For decades, neutralizing and filming amines have been used
to protect steam condensate in boiler systems. In refining operations, where steam is
utilized to improve fractionation, added attention is needed to
the type and amount of amines added to the boiler/steam system
to minimize amine chloride salt fouling in the distillation column and crude
overhead. New technology in volatile filming
corrosion inhibitors and lower-salting neutralizing amines can provide
cost-effective solutions for the steam-condensate system and
minimize the risk of corrosive amine chloride salt formation.
This approach is useful for refinery operations working to
maximize distillate production while maintaining protection of
difficult-to-treat steam condensate systems, e.g.,
flashed steam, and high-alkalinity makeup water sources.
Protecting steam systems
Ensuring the efficiency and reliability of the steam plant is
crucial to successful refinery operations. Steam condensate and
boiler feedwater (BFW) protection are integral parts of
maintaining the total health of the entire steam and boiler
system. By mitigating condensate corrosion, the associated
equipment and piping are protected. Additionally, by protecting
this system, the condensate can be returned to the boiler as
high-quality feedwaterthus, recycling valuable water and
conserving energy. Finally, minimizing the return of corrosion
products greatly improves the efficiency and reliability of
steam-generating equipment while minimizing the need for
Traditionally, refineries have used organic amines to
neutralize acidic contaminants, such as carbonic acid, in the steam
condensate and raise system pH to prevent corrosion. Refineries
may also supplement the neutralizing amine program with a
filming corrosion inhibitor. These corrosion inhibitors,
including the subset known as filming amines, establish a
tenacious barrier film on the metal surface, thus inhibiting
contact of the corrosive contaminants (such as carbonic acid,
dissolved oxygen and chloride salts) with metal surfaces. A key
advantage of effective filming corrosion inhibitors is that
they can be fed sub-stoichiometric to the acidic contaminant,
thus reducing total treatment costs.
In many cases, an effective filming inhibitor can reduce the
requirement for neutralizing amines by providing equivalent
corrosion protection at an incrementally lower condensate pH
than with the neutralizer alone. This can reduce treatment
costs, especially where amine feedrates are high. Historically,
traditional filming inhibitors, such as octadecylamine, should
be injected into the steam header because of their low
volatility and limited ability to enter the steam phase from
the boiler when fed to the feedwater.
Consequently, achieving effective system coverage is often
difficult with traditional filming inhibitors of limited
volatility. For example, many refineries produce and utilize
lower-pressure flash steam generated from
higher-pressure liquid condensate. This flashed steam, often
used for critical reboilers, can be heavily laden with carbon
dioxide (CO2), thus increasing the corrosion
potential in the affected condensate. A filming inhibitor with
limited or no volatility will not readily enter the flash steam
from the condensate, which may leave the downstream equipment
served by the flash steam vulnerable to severe corrosion.
Consequently, satellite feed of traditional neutralizing and/or
filming inhibitors to these areas is often required for
effective protection, requiring maintenance of the remote feed
system, pumps and product inventory.
Polyamine volatile filming inhibitor technology
A new polyamine filming inhibitor technology can allow
effective steam-condensate system coverage and protection from
one injection location, often the deaerator storage section, as
shown in Fig. 1.1 This is in sharp
contrast to the extremely low volatility of traditional filmers
| Fig. 1.
Steam-liquid distribution coefficients
for a polyamine as measured in research
An additional hurdle for steam treatment is maintaining
reliability of the equipment utilizing steam directly within
the process. A prime example is the atmospheric crude distillation tower, where stripping
steam is used to improve product separation. In this tower,
neutralizing amines are used for steam-condensate treatment and
also to minimize the risk of amine chloride salt fouling and
subsequent corrosion. As refiners decrease tower top
temperatures to increase distillate production, the risk of
amine chloride salt formation inside the distillation column
Amine chloride salt fouling depends on a number of factors
including: chloride levels, operating temperatures/pressures of
the distillation column, other sources of unwanted or tramp
ammonia/amines, and even amines used to protect the overhead
and associated exchangers, as shown in Fig.
| Fig. 2.
Amine sources with a refinery
and recycle loops.
These problems are more directly related to steam-treatment
additives in systems where higher levels of neutralizing amine
are required to maintain condensate corrosion protection. This
is often the case in utilizing high-alkalinity BFW and/or a
lower-percentage condensate return. The problem is compounded
in fractionation towers operating at lower temperatures where
the amine chloride salt point can potentially be driven into
the distillation column.
Unless crude oil selection, additives and impurities, and
operating parameters are consistently favorable, it is
recommended to use steam-condensate protection that will
provide minimum impact on refinery operations. There are new
steam-condensate corrosion inhibitor technologies now applied
to use lower-salting neutralizing amines for steam treatment.
In combination with the volatile polyamine filming technology,
this approach can potentially provide a lower-cost and
more-reliable steam-condensate program.
An integrated approach
A collaborative effort between water and process engineering
teams discovered a unique solution to ensure maximum
reliability of crude unit distillation processes while
providing superior condensate protection. Proprietary modeling
software was used in the development and application of the new
technology.2 Utilizing low-salt ionic equilibrium
modeling in combination with condensate modeling software, many
potential steam neutralizing amines were evaluated for their
compatibility with the refining process and their effectiveness
in managing corrosion in complex condensate
systems.2 This study included a rigorous examination
of the potential for forming amine chloride salts under
different contaminant loadings and operating conditions in the
atmospheric crude unit tower. Table 1 lists
comparative salt-point temperatures of typical neutralizing
amine blends used in refining steam condensate treatments.
Additionally, it was critical to uphold the required critical
parameters of neutralizing amines used in steam-condensate
treatments, which include the neutralization capacity,
basicity, steam-liquid partition coefficient or distribution
ratio, and thermal stability at boiler and steam temperatures.
A key component, the polyamine volatile filming corrosion
inhibitor, is typically included with the low-salting amines to
further enhance system coverage and reduce the traditional
neutralizing amine required for corrosion protection.
Consequently, the total tramp amine contribution
from the stripping steam can be reduced.
Because the modeling program can be used to simulate the
potential for ammonia or amine chloride salt formation in crude
atmospheric towers and to optimize the model amines and
contaminants in complicated steam systems, a more comprehensive
approach to refinery system reliability can be
taken.2 The combined modeling approach allows the
refiner and specialty chemical supplier to work together to
optimize refinery operations while maintaining the required
process and water treatment reliability.
For example, by modeling a refinerys steam condensate
system, the refinery operator and process chemical supplier
have a better understanding of the amount and type of amines
present in the stripping steam. Using that information,
combined with an understanding of the other ammonia/amine
sources and contaminants (e.g., chlorides), a more accurate
model of the atmospheric tower can be derived. This model will
then enable the refiner to better understand their operating
limitations and allow them to maintain optimal reliability and
Low-salt boiler amine and polyamine
Low-salt boiler amine and polyamine technology can provide an
opportunity to further optimize refinery boiler and process system
economics.3 Several refiners have reported
encountering limited optimizing economics due to tramp
ammonia/amines, often when trying to maximize mid-distillate
production and running at lower fractionation tower top
In some cases, it is the amine in the stripping steam that
can be the limiting factor, and low-salting amines were
recommended to reduce/eliminate the bottleneck.3 Two
refining cases reported small
amounts of traditional amines used in steam-condensate
treatment, cyclohexylamine and methoxypropylamine (MOPA), were
limitations in maximizing profitability. A compilation of
abbreviated case studies are documented in this article.
| Fig. 3.
Nonwettable surface provided
by polyamine filmer on corrosion coupons.
Case 1: Low-salting boiler amine with no polyamine
One particular refinery was having concern around a
particular steam-treatment amine. This refinery had suffered
some amine chloride deposits in a crude unit top pumparound
circuit. Prior to implementing the polyamine technology, its
goal was to use a low-salting boiler amine to achieve the same
pH and consequently, the same iron level achievable with
industry-standard amines in use. The refinery implemented the
low-salting boiler amine blend to replace the higher salting
amine from the steam.3 Condensate system modeling
was done to predict the required feedrates based on water
chemistry and system operating parameters and targets. The
low-salting boiler amine achieved the required system pH levels
as predicted. As a consequence, the steam-condensate pH and
iron levels remained approximately the same, as illustrated in
Fig. 4. Although satisfied with the initial
change to low-salting boiler amine chemistry, this refinery
converted to a low-salt and polyamine technology to further
optimize performance and economics.
| Fig. 4.
pH and iron levels controlled by a low-salting
Studies with polyamine and standard amines
Refineries utilizing BFW with high levels of
bicarbonate/carbonate alkalinity can generate significant
CO2 in the steam and, consequently, elevated levels
of corrosive carbonic acid in the condensate.
These refineries are often challenged to feed enough
neutralizing amine to achieve the required steam-condensate pH
levels to protect the condensate piping and equipment. The use
of condensate flash tanks to generate low-pressure flashed
steam, often for nonvented reboilers carrying
liquid levels, can also operate under highly corrosive
conditions because of the very high volatility of
CO2 to the flashed steam, as illustrated in
| Fig. 5.
Model of amine and CO2 distribution
and pH in a flash tank.
Under these circumstances, it can become very difficult and
expensive to maintain corrosion protection by relying only on
carbonic acid neutralization and boosting the pH. In addition,
the high use of amines can have an adverse impact on the
refining operations. In these situations, it is often best to
provide a filming technology.
A European refinery was experiencing
severe corrosion of reboilers/exchangers on a desulfurization
unit that used steam with a pH < 6. Due to the corrosion
problems, the refiner was replacing unit bundles about every 18
months. Traditional neutralizing amine treatment would require
very high feedrates and be deemed uneconomical. As a result, a
polyamine-neutralizing amine blend was applied at about 10% of
the theoretical neutralizing amine blend only
feedrate. Almost immediately after initiating the chemistry,
the measured total iron levels at the reboiler dropped
Reboiler total iron prior to polyamine-amine > 500
Reboiler total iron after polyamine-amine < 50 ppb
More importantly, during the last scheduled maintenance on one of the reboilers,
the refinery was set to replace the bundle per its normal
schedule. However, the inspection determined that no bundle
replacement was needed because of the improved corrosion
A similar application at a Southeast US chemical plant
showed a tremendous reduction in mild steel condensate
corrosion rates with the addition of the polyamine to the BFW.
This particular plant had high-alkalinity BFW contributing over
20 ppm of CO2 to the steam and no appreciable
condensate return. Consequently, the amine requirement for
neutralizing the carbonic acid and increasing the pH
was significant and uneconomical. A plan was developed to add
polyamine and begin reducing the neutralizing amine.
Fig. 6 illustrates the results regarding the
corrosion rates and mild steel coupon. The plant continues to
optimize, and has reduced neutralizing amine by over 70% while
improving the mild steel and the copper corrosion rates.
| Fig. 6.
Field study using a polyamine treatment program.
Case 4: Low-salt polyamine blend
A Western US refinery was in the scenario of having high
condensate corrosion potential and ammonia/amine chloride salt
fouling in the crude and coker operations. To improve
operations, key system treatment and corrosion data were
evaluated on both the water and process chemistry. Computer
modeling of the systems was conducted to predict, select and
validate the specific type of low-salt and polyamine chemistry
that would be appropriate to improve the reliability and
economics for the refinery.
With implementation of the program, the amine salting
potential was improved by removing nearly all of the higher
salt-point amines from the boiler steam treatment. The
steam-condensate pH and iron levels were regularly tested to
ensure that corrosion metrics were being met. After several
weeks of onsite iron testing and offsite iron corrosion product
(ICP) testing, the low-salt polyamine feedrate was decreased
further. This change also further reduced the total amine
contribution from the stripping steam in the crude tower, while
improving economics around chemical spend (Table
2). However, as modeling had predicted, this action
would lower condensate pH levels in the steam condensate
system. It included carrying a lower pH at some critical,
nonvented reboilers in the system. Now, more of the corrosion
protection responsibility was placed on the polyamine filmer.
Chemical usage was minimized, while increasing reliability in
steam condensate and refinery process via low-salting amines
and filmer protection.
After several more weeks of analysis, the corrosion
protection was maintained per onsite data and more accurate ICP
offsite ICP iron data indicated an improvement. Four of the
five samples in the system, including a nonvented reboiler,
showed less-than-detectable iron and copper levels
(Fig. 7). Another reboiler had very
low iron (< 2 ppb per ICP) at about 0.751 pH units
lower than initial treatment. HP
| Fig. 7.
Comparative amine impact
for corrosion in various refining units.
1 GE has recently incorporated a new, more
volatile polyamine filming inhibitor technology allowing for
effective steam-condensate system coverage.
2 Utilizing GE LoSalt Ionic Equilibrium modeling in
combination with GE Condensate modeling software, many
potential steam neutralizing amines were
evaluated for their compatibility with the refining process and
their effectiveness in managing corrosion in complex condensate
3 Steamate LSA is a patent-pending technology that
can provide an opportunity to further optimize refinery boiler
and process system reliability and economics.
Anthony Rossi is a 35-year veteran
of GE Water and Process Technologies and serves as
the global boiler product manager overseeing research
and new technology development for the boiler water
product line. He has also been the global boiler
engineering manager and a research chemist at GE. He
is a joint or sole inventor of record on four US
patents related to boiler water treatment technology innovations.
Mr. Rossi holds a BS degree in chemistry
from LaSalle University.
Gregg Robinson has worked as an
engineer for GE Water and Process Technologies for
over 15 years managing applications in boiler,
cooling, water/waste, RO/demineralization and
refining process chemistry. He specializes in the refinery and power plant
industries with a focus on optimum condensate
treatment of refining, chemical and power plant steam
systems. Mr. Robinson has a BS degree in chemical
engineering from Penn State University.
Trevor Dale has worked as a
scientist in research and development for GE Water
& Process Technologies for four years. He has a
PhD in physical organic chemistry and has worked on
new product development for corrosion and scale
inhibitors with an emphasis on the refining and petrochemical industry.
Dr. Dale is an inventor or co-inventor on five
granted patents/patent applications.