SpecialReport
CORROSION CONTROL
Originally appeared in:
March 2012, pgs 45-47.
Used with permission.
Operating philosophy can
reduce overhead corrosion
Boost refinery reliability by controlling potential amine recycle loops
M. Dion, B. Payne and D. Grotewold, GE Water & Process Technologies,
The Woodlands, Texas
S
alt fouling and associated corrosion in the crude unit
overhead are complex phenomena that impact refinery reliability, flexibility and, ultimately, profitability.
Establishing an appropriate balance of physical, mechanical
and operational parameters, unique to each unit, is critical to
minimizing fouling and corrosion throughout the crude unit.
Factors such as amine chloride salt points; optimum accumulator pH; and overhead water ICP (initial condensation point,
also referred to as water dew point) are interrelated and all
affect the potential for system fouling and corrosion.
Further improvements to refinery reliability can be attained
by controlling potential amine recycle loops that can cycle up
amine concentrations and move the salt point upstream or
within the atmospheric tower itself.
Crude unit overhead corrosion control. The first
line of defense against overhead fouling and corrosion is the
desalter. The desalter is designed to remove the majority of
water extractable chlorides that contribute to the formation of
highly corrosive hydrochloric acid (HCl) in atmospheric overhead systems. Depending on the desalter design and operation,
it typically extracts 90–98% of the water extractable species.
To protect the system from extractable chlorides that are not
removed in the desalter and non-extractable, hydrolysable
chlorides (such as organic amine chlorides), filmers, neutralizers and an overhead water wash are commonly utilized.
The first area of concern for overhead corrosion protection
is at the initial condensation point (ICP). As the first drop of
water condenses (Fig. 1), acids in the vapor phase will transition to the water droplet, creating a low pH, highly corrosive
liquid. The neutralizing amine (N) must be present at the ICP
to neutralize the hydrochloric acid.
Amines can also associate with chlorides in the vapor phase
under certain partial pressures, creating amine chloride salt.
Once formed, it can migrate from the vapor phase either as a
liquid or a solid and is typically extremely corrosive. The temperature at which the amine chloride salt exits the vapor phase
is commonly referred to as the “salt point.” The salt point is
dependent upon several factors, including the partial pressure
of the neutralizing amine, the partial pressure of HCl, and the
partial pressure of “tramp amines.”
Tramp amines are generally defined as those other than neutralizer amines. They can come from several sources including
being present in the crude naturally; from upstream additives
such as corrosion inhibitors or hydrogen sulfide scavengers;
from another processing unit; or from compounds that may
decompose into amines in the crude unit furnace.
Control. Overhead pH control is, perhaps, the most important aspect of overhead corrosion control. The pH in the overhead receiver is generally at least 0.5–1.5 points higher than
the pH at the ICP. The ICP should be maintained in a range
between 5.5 and 6.5 by use of an appropriate neutralizing
amine. As illustrated in Fig. 2, operating at a pH level outside
this range can have a deleterious impact in both directions.
For example, if the accumulator pH is 5.5, the ICP pH will
typically be between 4 and 5. When the ICP pH is 4.5 or less,
acidic corrosion becomes very aggressive. Conversely, when the
ICP pH exceeds 6.5, a region exists where the deposition of
liquid or solid amine chloride salts can increase the likelihood
of salt fouling and under deposit corrosion. H2S and other weak
acids will increase partitioning from the vapor to the liquid
phase as the pH increases. The additional sulfides and weak acids
in the condensed water will act as a buffer requiring significantly
more amounts of neutralizer for minor movements in pH. The
additional neutralizer concentration increases the partial pressure of the neutralizing amine, thereby increasing its salt point
Acids and bases at dew point
H CI
H CI
N
Henry partitioning
N
H CI
H CI
N
N
CIH+
H+
N
H CI
H+
H+ N
CI-
CI-
Electrolytic chemistry
First water drop at ICP
Fig. 1
Water chemistry for the initial condensation point.
HYDROCARBON PROCESSING March 2012
SpecialReport
CORROSION CONTROL
and the associated risk for under deposit corrosion.
Additionally, the destruction of metal passivating iron sulfide scales also becomes a factor under these conditions. In a
slightly acidic environment, sulfides will react with the iron,
forming a protective iron sulfide film. This protective film is
weakened as pH increases, inhibiting the effectiveness of the
naturally occurring protective iron sulfide film.
Therefore, both the upper and lower levels should be considered hard limits not to be exceeded. Having a pH excursion
beyond these limits is generally an indication that there is a
significant imbalance in the system from either an incidental
or a systematic situation.
Most refiners employ an overhead water wash to force the
condensation of water vapor and dilute the acids that condense
with the water. However, this may not protect against amine
chloride salt fouling if the amine salt forms above the overhead
temperature at the water wash injection point. The potential
corrosion risk can also be compounded if the high salting
amines reenter the atmospheric column in the reflux, which
can induce an amine recycle loop.
Amine recycle. As discussed previously, amines can be present as either tramp amines or introduced into the overhead as
Salt deposition; under-deposit
corrosion (NOTE: This saltpoint
curve will shift with varying
amine and chloride concentrations)
900
800
700
pH at which
saltpoint
exceeds water
dewpoint
Optimal
control range
pH 5.5 – 6.5
600
500
400
300
200
100
0
1
Fig. 2
(NOTE: The
corrosion rate
at pH >7 is
equivalent
to the rate
at pH 4)
Acid
2
3
4
5
pH
6
7
8
9
The impact of pH at the initial condensation point.
Neutralizer
Amine sources include:
• Overhead neutralizers
• Crude oil
• Slop oil
• Alkanolamine unit
• Sour water strippers
• H2S scavengers
• Cold wet reflux
Tank farm
Water wash
Amine
recycle
10
Ammonia:
Fractionation
column
Wash water
Typical amine recycle loop diagram.
Base
NH4+
Acid
HO – CH2 – CH2 – NH3+
HO – CH2 – CH2 – NH2
Fig. 4
Amine partitioning is dependent on the type of amine.
Accumulator
Amine
recycle
NH3
MEA:
Base
HDS effluent exchanger dP
(indication of exchanger plugging)
80
Unit shutdown for cleaning
Desalted pH modification treatment
Untreated
Eff dP actual
Eff dP model
Tower top
reflux
Amine
Desalter
Fig. 3
Iron sulfide
scale weakens
and H2S/CO2
partitioning to
liquid phase
is enhanced
Amine partitioning. The partitioning of amines between
the hydrocarbon and water phase is dependent on many factors
including the type of amine, the hydrocarbon polarity and the
pH of the water. Low pH water can protonate (add protons
to) an amine and drive the ionic compound into the water
phase. Conversely, alkaline water will deprotonate an amine
and drive the partitioning of the non-ionic compound into the
hydrocarbon phase.
Amine partitioning is dependent on the type of amine
(Fig. 4). As more carbons are added to an amine compound,
its partitioning will be less pronounced with pH. Ammonia
is easily partitioned to the water phase; MEA partitions to a
lesser extent; and so on.
In a crude unit overhead, operating the overhead accumulator water at a slightly acidic pH will assist in breaking the
reflux amine salt recycle loop. The use of a low salting amine
60
psi dP
Corrosion rate as a function
of ICP pH, mpy
1,000
neutralizing amines. When exposed to a liquid-liquid system,
amines—such as monoethanolamine (MEA), diethanolamine
(DEA), methyl diethanolamine (MDEA) and ethylenediamine
(EDA)—will partition to each phase. For instance, in the overhead accumulator, a portion of the MEA will partition to the
naphtha reflux and another portion will partition to the condensed water. If the condensate is used as desalter wash water,
it will again partition, with a portion of the amine exiting the
desalter in the desalted crude.
This creates amine recycle loops (Fig. 3) in the naphtha
overhead and desalted crude. These recycle loops can concentrate the amine within the system. The additional amine
loading to the overhead will add to the partial pressure of that
particular amine, which will, in turn, increase the salt point of
the amine chloride salt. If left unchecked, this amine recycle
loop may, in severe cases, foul the top distillation trays.
Stripping
steam
40
Untreated baseline
to 3/2008
20
1/7/2011
Fig. 5
2/26/2011
4/17/2011
6/6/2011
7/26/2011
9/14/2011
Detailed rendering of the diesel hydrotreater effluent
exchanger pressure drop.
HYDROCARBON PROCESSING March 2012
CORROSION CONTROL
to control pH at the initial condensation point and not salt
above the water dew point is critical to an effective overhead
corrosion control program.
At the desalter, reducing the effluent brine pH will also
drive more amines into the effluent brine, thereby minimizing the potential harmful impact from amine recycle loops. It
should be noted that the effluent brine pH is the equilibrium
pH after the crude oil and wash water mix. Consequently, the
effluent brine pH is the control parameter to amine partitioning within the desalter.
Out at the refinery. A US refiner was experiencing
throughput reductions and frequent slowdowns as a result of
fouling in the effluent side of the diesel hydrotreater feed effluent exchangers. Rather than treat the symptom with an amine
halide salt dispersant, the desalter effluent brine pH was lowered by injecting a product containing citric acid and a scale
inhibitor. This partitioned more amines to the effluent brine,
reducing the amines in the crude unit overhead, the diesel
stream and, consequently, the fouling in the hydrotreater unit.
The effluent exchanger pressure drop history was used to
generate a multiple regression linear model to normalize the
pressure drop for effluent flow and stream properties. The
actual exchanger pressure drop and the model estimate are
shown in Fig. 5. When the actual pressure drop increases above
the model’s predicted value, it is due to the amine halide salt
fouling at an advanced rate. The time periods in Fig. 5 (during
treatment) show that the actual pressure drop was lower than
the historical observations and, in fact, there was no increase
in pressure drop.
Wrapping it up. In some systems, amines may recycle back
into the tower with the reflux or may reenter the desalter from
the overhead condensate. At the desalter, the amines may partition back into the desalted crude and reenter the atmospheric
tower. These amine recycle loops may cycle up amine con-
centrations and increase the risk of corrosion from amine salt
deposits if they occur above the water dew point. The authors
believe a model can be used to assist in predicting amine salt
points. If the salt point occurs above the water dew point,
operating the desalter with an acidic effluent brine can partition a portion of these amines into the effluent brine, thereby
reducing the detrimental impact from recycling amines.
Using nonvolatile acid products is a good way to assist
in reducing the desalter effluent brine pH. The acid decomposes to inert substances in the crude unit furnace. As refiners
have recently reduced atmospheric tower top temperatures to
maximize diesel production, a thorough understanding of the
ICP, salt point and control of amine recycle loops is critical
to maintaining plant reliability in changing plant operational
conditions. HP
Michael Dion is a phase separation senior product applications specialist for GE Water & Process Technologies. He is responsible for technical support and marketing of a refining separation
product line. Mr. Dion has seven years of oil field experience and
21 years of refining experience. He has co-authored two patents
and numerous articles.
Brandon J. H. Payne is a product applications specialist
for GE Water & Process Technologies’ Refinery Corrosion Center
of Excellence. He is responsible for global support of GE refinery
corrosion treatment programs and has over 14 years of refinery
engineering and process treatment experience.
Delbert R. Grotewold is a senior regional engineer for
GE Water & Process Technologies in the Western US region. He
is responsible for process chemical treatment programs, refinery
process troubleshooting and process optimization of refinery
operations. Mr. Grotewold has over 27 years of refinery engineering and process treatment experience. He has authored or co-authored five
patents in refinery technology.
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