Corrosion may seem an unexciting subject, but international and
state oil companies now need to place much higher priority on both
the technology and management of its causes, monitoring its
effects, controlling its various outcomes and undertaking remedial
work. Extraordinarily for its potential consequences, it is one of the
few phenomena where widely-used inspection techniques remain
out of step with the reality of the chemical processes involved.
Companies unwilling to address this will have both their reputation
and value compromised.
During the last twenty years within the UK oil industry alone, there
have been several major corrosion-related shutdowns of facilities
and pipelines that have each cost hundreds of millions of pounds
to rectify. Prudhoe Bay will shortly join a global list that has already
grown significantly with major repair projects initiated in Russia,
India and the Middle East, all driven by problems with corrosion.
How has this come about?
Firstly, it is important to draw a
distinction between internal and external corrosion. The former
largely affects mature fields that are well past their primary
production phase, where the initial expansion of fluids and gas
below ground is sufficient to drive the flow of wells. Instead, in this
later, secondary phase, large volumes of water (typically from the
sea or a river) are injected into reservoirs to displace the oil, rather
like a piston. With time, however, water migrates through the oil,
so that wells eventually produce more than 90% water near the
end of the field life.
Through water separation in surface facilities, often assisted by
chemicals known as de-emulsifiers, the water content of the oil
transported by pipeline for shipment at a port can be reduced to
just a few percent. Internal corrosion of the steel pipe is driven by
the presence of this remaining water, oxygen dissolved in it, and
sometimes other substances such as carbon dioxide and hydrogen
sulphide. The last of these can be generated by sulphate-reducing
bacteria that are inadvertently introduced into the reservoirs during
water injection. Many of the facilities most vulnerable to corrosion,
in general, are well past their notional 25-year design life.
Corrosion is controlled routinely by both chemical and physical
means. For example, oxygen is reduced during the water injection process, and biocides are also pumped into the reservoirs. A key
step is the injection of corrosion inhibitor chemicals into the
pipeline itself, and the use of emulsifiers to limit the separation of
oil and water within the pipeline. Furthermore, to stop any settling
of water at low points in the line, and also to clear sludge and wax,
cylindrically-shaped mechanical ‘pigs’ with scrapers are sent down
the pipeline (driven by the flow of oil), to be recovered with the
collected debris at the downstream end.
Monitoring the effectiveness of these steps is through a variety of
techniques. These include the use of small steel discs, or coupons,
set into the pipeline so that they are exposed to liquids inside.
These can be removed periodically for inspection and
measurement without disrupting operations. Another method has a
small strip of wire carrying an electric current inserted into the oil
flow. As this corrodes over time, its electrical resistance increases.
For pipelines that are readily accessible to technicians, an
ultrasonic probe placed on the outer surface will indicate the wall
thickness of the pipe. Finally, by sampling the liquids and
measuring the way the concentration of iron salts varies along the
pipeline, the loss of metal from the inside surface can be
estimated. Collectively, all these methods indicate how extensive
corrosion might be, and corrective action can be taken to address
this.
Source: http://www.rsc.org/images/Corrosion_tcm18-62363.pdf
No comments:
Post a Comment