216 METALLURGY AND CORROSION CONTROL IN OIL AND GAS PRODUCTION
ISO 15156 is primarily concerned with hydrogen - related
cracking phenomena.
Weight loss corrosion can also occur under high -
temperature high - pressure downhole conditions. The
models for H
2
S corrosion are less widely known and are
not often used. The scales formed by downhole H
2
S
corrosion are often hard and compact, unlike the more
porous carbonate scales formed in CO
2
- rich environ-
ments. Relatively thick iron sulfi de corrosion products
can restrict fl ow in a manner similar to the scales formed
from carbonate or other mineral - rich fl uids. Unlike the
scales shown in Figure 3.24 , which come from precipita-
tion of produced fl uids as temperature and pressure
conditions change in wells, this plugging is due to cor-
rosion, but it can have the same undesired effect of
restricting oil well production rates.
31
A recent report discusses weight loss corrosion and
proposes explanations for corrosion in H
2
S - containing
waters. The parameters associated with when weight
loss corrosion occurs in wells containing H
2
S and/or
CO
2
are illustrated in Figure 8.12 .
31
This model for cor-
rosion prediction is very complicated, is only recently
presented, and has not been confi rmed by other opera-
tors. It only serves to illustrate how complicated an
understanding of downhole corrosivity is likely to be.
Predictive models are no substitute for monitoring and
inspection once production begins, and changes in cor-
rosivity as fi elds age are to be expected.
Most of the long - recognized environmental variables
on corrosivity of oil and gas production are associated
with three gases — oxygen, CO
2
, and H
2
S — and were dis-
cussed in detail in Chapter 3 , Corrosive Environments.
Less attention has been paid to the infl uence of organic
acids. These relatively small organic molecules have
similar molecular weights, and volatility, to the heavier
components in natural gas. Examples of organic acid
terms appearing in the oilfi eld corrosion literature
include carboxylic acids (formic acid, acetic acid, propi-
onic acid, etc.), formates, acetates, propionates, fatty
acids, and oxalic acid. All of these organic acid formers
have similar properties. As organic chemicals, they tend
to be less ionic than mineral acids (hydrochloric acid —
HCl, nitric acid — HNO
3
), but they can be signifi cantly
ionic and corrosive in some fl uids, such as condensates,
especially at elevated temperatures when they will tend
to become more ionic than at lower temperatures. CO
2
pitting corrosion in the absence of organic acids may not
occur. “ There is no record of CO
2
corrosion in a produc-
ing well in the absence of acetic acid. ”
37
This may only
mean that whenever acetic acid (the second smallest of
these organic acids) was present in natural gas streams,
it was detected and reported while formic acid, which is
smaller, plus propionic acid and other organic acids
likely to have been in the same produced fl uids, were
CO
2
corrosion models developed by K. DeWaard and
coworkers, which are some of the fi rst mathematical
models to have been proposed. These early models have
been widely adopted and discussed. Many operators
fi nd that the corrosion rates predicted by the DeWaard
and associates approaches tend to predict corrosion
rates higher than experienced in fi eld exposures. Most
of the newer models do an excellent job of predicting
corrosion rates under the controlled laboratory testing
conditions used for their development, and they have
been verifi ed by laboratory experimental data.
Unfortunately, unidentifi ed or non - included fi eld condi-
tions, often minor production fl uid constituents, are not
recognized in these models, and predicted corrosivity in
the design process must be confi rmed by monitoring
and testing once production starts.
26
Changes in pro-
duced fl uid characteristics also necessitate continuous
monitoring, especially for gas wells.
26,27,33
As produced
fl uid corrosivity increases, the need for more diligent
monitoring and inspection also increases. This often
happens at times when decreased production rates
suggest to management that lowered inspection and
maintenance budgets, which are often based on fi eld
production income, tend to also decrease.
CO
2
or sweet corrosion is the most common environ-
mental problem causing weight loss corrosion in oil and
gas production. H
2
S is substantially less corrosive, as was
shown in Figure 3.3 , which compares the infl uence of
dissolved oxygen, CO
2
, and H
2
S on water corrosivity.
Unfortunately, H
2
S, or “ sour ” weight loss corrosion as it
is often termed,
20
is not the only problem associated
with H
2
S production. Absorbed hydrogen from H
2
S
can also lead to various forms of hydrogen - related
cracking.
While the term “ sweet corrosion ” has historically
been used to indicate oilfi eld corrosion under condi-
tions where dissolved CO
2
in the aqueous phase lowers
in situ pHs, it is also used to differentiate between
conditions where the downhole fl uids have enough H
2
S
to come under the guidance of NACE MR0175/ISO
15156. The parallel term “ sour corrosion ” implies
corrosion in fl uids with enough H
2
S for MR0175/ISO
15156 to apply.
Most new oil and gas wells are now completed under
the assumption that they will eventually become “ sour ”
and produce undesirable levels of H
2
S. The appropriate
guidance for these designs should usually be NACE
MR0175/ISO 15156 with the publication date speci-
fi ed.
16,26,28,34,35
This standard, like many others, undergoes
periodic updates and changes, and it is important that
the appropriate version of any standard be understood
by all parties concerned, often several decades after the
design and installation of original equipment has been
accomplished.
36
Readers are cautioned that MR0175/
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