Appendix B - Pipeline material selection considerations

The pipeline material selection has been based on design against fracture. Design against long-running fracture in pipelines is based on the ability to arrest running cracks, rather than avoiding crack initiation. Brittle fractures propagate at high speed, and much faster than decompression of the pipeline contents. Hence, the driving force for brittle fracture is essentially the initial pressure in the pipeline and brittle fracture propagation is basically independent of the properties of the fluid in the pipeline. The design approach is considered to be adequate to avoid brittle fracture in the CO2 pipeline.

The second possible type of fracture is a ductile fracture (shear fracture). If a defect exceeds the critical size for the material and stress level, a crack may propagate along the pipeline driven by the hoop stress and internal pressure. Ductile crack propagation is slower than that of brittle cracks, and the driving force for cracking may be reduced by decompression of the fluid and resulting reduction in hoop stress at the crack tip. The properties of CO2 are such that the internal pressure during decompression remains at a higher level for longer than (for example) with methane.

The standard means of mitigating the risk of ductile crack propagation is to specify an adequate toughness, in terms of Charpy V-notch test values. If this is impractical, then various forms of mechanical crack arrestors may be used.

Internal corrosion can be mitigated by control of the water content and operational procedures to prevent a free water phase forming. Given the total maximum water level of 50 ppm (ppmv or mol ppm in gas phase) from the discharge of the capture compression unit, this limit is well below the water solubility limit in the normal operating conditions. Thus, by controlling the CO2 stream water content at the capture plant output, the internal corrosion risk can be mitigated.

The risk of forming free water in the pipeline during normal operation is therefore low and, if it does occur during transient operation, the exposure time is likely to be limited. However, a minimal corrosion allowance of 2.24 mm has been applied to allow for any short-term upset conditions that may arise over the lifetime of the pipeline.

External corrosion of the buried pipeline will be mitigated by a combination of coating and cathodic protection. A three layer system, consisting of a fusion bonded epoxy FBE base layer, an adhesive layer and an outer polyolefin layer (polypropylene or polyethylene) with minimum service temperatures of -40°C, will be provided for pipe coating. Three layer systems are favoured for resistance to handling and shipping damage. Field welded joints will be coated with a high integrity system (multi-layer shrink sleeves).