control dea corrosion in a gas refinery _ hydrocarbon processing _ may 2012

5/28/12 Control DEA corrosion in a gas refinery | Hydrocarbon Processing | May 2012

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Control DEA corrosion in a gas refinery

05.01 .201 2 | Atash Jameh, A., Sarkhoon & Qeshm Gas Treating Company , Bandar Abbas, Iran; Gharaghoosh, A. Z., Sarkhoon and Qeshm Gas Treating

Company , Bandar Abbas, Iran; Rashidfarokhi, A. R., Sarkhoon & Qeshm Gas Treating Co.,, Iran; Pakshir, M. , Shiraz Univ ersity , Iran; Paydar, M. H.,

Shiraz Univ ersity , Iran

Corrosion inhibitor selection and protective scales are key to prevention

Key words: [corrosion] [gas processing] [natural gas]

The sweetening unit is a key component of the gas processing plant, and the amine regeneration tower is one of the major parts of this unit. The

amine tower in the Sarkhoon gas plant in southern Iran has experienced severe corrosion [40–50 mils per y ear (mpy )] over a 2.5-y ear period. The

corrosion area is limited to the vapor and vapor/liquid interface spaces. The material in this area is carbon steel (A-516-GR-7 0) and is located on the

inside of the tower shell.

A recent study investigated the cause of this corrosion, along with the corrosion’s tendency to move from the top tray s of the tower to the bottom

tray s. The performance of the chosen corrosion inhibitor was also scrutinized during the investigation. Results showed that an amine solution in the

unit was degraded by dissolved oxy gen (O2 ), exposing the inside of the tower shell to corrosive amine degradation products. The injection of an O2

scavenger inhibitor into the amine solution has not corrected the problem, and design issues with the injection point and its piping have been

discovered.

Corrosion sources in a gas plant

A portion of the Sarkhoon gas plant’s feed is sour gas. In the feed-sweetening process (Fig. 1), a solution of 7 0% water and 30% diethanolamine (DEA)

is used to absorb H2 S in the contactor tower (C-101). Absorbed H2 S is released in the amine regeneration tower (C-103) in the presence of rising

temperature and pressure drop.1 In comparison with other amines [e.g., monoethanolamine (MEA), methy ldiethanolamine (MDEA), activated

MDEA (aMDEA)], DEA is more susceptible to oxidation and degradation, and it produces organic acid bases that form heat-stable salts in an amine

environment.2

Fig. 1. Gas-sweetening unit at Sarkhoon gas plant.

One of the major sources of corrosion on carbon steel vessels in sweetening units is heat-stable materials, which are a product of amine

degradation.3 ,4 Oxy gen play s a major role in DEA degradation. The reaction of O2 and DEA produces organic acids, such as acetic acid, formic acid

and so on. O2 solubility in a solution of amine (except DEA) and water is similar to the solubility of O2 in water.5

Foaming in the amine regeneration tower results in the increased contact of corrosive components of the amine solution with the tower internals, as



well as in a loosening of the protective iron sulfide (FeSX) surface lay er that is formed by H2 S. Heat-stable salts play an important role in foaming and

corrosion in the amine regeneration tower.6 ,7

Organic acids—such as formic acid, acetic acid and oxalic acid—at a temperature of 200°C contacting carbon steel would result in severe corrosion.

However, the corrosion activ ity of these acids is significantly reduced in an MDEA solution.3

The corrosiveness of a 20% amine solution on carbon steel in an environment containing either CO2 or H2 S gas at a temperature of 140°F to 212°F

would increase dramatically . However, env ironments containing either CO2 or H2 S gas in this temperature range tend to experience more

aggressive corrosion compared with an environment containing a CO2 :H2 S mixture of 1 :3 or 3:1 .8

One method to prevent corrosion in sweetening units is to use corrosion inhibitors. Corrosion inhibitors manufactured from heavy metals, such as

arsenic and vanadium, have the ability to control corrosion in the aforementioned environments, although these heavy metals are incompatible

with these environments. Furthermore, these ty pes of corrosion inhibitors are unable to protect splash zones and vapor spaces. Film corrosion

inhibitors prevent general corrosion, but are unable to control specific ty pes of corrosion.8

To avoid certain corrosion ty pes (e.g., sulfide stress cracking, hy drogen-induced cracking, etc.), guidelines contained in NACE MR-01-7 5 should be

followed during the material selection of sweetening units.9 Organic amines are traditionally used in the refinery crude column overhead to

neutralize and reduce pH as a means of corrosion control.1 0

Based on prev ious research on H2 S concentration increases in oil, two ty pes of scales form on contacting steel surfaces: Mackinawite and

Py rrhotite.1 1 Mackinawite scales have coarse grain in a loose and brittle form. Although Mackinawite scales reduce general corrosion, steel surfaces

are still susceptible to aggressive, pitting corrosion. Py rrhotite scales have fine grains and exist in continuous form, and are resistant to both general

and pitting corrosion.1 2

There are three zones in the regeneration tower: the vapor space, the liquid/vapor interface and the liquid phase. In the vapor space, the formation

of a protective lay er of FeSX results in low corrosion rates for a rich solution containing H2 S, compared with a lean amine solution that does not

contain H2 S.1 2

Corrosion tests

A number of field and laboratory tests have been performed to measure corrosion rates and levels at the Sarkhoon gas plant. Field tests included the

following:

Weight loss (coupon) test. This test was carried out based on standard test method ASTM-G-1 v ia coupon installation in 10 points of amine

solution cy cle input. Test results are presented in Table 1 .1 3

Iron count test. To evaluate the corrosion rate of the unit, this test was performed according to the spectrophotometric method. Samples were

taken from the circulating amine solution, and the amount of iron (which is generated by corrosion on vessels) was measured. The following iron

counts were observed: 16.9 ppm (Test 1), 10.6 ppm (Test 2), 35.0 ppm (Test 3) and 38.0 ppm (Test 4). Based on these data, the presence of an amine

solution containing concentrated heat-stable salts results in corrosion reactions. According to the unit design, the maximum allowable amount of

iron in the amine solution is 10 mpy .

Dissolved O2 in am ine solution. The amount of O2 present in the amine solution, which is a major factor in DEA degradation, was measured

according to test methods outlined in ASTM D-888 and ASTM D-5543. Results are represented in Table 2.1 4 ,1 5

Ultrasonic test. An ultrasonic thickness meter was used to measure tower wall thickness. The results of this test, which show a reduction in

thickness, are represented in Tables 3 and 4.



Laboratory corrosion tests included the following:

Inlet gas analy sis. This test was carried out according to ASTM D-1945 guidelines. A gas chromatography apparatus was used to pinpoint

components of the feed gas entering the contactor tower.1 6 Results are shown in Table 5.

Polarization test. To determine the corrosion rate of the lean amine solution containing 3.7 1% heat-stable salts, three tests at temperatures of

25°C, 50°C and 7 0°C were performed according to ASTM G-3 methods. Respective corrosion rates of 2.0 mpy , 4.8 mpy and 8.8 mpy were observed

at the various temperatures. These results are illustrated in Fig. 2.1 7

Fig. 2. Lean amine polarization test at three

different temperatures.

Im m ersion weight loss. To simulate corrosion in the three tower regions, this test was conducted according to ASTM G-31 guidelines in static

condition, with lean amine containing 3.7 1% heat-stable salts at a temperature of 120°C. The corrosion rates observed for the liquid phase,

liquid/vapor interface, and vapor phase were 2.10 mpy , 5.02 mpy and 8.16 mpy , respectively .1 8

Scanning electron m icroscope. To evaluate corrosion products on the carbon steel section of the tower shell, a sample from the bracket of the

downcomer of the ninth tray was prepared and tested by microscope. Test results are shown in Fig. 3.



Fig. 3. SEM test result on a specimen from the

downcomer.

Am ine solution analy sis. This test was performed to investigate lean amine solution components, and it is based on ion chromatography and

National Iranian Gas Co.’s test method for heat-stable salts. Results are presented in Table 6.

Corrosion inhibitor evaluation. To evaluate the O2 scavenging performance of a corrosion inhibitor injected into the amine cy cle, this test was

conducted according to methods outlined in ASTM D-888 and ASTM D-5543 for two samples of freshwater and a solution of 30% amine and 7 0%

water. Test results are shown in Table 7 .1 4 ,1 5

Corrosion test in acid/DEA environm ent. This test was conducted to evaluate the corrosion rate of carbon steel in a liquid phase contacting a

lean amine solution. The solution contained organic acids at a temperature of 25°C to 30°C, which is the temperature of the circulated amine solution

in the cy cle. Eighteen separate samples from the fresh amine solution containing an organic acid (i.e., acetic, oxalic, malonic, formic, buty ric,

succinic or gly colic) were prepared, and corrosion coupons were installed. Test results showed a corrosion rate greater than or equal to 0.2 mpy for

all of the above-named acids.

X-ray diffraction. Samples from a non-corroded portion of the tower were used in this test, as it was not possible to prepare samples from the

corroded area. The formation of iron disulfide (FeS2 ) was observed, as shown in Fig. 4.



Fig. 4. XRD test—FeS2 scale.

Corrosion in the gas-sweetening unit

DEA is used in the gas-sweetening unit. This unit was inspected one y ear after commissioning, at which time no corrosion or deterioration was

detected. A second inspection was carried out 2.5 y ears after commissioning, and aggressive corrosion was detected in the vapor space of the tower

shell, in the carbon steel section.

This tower consists of 20 tray s. The tower shell is made up of 316L stainless steel from the top head through Tray 8, and the remaining 12 tray s are

annealed SA516 Grade 7 0 carbon steel. The tower wall thickness is 12 mm, with 3 mm of corrosion allowance. The chemical composition of the

aforementioned alloy is presented in Table 8. Due to the existence of chloride ions in the feed, the chloride ion content of the circulating amine was

higher than the allowed limit during the first three months of operation. An anionic resin bed was used to absorb the negative ions. After feed quality

improved and the ion chloride content was reduced, the bed was taken out of serv ice.

Corrosion was observed in several forms. “Local” or “island-shaped” corrosion resembled several concentric, closed curves, with each curve hav ing

an almost equal center and differentiation in the borders between it and the next curve (Fig. 5). The corrosion morphology was described as “step-

down edges.” The most corroded areas were found at the centers of the curves. Here, the tower thickness was reduced by 3.5 mm to 4.0 mm.

Fig. 5. General corrosion at vapor phase area.

The “valley ” form of corrosion occurred in down-flowing liquid in the vapor/liquid interface of the shell. The depth of the valley s was 5.5 mm to 6.0



mm (Fig. 6). The corrosion shape was described as a “smooth valley ” and an “escarpment.”

Fig. 6. Tower corrosion (valley ty pe).

Investigation of corroded areas for both forms showed:

1 . Corrosion on the regions of the shell contacting the amine solution (liquid phase) was negligible. This was verified by coupon test results (Table 1).

2. Severe corrosion was observed on the tray vapor space and the liquid/vapor interface.

3. Corrosion severity in the aforementioned areas on tray s 8 to 20 (top to bottom) increased in correlation with area and depth.

Inlet gas to the contactor contains a maximum of 40 ppm H2 S. Software was used to determine the H2 S concentration in each tray of the regenerator

tower; this process was simulated based on rich amine content. Results are presented in Table 9.

In order to control corrosion, a corrosion inhibitor was injected into two lines with different pressures. These lines included a lean amine-to-

contactor line with a pressure of 60 bar to 65 bar and a reflux stream line with a pressure of less than 2 bar. Oxy gen scavengers function as the duty

of this inhibitor as well as a protective lay er (along with a surface scale of FeSX), based on the information prov ided by the inhibitor manufacturer.

Amine analysis results

The results of the circulating amine analy sis showed that the amine was degraded. Oxidation and degradation products are generally organic acids

that cause severe corrosion on carbon steel at proportional concentrations (Fig. 7 ). The analy sis showed that the amine produced heat-stable salts

after contacting organic acids, which can also cause corrosion on carbon steel (Fig. 8).

Fig. 7 . Carbon steel corrosion in various acids

and salt.



Fig. 8. Carbon steel corrosion in various acids.

Visual inspection and thickness monitoring detected no significant corrosion in the liquid phase of the amine stream on pipelines, towers or other

vessels in the gas sweetening unit. An analy sis of corrosion-monitoring results (Table 1) observed during an aggressive period of corrosion (as well

as subsequent corrosion periods) shows a corrosion rate of fewer than 2 mpy in the liquid phase. Field corrosion-monitoring results were verified by

immersion weight-loss tests in the laboratory .

The corrosion rate of the lean amine in the liquid phase was found to be within an acceptable industrial margin, according to a polarization test of the

lean amine solution (Fig. 2), which contained 3.7 1% heat-stable salts. Organic acids were also present in the solution. Although the results of the

polarization test showed rising temperature, the corrosion rate was less than 25% of the corrosion rate of the tower shell. Furthermore, the

temperature increase was related to the rich amine stream in the unit. In a rich amine stream, the formation of an FeSX lay er protects the surface. No

H2 S or FeSX lay er was observed in the lean amine solution in either the polarization test or the laboratory weight-loss test.

Use of oxy gen scavenger inhibitor. To omit O2 , which is introduced into the solution by a demineralized water makeup, an O2 scavenger

inhibitor was injected. Based on the characteristics of the inhibitor, the required temperature for starting a reaction with dissolved O2 is higher than

80°C, while the amine temperature in the tank and onstream before entering the regenerator tower (–103°C) does not reach the specified

temperature. Therefore, O2 cannot be entirely eliminated below 80°C.

Test results showed a partial decrease in the amount of dissolved oxy gen in the amine solution after the inhibitor was added, which raised the

temperature to 98°C for a period of 15 minutes. The O2 scavenging performance of this inhibitor at higher temperatures is in doubt, as it was found to

be unsatisfactory during this test.

Additionally , the results of the dissolved O2 field test are ev idence of the presence of O2 in the solution, which verifies the unsatisfactory

performance of the inhibitor. The poor performance was due to the amine coming into contact with O2 . In other words, the presence of oxy gen is a

factor in the production of organic acids.

The injection pump performs at a unique pressure, and it is not possible to inject the inhibitor into two points with different pressures, as setting the

pressure on the reflux stream would result in lower-than-desired pressure in comparison with the contactor stream. If the pressure setting is based

on contactor pressure (which is higher than reflux stream pressure), the high-pressure injection fluid would flow into the low-pressure stream

(reflux); therefore, it cannot be injected into the contactor stream.

Causes of corrosion. As mentioned above, corrosion observed on the interior of the tower is located on the vapor space or on the vapor/liquid

interface. According to an analy sis performed on degraded amine that was circulated during a period of severe corrosion, there are several organic

acid anions in amine that cause corrosion. Since tests cannot be v iably performed on liquids in the reflux drum or on outlet gases from the top of the

tower, process simulation software was used to evaluate the existence of acidic anions in gases flowing from the top of the tower. Simulation results

(Table 9) confirmed the presence of these anions in the vapor space of the tower. Vapor pressure research also indicated the presence of these

anions in the tower’s vapor space.

According to research and calculations, the corrosion rate is 40 mpy to 50 mpy . Taking into account the percentage of anion components found in

field-sampled amine, the corrosion rate was applied to these test results, as shown in Figs. 7 and 8. The FeSX scale formation on carbon steel was

found to have a smaller structure and to adhere better to metal in proportion to the increase in H2 S concentration. In lower H2 S concentrations, the

FeSX scale has a larger structure and is less adhesive to metal. Organic acid anions overcome the sulfur element of FeSX and, in the process of

destroy ing the scale, they form salts (e.g., iron acetate).

An X-ray diffraction analy sis was performed on an FeSX scale on the vapor space of Tray 9, in an area that was not affected by corrosion. Test results

(Fig. 4) show the scale ty pe to be Py rrhotite, which adheres suitably to metal and offers better surface protection than a Mackinawite scale.

The process simulation results presented in Table 9 show the decreasing presence of H2 S in the carbon steel regions of Tray s 8 through 20.

Consequently , these tray s have less adhesive FeSX scales.

The results of the sour gas-sweetening unit analy sis show that the percentage of H2 S is suitably low and meets conditions outlined in NACE MR-01-

7 5, even though the gas is sour. On the other hand, the low concentration of H2 S results in a loose and brittle FeSX scale, along with organic acid

anions in the vapor phase, steam that allows for an electrochemical condition, and the inability to inject an inhibitor into the liquid phase. All of

these factors create a tower environment that is susceptible to corrosion.

Furthermore, internal temperatures approach 120°C on the lower tray s of the tower and 100°C on the upper tray s. The higher temperature and

looseness of the FeSX scale on the lower tray s accelerate corrosion on the lower section of the tower.

Corrosion formed in a valley shape on the liquid/vapor interface due to FeS2 erosion from the use of an amine containing organic and inorganic

contaminations. Low reforming potential and a high concentration of acidic components next to the liquid surface also contributed to the corrosion.



Takeaway

According to the analy sis, the water used to prepare the amine solution contained an unacceptable concentration of oxy gen. Also, existing O2 in the

reaction with DEA resulted in DEA oxidation in the circulating amine solution, producing organic acids that entered the vapor phase of the tower. In

a corrosion-susceptible env ironment (i.e., the existence of water, high temperature, acids, and no amine in the vapor phase), the presence of these

acids contributed to corrosion on the shell interior of the tower.

The selection of a corrosion inhibitor was not correctly performed, as attention was not given to the required temperature for rationing with O2 .

Furthermore, the design of the corrosion inhibitor injection sy stem was corrupt, and the injection of an inhibitor into two points is not practical. The

lesson learned is that the selection of a corrosion inhibitor should be carefully performed. A revamp of the injection process—one that considers

simultaneous injection into two points at different pressures—is necessary . Also, the ty pe of FeSX scale that forms on carbon steel must be

considered, as this has a direct effect on the degree of surface protection achieved and the rate and extent of the corrosion that occurs.

An anionic resin bed play ed an unexpected and important role in corrosion prevention during the first y ear. In a situation where O2 cannot be

eliminated, the development and use of this ty pe of bed is recommended. Also, the implementation of a suitable lining on the tower interior can

provide temporary corrosion control. HP

ACKNOWLEDGMENT

Research for this survey was supported by Sarkhoon & Qeshm Gas Treating Co.

LIERAT URE CIT ED

1 Robert, N. and J. Morgan, Gas Conditioning and Processing, Vol. 4, Campbell Petroleum Series, Oklahoma, 1998.2 Jenkins, H., “Understanding gas treating fundamentals,” Petroleum Technology Quarterly, Winter 2001.3 Dupart, M. S., T. R. Bacon and P. C. Rooney , “Effect of heat-stable salts on MDEA solution corrosiv ity ,” Hydrocarbon Processing, March 1996.4 Rooney , C. P. and M. S. Dupart, “Corrosion in Alkanolamine Plants: Causes and Minimization.” NACE International, Corrosion 2000, Orlando, Fla.,

2000.5 Rooney , C. P. and D. Daniels, “Oxy gen solubility in various alkanolamine/water mixtures,” Petroleum Technology Quarterly, Spring 1998.6 Stewart, E. J. and R. A. Leanning, “Reduce amine plant solvent losses,” Hydrocarbon Processing, May 1994.7 Tanthapanichakoon, W. and A. Veawab, “Corrosion by heat-stable salts in amine-based CO2 capture unit,” Second Annual Conference on Carbon

Sequestration, Alexandria, Vir., 2003.8 Dupart, M. S., T. R. Bacon and D. J. Edwards, “Understanding corrosion in alkanolamine gas treating plants: Part 1 ,” Hydrocarbon Processing, April

1993.9 “Standard Material Requirements—Sulfide Stress Cracking Resistant Metallic Materials for Oilfield Equipment,” NACE International, 2002.1 0 Valenzuela, D. P. and A. K. Dewan, “Refinery crude column overhead corrosion control, amine neutralizer electroly te thermody namics,

thermochemical properties and phase equilibria,” Fluid Phase Equilibria, Vols. 158–160, June 1999.1 1 Ren, C., D. Liu, Z. Bai and T. Li, “Corrosion behavior of oil tube steel in stimulant solution with hy drogen sulfide carbon dioxide,” Materials

Chemistry and Physics, Vol. 93, 2005.1 2 Fan, D., L. E. Kolp, D. S. Huett and M. A. Sargaret, “Role of impurities and H2 S in refinery lean DEA sy stem corrosion,” NACE International,

Corrosion 2000, Orlando, Fla., 2000.1 3 ASTM International, “Standard Practice for Preparing, Cleaning, and Evaluating Corrosion Test Specimens,” ASTM G1-03, 1990 (reapproved

2003).1 4 ASTM International, “Standard Test Methods for Dissolved Oxy gen in Water,” ASTM D888-09, 1992 (reapproved 2009).1 5 ASTM International, “Standard Test Methods for Low-Level Dissolved Oxy gen in Water,” ASTM D5543-09, 1994 (reapproved 2009).1 6 ASTM International, “Standard Test Methods for Analy sis of Natural Gas by Gas Chromatography ,” ASTM D1945-03, 1996 (reapproved 2010).1 7 ASTM International, “Standard Test Methods for Conventions Applicable to Electrochemical Measurements in Corrosion Testing,” ASTM G3-89,

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T he authors

Ahm ad Zam ani Gharaghoosh is the managing director of Sarkhoon & Qeshm Gas Treating Co. He joined National Iranian Gas Co. in 1997 and

has more than 15 y ears of experience in gas refineries as a senior corrosion and welding engineer, inspection department head and research

committee member. He is an expert on static equipment inspection, risk-based inspection and corrosion investigation at gas refineries, and he has

authored or co-authored five papers for ISI journals and national and international conferences.

Abolfazl Atash-Jam eh heads the process engineering group at Sarkhoon & Qeshm Gas Treating Co. He joined National Iranian Gas Co. in 1999,

and he has 10 y ears of experience in different aspects of process engineering for natural gas. He has published seven papers for national and

international conferences.

Am ir Reza Rashidfarokhi is a mechanical engineer and heads the technical inspection group at Sarkhoon & Qeshm Gas Treating Co. He joined

National Iranian Gas Co. in 2002, and he has eight y ears of experience in different aspects of the technical inspection industry . He has also

participated in a number of industry studies and courses.

Mahm oud Pakshir is a tenured professor at the Department of Material Science and Engineering at Shiraz University in Iran. He has published

more than 7 0 papers on corrosion control and prevention.

M. H. Pay dar is an associate professor at the Department of Material Science and Engineering at Shiraz University in Iran. He has published more

than 20 papers in international magazines.



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control dea corrosion in a gas refinery _ hydrocarbon processing _ may 2012

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