METHODOLOGY OF MITIGATING CORROSION MECHANISMS IN AMINE GAS
TREATING UNITS
A. M. Al-Zahrani and S. I. Al-Luqman
Saudi Aramco,E-7600, Dhahran 31311,
Saudi Arabia
ABSTRACT
Di-Glycol Amine (DGA) has been utilized for acid removal from hydrocarbon gas for many
years by Aramco in Saudi Arabia. Over the years the gas demand increased significantly which resulted
in operating some gas treating units in excess of the original design. Running gas treating units over theoriginal design has impact on the process and utilities streams. This paper investigates the impact of
operating DGA units over their design on the vessels and piping. This paper will present the
methodology that was developed to evaluate the integrity of the units and how to discover wall thinning
of piping and vessels. This methodology starts by evaluating the unit process parameters such as pressure, temperature, H2S and CO2 level, and line velocity, and then evaluates unit materials. Potential
damage mechanisms and the appropriate locations for inspection are a critical part of the evaluation process.
INTRODUCTION
The subject plant has four low pressure 150 psig (11.6 kg/cm2) gas treating units. All units utilize
DGA for acid gas removal (H2S and CO2). These units worked smoothly, in terms of corrosion
problems, for about 20 years. However, the demand on gas processing increased sharply with time. As a
result, serious corrosion problems developed at various locations.
The material of construction for piping and equipment is principally carbon steel except for somelocations such as reclaimer tubes that are made from type 304 stainless steel. DGA can be very corrosive
to carbon steel at high temperatures and/or high velocity in the presence of H2S and CO2.1
Typicaldamage mechanisms are erosion/corrosion and localized corrosion. Corrosion is most common in heated
and/or high velocity areas of the units such as reboilers, reclaimer, stripper column, and rich amine
Analysis of process parameters revealed that the low pressure gas treating units were operating at125-150% of their original design capacity. Also, the acid gas content in the sour gas varies between 13-
17 mole% and sometimes exceeds 17 mole%. Also, it was found that the amine circulation rate has
increased by 16% with DGA solution concentration of 47-50 wt%. However, this additional amount ofamine solution is still not sufficient to maintain the required rich amine acid gas loading below 0.4 mol
acid gas/ mol DGA to minimize corrosion development, as designed.
Degradation of DGA to other products is another concern in amine treating units. The most
common DGA degradation product is N,N'his (hydroxyethoxyethyl)urea (BHEEU) that has a higherviscosity and boiling point than DGA. Build-up of degradation product in the system will result in
lowering the heat transfer, increasing pressure drop, and reducing the sweetening efficiency. In a DGAunit, a reclaimer is used to purify lean DGA from chemical degradation products. BHEEU can be
reversed back to DGA in the reclaimer at temperature range of 360-380oF (182°C -193°C), per the
following reaction:
2R-NH2CO+ (H2O or H2S)↔2R-NH2+ (CO2 or COS) (1)
Lean DGA target limits are 10 wt% BHEEU and maximum of 6 wt% morphaline. Reclaimer process is limited to 360-380
oF to avoid morphaline formation because it cannot be reclaimed back to
DGA. Morphaline is usually formed at temperature higher than 380o
F (193°C).
On-stream inspection program (OSI) using ultrasonic wall thickness (UT) measurements was
used exclusively as the corrosion monitoring technique for process streams except utilities lines. This
program is a non-destructive technique to measure corrosion rate and remaining life at specific locationsof vessels and piping but it is difficult to detect localized corrosion by using UT technique.
In 2002, a Risk Based Inspection (RBI) study was conducted on one of the subject gas treating
units as per API 5803. Some piping and vessels such as utilities lines were not covered by the RBI study.
Results of the RBI study support in identifying most of the high risk locations in the units.
Following the RBI study, an intensive assessment program was established to identify the rootcauses of corrosion problems and provide the required protective actions to ensure safe operations and
avoid reoccurrence of failures. The study was highly dependent on the inspection data and operating parameters such as acid gas loading, linear velocities, gas processing rates, operating pressures, and
operating temperatures.
PROCESS DESCRIPTION
Figure 1 shows the typical process streams and vessels of the DGA unit. Sour gas associated
with H2S and CO2 enters the feed filter separator to remove solid particles. Then, the sour gas enters the
contactor from bottom and as it rises to the top, it contacts lean DGA that flows to the base of thecolumn. When H2S and CO2 are transferred to the DGA, it is then referred to as rich DGA. The sweet
gas goes to gas compression area.
The rich DGA goes to the rich DGA flash drum that has a lower pressure (70 psig or 6 kg/cm2)
than the plant inlet pressure (150 psig or 11.6 kg/cm2). The drop in pressure causes gas to be released
from the rich DGA. This gas, which is called flash gas, goes to the boilers in the utility area as fuel gas.
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Inside the stripper, rich DGA gets rid of H2S and CO2 by utilizing steam. The heat required forstripping is supplied by four steam reboilers and a portion by the reclaimer return. The lean DGA is
returned to the contactor to continue the gas sweetening process. The acid gas leaves from the top of the
stripper to a fin fan cooler. The acid gas and water are separated in a reflux drum before sending the acidgas to sulfur recovery units.
PLANT CORROSION EXPERIENCES
Recently severe thinning and leaks were experienced in the DGA units. By reviewing the
available inspection, corrosion, and process data, it was found that the following locations are sufferingof high corrosion rates:
• Line between contactor bottom and flash drum
• Line between flash drum and stripper
• Lines in the outlet of all reboilers
• Lines in the outlet of contactor side coolers
• Reclaimer tubes
• Flush drum control valves
Areas of high velocity or turbulence such as reducers (located upstream and downstream ofcontrol valves) and elbows experienced high corrosion rates. Simply, increasing the gas processing rate
will definitely increase the amine circulation rate. Figure 2 shows the metal loss of an elbow upstream of
a flash drum’s level control valve. The metal loss was significantly increased after year 2000 as highergas feed rate was introduced to the gas treating units. The microscopy examinations specified the root
cause of this increase in metal loss as erosion attack due to high velocity.
METHODOLOGY
Over 25 years, the subject gas plant had several process changes that include increasing plantthroughputs, increasing water amount associated with gas, and H2S and CO2 levels in the feeding gas.
The number of failures has increased with time in the DGA units. Some of these failures occurred inlocations not classified as high corrosion locations because they were not included in the inspection
program such as utilities lines. Other failure locations were found approximately a meter away from the
OSI points. Also, it was found that all OSI points were not modified since the start-up of the units (25years ago). Obviously, these points are not representative of the current critical locations, especially
after increasing the units’ throughputs.
The repetitive failures necessitated the engineering team to re-evaluate the system to develop an
evaluation method that enhances process engineers, corrosion engineers, and inspectors to maintain a
reliable system. Figure 3 presents the developed method that can be simplified in the following steps:
• Review the process parameters and piping material.
• Identify the suspected corrosion type (damage mechanism).
• Include critical locations in the OSI program with specific non-destructive testing (NDT)method.
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• Classify a corrosion control method to be used such as coating, upgrade utilized material, or
modify design (process modification).
The developed method is in line with API 5702 and API 580
3. This method is considered as the
road map for evaluating the existing systems. Applying of this method supports in identifying criticallocations in proactive manner. This paper will present in detail three cases reflecting the beneficial and
successful of this methodology in evaluating corrosion mechanisms in gas treating units and preventing
occurrence of additional failures.
CASE STUDIES
Case Study 1: Rich DGA Piping Spools
The rich DGA piping spool downstream of the level control valve (Figure 4) of the Flash Drumwas evaluated since it is an area subject to severe wall thinning. Inspection history showed that the
piping spool downstream of the flash drum level control valve had experience a leakage. However, OSI
data did not report severe wall thinning. Also, the history showed all flash drums’ level control valves inthe four gas treating units had experienced severe damage.
Based on RBI study results, the rich DGA piping spool was identified as a critical circuit.
Accordingly, the circuit was evaluated using the above method. During the reviewing of the circuit process parameters, it was found that H2S and CO2 levels are 13500 ppm and 3.7 mol% respectively.
The line velocity was calculated by Computational Fluid Dynamics (CFD) program. The CFDresults (figures 5a and 5b) indicated that the control valve and the reducer have experienced high
velocities in the range of 19 ft/s (8.4 m/s). Also, it indicated that the 12 o’clock position had
experienced back flow which caused turbulence at this location after three years of increasing the plantthroughput.
The material of the reducer downstream of the control valve is carbon steel. Aramco internalguidelines and API 945
9 recommend both lean and rich amine velocities less than 6 ft/s (1.8 m/s). API
5718 recommends rich amine velocity between 3-6 ft/s (1-2 m/s) for rich amine and 20 ft/s (6 m/s) for
lean amine lines. Accordingly, the linear velocity of the reducer is considered as a very high velocity.
Therefore, the reducers are subject to severe metal loss based on the first and second steps of theevaluation method.
Third step in the evaluation method is reviewing the OSI data. OSI locations identified for thatcircuit were found at 3 and 9 o’clock positions. Historical data did not reveal severe metal loss at 3 and 9
o’clock positions. CFD data, Figures 5a and 5b showed the back flow at 12 o’clock position. The visual
inspection and UT measurement during the shutdown showed severe erosion-corrosion at the 12 o’clock
position which confirms the CFD data. This shows that OSI selected points (3 and 9 o’clock) are not themost appropriate locations and 12 o’clock should be monitored.
CFD results also showed the velocity of the rich DGA main pipe upstream and downstream of
the control valve is lower than 6 ft/s (2 m/s). Visual examination and UT measurement of these linesrevealed no severe metal loss with linear velocity less than 6 ft/s (2 m/s). This supports the internal
Aramco guidelines and API 5718 that allow rich DGA velocity up to 6 ft/s (2 m/s).
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It is worth to mention that evaluating the lean DGA lines using the above methods indicatedsome piping spools reached up to 17 ft/s (5 m/s) without severe metal loss. Only severe metal loss was
found in locations that have velocities higher than 25.2 ft/s (8.4 m/s). This finding support API 5718 that
allows lean amine velocity to maximum of 20 ft/s (6 m/s).
To successfully provide maximum integrity assurance to the units, a combination of upgrading
the material and frequent UT inspection were recommended:
.
• Regular UT measurements are recommended at the 12 o’clock position.• Reducers downstream of the control valve are upgraded to type 316 stainless steel
• The main rich DGA line should remain carbon steel.
Case Study 2: 75 psig Steam Line
Running the gas treating units over the original design impacts the utilities streams such as 75
psig steam lines as well as the process streams. The 75 psig steam is used in the stripper’s reboilers and
the reclaimer to increase the DGA temperature and reduce H2S and BHEEU level in DGA. Therefore,
75 psig is essential for DGA processing and may cause unit shutdown if the steam line has a failure.
The 75 psig steam lines in the gas treating units were evaluated using the developed method. Theconstruction material of these lines is carbon steel schedule 40. The calculated line velocity at themaximum operating conditions is around 216 ft/s (65.8 m/s). This is above the maximum allowable
velocity required by internal Aramco guidelines of 175 ft/s (53.3 m/s). Accordingly, this high velocity
could cause erosion of the steam lines.
Utilities lines are not included in the plant OSI program. Also, 75 psig steam lines cannot be
inspected by the conventional UT machines since these lines are very hot and thermally insulated.
Visual inspection was used exclusively to inspect these lines. During the turnaround of one of the unit,three windows were opened in the 75 psig steam line for visual inspection. The inspection reveled that
very thin areas located at 9-12 o'clock position of the line. Figures 6 and 7 show detailed views of two
thinned areas. The pattern of thinning suggests a form of erosion or impingement. The thinned areaswere bright and shiny upon opening, whereas most of the section showed a dark grey color, typical of
the appearance of a well-passivated steam-system surface (magnetite film).
Failure analysis of a defective piping sample was performed to identify the damage mechanisms.
The root cause was related to excessive steam velocity, but other factors may have contributed namely:
• Possibility of some condensation, giving wet steam and possible impingement.
• Reports of loud noises as hammering that indicates water presence (condensation) in the system
As a result of applying the evaluation method steps, following corrective action was
recommended to provide maximum integrity assurance of 75 psig steam piping in amine treating units:
• Conduct visual inspection and UT measurements on the 75 psig steam line during futureturnaround.
• Consider installing extra steam traps to reduce chances of wet steam.
• Conduct a monthly survey on all steam traps installed in the 75 psig steam system and fix/replace as required to eliminate oxygen contamination.
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• Evaluate the adequacy of the existing steam traps for handling the increased steam condensation
load versus the original design.
• Maintain the line velocity below 175 ft/s which can be achieved by increasing steam piping sizes
as per internal company guidelines.
Case Study 3: DGA Reclaimer Tube
Lean DGA requires continual reclaiming to convert BHEEU degradation products back to DGA.
All gas treating units use reclaimer (kettle type heat exchanger) with lean DGA in the shell side andsteam in the tube side. Each reclaimer has 951 tubes and made from carbon steel (shell side) and type304 stainless steel (tube side). BHEEU is converted back to DGA at temperature around 360°F (182°C).
Operating reclaimer at higher temperature will convert DGA to morphaline (irreversible product).Reclaimers are quite tolerant--60% of the tubes can be plugged before there is a significant impact.
Impurities such as chloride can cause pitting and stress corrosion cracking to type 304 stainless
steel materials. According to the unit analysis, chloride level in lean DGA is usually in the range of 100-200 ppm but sometimes it reaches above 600 ppm. Based on Aramco experience, chloride level is
maintained less than 1000 ppm. Limited information is available in the literature about the
recommended chloride level in DGA. API 945 indicated that type 304 stainless steel can be exposed to
DGA solutions containing chloride up to 4000 ppm without specify the system temperature 9. As ageneral rule, chloride SCC of process equipment occurs only at temperature above 145°F (65°C)
10.
However, the following presented case dose not support the proposed API limits.
Reviewing the reclaimers’ historical inspection data revealed that two tube bundles were
replaced by new ones. The other two tube bundles have between 309 and 449 tube plugged. Also,history showed a few bundle failures occurred during shutdown periods, when Maintenance pulled out
the tube bundle. Because of these frequent tubes failures, reclaimers were evaluated utilizing the
developed methodology.
Based on the reclaimer process parameters, equipment material, and inspection history, all
susceptible damage mechanisms were identified. The most common damage mechanisms that have beenexperienced are:
• Pitting corrosion
• Fretting Corrosion
• Chloride stress corrosion cracking
• Mechanical damage
Pitting and chloride stress corrosion cracking had been experienced in the reclaimer tubes. Theexperience of Saudi Aramco and other oil companies showed cracking developed in the units, when
chloride level reaches higher than 500 ppm. Fretting corrosion in reclaimer was at the interface between
tube bundle and baffle surfaces under load. Agitation resulting in the movement of the tubes against the baffle surfaces was probably caused by the downward flow of the DGA solution through the reclaimershell. Mechanical Damage was taking place during installation and removing of tube bundles due to
improper handling.
From the history of all reclaimer units, it can be noticed that sludge accumulation at the bottom
of each unit has direct impact on tube failures. All reclaimer units are equipped with sparging steam line
which is installed below the reclaimer tube bundle. The main advantage of the sparging steam line is
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preventing settling of the accumulated sludge and solids around the reclaimer tube bundle. In addition,the sparging line is helpful in removing sludge at the end of the reclaimer cycle. Failure analysis
examinations refer corrosion of the DGA reclaimer as a result of:
• Excessive reclaimer cycle period
• Improper boil down procedure at the end of each cycle
• Excessive flux rates of the tube bundle
• High chloride content
Sometimes, the reclaimer ran with insufficient level. The low liquid level on the shell side
usually gives the chance for the upper tubes to be hotter than lower tubes that will subsequently increase
the possibility of corrosion occurrence at the upper tubes. According to the operational history of thereclaimers, bottom tubes and mostly upper tubes have experienced failure.
Currently, the OSI program is monitoring lean DGA piping feeding and coming out of the
reclaimer. Reclaimers’ tubes are not included in the OSI program because of accessibility. As a result,the following targets of process parameters are used to monitor reclaimers’ tubes corrosion:
• Solids target is less than 100 ppm
• Chloride target is less than 500 ppm
• BHEEU target is less than 6%
• Morphaline target is less than 10%
• Acid gas loading target is less than 0.4% mole acid/mole DGA
• DGA concentration target is between 47-50%.
• DGA concentration “in steam return condensate drum” should be 0.
By following the evaluation methodology, the following recommendations were proposed tocontrol the failure mechanisms in the DGA reclaimers:
• Utilize higher corrosion resistance material such as type 316 stainless steel with reclaimer’s
tubes.• Maintain liquid level above tubes during normal operation to prevent upper tube form over
heating.
• Use sparging steam line in the reclaimer every 40-60 days in order to control sludgeaccumulation.
• Maintain chloride level below 500 ppm in the lean DGA. Controlling chloride at lower limit like
100 to 150 ppm will help on controlling pitting corrosion and chloride stress corrosion cracking.
• Consider limiting maximum heat flux rates rather than average flux rates. The maximum heat
flux for type 304 stainless steel is 12,000 BTU/hr/ft2 6
.
• New tube bundles should be designed in a way to maintain a minimum vibration inside reclaimershell. This will minimize fretting corrosion.
CONCLUSIONS
It is clear that increasing of gas processing rates in amine treating units must not be done withoutconsidering the effects this will have on corrosion performance. This corrosion evaluation must be one
part of a thorough (Management of Change) review. During the evaluation, it was noticed that different
corrosion mechanisms attacked the amine treating units; however, the most likely corrosion type
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classified as the root cause is erosion/corrosion attack due high stream velocities. In this paper, amethodology was introduced that can assist in controlling corrosion in amine treating units. This
methodology calls for an evaluation of the process parameters including pH, pressure, and temperature.
Also, an attention to stream velocity since it plays a major role of most erosion/corrosion attack. Inaddition, OSI program must be optimized to ensure accurate measurements of piping and vessels wall
thickness. Not all corrosion mechanisms can be detected by conventional UT measurement, but
selecting the most appropriate NDT method is essential to detect corrosion before a failure. Corrosion
control options for these systems include materials selection, improved chemical treatments, reduction in
line velocities, and careful process control will help on having a safe and reliable system.
ACKNOWLEDGMENTS
The authors wish to recognize Yousif Al-Said, Mohammed Al-Anazi, and Salamah Al-Anazi,from Saudi Aramco who assisted in this study.
REFERENCES
1. M.K. Seubett and G. D. Wallace, “Corrosion in DGA Gas Treating Plants” Corrosion 85. 1985.2. API 570” Piping Inspection Code”.3. API 580 “Risk Based Inspection”.
4. Malcow Huval and Harry Van De Venne “Gas Sweetening in Saudi Aramco in Large DGA
Plants”, Gas Conditioning Conference, 1981.5. A M. Al-Zahrani, Y. A. Al-Said, A. A. Al-Safran and H. Busalih “75 PSI Steam Line Erosion in
Gas Treating Units”, Saudi Aramco Report, 2004.6. T. F. Moore, J. C. Digman, and F. L. Johnsone, Jr “A Review of Current Diglycolamine Agent
Gas Treating Applications”, Engineromental Progress, Vol. 3, No.3, 207-212 (1984).
7. R. B. Nilsen, K. R. Lewis, J. G McCullough and D. A. Hansen, “Corrosion in Refinery AmineSystem” Corrosion 95, paper 571.
8. API 571 “Damage Mechanisms Affecting Fixed Equipment in the Refining Industry”.9. API 945 “Avoiding Environmental Cracking in Amine Unit”.
10. J. Guzeit, R. D. Merrick, L. R. Scharfstein, “Corrosion in Petroleum Refining and PetrochemicalOperations, Metals Handbook, 9 Edition, Vol. 13.
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