Paper No.

391COIIRI?OSIONc)L,The NACE 1Mernational Annual Conference and Expositiorl

MORE EXPERIENCES V/ITH CORROSION ANDFOULING IN A REFINERY AMINE SYSTEM

Michael J, I,itschewskiSun Company, Inc.1819 Woodville RoadToledo, Ohio 43616

ABs’rlucT

This paper describes a roller coaster ride of corrosior[ and subsequent fouling in a Refinery MDEAsystem. The accelerated corrosion was first initiated by addition of caustic and the following up anddown corrosion rate was a result of operating conditions imposed by increased sour crude charge,fouling and mis-application of MDEA. System vari:.bles that were controlled during this periodincluded equipment metallurgy, the addition of caustic to neutralize heat stable salts (HSS), ionexchange to remove HSS and sodium, amine circulal ion rate, reboiler steam rate and the injection ofcorrosion inhibitor,

PROCESS DE:SCRIPTION

The amine plant, shown in Figure 1, processes refinery sour wet gas from the Fluid Catalytic Crackin,Unit (FCC), and crude units and dry gas from other tefinery streams. Sour propane - propylene istreated in a liquid amine absorber. The amine regenerator or stripper has a horizontal kettle type reboiusing nominal 60 psig steam. Filtration is provided by 5-10 micron bag type and a clay filter. The riclamine flash drum operates at 5 psig

The Regenerator and Dry Gas Absorber have 21 and 20 trays while the Wet Gas Absorber and theLiquid Treater have packed beds. Trays, associated ~ttachment hardware and support rings are 304stainless steel. Packing is 316 stainless. The Lean ~ mine Cooler and Regenerator Overhead Conden:are SB-33 8-2 Titanium. Of the two Lean/Rich exchangers, one is SA-214 carbon steel, the other 31stainless, System volume is about 23,000 gallons clf 33-35°/0 MDEA. Normal acid gas loadings are0,20 mol acid gas/mol rich MDEA and ,0014 mol acid gas/mol lean MDEA.

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Copyl’ight01996 by NACE International. Requests for permission to publish this manuscript in any form, in part or in whole must be made in writing to NACEInternational, Conferences Division, P.O. Box 218340, Houston, Tex=s 77218-8340. The material presented and the views expressed in thispaper are solely those of the author(s) and are not necessarily endorssc by the Association. Printed in the U.S.A.

Background

The system used MEA for 10 years but was switchetl to a proprietary MDEA in 1986. The aminechange was to reduce energy consumption and corrosion which allowed for elimination of an expensivecorrosion inhibitor program,

Corrosion was a major concern while using MEA, The regenerator was replaced in 1985 after 9 years

on MEA and reboiler bundles were replaced on an almost yearly basis, In a effort to improve bundlelife several metal lurgies were tried (on MEA) inclLding 304L, 316, and Sandvik 3RE60. These failed,often in a very short time. Several factors contributed to failure, including excessive vibration fromdisengaging gases, non-flooded top tubes and corrcls on.

Reboiler life remained our primary corrosion concer I after switching to MDEA although somecorrosion had been observed in the bottom of the regenerator, Routine amine analysis indicated that theamine was well stripped but poor sampling techniqulx contributed to low Acid Gas Loading (AGL)results. Acid Gas Loading results of a sample colle{:ted with a small water cooler indicated periods cfhigher AGL in the lean amine. Higher AGL COUICcontribute to corrosion in the regenerator andreboiler,

Corrosion monitoring consisted only of a carbon st:~ 1coupon in the liquid outlet piping of the reboiler.This coupon was mounted on a Type 316L stainless holder and inserted into the stream via a valve andpacking. Normal historical corrosion rates were less than 8 mpy. The same holder and couponmetal Iurgy was used through the entire reported history.

In October 1989, a newly designed bundle was placed in service after a failure with MDEA as thesolvent, The bundle had an “X” pattern of omitted tubes to allow for gas disengaging, The carbon steeltubes had a heavier wall (O.120”) than previous bundles (0.065”).

In November 1991, several tubes were plugged anc the bundle was eventually replaced in March 1992Bundle life had increased from 10-12 months to 18-;0 months. Inspection of the bundle showed severtpitting and weak acid or acid gas attack, Failure WM in the top 4-5 rows of tubes where general ODthinning had reduced tube diameter sufficiently to al ow tubes to vibrate in the baffles and wearthrough by fretting.

Corrosion coupons of several metal lurgies were inst~ lled on the March 1992 bundle and another set onthe new bundle installed in September 1993. The coupons were installed on the back baffle as close tothe heat transfer surface as possible. The results are given in Table 1.

Sour crude charge was gradually increased such thal average weight percent sulfur rose from 0,34 wt’%

in 1985 to 0.46°/0 in 1994, Prior to 1989, unit shutdcwns were taken every 2.5 to 3 years, at the time ofthis incident the unit was 3 years into an eventual 5 ~ear run.

DISC1J3SIONCaustic and Corrosion

The MDEA solution contained about 2.6 wt% HSS ESMDEA at the time of the March 1992 bundlereplacement. The amine was clean even though the :]recoat filter was out of service. The clay filter WM

keeping the particulate concentrations acceptably 10W.

After viewing the reboiler bundle, the amine supplie - recommended neutralization of the HSS withcaustic. Neutralization of HSS with caustic has beer reported in literature for MEA and DEA but littlehad been published on neutralization of HSS with caustic in MDEA solutions in 19921Z, The basicconcept is to react a strong base with the acids that accumulate in the amine, This should release theamine bound by the acids to resume acid gas absorption. The acidic and the sodium ions remain in theamine solution. In April of 1992, two additions of Rayon grade (high purity) caustic, totaling 200gallons, were made to the MDEA solution,

About 30 days after caustic addition , the corrosion coupon was analyzed and showed a slightly elevatedrate. Although the rate was within the historical ral:~e, the nature of the metal loss was more localizedBecause the system has no purge, sodium had increa;ed to 2.3 wtOAand ash to 0.88% A secondcoupon showed an elevated corrosion rate of 18 milsiyear (mpy). Coupon frequency was increased toabout 30 days because of the localized nature of the ;Lttack. Coupon corrosion rates are shown in Table2.

Corrosion of the coupons was most severe at the Ieac ing edge of the coupon and the coupon holder, atype of crevice attack. Identical corrosion was observed on all 5 coupons after caustic addition but priorto sodium reduction to less than 150 ppm by ion exchange. An alternate theory that the attack wasunder deposit corrosion was not supported by system conditions as shown in Table 3. The aminesolution remained clear and iron levels did not incr:z se until nearly seven months after caustic addition.

Crevice corrosion, once initiated, is very difficult to ]top due to the stagnant conditions within thecrevice. Stainless steels like other alloys forming protective oxide layers are susceptible to this type ofattack, A 3 16L stainless steel thermowell on the ret oiler and the 304 stainless steel packing supportring attachment hardware (Wet Gas Absorber) failed The failure of the support ring attachmenthardware resulted in collapse of the bed.

Additional evidence that crevice corrosion was init ated by the caustic addition can be seen in Table 3.Chromium content in the amine began to rise immediately following caustic addition from historicallyless than 1 ppm to a peak of 12 ppm. It remained ligh, despite reduced corrosion rates following ionexchange and dilution from higher than normal fresh amine additions. Three separate cleaningmethods, a complete solvent change out and the initi ition of a corrosion inhibitor program occurredbefore chromium content returned to near normal co lcentrations.

The coupons attached to the reboiler bundle during tile period of caustic addition and high sodium levelsshowed heavy pitting as compared to those installed after sodium removal by ion exchange. Corrosionrates and descriptions of the coupons attached to the reboiler bundle are listed in Table 1.

Formate Concentrations

The formate ion concentrations in the MDEA solvcmt are historically high as listed in Table 3. Formicacid is a primary contributor to HSS and high conce~itrations can contribute to increased corrosionactivity. Figure 2 identifies the corrosion rates of tht; reboiler outlet coupon and the formate levelcorresponding to the exposure period.

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The corrosion rates appear to reflect formate ion concentrations but closer examination reveals that thecorrosion rate increase is more closely linked to the : odium concentration (Table 3). Coupon corrosionrates had historically been less than 12 mpy with fcr]nate concentrations up to about 8000 ppm, Aftercaustic addition, corrosion rates increased rapidly to 44.4 mpy while formate ion concentrationsincreased to 11,900 ppm. The increase in formate l:~el certainly contributed to the acceleratedcorrosion, however the rapid increase in corrosion ar d formate concentrations both occurred aftercaustic addition.

An unanswered question is the possible impact of cal]stic on the formate ion formation. Kim, Palmerand Millimans discuss one method of formate ion formation in the presence of carbon monoxide thatindicate MDEA has a slow carbon monoxide absor~tion rate as compared to potassium carbonate. Themethod they discuss may imply that caustic addition could increase the carbon monoxide absorption ra:einto the solvent and thus increase formate ion form~tion, The reported mechanism requires no oxygen.

Our investigation into the increased formate ion concentration revealed that the crude diet wasessentially unchanged. All wet gas streams are watel”washed three times prior to reaching the amineunit. Routine analysis of these water streams showed no increase in organic acids, including formic.

Retlnerv MDEA Use

The system operated with MEA and a corrosion inhibitor program prior to 1986. The only challenge:experienced were cracking in non-stress relieved pip; welds, corrosion and replacement of theregenerator and failure of the amine reboiler bundle. The regenerator corrosion was attributed togalvanic action between collapsed 304 stainless tr~~s and the regenerators carbon steel walls. Thereboiler problem was attributed to bundle design ar d was corrected in March 1992 after switching toMDEA, No corrosion problems were noted and the :;ystem was clean at the end of each 2-3 year run.The regenerator was periodically water washed and the effluent was usually black.

In 1986, the solvent was changed to MDEA and the corrosion inhibitor program stopped. About 2.5years later, some operational problems were experi:rced, but were not clearly documented, After 3years of service on MDEA, the system was brought down for routine turnaround. During theinspections, much of the equipment inspected, showed moderate to heavy buildup of sludge. Theregenerator trays below the rich amine feed nozzle h,~d2-3 inches of material accumulated. Thismaterial, when analyzed was primarily iron sulflde

After turnaround, the unit began the five year run vd ich included the previously discussed causticaddition. Following the February 1993 Ion Exchang: treatment, the corrosion rates returned to normallow levels, They remained low only about 3 months before returning to a 20-30 roil/year range. Theauthor believes these higher corrosion rates were the result of inherent weaknesses of using MDEA inour system, as given below.

First inherent weakness of MDEA in our system is tie iron sulfide corrosion product fouling ofequipment and the limited means to remove acids ud corrosion products in our MDEA system. In oursystem, fouling while using MEA was less signific;lrt due to the amine reclaimer which removes solid:;and acids and the use of an inhibitor to disperse solics and protect metal surfaces, MDEA cannot beeasily or economically reclaimed continuously, Filtration removes solids and foaming agents but Leanfiltration had been inadequate to remove corrosion p -oducts.

39”f4

MDEA is sold as non-corrosive” and to take advantage of that we eliminated an expensive corrosioninhibitor program, There is ample evidence that cl(;an MDEA is less corrosive than DEA or MEA butmost of the literature deals with carbon dioxide systtms and does not compare the amines at normalrefinery operating concentrations or conditions, Pea ‘ce and Brown reported corrosion rates of 20-26mpy in a 50°/0MDEA solution saturated with hydro!,en sulfide.5

Increasing MDEA concentration increased corrosicn rates as shown in Figure 3 and reported inliterature.f’7 All high corrosion rates from the caustic episode were eliminated from the graph. Onlythose corrosion rates generated with similar operatic, ~ conditions at different amine concentrations wereused,

A second weakness of MDEA in our system is the high MDEA volubility in propane at high amineconcentrations. Because of the systems liquid treater and the high volubility in propane, MDEA waslimited to about 35’% concentration. This is comparable to an MEA concentration of about 18 wtOAora molar basis and is considerably less than the 45-50’% recommended operating range for MDEA.Exceeding 35% resulted in high amine losses, and o her adverse downstream effects.

The 35°A concentration worked well until the syste~n fouled and the refinery was attempting tomaximize sour crude production, The first noticeabl a result of the fouling was the lean aminetemperature. Normally, lean amine cooler outlet ten- perature target was 120 F, but following the ionexchange, amine temperature gradually increased to 150 F. The hotter lean amine and lowconcentration severely restricted acid gas removal capacity.

To compensate for this low concentration, the unit would run with higher circulation rates and thenoverstrip in the regenerator. As shown by Figure 4, ]lormal amine circulation rate prior to the initialaccelerated corrosion cycle were 450-460 BPH. They gradually increased to 550-600 BPH as thefouling progressed. Overstripping was measured by steam rate to the reboiler. This increased from anormal of 10-12 Mlbs/hr to a routine of 17-18 Mlbs/ n- with peaks as high as 22 Mlbs/hr. Byoverstripping, the capacity of the amine was rnaximi:red and the higher circulation rates increased therelative contact time, in effect increasing the relati~c: amine concentration.

The combination of increased circulation rate and reljoiler steam rate was not enough to preventhydrog-en sulfide breakthroughs and the refinery was forced to cut sour crude charge rates, It appearsthat these operating conditions only served to incre~se corrosion and promote additional fouling, Table2. Overstripped amine may contain too little hydrog m sulfide to maintain a protective iron sulfide sea’ ein the reboiler and hot lean amine piping, allowing fc)rmore aggressive corrosion.

In September 1994, the system was brought down for an acid cleaning of selected equipment and the

solvent was changed out, A filming type corrosion nhibitor program was initiated with the intent ofstabilizing the iron sulfide protective scale and remo.ling solids. Since the startup, the amine solutionremained clear, filter bag changes were reduced from every 4 hours to once a day or less, and corrosiot~rates began to return to normal. Additionally, the rcf nery was able to resume sour crude productiontargets and meet H~S specifications.

It should be pointed out that a corrosion inhibitor is, like MDEA, not a panacea. Certain conditionsmust exist for it to work properly. This was made c Iear when the corrosion rate jumped from 3.7 mpyto 20 mpy just prior to unit shutdown. Investigation revealed that changes in system operating

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conditions had set up circumstances that limited the ilbilities of the filming amine type inhibitor

The 3.7 mpy coupon was removed O1/06/95 and ths 20 mpy coupon installed at that time, As withprevious low corrosion rate coupons, the 3,7 mpy cc upon had a good black, protective film formed onthe surface. At about the same time the second coup m was installed, amine concentration dropped fromabout 37°/0 to 33°/0 and the unit was having difficulty meeting HZS specification. To compensate,circulation rate was increased -1 4°/0, from 550 to 625 BPH and to overstrip the amine, steam rate wasalso increased 20°/0. This condition existed during the entire 33 day exposure period of the secondcoupon. The coupon, when removed, was white as no iron sulfide film had formed, The operatingconditions of over circulation and overstripping had ,;imply prevented the formation of a film for theinhibitor to stabilize.

The author believes that the inhibitor was still benefi ;ial during this incident, The corrosion rate waslower than those measured during similar operating conditions, the solvent remained clean and therewas no increase in the frequency of filter bag chan~e outs.

Proper corrective action to restore amine concentrati(m and reduce operating severity were initiated, butthe unit was shut down shortly after and the effect of these changes on corrosion were not measured.

CONCLUSION

As Refineries push toward longer runs and economics favor running more sour crude, maintainingcleanliness in these important environmental units w 11become more critical. Minimizing corrosion iskey to maintaining cleanliness. Three recommendations have been made to improve the long termreliability of this system.

1. Corrosion coupon results were used to change the reboiler metallurgy to type 304 stainless steelThis should extend the bundle life to well beyond thf current 18 months.

2, A filming type corrosion inhibitor program was itlitiated to minimize corrosion and maintain systemcleanliness. Fouling is reduced by the inhibitor disx:rsing solids until they can be properly removed byfiltration,

3. Investigate replacement of MDEA solvent with Z.solvent with higher hydrogen sulfide capacity andlower propane volubility at operating concentrations.

ln addition to these recommendations, three conclusi ms were formulated

1, Caustic addition has the potential to initiate cre~ it:e corrosion in stainless steel as determined by thefailed stainless steel equipment, increased chromium concentrations in the amine and increasedcorrosion rates of the stainless steel coupons attachec to the reboiler.

2. Caustic addition may promote the formation of Fcrmate ions

3. Over stripping MDEA results in too low a hydrogen sulfide concentration to form a protective ironsulfide scale in the regenerator bottom section, reboi er and hot lean amine piping.

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REFERENCES

1, Butwell, K.F,, Kubek, D,J, and Sigmund, P.W,, ‘~dkanolamine Treating”, Hydrocarbon Processing,March 1982,

2. Ball, H. T., “Designa ndOperationo fAmineU nits”, Petroenergy, October 23-27, 1989,

3. Kim, C. J., Palmer, A.M. and Milliman, G.E., “Abs~rption of Carbon Monoxide into AqueousSolutions of K2C03, Methyldiethanolam ine and D [ethylethanolam ine”, American Chemical Society,1988,

4. Sales brochure

5. DuPart, M.S, Bacon, T,R,, and Edwards, D. J., “ Understanding Corrosion in Alkanolamine GasTreating Plants”, Hydrocarbon Processing, April 1993

6. Pearce, R.L, and Brownlie, T.J, “Selective Hydrc)gen Sulfide Removal, ” Gas ConditioningConference, Norman, Ok, March 8-10, 1976

7, Keller, A.E and Mecum, S.M., “Heat-Stable Salt F.emoval From Amines By the HSSX Process UsingIon Exchange”, The Laurence Reid Gas Conditionin~~ Conference, March 2, 1992.

T,% BLE 1

IN-SITU CORROSICIN COUPON RESULTS(rates are in mpy)

Days Exposure 508 days ::~:::~:~J:::~:J:::~:::~:::::~:::~:~:::J:::m~:~.:::::::::::::::::::::::::$W347 days %i&i@gT:r:T::::i:.:.:::..ft$.f:!:.:.:+:~:..‘ yJJ$J\$]i.:::?c*$;J*&#$~*::::::::::::::::::::~::::::::::w.:::w::~:::#$::..:::~.j$....................................................... ...+.,.. ................................................................:.:!.i}:y:.:.:.:..:.:.:.:.::.::::::::::::::::::::::::::::::t.:.:.:.:.:.:.:.:.:=.:.:+:.!.:...:.:.:.:.:.:.:.:.:.:.: ~<@%#8%XW&W:;

Material 9-93 Cor Rate CommetIt!; 9-94 Cor Rate Comments5 Cr-. O5 moly* 27.6 Badly Att~ ked 19.9 Uniform Thinning

9 Cr-0,5 moly** 12,6 Uniform ’17inning 0,08 Some Attack—Carbon Steel 13 Uniform Tl inning 15,9 Uniform Thinning

304 Ss 1.1 Heavy Pit~lg o Like New—316SS 1.2 Pitting o Like New

317LSS o Like New– 0 Like New

AL6XN o Like New– 0 Like New

904L o Stained – o Like New

2205 0 Like New– 0 Like New

SAF2304 o Like New– 0 Like New

Titanium o Like New– 0 Like New

(rates are general ;Irrosion rates in mpy)* A182F5a**A182F9**CIO1O

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TAIB .E 2HISTORICAL CARBON STEEL CORROSION RATES

Date Installed Days mY Z vent

04/17/90 15 1.3 –

05/02/90 19 1.1 –

05/21/90 22 6.1 –

06/ 12/90 35 7.2 –

07/17/90 15 11.8 –

08/0 1/90 62 1,9 –

10/02/90 224 1,4 –

05/14/91 366 7,2 –

05/14/92 109 18.3 ;; ded NaOH 30 days prior—08131/92 39 37,9

10109192 25 44.4 “

12/04192 32 38.2 “

01/05/93 30 35.8 “

02/ I 5/93 28 3 ~)n Exchange

03/15/93 44 4.1 –

04/28/93 37 2.1 “

06/04/93 25 19.9 “

06/29/93 34 23.7 –

08/02/93 32 26.2 –

09/03/93 14 27.8 ~ heroical Cleaning

10/06/93 37 11,2 –

1l/12/93 33 46,8 –—12/15/93 60 gone

02/ I4/94 59 7.6 –

04/14/94 136 30 –

10/20/94 32 8.4 ~;id cleaning & solvent change outreinstallation

11/21/94 46 3,7 –

01/06/95 33 20 finit down for Turn around—

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TAIBI.E 3CONDITION MIIEA SOLUTION

Date Iron* Sodium —.(.hromium Fonnate Appearance—01/90” 1 45 <1 3,110 GREY—07/90 1 40 <1 6,844

—()()/g 1 2 50 <1 8,064 Light Yellow—01/92 10 60 <1 4,951 Ycl]ow

04/92”’ 4 1,400 ‘2 6.265 Green

05/92 5 2,300 – 4,995 Light Yellow

06/92 6 2,1OO 2 4,96 I Light Yellow

11/92 20 2,400 5 11.900” Clear

12/92 350 2,300 – 5.8 9,983 Black—

ol/93 455 2>()()0 5.8 8.896 Black—02/93”? 4.5

—03/93 61 100 10

—04/93 17 120 11,9 1>118 Green tint

—05/93 25 120 12 1,045 Dark Green

—06/93 21 105 10.6 3.151 Clear

—07/93 58 120 7 3,495 Grcy

—ox/93 138 135 6 3,966 Black

—oy/y~’” 310

—10/93 ~y 4,411 Brown

—I l/93 20

—01/94 496 Grcy

—05/94 16 75 2 7.666

—06/94 35 80 1 10.25O

—07/94 38 82 1 10.650 Yellow

—og/gJ -1 22 4 500” Dark Amber

—10/94”” 1 40 2 850 Dark Amber

.11/’94 2 58 I 2,640 Dark Amber

—02/95 4 5x <1 6,135 Dark Amber

—*All units in ppm*1- Caustic added*2 - Ion Exchange*3 - Chemical Cleaning*4 - Acid Cleaning and Solvent change out

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FIGURE 2FORMATE AND CORROSION RATE

FORMATE MPPM COR RATE MPY14

12

10

8

6

4

2

0

] 50

30

20

1100BAR = FORMATE; LINE = CORROSION RATE

CORROSIONRATES AS A FUNCTION

MPY

30

25

20

10

5

03

R SQUARED= 0.86 ,/E

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❑/“

,/

//’

,.///-

a /ES

// /“

/“’/ ’,,

../’

/4ii,/,/’

//’”’/“ ❑ ❑

/ // ❑

El ‘“,// / ‘x ❑ M

,//I I ! I 1 I

34 36 38 40 42 44

AMINE CONCENTRATION WT%

00

m0

(f)co

Z6AN

Z6nr

(363(3

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