Page 200 - Challenges in Corrosion Costs Causes Consequences and Control(2015)

178 CORROSION CAUSES

According to J&H Marsh and McLennan, Inc., in the hydrocarbon processing
industry (HPI) market data 2000 report (34), approximately 45% of large losses are
because of mechanical failure of equipment. Equipment such as piping, tanks, reac-
tors, process drums and towers, pumps and compressors, heat exchangers, heaters,
and boilers fail regularly.
The most important raw material in the HPI is crude oil that often contains some
water. Corrosive species present in oil–water mixture consist of sulfur compounds,
chlorides, ammonia, sulfuric acid, hydrochloric acid, polythionic acid, carbonic
acid, phosphoric acid, naphthenic acid, and cyanides. In spite of the treatment for the
removal of these corrosive species, trace amounts are left behind in the water. These
trace amounts of corrosive species are responsible for corrosion. Water, used in
large quantities by hydrocarbon processing plants for cooling, heating, and purifying
process streams, is another source of corrosives and foulants. Chlorides, sulfates,
magnesium, and calcium salts dissolved in water-cooling systems can cause scale,
sludge, and corrosion. Water in the process stream can accelerate corrosion as it acts
as an electrolyte and dissolves certain materials.
Three types of corrosion have been identified. The first type of corrosion can
be identified by visual examination. The second type of corrosion may require
supplementary means of examination. The third group requires studies involving
optical or electron microscopy, which may sometimes be amenable to study by the
naked eye.
The first group consists of general, localized, and galvanic corrosion. Localized
corrosion includes both pitting and crevice corrosion. The second group consists of
velocity effects such as erosion, corrosion, and cavitation; intergranular attack (IGA)
where grain boundaries are preferentially attacked; and dealloying corrosion. The
third group consists of cracking phenomena, and high-temperature corrosion cracking
phenomena include SCC, hydrogen-assisted cracking (HAC), liquid metal cracking
(LMC), and corrosion fatigue.
The Materials Technology Institute (MTI) of the Chemical Process Industries, Inc.
published a compilation of experiences of corrosion failure mechanisms in process
industries (35).
Cracking was found to be the most frequent failure mode. Cracking ranged from
27% to 36% of the corrosion failure mode. General corrosion was the next most
frequent (17–26%) mode followed by 12–20% of localized attack. In the case of
localized attack mechanisms, pitting was the most frequent failure mode followed by
intergranular corrosion. The study found that steel and stainless steel were involved
in the majority (48–61%) of the SCC failures reported.
The MTI report (35) listed the corrosion failure modes along with the frequency
of the occurrence as follows in Table 3.12.
The reported data on failures was collected from five companies and a total of more
than 1272 failures. The failure mode of cracking includes SCC, fatigue cracking and
caustic cracking.
The distribution of SCC of different materials of construction is as follows in
Table 3.13.