For crude-unit overhead systems, pH is the main process
parameter that impacts corrosion rates. To control corrosion
conditions, many operators use various neutralizers at optimum
ranges determined by site-specific conditions. A four-year
study (20052008) was conducted at a Petrobras refinery using amine-blend
solutions to control pH. Over this period, corrosion rates were
measured through ultrasonic inspections and weight-loss
coupons. Important process parameters monitored included:
pH, chloride and iron concentrations at the
bottom of the overhead drum
Neutralizer and inhibitor flowrates.
A qualitative comparison was done with two refineries, using
two other neutralizers: sour water from fluid catalytic
cracking (FCC) unit and an ammonium aqueous solution. This
investigation proved that maintaining a low chloride level and
stable pH levels were the most effective ways to control equipment damage from corrosion.
Also, the study found that several inspection techniques were
particularly useful in estimating service life for pipes and
other crude-unit equipment. Applying better pH control and
improved monitoring and inspection programs can reduce
equipment damage from corrosion.
Hydrocarbon-processing companies follow different methods in
controlling crude distillation unit (CDU) overhead
corrosion. Common approaches include inhibitors to neutralize
acid solutions. Even with a good control on crude oil in
storage tanks and the desalting process, hydrochloric acid
(HCl) will still be present at the atmospheric tower overhead
and it demands proper chemical treatment. Merrick and Auerbach
performed a study on 129 different distillation units. From these
studies, it was observed that the average chloride
concentration was 10 ppm to 30 ppm in accumulator overhead
drums.1 Chlorides are generated from some salts
contained in the crude oil that is processed in the CDU; thus
HCl is formed.
There are three main ways to neutralize acidic aqueous
solutions at the CDU overhead; they include injecting:
Gaseous ammonia (NH3)
Ammoniac water (NH4OH solution)
Neutralizing amine solutions.
Regardless of the neutralization technique applied, the pH
is lower than the dew point of water. This adds more challenges
in measuring pH when condensation occurs; this is the preferred
region for the corrosion process to begin. Neutralization
HCl (aq) + NH3 (aq) => NH4Cl
HCl (aq) + RNH2 (aq) => RNH3Cl
One concern for neutralization is the difficulty of
controlling the ammonia or amine flowrates, which depend on the
varying HCl levels in the CDU. The neutralizer injection levels
can be too low and the pH in the overhead can drop. Excess
neutralizer levels, especially in the presence of hydrogen
sulfide (H2S), contribute to precipitation of salts,
such as ammonia or amine disulfides or chlorides. Once formed,
these salts (molten or solid) deposit on pipe surfaces,
likewise, they can cause localized corrosion with a high rate
of thickness loss. If salt formation occurs after condensation,
then its dissolution into water represents minimal corrosion
In this article, some field results are presented, including
chemical analysis, pH and corrosion rate for a CDU tower
overhead. A qualitative comparison was conducted investigating
the different ways to control corrosion, as listed in Table
At Refinery A, the observed corrosion rates in pipes, heat
exchangers and accumulator drum, were obtained from thickness
measuring via ultrasonic testing. Corrosion rates reached
values of 0.15 mm/yr. The heat exchanger tubes presented an
average service life of only seven years, and corrosion
deposits were found in baffle-plate regions. Some thickness
loss and stress-corrosion cracking were also reported on the
shells of the equipment, which can be attributed to high
H2S levels (2,553 ppm) in the neutralizing solution
At Refinery B, high chloride levels, caused by
inefficiencies in the crude preparation and desalting
processes, generated high corrosion rates. The average
corrosion rate observed by the coupon weight loss over two
years was 0.29 mm/yr. The pipes connecting the top of the
atmospheric tower and condensers have flaws from previous
campaigns. Localized under-deposit corrosion in the lower blank
of the condenser shell was observed.
At Refinery C, monitoring results for coupons installed in
the overhead condenser (air cooler), had average corrosion
losses of 0.16 mm/yr. This reflects a uniform thickness loss
expected in equipment and pipes. But there were failures in
pipes caused by localized under-deposit corrosion. In the air
cooler, the average tube service life was five years, and
failures were reported immediately after the flow entrance,
where condensation begins.
For this study, two regions of the overhead pipe were
selected at Refinery B to conduct thickness measurement via
ultrasonic testing. Initially, the testing was separated into
Overhead atmospheric tower and condenser
Between the condenser and accumulator drum.
Different behaviors are expected from the pipes carrying the
fluid before the condenser in the vapor phase (by design), then
after, where the water is already in liquid phase. Thus, the
observed corrosion rates were different, as shown in Fig.
1. CDU showing locations identified for
thickness monitoring by ultrasonic
The locations for thickness measurement are always chosen
based on the experience of the inspection team supervising the
unit and the measurements usually apply these aspects:
In the curves, the corrosion rates may be higher
due to an increased propensity for the occurrence of corrosion
associated with erosion.
Regions of encounter between two pipes, in the
form of T, are also preferred regions for
In the straight sections, fewer points are
selected, which are expected to be representative of the
In 2004, measurements were made on about 70 points before
the condensers. Another 70 points were inspected with the same
technique in pipes after the condensers. The same 140 points
were inspected again in 2005. The results allowed defining
several average corrosion rates:
Before the condensers: 0.14 mm/yr
After the condensers: 0.16 mm/yr.
Also, there were high standard deviations in both cases,
0.16 mm/yr before and 0.15 mm/yr after the condensers. The
highest rate observed in the first case was 0.63 mm/yr, and the
lowest 0.02 mm/yr. After the condensers, the highest rate was
equal to 0.61 mm/yr and the lowest 0.02 mm/yr.
Before the condenser, 25 points were measured again in 2008;
the average corrosion rate (20052008) was equal to 0.17
mm/yr. The data from the corrosion coupons indicated an average
rate of 0.19 mm/yr in the same period.
In December 2008 and June 2009, five points were measured in
random areas of the pipes before the condensers, resulting in
an average corrosion rate equal to 0.21 mm/yr. In the same
period, some corrosion coupons were analyzed monthly,
positioned on the inlet connections of overhead condensers;
these coupons had an average corrosion rate equal to 0.28
For Refinery B, the study was expanded to include how
operating conditions had contributed to equipment
deterioration. For example, in 2007, some studies researched
the impact from the chloride content variations in the feed at
the pre-flash tower overhead, while the corrosion rates were
measured by coupons. Due to the ineffectiveness of desalting,
there was a direct influence on the corrosive process in the
overhead system, as is illustrated in Table 2. During these
periods, electrical problems caused transformer problems that
affected the inner electrodes to the desalting drums. Poor
desalting of the crude led to chloride levels above 1,000 ppm
in the overhead accumulator drum. Also, pH was affected,
reaching values approximately 4. Weight-loss coupons were
installed in the inlet connections of the atmospheric overhead
To improve desalter efficiency at full operating conditions,
more tests were made by adjusting the differential pressure of
the mixer valve. Usually covered with ∆P = 1
kgf/cm², this value was increased by 0.2 kg/cm².
Result: Without any other changes in operating
parameters, a reduction of 44% in the chloride content in the
accumulator drum was obtained.
In the overhead atmospheric system, pH, chloride, iron and
corrosion rates were monitored by weight-loss coupons. Fig. 2
shows the historic data of pH values measured in the
accumulator drum since 2008. The figure shows the mean values
and standard deviations for measurements over each month,
except May and September, when there were no analysis
2. Historic data of pH values in the
overhead accumulator drum of the
atmospheric tower for refinery B.
It is observed that the average pH over the years has always
been very close to or within the recommended range. But the
high standard deviations showed a lack of control during some
periods. There were some incidents in January in which a pH
reaching 1.5 was observed and adjusted to 3 on the same day and
recovered to a pH = 6 on the next day. On two days, the pH
reached 4. The higher standard deviation observed in this month
contributed significantly to increased corrosion rates.
Fig. 3 shows the measured chlorine values in the same drum.
The target is 40 ppm as the maximum, which can only be
guaranteed with efficient control in crude preparation at the
storage tanks and desalter.
3. Historic data of chloride values in
overhead accumulator drum of the
atmospheric tower for Refinery B.
It is observed that the values remained above the recommended
targets throughout the year, showing deficiency in the early
stages of crude processing. As an immediate consequence, we can
expect greater usage of neutralizers and corrosion inhibitors.
What is not always sufficient to maintain is the appropriate pH
and low corrosion rates over slack periods, as observed in
January (average of 108.96 ppm chloride).
4. Historic data of iron values in
overhead accumulator drum of the
atmospheric tower for Refinery B.
The iron level in the water was also monitored. Iron can be
another indicator of corrosion in the overhead system. In Fig.
4, the measurements from 2008 are shown; conditions exceeded
the maximum value of 1 ppm over the year. Also, we can observe
that the iron content was below the recommended limit 4 of the
10 months evaluated. These results vary greatly over the month,
with standard deviations above the mean values; the data is not
included in Fig. 4. Intakes of neutralizing solutions and
corrosion inhibitors also represent relevant data on analyzing
control parameters in the overhead system. Figs. 5 and 6 show
the injection rates for neutralizers and inhibitors for
Refinery B in 2008.
5. Historic data of neutralizer amine
flowrates at overhead pipe in the
tower for Refinery B.
6. Historic data of inhibitor flowrates
overhead pipe in the atmospheric tower for
The mass balance at the tower overhead is shown in Fig. 7.
It is known that the chloride content measured in the top
accumulator is directly linked to the presence of HC1 formed
from the hydrolysis of salts present in the feed. Thus, it is
possible to set base values for neutralizing agent flowrates.
From the condensate analysis in the overhead drum, several
periods were selected in which the chloride content was close
to 100 ppm, or 50% of this, 50 ppm. On the same dates, the
average flowrates of the neutralizing solution and pH were
recorded, as listed in Table 3.
7. Mass balance of the atmospheric
overhead systemRefinery B.
With the pH near the equivalence point, if we consider only the
presence of HCl, neutralizer and water, the result is salt
formation, N2Cl, which dissociates. We can determine
the resulting pH; the reactions are:3
N2Cl j N2+ + Cl- (1)
N2+ + H2O = N2OH + H+
From the salt concentration, it is possible to determine the
As Ka is very low, the salt concentration
Cs = [N2+]:
There are many other contaminants in the overhead system,
such as H2S, ammonia (NH4), sulfur oxides
(SOx) and others that can alter conditions and force
changes on the predicted pH values. We cannot establish a
direct relationship between the chloride (Cl-),
flowrate and pH neutralizer from field results.
However, we can determine the salt concentration (N2Cl) from
the N2 solutions, as described in Table 4, and compare it with
the expected resulting pH. Table 4 lists the results; observing
that, in a few cases the values coincide, as in D1, D3, D4 and
D5, and the neutralizing added on top is extremely diluted into
the total water solution (264,000 l).
Corrosion monitoringweight-loss coupon.
Fig. 8 shows the historic data of the weight-loss coupons,
installed on the inlet connection of the overhead condenser.
There were many lack periods, in which the corrosion rate is at
greater than the established limit (0.125 mm), such as in
November 2004 (0.60 mm/yr), January 2008 (0.53 mm/yr) and
November 2008 (0.55 mm/yr).
8. Weight loss monitored by corrosion
coupons, installed at the inlet connection
the overhead condenserRefinery B
November 2004 to May 2009.
At the three refineries presented in this study, various
problems caused by corrosion are sourced to low operating
efficiencies in the crude desalting unit, which is initiated at
the storage tanks. Checking field data and literature to find
benchmark values for evaluating the effectiveness of existing
desalters can help maximize salt-removal efforts.4
Also, leakages observed in pipelines in Refineries B and C were
mainly caused by deficiencies in pH control. This is the main
control parameter in the tower overhead, and it must be kept
within the range with the minimum possible deviation. We could
not associate a neutralizer type to observed failures.
The results of Refinery B showed that even with at stable pH
behavior over the study period, corrosion increased. The
standard deviation observed during 2008 was 0.54, with daily
routine measurements. This value is consistent with observed
deviation cited in the literature, equal to 0.78, when gaseous
ammonia was used as a neutralizer in the same
The literature shows that low pH values lead to high
corrosion rates on mild steel, even though the presence of
inhibitors may be insufficient to alleviate this
problem.6 Conversely, a pH too high can also bring
Using excess neutralizing solutions, based on
amine or ammonia, favors the occurrence of deposits, leading to
localized corrosion with extremely fast kinetics.
In stream containing H2S, such as the
CDU, stability of the protective iron-sulfide film is
compromised while increasing its solubility, thus accelerating
We can analyze a phase diagram for H2O-HCl and
correlate it to the overhead corrosion process.8 It
is possible to observe a temperature range of approximately
100°C to 102°C, in which an average concentration
observed in the field (0.7% HCl), and in which two phases are
present in equilibrium conditions: vapor (rich in water) and
liquid (rich in HC1). At the temperature where condensation
begins, the HCl concentration in the liquid is 10 times higher
than vapor phase. Only below 100°C, in equilibrium
condition, the steam is fully condensed, and the final
concentration of the liquid is reached. In Refinery C, this
behavior was well marked, as leakages occurred in the starting
point of condensation on the overhead air cooler, while the
rest of the pipes were found in good conditions.
To increase the process data analysis, the measured
consumption of neutralizing amine in the overhead during 2008
were compared with values originally estimated by the
supplierdata presented in Table 5. The comparison was
done in a period in which the main process variables, such as
pH and chloride content in the overhead drum, did not suffer
interference from typical discontinuities, such as high levels
of base sediment and water in oil. The selected period was the
months of June 2008 to August 2008, in which the corrosion rate
was below the recommended target of 0.125 mm/yr, as shown in
Application of neutralizing amine can be varied for many
reasons, such as incorrect pH measurement, which interferes
directly in injection flowrate. If the quality of the crude is
kept almost constant, the product amount injected into the
overhead stabilizes. This is the condition studied in the
chosen periodoptimum injection to compare the predicted
with the far field. From Table 5, the relationship between the
measured and predicted consumption of neutralizer is
For a maximum chloride content of 50 ppm at the overhead
using data of steam injection background and specific
consumption provided by the manufacturer, the amount of amine
provided at the top would be 60 l/d, while in practice, keeping
variables under control, the measured consumption was 120 l/d.
We can conclude that the predicted flowrate for the
neutralizing solution can be a guide for the process, but only
constant pH monitoring (preferably online) can promote adequate
control for amine injection.
Corrosion rates are directly proportional to
pH. Accordingly, field monitoring uses weight-loss
coupons to validate the quality of process parameters control.
At Refinery B, measurements were made from 2004 until early
2009, when only 45% of cases were below the limit0.125
mm/yr. Throughout 2008, the weight loss was framed in only 30%
of the months monitored. Comparing these results with
inspections by thickness measurement, we realized that the
difference between the rates obtained with both techniques was
short only at the second decimal number, as shown in Table
This study listed a number of results available in many
CDUs. But the relationship between them can generate even more
support for inspection teams that manage equipment integrity.
From the temperature (T) and pressure (P) in
the overhead pipe, it is possible to estimate if water vapor
and its components reach the dew point before the condenser.
The pH measured in the accumulator drum indicates how the
developed corrosive process will progress throughout the
system. The chloride content, which is directly related to the
flowrate of the neutralizer, also increases corrosion at high
values, even if the pH is controlled. Injecting inhibitors can
reduce corrosion rates but not with the same intensity as pH
adjustments. Thus, we must work to meet the primary objective
of the refinery integrity program: to reduce unplanned
shutdowns, identify root causes for corrosion degradation of
equipment and ultimately develop a good corrosion monitoring
Conclusions. Among the available neutralizing solutions,
refiners should use the one that provides the best efficiency,
coupled with the cost benefit for each unit, while considering
environmental aspects from waste
generation and final treatment. There are pros and cons
associated with each neutralizer.10 The results
showed that the type of neutralizer used on the CDU atmospheric
tower overhead was not the determining factor in
minimizing corrosion. Only a good control of process
parameters, especially the desalting efficiency (low chloride
level at the overhead accumulator drum), can increase equipment
service life. We can also establish a direct relationship
between the historic data of the process parameters (chloride
level, pH, temperature and pressure) and the expected thickness
loss of the equipment and pipes.
Monitoring weight-loss coupons is essential to validate the
quality of the process parameters control. At Refinery B,
the rates obtained with the coupons were compared to results
from inspections by ultrasonic thickness measurement, where
only a small difference in the second decimal number (0.02 mm
to 0.07 mm) was observed. With these low rates and constant
monitoring, the likelihood of failure is minimized, and it
becomes possible to predict damage to equipment and avoid
unplanned shutdowns due to equipment failures by corrosion.
Plant results and literature data indicate that there is an
optimal pH control range for the CDU overhead system. The main
process parameter, defined in terms of two main corrosion
At low pH (pH below 5.5) the HCl causes severe
corrosion in the mild steel
At high pH (pH above 6.5), due to the presence
of H2S, there is an increase in the uniform
corrosion rate due to the breakdown of the iron sulfide layer,
and localized corrosion under deposit is also more likely to
occur because of the salts formed.
For each system, an optimal range should be specified. It
will depend on the chemical composition of the final solution
obtained in the accumulator drum. It is important to note that
pH stability is dependent on system automation. More reliable
online information enables low deviations if there is an
instrumented injection control fed by online pH measurement.
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unit overhead corrosion control, Materials
Performance, September 1983, p. 15.
2 Couper, A. S. Bothered by corrosion of
your crude-unit condensers?, Oil & Gas
Journal, July 1964, p. 79.
3 Harris, D. C., Quantitative Chemical
Analysis, 7th ed., California, 2006.
4 Gutzeit, J. Controlling crude unit
overhead corrosion by improved desalting, Hydrocarbon Processing, February
2008, p. 119.
5 Jambo, H. C. M., D. S. Freitas and J. A. C.
Ponciano, Ammonium hydroxide injection for overhead
corrosion control in a crude distillation unit,
International Corrosion Congress, Granada, Spain, September
6 Gutzeit, J. Effect of organic chloride
contamination of crude oil on refinery corrosion, Nace,
Orlando, Florida, March 2000.
7 Sardisco, J. B. and R. E. Pitts,
Corrosion of Iron in an
Composition and Protectiveness of the Sulfide Film as a
Function of pH, Corrosion, November 1965.
8 Potolokov, V. N., V. A. Efremosv, S. V.
Nikolashin, T. K. Menshchikova, E. G. Zhukov and V. A. Fedorov,
Liquid-Vapor Equilibrium in the AsCl3-HCl-H2O
System, Inorganic Materials, September 2006, p.
9 Ropital, F. Current and future corrosion
challenges for a reliable and sustainable development of the
chemical, refinery, and petrochemical industries,
Materials and Corrosion, July 2009, p. 495.
10 Jahromi, S. A. J. and A. Janghorban,
Assessment of corrosion in low carbon steel tubes of Shiraz refinery air coolers,
Engineering Failure Analysis, November 2004, p.