8-aggressive corrosion of 316ss in an amine unit-causes and cures

of 15/15
AGGRESSIVE CORROSION OF 316 STAINLESS STEEL IN AN AMINE UNIT: CAUSES AND CURES Fred Addington Baker Petrolite 12645 West Airport Blvd. Sugar Land, Texas 77478 David E. Hendrix, P.E. The Hendrix Group, Inc. 15823 North Barkers Landing Houston, Texas 77079 ABSTRACT This paper describes the unusually high corrosion rates of UNS 31603 (Type 316L stainless steel) in the regeneration section ofa Sulfiban amine unit and the measures taken to reduce corrosion rates to acceptable levels. Corrosion in the system was mitigated through a combination of process control, chemical inhibition, and mechanical redesign. Included in the paper is a case history describing the failure of Type 316L reboiler tubes and of the Type 316L regenerator tower. Keywords: austenitic stainless steel, MEA, reboiler tube, inhibition, process control, Sulfiban, formic acid, amine units BACKGROUND Baker Petrolite was asked to determine the root cause for aggressive corrosion occurring to process equipment associated with a Sulfiban acid gas-scrubbing unit and to recommend changes to improve the unit operation. The Sulfiban unit was installed in the coke production facility of a steel mill and used monoethanolamine (MEA) as the absorbing amine. The unit was designed to remove hydrogen sulfide (H2S), carbon dioxide (CO2) and hydrogen cyanide (HCN) from a coke oven gas stream. The unit experienced significant corrosion damage, including a throughwall regenerator column failure, failure of rich/lean and regenerator reboiler exchanger tubes, significant heat transfer fouling, and greater than expected amine losses. Initial investigative actions included process stream analyses, review of operating practices, and review of corrosion control measures. Additional efforts included a review of process equipment mechanical design, review of available literature, and a laboratory analysis of failed reboiler tubes. Process description The process utilizes amine absorption and regeneration to remove contaminants from the coke oven gas stream. Table 1 shows a typical coke oven gas composition. The system is comprised of four basic parts: 1. Contactor tower 2. Regeneration column Copyright ©2000 by NACE International.Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE International, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in U.S.A.

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  • AGGRESSIVE CORROSION OF 316 STAINLESS STEEL IN AN AMINE UNIT: CAUSES AND CURES

    Fred Addington Baker Petrolite

    12645 West Airport Blvd. Sugar Land, Texas 77478

    David E. Hendrix, P.E. The Hendrix Group, Inc.

    15823 North Barkers Landing Houston, Texas 77079

    ABSTRACT

    This paper describes the unusually high corrosion rates of UNS 31603 (Type 316L stainless steel) in the regeneration section ofa Sulfiban amine unit and the measures taken to reduce corrosion rates to acceptable levels. Corrosion in the system was mitigated through a combination of process control, chemical inhibition, and mechanical redesign. Included in the paper is a case history describing the failure of Type 316L reboiler tubes and of the Type 316L regenerator tower.

    Keywords: austenitic stainless steel, MEA, reboiler tube, inhibition, process control, Sulfiban, formic acid, amine units

    BACKGROUND

    Baker Petrolite was asked to determine the root cause for aggressive corrosion occurring to process equipment associated with a Sulfiban acid gas-scrubbing unit and to recommend changes to improve the unit operation. The Sulfiban unit was installed in the coke production facility of a steel mill and used monoethanolamine (MEA) as the absorbing amine. The unit was designed to remove hydrogen sulfide (H2S), carbon dioxide (CO2) and hydrogen cyanide (HCN) from a coke oven gas stream. The unit experienced significant corrosion damage, including a throughwall regenerator column failure, failure of rich/lean and regenerator reboiler exchanger tubes, significant heat transfer fouling, and greater than expected amine losses. Initial investigative actions included process stream analyses, review of operating practices, and review of corrosion control measures. Additional efforts included a review of process equipment mechanical design, review of available literature, and a laboratory analysis of failed reboiler tubes.

    Process description

    The process utilizes amine absorption and regeneration to remove contaminants from the coke oven gas stream. Table 1 shows a typical coke oven gas composition. The system is comprised of four basic parts:

    1. Contactor tower 2. Regeneration column

    Copyright 2000 by NACE International.Requests for permission to publish this manuscript in any form, in part or in whole must be in writing to NACE International, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in this paper are solely those of the author(s) and are not necessarily endorsed by the Association. Printed in U.S.A.

  • 3. Heat exchange equipment 4. Reclaimer and filters

    Figure 1 shows a basic flow diagram of the unit. The following equipment is constructed of type 316L stainless steel: Rich/lean exchanger tube bundle Regenerator column Reflux condenser tube bundle Regenerator reboiler tube bundle

    The rest of the equipment is constructed of carbon steel. All carbon steel materials in contact with amine solution, including storage vessels, are stress-relieved. Removal of acid gases (hydrogen sulfide, hydrogen cyanide, and carbon dioxide) is accomplished by absorption into an amine solution. The amine solution and the sour coke oven gas are contacted in a vertical, packed tower. The amine solution enters near the top of the tower and flows downward through a packed section. The sour coke-oven gas enters the bottom of the contactor, where entrained liquids are separated and pumped to a holding tank. The gas flows upward through the chimney section and through the packing. The packing is designed to maximize gas-liquid contact with minimal pressure drop. The gas continues up the tower to the water wash section of the contactor. Amine losses are minimized by water washing the coke oven gas prior to its exiting the tower.

    Rich amine solution from the bottom of the contactor flows to the rich amine surge drum then is pumped to the stripping section. The rich amine is filtered and then heated through the rich/lean exchangers where heat is transferred with lean amine flowing to the contactor. Rich amine then flows into the regenerator. The rich solution enters through the top of the regenerator tower, and as it falls, a counter flow of steam liberates acid gases from the amine, which exit the top of the column. A thermal siphon reboiler and a reclaimer, at the bottom of the column, generate the steam. Lean amine solution exits the regenerator column through the bottom nozzle, flows through the reboiler to the lean surge drum, and is pumped through the rich/lean exchangers where it is cooled then returned to the contactor inlet.

    The reboiler has an internal weir, which is supposed to ensure that the tubes are continuously submerged in liquid. Acid gas and steam that exit the top of the regenerator column are cooled through the reflux condenser where the steam condenses to water and is separated in the reflux accumulator. The reflux is returned to the regenerator column and the acid gas is sent to the cyanide destruct unit for further processing. The reclaimer receives a portion (approximately 10%) of the regenerator lean amine effluent and boils it, retuming the vapor to the column, concentrating heat stable salts and other non-volatile impurities.

    Process parameters

    The amine system was designed to process the sour gas stream with a gas temperature of 70-85F (21-39C). Gas above 95F (35C) promotes amine losses through evaporation, diminishes hydrogen sulfide stripping efficiencies, and results in higher concentrations of liquid hydrocarbon impurities. Lean solution temperature to the contactor was controlled two to five degrees above the temperature of the incoming gas stream. Lean solution was comprised of MEA and steam condensate. The concentration of the MEA was maintained at 15%; however, the solution was permitted to fluctuate between 8% and 30% while operating with reboiler steam leaks. The regenerator overhead temperature was 230F (110C) and the column was maintained at a pressure of 10-12 psig (69- 83 KPa). Table 2 shows a typical analysis of the lean amine solution.

    Corrosion control

    During the first year of operation, corrosion in the unit was determined by measuring metals levels in the circulating rich and lean amine solutions. Corrosion inhibition was attempted with additives placed in the amine by the manufacturer. A carbon steel weight- loss coupon was inserted into the rich amine stream and did not show significant activity. However, filters in the rich and lean amine streams required changing after 50 hours of service due to plugging by corrosion products.

    Scope of corrosion

    Figures 2-4 illustrate examples of the type and severity of corrosion damage experienced by the amine unit equipment. Figure 2 shows deposit-covered and corroded type 3 i 6SS rich/lean amine exchanger tubes after removing the bundle from the system. Figure 3 shows a section of the type 316SS-regenerator tower exhibiting "mesa" corrosion. Figure 4 shows a section of the reflux distributor with its preferential weld heat-affected-zone (HAZ) corrosion.

    Type 316L stainless steel reboiler tubes failed after being in service for eleven months. Pitting initiated on the outside diameter of the tubes and affected only the top four rows. A new tube bundle was constructed of 316L stainless steel and

  • installed. This bundle failed after seven months with a similar corrosion profile and was repaired. The 316L stainless steel rich/lean exchanger tubes failed from the inside diameter (rich amine side) after one year of service and were replaced with titanium tubes. The regenerator column developed a through-wall leak caused by corrosion on the 316L stainless steel plate after one year of service. After inspection of the entire vessel interior, a twenty-foot section of the column was replaced with 316L stainless steel plate. The carbon steel reclaimer experienced significant fouling and trouble with level control throughout the first two years; however, inspection showed that there was no significant corrosion on this vessel or the tubes.

    INVESTIGATION

    Several steps were taken to determine the operating efficiency of the system and the rate of metal degradation. Samples were evaluated in addition to the areas already under surveillance. These samples included lean amine, rich amine, reclaimer bottoms, reflux stream, and steam condensate used for solution make-up. In addition, corrosion monitoring probes and coupons were installed in critical locations throughout the plant. These locations included:

    !. Inlet of the reboiler 2. Outlet of the reboiler 3. Reboiler/reclaimer common vapor return line 4. Through the wall of the regenerator column in the area that was replaced due to excessive corrosion.

    Each of the four new probes was connected to data recording instruments to allow trending and correlation of the corrosion rate with other system events. The unit included a Digital Control System, which made it possible to trend various plant parameters. Evaluation of the unit trends yielded the following observations:

    Levels in the contactor and reclaimer fluctuated wildly Reclaimer thermal cycles were not behaving as designed Liquid level inside the regenerator was not maintained adequately Steam inlet temperature to the reboiler was excessive Steam flow to the reboiler was below the recommended rate

    Review of the system flow diagrams revealed an oversight in the design of the piping layout. The control valve that maintained the rich amine level in the bottom of the contactor was located in the rich amine flow upstream of the rich/lean exchangers. The pressure drops associated with flow through the valve resulted in acid gas evolution in the flowing rich amine stream and nucleate boiling on the exchanger tube surfaces. The plant responded to this condition by removing one of the three rich/lean exchangers from service to lower the solution temperature at the effluent of the exchangers. This resulted in a need to add more heat to the system through the reboiler to maintain gas-stripping efficiency in the regenerator. The reboiler tube bundle began to experience corrosion and resulted in multiple tube failures. A failed reboiler tube sample was evaluated from the second reboiler failure and the results are recorded below.

    REBOILER TUBE FAILURE ANALYSIS

    As part of the overall investigation into the unit corrosion, a laboratory failure analysis was conducted on several type 316L stainless steel reboiler tubes that had failed due to general corrosion. The samples were from U-tubes and contained lean amine solution on the shell side and steam on the tube side. The submitted samples were from upper row tubes next to the steam inlet section of the tubesheet.

    Laboratory Procedures

    Laboratory procedures employed to analyze the tube sample included: (1) visual observations, (2) energy dispersive spectroscopy (EDS), (3) chemical analysis and, (4) metallographic observations using mounted and polished specimens.

    Results

    Visual Observations. Figure 5 shows a failed tube sample, as it appeared when it was removed from service, illustrating an area of general corrosion. The corroded area was unusual in that the corrosion appeared to stop at a specific distance below the O.D. surface and followed the circumferential shape of the tube sample, In uncorroded areas the sample was covered with a thin, adherent green scale. The tube sample I.D. (not shown) was in good condition with no observed general/pitting corrosion or hard water deposits. Also, the ERW weld did not exhibit significant corrosion.

  • Metallographv. Figures 6 - 8 illustrate the microstructure of the tube sample at various locations of interest. Figure 6 shows the microstructure at an interface between a corroded and an uncorroded area. No microstructural features were observed which would account for the specific pattem, shape or depth of the O.D. corrosion. Figure 7 shows the microstructure at the bottom of an O.D. corroded area. Again, the microstructure exhibited no features that would explain the peculiar corrosion pattern. The microstructure consisted of equiaxed austenitic grains with scattered non-metallic inclusions. No evidence of stress corrosion cracking was observed. Figure 8 shows the microstructure at the autogenous weld. The weld contained a dendritic structure, suggesting that the tube was not sufficiently cold worked and heat treated during mill processing to homogenize the microstmcture, per the requirements of ASTM A-249.

    Chemical Analysis. Chemical analysis results show that the tube sample met the chemical composition requirements for ASTM A-249 Gr. TP 316.

    EDS Analysis. Figure 9 shows EDS analysis results of the green scale/deposits on the tube sample O.D. The O.D. deposits are composed primarily ofchromiurn and oxygen, probably combined as a chromium oxide corrosion scale. Lesser quantities of other base metal elements were detected, e.g., iron, nickel, molybdenum, as was some sodium and silicon.

    Reboiler Tube Sample Corrosion Characteristics

    Examination of the reboiler tube sample showed that it had experienced loss ofpassivation and rapid general corrosion. Although the corrosion pattern was unusual, no microstructural or chemical composition anomalies were observed that would have contributed to the corrosion. The weld did not appear to have been properly heat-treated; however, it was not involved in the corrosion.

    Austenitic stainless steels typically corrode due to pitting, based on the tenacious chromium oxide scale that forms on their surfaces. In aggressive (highly reducing) environments where passivity is lost, types 304SS/3 ! 6SS can suffer general corrosion, and in such cases, corrosion rates can be high. Austenitic stainless steels like type 316SS typically lose passivity in strong reducing acids, in moderately corrosive acids at high temperatures, or in aqueous solutions with insufficient oxidizing capacity to maintain the oxide film.

    A review of amine solution analyses reports suggested that the high levels of formates were likely candidates for causing the corrosion. In certain conditions, low percentages of free formic acid can be formed from formate salts. Type 316SS is normally resistant to all concentrations of formic acid up to the atmospheric boiling point; however, at higher temperatures, or in solutions of low oxidizing capacity, type 316SS can corrode at high rates. Types 304SS/316SS can also suffer intergranular corrosion (1GC) in hot organic acid solutions, if sufficiently sensitized due to grain boundary carbide precipitation. IGC may have partially accounted for the observed preferential weld seam corrosion in the reboiler and rich/lean exchanger tubes. Other rich amine contaminants that are normally controlled to prevent excessive corrosion of carbon steel, including high acid gas Ioadings and CO,_ to H2S ratios, are normally not corrosive to type 316SS. Chlorides were not considered to be a contributing factor in the accelerated corrosion as their concentration in the amine was low. They also promote chloride stress corrosion cracking (SCC), pitting, or crevice corrosion. The tube sample experienced general corrosion and not any of the typical chloride induced mechanisms.

    Corrosion in amine solutions

    Corrosion in lean and rich amine solutions has been studied extensively 16. Minimizing corrosion in amine units involves a holistic approach 7. Rarely does changing a single operational or process parameter resolve an aggressive corrosive condition. Most studies have been directed at minimizing corrosion of carbon steel, as they are the most frequently used materials in amine units. Where conditions dictate, austenitic stainless steels, i.e., types 304SS or 316SS, have been used in hotter sections of amine units, either where corrosion cannot be controlled otherwise, or where the use of stainless steel would allow greater flexibility in unit operation. A review of available literature suggests that austenitic stainless steels generally have provided good service in all but the most severe environments 8-1~. When excessive corrosion has occurred, it has often been associated with excessive temperatures and high heat stable acid salt (HSAS) content. Corrosion of austenitic stainless steel tubes has occurred in amine reboilers using high-pressure steam or when upper row tubes become starved and overheated.

    A review of amine solution analyses showed that the lean amine solution exceeded generally accepted targets for contaminants and degradation products established by various researchers and end users, based on experience 2.4. Generally accepted guidelines call for maintaining HSAS levels below 2%, with some guidelines stating less than 1% as a target s.

    It is difficult to apply amine contaminant target levels to the reboiler and regenerator corrosion problem since the

  • established contaminant levels have been derived to limit corrosion of carbon steel components. However, initial efforts at process control to minimize the regenerator and reboiler corrosion focused on reducing HSAS levels. Other activities that were targeted for investigation, based on their potential contribution to HSAS levels and system corrosion, are discussed below.

    HSAS precursors. High formate, thiocyanate and thiosulfate levels in the amine solution (see Table 2) suggested that oxygen from an unknown source might have been entering the amine unit. Oxygen in an MEA solution contributes to formate, thiosulfate and cyanate HSAS formation 3. Oxygen is also known to promote formation of formic, acetic, and oxalic acids in MEA. It is for this reason that deaerated water is recommended for MEA solution make-up.

    Other compounds that may have contributed to HSAS formation include carbon monoxide in the coke oven gas stream and reaction of oxygen with hydrogen sulfide to form sulfur dioxide. Carbon monoxide specifically would contribute to formate production, while sulfur dioxide would promote sulfate salt formation.

    Regenerator-reboiler Operation. Regenerator operation should attempt to strip acid gases on the trays instead of in the reboiler. If regenerator internal pressures are insufficient, inadequate stripping will occur and the reboiler will be exposed to increased acid gas concentrations.

    Reboiler operation can contribute to acid gas breakout in the vapor space. Acid gas breakout containing formic acid can result in high concentrations of formic acid on tube surfaces and create aggressive corrosion. Conditions that can contribute to acid gas breakout are high tube metal temperatures and/or low solution levels. Low regenerator liquid level could result in hydrostatic head pressures that were insufficient to flood thermosyphon reboilers. Reboiler tube metal temperatures were also investigated, based on steam pressures and flows, and found to be in excess of 320F (160C).

    Reflux stripper operation. The reflux stream, which is pumped from the reflux accumulator to the regenerator, first flows through a steamed stripper to remove hydrogen cyanide. The hydrogen cyanide gas is returned to the coke oven gas flow upstream of the amine unit. As a result the cyanide levels are permitted to concentrate in the unit, which adds to heat stable salt levels and corrosion in the system.

    CORRECTIVE ACTIONS

    Various operating parameters, design changes, and chemical additives were employed to address issues revealed in the investigation. Sample analysis showed very high levels of amine contamination and indicated inadequate function of the reclaimer. Further study of the fluctuating reclaimer level suggested that liquid was flowing through the vapor return line into the regenerator. Increased corrosion rates and the inability to reduce heat stable salts in the amine solution confirmed this event. Foaming and the inability of the level control system to respond to the condition contributed to uncontrolled reclaimer levels. To correct this, the reclaimer level control circuit was placed on manual control and an antifoam chemistry was added to eliminate liquid transfer through the vapor line. Figures 10-12 show the levels of contamination and the rate of amine loss from the unit. Figure 10 depicts a close relationship between corrosion rates and reclaimer function. The amount of corrosion products in the stream decreased with improved reclaimer operation and control. Similarly, the rate of amine lost from the unit decreased as the reclaimer level control was improved and the foam inducing solids diminished (Figure 11 ). The reclaimer, due to improved efficiency, reduced the heat stable salt concentration in the solution (Figure 12).

    Stream analysis indicated that amine-stripping capacity of the regenerator was not sufficient due to inadequate reboiler steam feed rate. Study ofreboiler tube skin temperatures showed them to be excessive, based on thermal degradation of MEA. The steam pressure to the reboiler was decreased to lower the saturated steam temperature while the steam feed rate was increased. This allowed for additional heat into the system to enhance stripping efficiency in the regenerator without thermally degrading the amine. A water dispersible corrosion inhibitor was added to the circulating amine solution to protect carbon steel components.

    During the 1999 outage the contactor level control valve was relocated to a position down stream of the rich/lean exchangers and close to the amine inlet nozzle of the regenerator. This configuration provided a consistent backpressure on the rich amine system and permitted the addition of more heat through the rich/lean exchangers without the risk of acid gas evolution.

    Flow through the reflux stripper was minimized in order to limit the amount of hydrogen cyanide gas recycled to the amine unit. At this writing, there were plans to construct a cyanide destruct unit to treat this gas stream, at which time the reflux stripper could be operated as it was designed.

  • CONCLUSIONS

    Corrosion of the 316 stainless steel reboiler tubes was most likely due to formic acid attack caused by the high levels of formate containing heat stable acid salts in the circulating amine stream. Improper reclaimer operation contributed greatly to the corrosive environment by introducing a concentrated stream of contaminants into the amine solution through the reclaimer/reboiler vapor return line. Because the amine solution was not replaced after the first failure and subsequent outage, the high levels ofcontarnination persisted during the investigation. This led to additional failures and a prolonged recovery period. One should carefully consider the benefits of reclaiming or replacing the amine solution rather than expose the system to an aggressive environment by attempting to recondition a dirty solution during operation.

    Some users attempt to treat stainless steels the same as carbon steel for corrosion mitigation. This is not the correct approach as the materials react differently to the environments present in an amine system. Carbon steel tends to form a passive iron sulfide film that can be enhanced through the use of corrosion inhibitors. Stainless steels do not react with the sulfide because of the tenacious chrome oxide film on the metal surface. Therefore, filming corrosion inhibitors are not effective with these metallurgies.

    Corrosion in this unit was brought under control with HSAS measuring < I wt. % and corrosion rates < I mpy (Figures 13- 14). The system filters have remained in service for 2000 hours prior to replacement. The key to corrosion control in amine systems with stainless steel is the proper control of HSAS.

    REFERENCES

    . H. Lee Craig Jr., B. D. McLaughlin, "Corrosive Amine Characterization", CORROSION/96, paper no. 394, (Houston, TX: NACE International, 1996).

    2. J.C. Dingman, D. L. Allen, and T. F. Moore, Hydrocarbon Processing 45,9 (1966): p.285.

    . P.C. Rooney, M. S. DuPont, and T. R. Bacon, Hydrocarbon Processing, July 1998, p.109.

    . R. B. Neilson, K. R. Lewis, J. G. McCullough, D. A. Hansen, "Corrosion in Refinery Amine Systems", CORROSION/95, paper no. 571, (Houston, TX: NACE International, 1995).

    . A. L. Cummings, F. C. Veatch, A. E. Keller, "Corrosion and Corrosion Control Methods in Amine Systems Containing H2S", CORROSION/97, paper no. 341, (Houston, TX: NACE International, 1997).

    6. E. Williams, H. P. Leckie, Materials Protection, July 1968, p. 21.

    7. R.G. Abry, M. S. DuPont, Hydrocarbon Processing, April 1995, p. 41.

    8. P.C. Rooney, T. R. Bacon, M. S. DuPont, Hydrocarbon Processing, March 1996, p. 95.

    9. A.J. MacNab, R. S. Treseder, Materials Performance, January 1971, p. 21.

    10. H. P. E. Helle, "Corrosion Control in Alkanolamine Gas Treating Absorber Corrosion", CORROSION/95, paper no. 574, (Houston, TX: NACE International, 1995).

    11. E.D. Montrone, W. P. Long, Chemical Engineering, January 1971, p. 94.

  • Table 1

    Typical Coke Oven Gas Composition

    ORGANIC SULFUR HcN H2S Hz

    0.15

    (grains/100scf) (grains/100scf) (volume %) (volume %) 5 20 0.37 55.1

    02 N2 CO CH4 (volume %) (volume %) (volume %) (volume %)

    0.19 5.61 5.84 28.63

    COz CzH4 CeHe (volume %) (volume %) (volume %)

    1.58 2.03

    Table 2

    Typical Lean Amine Analysis during the Second Half of 1998

    Carbon dioxide weight percent 0.355 Amine concentration weight percent 10

    Heat stable salts weight percent 8 Chromium PPM 70

    Iron PPM 400 Nickel PPM 50

    Thiocyanate PPM 3,900 Formate PPM 50,000 Chloride PPM 35 Sulfate PPM 40

  • Figure I : System diagram of the amine unit.

    Sweet Coke Oven GaS

    Sour Coke Oven Gas J ~

    Rich Amine

    Drum

    X

    X c

    E

    HCN Destruct Unit Claus Unit Incinerator

    I (I,.,.,=1)

    .J

    ~r -~

    L nAmn

    Figure 2: Shows deposit-covered and corroded type 316SS rich/lean amine exchanger tubes atter removing the bundle from the system.

  • Figure 3: Shows a section of the type 3 i 6SS-regenerator tower exhibiting "mesa" corrosion.

    Figure 4: Shows a section of the reflux distributor with its preferential weld heat affected zone (HAZ) corrosion.

  • Figure 5 - Amine reboiler tube sample showing corrosion damage typical of that observed to all corroded tubes. -1.75X

    Figure 6 - Microstructure of the tube sample in Figure 5 at interface between the corroded and uncorroded area. No metallurgical or structural differences are evident that would account for the corroded geometry. 50X

  • . . , Q , ~o ' o - .

    . 11 ~, . *o f 4 * ' ~X

    ~' ~ " ~ i ; , "~ " . . . . "." " "/" . - i " *. '~*.

    , j ' , . ; j , , . o ' . , , . .

    : , ,, , " " , : , . . ~ . , , . " , . , . . ) , , " o . . o - . ,p

    .?'. ", " ; '~'.~ ' . . . . . " ' . " , , . - i . - - . - . " '~ i "~ ' *~ ' ' ' " t . . ,

    ' " " ' , .~ 3. r ' . " .~' , , . ' . . . . " . : " : ; " ~ . /

    Figure 7 - M icrostructure of the corroded reboiler tube sample in the middle of the corroded area. The tube O.D. is at the top of the photograph. No microstructural anomalies are evident here that would account for the unusual corrosion pattern.. -100X

    Figure 8 - Corroded reboiler tube sample at the unaffected ERW weld Here, the weld does not exhibit preferential corrosion. The dendritic structure of the weld suggests that it was not properly cold worked before heat treating to remove the dendritic structure per ASTM A-249 requirements 100X

  • Figure 9

    EDS Elemental Analysis of Green Colored O.D. Scale From a Failed Amine Reboiler Tube Sample

    O

    S I

    C R

    , r IIC n i l M - _ E

    N L !~ 0 T f~

    A ~ :" VFS = 4096 10 240

    136 1-19917, RMINE REB(} [LEP 1 UF~E 0 D DEPOS I l

    El ement K - ra t io Z A F ZAF ~L - E: -K g .Og7 0 .901 4 .492 g .999 3 .966 6 .98 2 .89 [~ -K g.132 8 .918 2.281 0 .998 2 .g89 49. , 9 27.55 Ha-K g .e05 g .977 4 .g77 g .999 3 .982 2 .32 I .~4 Mg-K g .Og4 g .~53 2 .816 g .999 2 ,~gO I .34 I .12 ~,I -K g .g03 g .982 2 .126 0 .998 2 .082 0 .57 g .53 ~;i-l< g .g35 0 .953 1.6~5 g .P~8 I .613 5 .82 5 .63 ~lo-L g .g2g I .142 1.122 g .995 1.2775 g .76 2 .49 l i -K 0 ,g36 I .g68 I ,024 g .?g2 0 .987 2 .17 3 ,58 (~r-K g.431 I .g71 I .g12 g .992 I .g75 25 .85 46 .29 t ln-K 0 .017 | .g87 I .g06 0.?P9 ! .092 0 .96 I .82 Fe-K 0 .g47 I .g67 I .g92 g .?99 I . 164 2 .g5 5 .4~ lq i -K 0 .gg7 I .g2E, i ~ 1 . Ig5 0 .38 8 .77

    Tota l= 100.00%

  • 600

    500

    400

    300

    200

    100

    Iron Level, ppm B-Point Moving Average - - -Reclaimer Bundle Cleaning Limit

    . io o

    gem, - __ Oi

    . " ! "-,,,, " . . i . i l

    ~ o o " Ot i

    oOoo~ NO

    o . - . - ~, ~, o , - ~ o ~ ~, o . - ~,

    Figure 1 O: Iron level in the lean amine.

    18-1~ r-08

    Daily MEA Usage, gal 7.Point Moving Average Limit Limit

    O4-Nov-06

    22-Jun-05

    08-Feb-04

    26-Sep-02

    14-May-01

    O0..Jsn-O0 1...., ....... , .............................. ." .........................................

    u

    I "2 \%" *

    , ! I ~ i i

    . . ~ . . . .~ : ; " _ . - . . .

    D e

    .

    Figure 11 : Amine usage rate.

  • Heat Stable Salt., wt% ~L imi t i 12

    10

    i 4

    ~ go e e

    O me ,me

    ~ ,~

    e 00

    % . ' .* "o O 0~41)

    o o e~e O ,~'sp

    0 0

    8 o I f m. '11 "

    eom e - - -o ,~,d l~ --- d .e . '~ . ,e '%, . . , _ .1

    7 dl . . " " " ,7 - .1 glq~oO qr /

    . . . . . . . . . . . . . . i . . . . . . . . . . . . .

    F iNe 12: Heat s ta le salts in rich ~ ine .

    35

    30

    B Inlet to Reboiler (316L) Outlet of Reboiler (316L)

    . I | , It

    L ,, I11 II, , I ! o !

    Figure 13: Corrosion rates of type 316L stainless steel at the reboiler inlet and outlet.

  • Inlet to Reboi ler (CS) i~ Outlet o f Re boi ler (CS) 45

    40

    3O

    25

    2O

    15

    ' . , 'Li ~l l j L ~ . , , ~ ~ ~ ~, ~ ~ ~,

    i

    8~

    Figure 14: Corrosion rates of carbon steel at the reboiler inlet and outlet.

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