Risk of corrosion “H₂S Challenges in CO₂ Pipelines”

 In January 2023 the JIP was expanded to include ExxonMobil, Woodside, ArcelorMittal, Vallourec, Subsea7, Tenaris and Corinth as partners. The project is scheduled for completion in summer 2024.

How H₂S affects the risk of corrosion

The project will investigate how hydrogen sulfide (H₂S) as an impurity in CO₂ streams affects the risk of stress corrosion and “normal” corrosion in transport systems. Project manager Klas Solberg, Senior Engineer at the Veritas Centre (DNV) in Høvik, has a PhD from NTNU, specialising in fatigue and fractures in pipeline systems. Solberg sums up the dilemma addressed by the project as such:

“Higher tolerance of impurities in the CO₂ stream could make CCS achievable to more companies,  but on the other hand, too much H₂S in the CO₂ stream could damage the pipeline system. Our project is trying to find the ideal balance.”

CO₂ streams from capture plants will contain small amounts of impurities, such as H₂O, NO₂, SO₂, H2S and O2. If the CO₂ stream is liquefied, then a proportion of the impurities will be removed, but there will still be impurities at the “parts per million (ppm)” level in the CO₂ stream.

Impurities can lead to corrosion and precipitation of solid reactive products in the transport system. Corrosion poses a risk to HSE, costs and the reputation of CCS. This risk can be reduced by cleaning the CO₂ stream of impurities, and through the use of more corrosion-resistant materials and of greater safety margins (thicker and stronger materials in pipes and tanks). These measures will increase the cost of the transport system. More knowledge about the concentrations and combinations of impurities which can lead to corrosion will contribute to optimised designs of transport systems.

May result in changes to the CO₂ specification

The Northern Lights (NL) project has set limits for impurities in a CO₂ specification, but this does not mean that the NL specification is optimal for future CCS chains. New knowledge and new materials can lead to changes in the CO₂ specification, providing better optimisation of risks and costs.

CO₂ streams from refineries and steelworks, for example, may contain H₂S. To avoid stress corrosion, current industry guidelines (standards and recommended practice) recommend that stress levels of steel exposed to H₂S is kept well below the yieldstress. For pipelines operators allowing higher than recommended stress levels may reduce the cost of rock dumping for subsea pipelines.

The project will carry out experimental testing to map the relationship between H₂S concentrations and stress corrosion and normal corrosion. The testing is being carried out by DNV, IFE and Wood.

The project consists of four technical work packages

1. Analysis of risks and challenges resulting from increased H₂S concentrations. Investigate current concentrations of H₂S from selected industries and processes.
2. Define the risk of sulfide stress cracking (SSC) at relevant concentrations.
3. Investigate how increased concentrations of H₂S will affect the chemical environment in the transport system, and whether it might create a corrosive environment and affect the normal rate of corrosion.
4. Assess solutions for removing H₂S from the CO₂ stream before it enters the transport system.

The results of the project will be used for two main deliveries

1.  Report on recommended H₂S limit for the Northern Lights project, which may increase the H₂S limit for future CO₂ streams.
2. Update DNV’s recommended practice document DNV-RP-F104 “Design and operation of carbon dioxide pipelines”. This will mean the results of the project will be available to actors beyond those in the partnership.

An increase of the upper limits for H₂S may reduce the cost of future CCS chains. Knowledge from this project will also be important input to requalification of used oil and gas pipelines for CO₂ transport.