Of the pipelines currently operating in pure hydrogen service mode, almost all were designed and built exclusively for that purpose. Current hydrogen codes (principally ASME B31.12) tend to be more restrictive than their natural gas equivalents with respect to pipeline design and integrity management requirements. For steel line pipe, limits are placed on the allowable stresses and tolerable defect sizes, and restrictions are placed on material properties. This is largely a reflection of the fact that hydrogen can degrade the mechanical properties of steel. A full explanation of how this happens would fill several libraries but revolves around the way that gaseous (molecular) hydrogen can dissociate at the internal surface of a pipeline, leading to the absorption of atomic (or ionic) hydrogen into the steel structure and a consequent decrease in ductility, decrease in toughness and increase in the fatigue-crack growth rate.
Although these impacts are known in qualitative terms, the challenge lies in quantifying exactly what they will mean for re-purposing an entire infrastructure that was not designed or built to take account of hydrogen service. In fact, it is common that original material and construction records have been lost, and there is consequently a limited knowledge of the range of different materials and pipe grades existing within most pipelines. It must also be noted that many existing gas pipelines have been in service for several decades and therefore exhibit a wide range of conditions with respect to the presence and severity of integrity threats.
Fortunately, many of our unanswered questions can now be explored using the IDW. Here are just three examples.
According to ASME B31.12 PL-3.7.1 (5), “Pipe sizes above 4 inch shall have a wall thickness of at least 0.25 inch.” What does this mean for existing infrastructure?
At present, the IDW contains inspection results for several thousand individual gas pipelines with outside diameters greater than 4 inches. Of these pipelines, 22% had a nominal wall thickness of less than 0.25”/6.35 mm. Conversion of these pipelines is therefore going to be a challenge within the existing codes and may require additional justifications or assessments to be made with respect to integrity management.
Since hydrogen is known to increase the fatigue-crack growth rate and decrease fracture toughness, cracking could potentially be a major threat for hydrogen pipelines. How widespread are cracks or crack-like features that could be exacerbated by hydrogen in the conversion of existing gas pipelines?
Most pipelines do not have extensive cracking – a point that can be exemplified using the results from several hundred crack inspections in the IDW.
Noting that the sample of inspected pipelines is already biased towards those with the higher risk profiles, we can take heart from the fact that only 20% had more than 1 crack per kilometer at the time of their inspection, and only 3% had more than 10 cracks per kilometer. With the right crack management framework in place, the threat of cracking can be readily managed in the majority of pipelines, even with the introduction of hydrogen.
For pipelines with more extensive cracking, the conversion to hydrogen could spell the difference between a manageable risk and an unmanageable one. These more challenging assets require additional focus to ensure that the existing flaws would be safe in the presence of hydrogen, potentially requiring mitigation through limits on operating stresses and/or adjustments to integrity management and inspection strategies. Through ROSEN’s IDW, such pipelines with a higher likelihood of containing significant cracking can be predicted based on factors such as design and construction, environmental conditions, operational history, and available survey data.
ASME B31.12 constrains the use of higher-grade materials by reducing the allowable stress levels, especially for grades above X52. So how much of the existing gas network can be converted to hydrogen service without possible reductions in operating pressure, i.e. with grades below X52 and operating within the allowable stress limit?
According to ROSEN’s IDW, only 37% of gas lines in the United Kingdom are below X52, and 57% of these have a current maximum operating pressure below 30% SMYS. Therefore, up to 80% of UK pipelines may require some reduction in operating pressure or further assessments to justify safe operation at current or higher pressures.
Things start to get even more interesting when the situation outside the UK is examined. According to the IDW, 41% of gas lines worldwide are below X52, but only 15% have a current maximum operating pressure below 30% SMYS. Therefore, up to 95% of worldwide gas pipelines may require some reduction in operating pressure or further assessments to justify safe operation at current or higher pressures. This highlights the need to establish a robust body of knowledge regarding the existing materials and pipe grades present within any pipeline intended for hydrogen conversion.
Looking forward
The data available in the IDW will continue to grow – and, with it, the power to predict pipeline condition, enhance inspection results and even identify effective mitigation activities. However, the ability to answer questions about the world’s critical pipeline infrastructure – in a quantitative and meaningful way – is also invaluable. As the industry strives for more data-driven decision making, this relatively simple application should not be underestimated.