrosion
Process/flow conditions can impact the corrosion rate. For example, chloride concentration can decrease uniform corrosion but can also trigger localized corrosion by interacting with scale formation. The presence of elemental sulfur from oxygen ingress can significantly increase the corrosion rate. Along the length of the pipeline, any temperature decrease can condense water, which can enhance corrosion.
Top-of-the-line corrosion (TLC) tends to occur with wet gas flow or stratified multiphase flow combined with a significant temperature difference between the pipeline and ambient conditions. The corrosion rate can be high because corrosion inhibitors tend to stay in the liquid phase and do not prevent corrosion in the stratified flow. TLC in sour conditions often exhibits lower corrosion rates than TLC in sweet systems.
Pipelines are also susceptible to microbiological corrosion from both aerobic and anaerobic microbes. Microbiologically induced corrosion (MIC) results from sulfate-reducing bacteria producing H2S.
Cracking Caused by H₂S
Hydrogen-induced cracking (HIC) in carbon steel pipelines is caused by the dissociation of H2S to produce atomic hydrogen that collects at defects in the steel. The uptake of hydrogen and formation of molecular hydrogen can then potentially cause blister formation or crack initiation. Crack propagation is not extremely rapid.
Hydrogen-induced cracking in steel. (Source: CEphoto, Uwe Aranas / Wikimedia Commons)
Sulfide stress cracking (SSC) involves wet H2S, with the hydrogen atoms diffusing into the lattice of the steel. This reduces the ability of the steel to withstand deformation from either residual or applied stress. SSC can initiate and propagate to failure much faster than hydrogen-induced cracking. Additionally, it often initiates at weld heat-affected zones.
While Fe-S scale as mackinawite can diminish hydrogen ingress and hydrogen embrittlement, the coexistence of mackinawite and pyrrhotite from process and concentration conditions can lead to the greater potential of hydrogen embrittlement of steel pipes.
Integrity Management Analysis and Strategy
The Pipeline and Hazardous Materials Safety Administration (PHMSA) Mega Rule has been designed to improve pipeline safety. The requirements include identifying safety threats, integrity management, corrosion control, inspections, and repairs.
Additionally, the U.S. Code Federal Regulations “Integrity Management Program,” 49 CFR 192 Subpart O and 49 CFR 195.452, and PHMSA ADB-08-08 are useful resources for professionals in these industries.
To minimize the potential of a pipeline failure, one can use a quantitative risk assessment methodology:
1. First, a detailed assessment of potential hazards is identified. Such an assessment can be performed for a new pipeline, when updating an existing pipeline, or when process fluid and/or contaminants have been changed.
2. Next, the hazards are evaluated for their likelihood and severity of causing a leak or rupture. Factors to consider include corrosion, external damage, operational issues, and environmental conditions.
An engineer checking a petrochemical gas pipeline at a construction site. (Source: RGtimeline/iStock)
The key aspects of the risk assessment’s corrosion section include the following:
- Relative amounts of contaminants such as sulfides, chlorides, carbon dioxide, and water
- Potential variation in these contaminants with varying service conditions
- Temperature and pressure at various pipeline locations
- Condensate and water at these locations, and the extent of liquid water
- Flow conditions between fluids resulting from variations in wall shear stress
- Stratified flow (TLC)
- Dead legs
- Pooling of water in synclines in the line, leading to the potential development of biofilm and MIC on the exterior of the pipeline
Once the key corrosion issues are identified and quantified, mitigation procedures can be designed. Regular monitoring and documentation for the identified risks need to be incorporated into the mitigation plan.
Mitigation and Prevention Strategies
Approaches to controlling corrosion can include selecting a corrosion-resistant alloy, cladding, or coating; using cathodic protection (CP) to change the material’s electrochemical potential; and/or modifying the chemical environment. Such modifications can include water dehydration to a specified dew point, pH change, corrodent scavenger, or adding a corrosion inhibitor that forms a barrier between the material and the corrosive aqueous electrolyte solution. Below is a more detailed breakdown of just some of the aforementioned strategies.
Cathodic Protection
CP is an electrochemical process that slows or stops corrosion currents by applying a direct current to the metal. CP systems control corrosion through either sacrificial anodes or impressed current:
- With galvanic protection, a protective anode (such as a zinc coating) sacrificially corrodes to protect the steel until it can no longer provide protection.
A cathodic protection rectifier on site. (Source: Cafe Nervosa / Wikimedia Commons)
Corrosion Inhibitors
Corrosion inhibitors can be used either continuously or in batches. However, an accurate chemical dosing and an understanding of the requisite corrosion mechanism are critical for successful inhibition.
Amine film-forming inhibitors create a protective surface layer but have the limitation of potentially being sheared from the pipeline wall depending on the flow conditions. When little liquid is present around the inhibitor’s injection point, the corrosion inhibitor may not be transported throughout the length of the pipeline. Alcohols and glycols used for dehydration can impact the protectiveness of the scale.
Isolation Joints
Proper design and implementation of a CP system in conjunction with isolation kits and/or joints is critical for optimum operation. Monolithic isolation joints and flange isolation joints eliminate metal-to-metal pipe contacts, can prevent static current corrosion, and aid with CP by segmenting the pipeline.
The selection of the type of isolation joint for a specific application should be based on operational, installation, and maintenance requirements. The distance between isolation joints or kits is a determining factor in corrosion protection since extended distances might allow current bridging from the unprotected side of the isolation kit/joint to the protected side.
Isolation Gaskets
Gasket material for the isolation joint is a function of operation, the fluid’s corrosiveness, and the pipeline’s temperature and pressure. The ideal isolating gasket would be specifically designed for aggressive pipeline streams.
An example of such a product on the market is GPT Industries’ fully encapsulated isolating gasket, EVOLUTION®. Unlike others, this gasket completely blocks current from flowing through the deposits, therefore helping to prevent electrical bridging. Electrical bridging occurs when conductive deposits such as Fe-S scales build up at the flange intersection, which allows CP current to bypass the isolation joint.
EVOLUTION®’s differentiator is its ID seal, whose functions include the following:
- It doesn’t enable deposits to stick at the interface (where isolation would be lost).
- It increases the isolating distance by disallowing any metal core’s exposure to media.
- It matches the pipe bore, preventing media buildup between the flanges for a bridge.
- Protruding the ID seal even slightly into the bore has a positive effect on bridging.
Glass-reinforced epoxy gaskets are becoming more and more vulnerable to the increasingly aggressive media in pipelines. This includes attacks on joints from higher H₂S and CO₂ applications. EVOLUTION®, on the other hand, has gone through rigorous sour media testing—without any degradation or permeation. With its extreme tightness, such a gasket is particularly suited to being a one-stop sealing solution for transporting hydrogen, greenhouse gases, and liquefied natural gas applications.
The gasket’s proprietary coating is also chemically resistant to attacks by H₂S, CO, CO₂, and other chemicals usually found in oil and gas pipelines. Furthermore, EVOLUTION®’s dual seal design (the ID seal and C-ring) prevents permeation through the gasket, which in turn prevents chemicals from degrading the metal core.
A gasket like EVOLUTION® is resistant to typical oil and gas chemicals, especially H₂S, CO, and CO₂. (Source: GPT Industries)
Remote Monitoring
Part of a management integrity program is monitoring the pipeline for potential corrosion issues. This is particularly critical for new pipelines, when the feed stream is changed, or to assess fitness for continued service.
A real-time, online remote monitoring system consists of a sensor network mounted in the pipeline combined with portable electronic hardware and diagnostic software. Continuous monitoring for corrosion eliminates issues associated with manual methods. For detailed inspection, this information can be combined with a high-tech smart pigging device.
Impact of Renewable Feeds on Corrosion
Renewable feeds can be more corrosive than hydrocarbon feeds because of high-temperature fatty acids and higher contaminant levels of H2S and oxygenated compounds. Special corrosion prevention is required for pipelines transporting such feeds, including CP, corrosion inhibitors, gaskets and seals, coatings, and construction materials. Alternating between hydrocarbon and renewable feeds can accelerate corrosion issues and requires special design attention and monitoring.
As feed streams become more sour with higher H2S concentrations, corrosion and potentially catastrophic leakage may become common occurrences. Therefore, to prevent such threats, an integrity management system is required. This includes a corrosion prevention strategy with CP that incorporates the latest developments in isolation and remote monitoring technology. Even pipelines with upgraded metallurgy and coatings require such a strategy.
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Additional Resources for Professionals in North America: