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Hp oh corrosion
1. CORROSION CONTROL SpecialReport
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 refin-
ery 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 accumula-
tor 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 over-
head 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, neutral-
izers 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 transi-
tion 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 tem-
perature 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 neu-
tralizer 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 impor-
tant aspect of overhead corrosion control. The pH in the over-
head 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 pres-
sure of the neutralizing amine, thereby increasing its salt point
First water drop at ICP
Acids and bases at dew point
Electrolytic chemistry
Henry partitioning
CIH
H+ N
N
N
N
N
N
H+
H+H+
CIH
CI
CI-
CI-
CI-
H
CIH
CIH
Water chemistry for the initial condensation point.Fig. 1
Originally appeared in:
March 2012, pgs 45-47.
Used with permission.
HYDROCARBON PROCESSING March 2012
2. CORROSION CONTROLSpecialReport
and the associated risk for under deposit corrosion.
Additionally, the destruction of metal passivating iron sul-
fide 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 con-
sidered 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 pres-
ent as either tramp amines or introduced into the overhead as
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 over-
head accumulator, a portion of the MEA will partition to the
naphtha reflux and another portion will partition to the con-
densed 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 con-
centrate 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.
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 accumu-
lator water at a slightly acidic pH will assist in breaking the
reflux amine salt recycle loop. The use of a low salting amine
Amine sources include:
• Overhead neutralizers
• Crude oil
• Slop oil
• Alkanolamine unit
• Sour water strippers
• H2S scavengers
• Cold wet reflux Amine
Wash water
Amine
recycle
Amine
recycle
Stripping
steam
Fractionation
column
Desalter
Tank farm
Neutralizer Water wash
Tower top
reflux
Accumulator
Typical amine recycle loop diagram.Fig. 3
Ammonia: NH3 NH4
+
MEA: HO – CH2 – CH2 – NH2 HO – CH2 – CH2 – NH3
+
Acid
Base
Acid
Base
Amine partitioning is dependent on the type of amine.Fig. 4
20
40
60
80
1/7/2011 2/26/2011 4/17/2011 6/6/2011 7/26/2011 9/14/2011
psidP
HDS effluent exchanger dP
(indication of exchanger plugging)
Eff dP actual
Eff dP model
Untreated baseline
to 3/2008
Unit shutdown for cleaning
Untreated
Desalted pH modification treatment
Detailed rendering of the diesel hydrotreater effluent
exchanger pressure drop.
Fig. 5
Corrosionrateasafunction
ofICPpH,mpy
0
100
200
300
400
500
600
700
800
900
1,000
1 2 3 4 5 6 7 8 9 10
pH
Iron sulfide
scale weakens
and H2S/CO2
partitioning to
liquid phase
is enhancedpH at which
saltpoint
exceeds water
dewpoint
Salt deposition; under-deposit
corrosion (NOTE: This saltpoint
curve will shift with varying
amine and chloride concentrations)
(NOTE: The
corrosion rate
at pH >7 is
equivalent
to the rate
at pH 4)
Optimal
control range
pH 5.5 – 6.5
The impact of pH at the initial condensation point.Fig. 2
HYDROCARBON PROCESSING March 2012