A detailed review of all the relevant corrosion mechanisms has been conducted (see Appendix Q4.7), and the strategy for monitoring and control is given in Appendix Q5.1 The main aspects of corrosion mechanisms and management relevant to the selection of frequencies within this QRA (taken from the above references) are given below.
CO2 and Organic Acid Corrosion
Carbon dioxide (CO2) becomes corrosive when it dissolves in water to form carbonic acid, and this will be the primary corrosion threat to the pipeline. The presence of organic acids can increase the corrosivity. If the fluids in the pipeline are uninhibited, the predicted corrosion rates in the onshore pipeline are 0.12mm/yr for condensed water and 0.2mm/yr for formation water. To mitigate such corrosion it is common practice to inject corrosion inhibitor (which forms a barrier against the corrosive fluids) or to inject glycol or methanol which are miscible with the corrosive water and further reduce the corrosivity.
For the Corrib pipeline the threat of CO2 and organic acid corrosion will be mitigated primarily by injecting corrosion inhibitor but will also benefit from the presence of methanol. The predicted inhibited corrosion rates in the onshore pipeline are <0.05mm/yr for all production scenarios. The pipeline design includes a 1mm corrosion allowance and in addition the 27.1mm wall thickness of the design provides further contingency.
For sections of the pipeline where protection of the carbon steel pipe by the film forming corrosion inhibitor cannot be assured, e.g. due to insufficient length to establish the film or where there is turbulent flow, corrosion resistant materials have been used. This includes the LVI pipework and valves. The section of onshore pipeline and 20” valve within the LVI has also been overlay welded with Alloy 625 because of the potential for turbulent flow and the presence of stagnant conditions during normal operation.
Top of the Line Corrosion
CO2 or organic acid corrosion can occur in pipelines where the flow regime is stratified and condensation occurs at the top of the pipeline. The corrosion inhibitor does not generally provide protection here, but mitigation will be provided by the co-condensing methanol. The expected flow regime over the full length of the Corrib pipeline is annular dispersed for the 20 year field life which precludes top of line corrosion as a mechanism.
Preferential Weld Corrosion
Pipelines in wet gas service are susceptible to preferential CO2 corrosion at the welds but this will be mitigated by the corrosion inhibitor as described above, and control of the weld chemistry.
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Galvanic Corrosion
Galvanic corrosion occurs as a result of differences in electrochemical potential between metals, e.g. between the stainless steel T-piece and the pipeline at the LVI, but has not generally been observed in producing oil and gas systems and will not occur along the pipeline. Mitigation at the interface will be provided by the corrosion allowance, and the absence of this mechanism will be confirmed by wall thickness checks at the LVI.
H2S Corrosion
As there is no hydrogen sulphide (H2S) in the Corrib wells, this type of corrosion will not occur (however measurements will be taken at the terminal to monitor for the presence of H2S).
Microbial Induced Corrosion
Bacterial related corrosion is unusual in gas/condensate production systems and with no requirement for water injection there is no expectation that this mechanism will occur in the Corrib pipeline during operation.
Corrosion by Hydrotest Water
In common with other gas pipelines, there will be a pressure test using water. Standard methods will ensure that all threats of corrosion from this activity are mitigated prior to putting the pipeline into service.
Stress Corrosion Cracking
There are no credible internal stress corrosion cracking mechanisms for carbon steel and no chloride stress corrosion cracking of stainless steels is anticipated with the Corrib production conditions.
Stray Current Corrosion
Stray current corrosion can occur when an isolation joint fails due to bridging or short circuiting. An isolation joint is provided between the pipeline and the terminal and will be periodically monitored for this corrosion mechanism. There is no isolation joint between the offshore and onshore cathodic protection systems thus eliminating the possibility of stray current corrosion. 6.4.3.1 Internal Corrosion Failure Frequency
There is no database frequency for internal corrosion that directly correlates with, and hence can be directly applied to, the Corrib pipeline. The two most closely appropriate databases are EGIG [5] for treated natural gas and CONCAWE [6] for hydrocarbon liquids. Expert metallurgical review has concluded that the overall corrosion potential associated with the Corrib gas is greater than that for treated natural gas (EGIG) but less than that for crude oil (CONCAWE) (see Appendix Q4.7). Consequently the use of CONCAWE [6] for crude oil pipelines only as a base frequency would be conservative and has thus been adopted. This value is 5.85E-05 per km per year
The same modification factor as discussed above (6.4.3.1) from de Stefani [10] for external corrosion was used for pipeline thickness (0.003) together with an additional modification factor of 0.175 for in-line inspection which gives an overall base case failure frequency of 3.1E-08 per km per year.