Hydrocarbon Processing - October 2021 - 76

Water Management
which allow water to penetrate through
various channels. As the water approaches
the tube surface, temperatures increase.
The water boils off, leaving other species
behind. This phenomenon is known as
wick boiling (FIG. 4).
Boiler water impurities, including treatment
chemicals, can concentrate many
times at the tube surface and induce corrosion
(sometimes severe) that may lead
to rapid boiler tube failures. A common
reaction in boilers subject to contaminant
ingress is shown in Eq. 1:
MgCl2
+ 2H2O→
Mg(OH)2
↓ + 2HCl
(1)
One product of this reaction is hydrochloric
acid (HCl). While HCl can cause general
corrosion in and of itself, the compound
will concentrate under deposits where reaction
of the acid with iron generates hydrogen,
which in turn can lead to hydrogen
damage in the tubes. In this mechanism,
atomic hydrogen penetrates into the steel
and reacts with carbon atoms to generate
methane (CH4
4H + Fe3C→ 3Fe + CH4
), as shown in Eq. 2:
↑
(2)
Gaseous methane and hydrogen molecule
formation induces cracking, greatly
weakening the steel's strength. Hydrogen
damage is troublesome because it cannot
be easily detected. After hydrogen damage
has occurred, the plant staff may replace
tubes only to find that other tubes continue
to rupture (FIG. 5).
One may consider an important twist
to this example. As will be discussed later,
sodium phosphate compounds, and sometimes
even straight caustic (NaOH), are
added to boiler water to maintain alkalinity
and minimize general corrosion. However,
under heavy deposits, sodium hydroxide
concentrations can rise to much higher
levels than in the bulk boiler water. The
concentrated NaOH attacks the boiler
metal and protective magnetite film via the
following reactions, shown in Eqs. 3 and 4:
Fe + 2NaOH→ Na2FeO2 + H2↑ (3)
Fe3O4
Na2FeO2
+ 4NaOH→ 2NaFeO2
+ 2H2
+
O (4)
FIG. 3. Influence of deposits on boiler tube wall
temperatures. The increase in wall temperature
can degrade metal integrity and lead to
premature failures from metal deformation.
The upshot of these examples is that
chemistry throughout the steam generation
system requires careful control to
minimize corrosion and corrosion product
transport. Modern methods for this
purpose are examined in the next section.
Temperature, °F
100
80
60
FIG. 4. An illustration of wick boiling.
40
20
FIG. 5. Hydrogen damage. Note the thicklipped
failure with little metal loss from direct
corrosion.
76 OCTOBER 2021 | HydrocarbonProcessing.com
50
100
150 200 250 300 350
Temperature, °C
FIG. 6. Influence of temperature and pH on
iron dissolution from carbon steel.1
100
200 300 400 500 600
NH3
[mg × kg-1
0.1
0.2
0.3
0.5
1
2
]
8.75
8.9
9
9.2
9.4
9.6
pH
Feedwater and condensate return
system protection. A critical requirement
for steam generating systems is
proper pH control to minimize general
corrosion. An extremely informative
graph of the effects of pH and temperature
on carbon steel corrosion was prepared a
half century ago and is shown in FIG. 6.
This research was conducted in highpurity
water samples. A key aspect of this
chart is the influence of pH on carbon
steel corrosion, which greatly decreases
with pH elevation from 8.75 to 9.6. Note
that the results were based on pH adjustment
with ammonia (NH3
), the common
feedwater pH-conditioning chemical for
power plants, especially those with no
copper alloys in the feedwater system.
Ammonia raises the pH via the reaction
shown in Eq. 5:
NH3 + H2O ↔ NH4
+ + OH-
(5)
Eq. 5 is an equilibrium reaction; therefore,
the alkalinity increase is limited, minimizing
excessive steel corrosion in the event of
a chemical feed upset.
Complications arise in many industrial
condensate systems as they have multiple
metallurgies, often including copper alloy
heat exchanger tubes. Ammonia and dissolved
oxygen in combination are very
corrosive to copper. Furthermore, the optimum
pH range for general copper corrosion
control is 8.8-9.1, somewhat lower
than the pH range for carbon steel. In systems
with both carbon steel and copper
alloys, a balanced pH range of 9-9.3 is often
recommended. Accordingly, for many
industrial units, neutralizing amines may
replace ammonia. Neutralizing amines
are small-chain organic molecules with an
ammonia group attached to or embedded
within the compound (FIG. 7).
Some of the amines have a higher basicity
than ammonia and can raise the pH to
higher levels if necessary. Another important
property of these chemicals is the distribution
ratio-i.e., the amount of amine
that carries over with steam vs. the amount
that remains in the water. The ratios vary
with boiler temperature and pressure, but
some products tend to remain in the boiler
water while others significantly partition
with the steam. Careful selection of a
blended product can provide comprehensive
pH conditioning to the boilers, steam
system and condensate return network.
Also important for condensate/feedwater
treatment is choosing an oxygen
Fe, µg × kg-1
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