Why are corrosion resistant alloys used in offshore process pipewrok
Archived, originally published in April 2017
When is it impractical to use carbon/carbon manganese steel in offshore process pipework?
When the process fluid is corrosive and the corrosion rate would mean that the pipework would need to be replaced regularly.
How does the designer know if the process fluid is corrosive?
It is normal for the process fluids on an offshore platform (i.e. ‘crude’ oil and/or gas) to contain appreciable amounts of water and carbon dioxide. These combine to produce carbonic acid and, whilst this is not particularly corrosive at atmospheric pressure, at the pressures used in process pipework it may be.
So how does the designer know if the process fluids are corrosive?
If the system is ‘dry’ (i.e. there is no liquid water present), they won’t be. Unfortunately, this is rarely the case and, unless the designer can be certain it is, it must be assumed that they are.
So how does the designer know what the corrosion rate is likely to be?
Fortunately for the designer there are formulae available to allow them to predict the corrosion rate based on the design pressure, the design temperature and the percentage of carbon dioxide in the oil/gas (e.g. Norsok Standard M-506). As a rule of thumb, if the predicted corrosion rate over the lifetime of the system is likely to result in a loss of wall thickness of more than 6 mm, the corrosion rate would be considered excessive and a corrosion resistant alloy would normally be used.
Can’t the designer reduce the corrosion rate by using corrosion inhibitors?
Yes, but the life-cycle cost of using corrosion inhibitors offshore is high so it may not be cost-effective. Not only is there the cost of the inhibitor itself to consider, but also the storage and transportation costs as well as the cost of the manpower involved in the supervision and maintenance of the inhibition equipment. The designer needs to balance the operating costs of using carbon/carbon manganese steel with corrosion inhibitor with the capital costs of using a corrosion resistant alloy which in theory should be maintenance-free.
It should be noted that using corrosion inhibitors does not remove the need for a corrosion allowance, which may still be substantial and, as one of the aims of the designer is to minimise topside weight, the additional weight associated with the use of an inhibitor together with the corrosion allowance may be significant.
Surely, the use of a corrosion resistant alloy is more expensive than carbon/carbon manganese steel so why does the designer not increase the wall thickness to compensate for the loss due to corrosion?
This is where the figure of 6 mm comes in. For corrosion rates up to 6 mm, it is relatively straight forward to add a corrosion allowance to the design thickness for the pipe wall and be reasonably confident that the pipework will not fail prematurely due to corrosion.
When the predicted corrosion rate is greater than 6 mm the situation is not so straightforward, particularly if the loss in wall thickness is due to pitting rather than uniform corrosion (see the introduction to corrosion blog article for more information about corrosion). Pitting corrosion can be very localised and is difficult to monitor. In order to guard against the risk of failure due to pitting corrosion, it may be necessary to use a corrosion allowance well in excess of the predicted corrosion rate. This will increase the weight of the pipework, which will have a big impact on the cost of the support structure.
It is not just the wall thickness that may be affected by the corrosion allowance. The reduction in the bore may be unacceptable; meaning that the designer has to go up a pipe size. Not only will this have a huge effect on the topsides weight, but it may not actually be possible due to the space available. Space is at a premium on an offshore installation, which is why process pipework and equipment is packed in so tightly.
For these reasons, the most cost effective option is probably to use a corrosion resistant alloy; at least until the corrosion allowance can be reduced below 6 mm.
Why does the designer not try to remove the water and/or carbon dioxide from the system?
They do. On an offshore platform, the process fluids go through various stages of separation where they are cleaned and dried before they are finally exported to shore. At each stage in the separation process, water and gas are removed from the oil, and water is removed from the gas. At the same time, the pressure is also being reduced.
At what stage in the separation process is it okay to use carbon/carbon manganese steel?
It is normally only after the first stage separator that the designer can consider running the pipework in carbon/carbon manganese steel and then only for pipework carrying ‘oil’. At this stage, the bulk of the gas should have been separated from the oil so the carbon dioxide content should be relatively low.
From a corrosion viewpoint, ‘gas’ systems require greater consideration than ‘oil’ systems. If corrosion inhibitors are to be used, whilst these may be effective in controlling wet gas corrosion at low temperatures and low velocities they may be ineffective at higher temperatures and velocities or when the flow is turbulent. The designer is unlikely to consider using carbon/carbon manganese steel for the pipework carrying ‘gas’ until the ‘gas’ has been ‘dried’ such that dew-point of the gas is below the temperature at which condensation will occur.
Unlike carbon/carbon manganese steel, both standard and special duplex and austenitic stainless steels and various medium and high-nickel alloys exhibit excellent resistance to wet gas corrosion at relatively high ‘gas’ velocities. This is important as it means the designer may be able to reduce the pipe size from that he/she would need to use for carbon/carbon manganese steel.
What happens to the water removed from the oil and gas?
The water removed at each stage of separation would normally be discharged to the ‘closed-drains’ system. This generally operates at relatively low pressure, as a result, the corrosion rate is not too high and carbon/carbon manganese steel can be used.
What happens to the carbon dioxide left in the gas?
Provided the system is ‘dry’ (i.e. the dew-point of the gas is reduced to a temperature at which condensation will not occur) corrosion will not occur so the carbon dioxide is no longer a concern from a corrosion viewpoint. It should only be necessary to remove the carbon dioxide from the gas offshore if the gas is going to be liquefied or if the quantity of carbon dioxide in the gas is so great that the cost of treating the gas offshore is cheaper than the cost of transporting the ‘carbon dioxide’ to shore.
Source: LFF Group