Refinery Amine Systems: How to Avoid Interruptions to Production and Cuts to Your Bottom Line

System reliability – ensuring peak operating performance and maximizing production rates – depends on a refinery being able to reduce equipment fouling, minimize corrosion, extract contaminants and maintain equipment in its optimal operating condition.

One area which poses particular challenges is the efficient removal of hydrogen sulfide (H2S) and carbon dioxide (CO2) from amine refinery systems – especially during the hot summer months.

Why is H2S removal so important?

The removal of H2S from hydrogen-rich streams is a crucial part of hydrotreating processes performed by hydrocrackers, hydrodesulfurization units and natural gas sweetening units.

H2S is a gas that’s lethal at very low ambient concentrations. It’s highly toxic and its combustion products can be environmentally polluting, so a critical operation at all refineries is extracting H2S from hydrogen-rich streams.

How is H2S removed?

Amine gas treating – also known as gas sweetening because of the sour odor H2S gives natural gas – refers to a group of processes to remove H2S and CO2 from gases by using water-based solutions of various amines (alkylamines).

A downflowing sequestrating solvent in a scrubber absorbs H2S and CO2 from upflowing sour gas and produces a sweetened gas stream. It also produces a rich amine liquid, containing the absorbed acid gases.

That rich amine is then routed to a regenerator, where lean amine is produced, before being recycled back to the scrubber where it’s reused to start the process again. The stripped overhead gas from the regenerator is acid gas – concentrated H2S and CO2.

However, this all depends on the lean amine being fed to the scrubber at a suitably low temperature.

The importance of cooling

If the temperature of the lean amine entering the scrubber is too high then H2S and CO2 will not be absorbed and will leave the scrubber with the overhead gas. That puts the plant at risk of violating limits imposed by environmental regulations.

The problem for refineries is that the most efficient solutions for removing H2S and CO2 – those containing monoethanolamine (MEA) – are also the most corrosive. This leads to a number of issues.

Acid gas removal issues

When MEA solutions are combined with an atmosphere rich in H2S or with the oxidation products generated when amine is exposed to atmospheric oxygen, their rate of corrosion accelerates.

This results in an iron sulfide (FeS) corrosion product. This FeS product has an effect on the rust-prevention coating on the steel surfaces exposed to corrosion, which is made worse by amine flow’s abrasive quality.

What you then get is a build-up of solid FeS in the liquid stream, which makes it even more abrasive. And even when you use corrosion inhibitors or an amine reclaimer, you’ll often see amine streams containing 40 to 200 mg/l of FeS – sometimes with as much as 700 mg/l.

This causes several issues:

• Poor amine regeneration and scrubbing efficiency
  This occurs because of fouling of the regenerator and scrubber internals, as well as fouling and failure of reboiler tubes.
  
• Excessive foaming of the amine solution due to high solid content
  When this occurs, it leads to amines being present in the regenerator reflux drum; amines being present in the scrubbed gas fed to the reactor; and enhanced corrosion of the condenser.
• Fouling of lean amine lines and relevant cooling equipment
  As the concentration of suspended solids in the lean amine goes up, the efficiency of the cooling equipment drops, resulting in a rise in temperature of the lean amine fed to the scrubber.

And because the presence of H2S in the recycled gas hinders the desulfurization reaction, you particularly need to watch out for fouling of the lean amine coolers, the lean amine air cooler and the regenerator feed-effluent exchanger.

If fouling of the air cooler and feed-effluent exchanger are allowed to continue, this can lead to the lean amine that’s fed to the scrubber rising to an unacceptably high temperature.

And matters are compounded during the summer months, when on particularly hot days you could see the lean amine temperature soar to as high as 176° F, putting the plant at serious risk of breaching environmental limits.

What’s more, hot weather conditions, fouling and foaming all ratchet up each other’s effects.

How operators traditionally respond

When operators are faced with heat exchanger fouling – particularly where there’s a decline in regenerator overhead cooling during hot summer weather – what they will traditionally do is raise tower pressure to offset warmer ambient air and cooling-water temperatures.

However, an increase in tower pressure leads to a reduction in regeneration efficiency and will likely see pressure get dangerously close to pressure relief valve settings and the upper regenerator tower pressure limit.

What happens then is that, for safety reasons, operators are forced to reduce the sour gas upstream unit throughput, which can lead to huge economic losses.

A better response

A cost-effective alternative is provided by temporary cooling systems, such as those we supply at Aggreko.

Our team of process experts can connect a number of temporary exchangers at strategic positions along the hot lean amine circuit. These will provide the additional cooling power needed to reduce the lean amine temperature to an ideal level and ensure ongoing regulatory compliance.

Depending on how low you want the lean amine temperature, the temporary heat exchangers can be cooled using a combination of mobile air coolers, mobile cooling towers and/or mobile chillers.

With Aggreko’s temporary cooling, you can:

• maintain ideal process conditions
• avoid cutbacks
• and maximize the productivity and profitability of your plant.

Learn more about our solutions for the petrochemical and refining sector

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