Paper No.

392COIRI?OSIONC)L.The NACE International Annual Conference and Exposition

CORROSION IN MDEA SO LJRGAS TREATING PLANTS:CORRELATION BETWEErhr LABORATORY TESTING

AND FIELD I;XPERIENCE

Nguyen N. Bich imd Frank VachaShell Canalki Limited

P.O. Iicx 2506Calgary, Alberta, T2P 3S6, Canada

Roy SchubertShell Canal~a Limited

Caroline Com )lex, Bag 500Caroline, Alberta, TOM OMO,

ABSTRACT

Canada

Corrosion in MDEA sour gas treating systems operating in severely loaded conditionsinvestigated using both laboratory data and actual ga,; plant experience. Effects of acid gas loading, floturbulence, solution quality, temperature, etc. on corrosion are being studied. Preliminary resulindicated severe corrosion of several mm/y would o(:cur if acid gas loading, circulation rate and level (suspended solids are all high. A mitigation strategy based on operating envelopes is formulated.

Keywords: carbon dioxide, hydrogen sulfide, gas treating, amine

INTROD1JCTION

In refineries, amine treaters are used to clean llp relatively small streams of sour gas. In contra:in natural gas plants, amine units are the principal process units of which the size, metallurgy al

isw

k)f

t,Id

efficiency strongly influence project profitability. For a given sour gas plant design, pushing t ie

1

operating envelopes beyond the normal values withlmt significant increase in corrosion can have so ~erewarding economic benefits such as reduced energy consumption per unit volume of gas processed, dincreased revenues with less capital employed. Whi e corrosion can be tolerated for a short period )ftime, prolonged unmitigated corrosion can lead to nlpid contamination of solution, fouling, plant ups t,increased unplanned shutdown, and eventually costly ~quipment replacement.

Copy I ight@lI$196 by NACE International. Requests for permission to publish this ma luscript in any form, in part or in whole must be made in writing to NACEInternational, Conferences Division, P.O. Box 218340, Houston, Texas 77218-8340. The material presented and the views expressed in t ispaper are solely those of the author(s) and are not necessarily endorsed by the Association, Printed in the U.S.A. 7

Acid gas loading is one of the most imporl.a It variables affecting the economics of a sour gastreater. In addition, the limits of acid gas loading, temperatures, and allowable turbulence suitable forcarbon steel equipment become an equally importan: design parameter. Numerous rules of thumb areutilized during treater equipment sizing and mate rids selection. However, some of these rules can ~eeither needlessly conservative or not quite adecluate if they are not considered jointly with otherparameters affecting amine system corrosivity. In Shell Canada, we believe that the synergistic effe~tsbetween some corrosion variables exist and have devised a laboratory testing and plant corrosivitymonitoring program to isolate and identify at least S(lme of these relationships.

INDUSTRYS 3XPERIENCE

Corrosion experience with amine gas treaters varies widely. For every successful application,there seems to be a case history pointing towards a potential for operational difficulty or failure withinwhat appears to be the same or similar application{. However, since no two amine treaters are operatedthe same way, accurate and reliable comparisons irl t:orrosion are not easy. From the literature [1-5] andour own experience, the following variables and prot~ess parameters are believed to influence corrosiorl:

l

l

l

l

l

@

l

l

l

l

l

l

l

l

l

a

l

b

type of amine solutionsour gas loadingsolution strength (water content)HzS/COz ratiofeed contaminants (cyanide, sulfite, elemental slllfur, etc.)air ingressoperating pressuresoperating temperaturesorganic acid concentration and compositionvarious, sometimes undefined, amine degradation productssolids loading of solutions (mostly Fe Sx)solution circulation ratemechanical design detail influencing gas release from solution (pressure drop)turbulencesurface roughnesssutidce passivitypresence of inhibitorsmaterials, etc.

It should be evident that many of the abow variables are interdependent, e.g., for the givenmechanical design and solids loading, higher soluti[m circulation rate will result in greater turbulencewhich will likely result in absorbed gas release in 10Cal spots. This in turn will provide more mechanicalenergy for removal of iron sulfide scales forming on the equipment surfaces leading to acceleratedcorrosion.

It should be also noted that on the rich side of the circuit, the freshly-fotmed passive layers aremostly amorphous sulfide scales with traces of mack nawite. In general, these scales are poorly adherir,gand easily removed. In lightly loaded solutions, :hese passive layers will eventually become more

332/2

coherent and significantly reduce corrosion. In hi~~hly loaded systems, the passive layers apparentlycannot change into more coherent barriers without INlp from inhibitors.

On the lean side, aged passive layers often contain significant volumes of pyrite or pyrrhotite, whi:hprovide better protection to the underlying steel. t is also known that insufficient H2S and/or highorganic acid concentrations might result in condit ons where the coherence of the passive layers inreboilers or regenerators is compromised, leading to $evere corrosion.

In a similar manner, for a given throughput, increase in water content of amine solution will result inhigher sour gas loading and greater volatility of Iith amine solutions. Increase in circulation rates willreduce the loading, but may tend to increase the ;~as flashing at vulnerable locations, hence possitlehigher localized corrosion mtes.

Because of the interdependence between varial)les, it is entirely possible that changing some of theoperational parameters may decrease corrosion in some parts of the units while increasing it in others.

From experience, it has been known that lov{er loaded units generally have less corrosion andfoaming, as well as lower velocities, temperatures, ~md pressures. Absence of contaminants and solidsand particularly use of suitable corrosion-resistant al oys all tend to reduce operational problems such ascorrosion fouling and foaming in the rich side of the system.

With the exception of reboiler bundles, lean ~nine corrosion is often significantly less severe thanrich side corrosion. It is also interesting to note that lean amine corrosion appears to be affected bysimilar variables as the rich amine corrosion, i.e., if Iligh corrosion rates are experienced on the rich sideof the plant, a proportional increase has been observed on the lean side.

In large sour gas plants, attempts to keep all the operating parameters (acid gas loading,temperature, circulation rate, etc.) conservatively lI)W will greatly influence the size and cost of thetreating units. There is a significant incentive to understand effects of the most important variables onprocess and corrosion performance. The complexity and intricate integration of many process variablesrequire an integrated theory or model enabling the clesigners and operators to identify the optimum rangesof corrosion mitigation measures such as use of cor osion resistant alloys, inhibition, filtration, solutionreclaiming.

OBJECTIVES OF THE F.ESEARCH PROGRAM

Objectives of our research program were to identify and isolate some of the more importantvariables in both rich and lean sides of the amine systems. Closer scrutiny of the corrosion variableslisted in the previous section allows regrouping them as follows:

l type of amine solution (MEA, DEA, MDEA, Sldfinol, etc.)l sour gas loading

l sour gas composition (H2S and C02 percentaglx, partial pressures)l turbulencel solution quality (solids loading, feed contamination, process degradation products)l temperature

332/3

We consider the above parameters to be the pri lcipal influences on amine system corrosivity. Aprofound understanding of the dominant variables allow optimum design and operation of amine gastreaters. Among the possible mitigation measures, i nliibition is also included in the test program.

LABORATollY TESTING

Equipment Set up

The laboratory tests were carried out in a hii~h-pressure, high-temperature flow loop (Figure 1).The flow loop consists of an autoclave, an internal gear pump assembly, and an external tubing and flewcell assembly.

The 5L autoclave, made of UNS N10276, is I;apable of withstanding up to 260C and 5000 p,~i.Four flat strip coupons, labeled Coupons 5 to 8 were hung inside the autoclave. Coupon 5 sees mainlythe vapor phase, with possibly some small degree of liquid splashing. Coupon 6 is positioned right at thevapor-liquid interface. Coupon 7 is totally immersed in the liquid zone. Coupon 8 extends nearly acrossthe height of the autoclave. The vessel is normally filled with liquid up to the 75% volume level. Asimple foaming detector, a 5-wire electrical conduct x-, is installed at the autoclave head. The usual gasinlet and outlet complete the autoclave.

The gear pump assembly consists of two m,~t:hed gears housed in a UNS N10276 housing andmagnetically driven by an external electrical motor and two 1-inch UNS N1 0276 tubings, terminating atthe autoclave head. The circulating liquid is pushed :0 the external loop, returned to the liquid space andsucked backed into the assembly gear housing. This arrangement is designed to continuously freshen theliquid with acid gases and minimize solid settling at tl~ebottom of the vessel.

The tubing assembly is made of several l/2-ir ch ID and one l/4-in carbon steel sections, joinedtogether by 8 carbon-steel fittings, labeled F1 to F8. The flow cell assembly consists of 4 hollow carbonsteel sections, labeled coupons 1 to 4, electrically-separated by non-metallic spacers. The varying ID ofthe four coupons allows different flow velocity of tl.e circulating liquid. Control of the fluid flow by acalibrated flow meter permits a calculated velocity o~0.5, 0.8, 1.6 and 2.1 rids, respectively, for the fourcoupons.

The entire flow loop is housed in a containrlent vessel to minimize hazards created by leaks.Remote operation of the flow loop valves is possible by flexible coupling to the containment vesselhandles.

The carbon steel components of the flow loop v~ere selected to match the original volume to surfacearea ratio of one plant amine gas treating unit equipment. Table 1 summarizes fluid flow turbulenceexperienced by the various coupons and their plant equipment equivalent. A more precise calculation ofactual turbulence mathematical equivalence is underway.

Test Parameters

The following parameters and their ranges have been formulated to study their effects on MDEAcorrosion:

33.2/4

Solution quality: virgin solution, actual plant :;~lutions, reclaimed solutions, fully or partially fdtemdsolutions.

Acid gas loading: O, 0.4, 0.6,0.8 and higher rnlWmol loading

Organic acids addition: 6000ppm,12,000ppn

Rich-side temperature: 72and78C

Lean-side temperature: 128 and 135C

Amine strength: 40,50 and 60%

Inhibition: various concentrations of several ca~didates

As the testing progresses, other parameters \/ill be introduced. To reduce the size of the testprogram, only certain combinations of these paramet~xs will be tested.

RESULTS ANE DISCUSSION

Laboratory Corrosion Rates

Corrosion rates for coupons placed at low t~rbulence areas (Coupons 5-8, Fitting Fl) and atmediurdhigh turbulence areas (Coupons 1-4, Fitf irlg F2 to F8) are summarized in Tables 2 and 3,respectively.

Rich-Side Corrosion: The data indicate that severe corrosion will result if all three conditions aremet (Tests 4 and 5):

e contaminated solution.l high acid gas loading, and,l high turbulence.

For example, in Table 3, corrosion rates for hig I turbulence areas were high to extremely high (1 1:06.33 mm/y) for contaminated solutions and high acid gas loading (Tests 4, 5). In Tdble 2, corrosion ratesfor low-turbulence areas were low for all the conditi(ms tested. Most rates were less than 0.2 mm/y wi:ha few exceptions in the 0.3-0.4 mm/y range.

Rich-Side Inhibition: Tests 6 and 8 showed the effectiveness of inhibitors X and Y, at 500 ppm, inthe rich circuit at 78 C. Both inhibitors indicace ~ significant reduction in corrosion even at highturbulence areas. Corrosion was reduced to 0.05 aml 0.14 mndy or less for F2 coupon (vs. blank rate of6.33 mrdy), approximately 99 and 97% effectivenas, for X and Y, respectively. However, when thesolution containing 500 ppm inhibitor X was pre-heated to 130C for 3 days (to simulate the repeatedtrips to the reboiler), inhibitor X lost some of its ~ffectiveness. Corrosion rates for the 3 flow cellcoupons 6, 7 and 8 (from 0.8 to 2.1 rrds) jumped up to 0.53 to 0.54 mrrdy range (vs. 0.11 to 0.13 mmyin Test 6, without pre-heating, and 0.96 to 1.17 mm/~ in Test 5, the blank). The performance of inhibitorX was probably undermined by the thermal exposura.

3~)215

Lean-Side Corrosion: Only one test was done it 128C (Test 9). Again, corrosion was significantin high-turbulence areas (Flow cell coupons 5 to 8, F2), ranging from 0.43 to 1.24 mm/y. Thesecorrosion rates were consistent with the plant reboill>r tube failure (1 mm/y). For unknown reasons, thefittings suffered lesser corrosion mtes (O.13 to 0.45 rrdy)

Lean-Side Inhibition: In test 10,500 ppm of inh ibitor Z suppressed corrosion down to a level of lessthan 0.22 mm/y. More inhibitor candidates are bein;: avaluated.

Correlation with Plant Data

Plant corrosion was measured by onstream corrosion probes, corrosion coupons, ultrasonicthickness (UT) evaluation, and offstream visual and JT inspection. Frequency of probe readings is daily;coupons were pulled every 28 days; and UT thickness measurements were performed every 90 days. Theplant corrosion data and corresponding laboratog test data are summarized in Table 4. Overall, thelaboratory data showed good correlation with the onstrearn and offstream corrosion measurements.

Corrosion Modeling

Based on preliminary results, a corrosion medal has been formulated. Initial number crunchingexercises have been promising. The corrosion rate or carbon steel in MDEA could be predicted usingthe following formula:

CR = CCR x FpH x Fv / (Fscale x Finh)

where :

CR = corrosion rate in MDEACCR = corrosion rate due to COZ, adjusted to amirke environmentFpH = pH adjustment factor= f (PC02, PH2S, aci~ic contaminants, etc.)Fv = velocity effects factor = f (velocity, acid gas loading, temperature)Fscale = scale stability factor= f (suspended solids, ~H, velocity)Finh = inhibition efficiency Pactor

The factors are being validated using both k boratory and field data. Figure 2 shows a typicalsimulation of plant corrosion operating within 2 different envelopes. The lower curve is for a typicalplant operation (0.4 mol/mol loading, circulation ve Iocity less than 2 m/s). Removal of solids by filtraticmis assumed marginal, so some solids generated by co -rosion continue to build up over time. Corrosion isseen to progress slowly over time, from approximate y 0.2 mm/y to 0.4 mrrdy in less than three years andremains at 0.4 mndy maximum. In contrast, the t pper curve simulates a more aggressive operatirlgenvelope (0.8 mollmol loading, circulation velocity of 3 rds). The initially high corrosion (0.8 mrrdy)generates so much corrosion produc~ that the level l)f solids increases rapidly, causing the corrosion toincrease further. The autocatal ytic corrosion-solid build up mechanism allows corrosion to reach a velysevere level of 3.7 mndy within 100 days. This corrc sion acceleration pace has been actually observed inone gas plant.

MITIGATI(IIJ METHODS

Listed in Table 5 are some alternative mitigation measures considered for economical corrosion control.The research objectives are to define the boundar es for effective and economic applications of thecorrosion control measures. Each control measwt~ has its own advantages and disadvantages. Forexample, stainless steel is most appropriate under tile most severe operating conditions (high acid g Mloading, high fluid circulation, and dirty solution), but perhaps too conservative for lesser conditions. Itsdelivery requires longer lead time, hence could b? a factor for unplanned shutdown replacements,especially for vessels. Slip stream solid filtering is a.d~quate only for mild corrosion, but totally unsuitablefor severe corrosion.

SUMMARY AND CONCLUSIONS

Under normal operating conditions, corrosion of carbon steel equipment in MDEA gas treatingunits is usually acceptable. Operating beyond the normal conditions can increase corrosion to a muchmore severe level, resulting in solution contaminat- on, fouling, plant upset, unplanned shutdown andeventual equipment replacement. Our experience in the laboratory and actual field operations areproviding useful and valuable guidelines in determini]lg the acceptable boundaries of operating conditions(e.g., temperature, loading, circulation, etc. ) and in implementing appropriate conmol measums(e.g. inhibition, metallurgical upgrades, etc.).

REFERENCE

1. Stray, J. D., Control of Corrosion and Fouling in Amine Sweetening Systems, paper presented atthe NACE International Canadian Region Western Conference, February 20-22, 1990, Calgary, Alberta.

2. Gutzeit, J. Refinery Corrosion Overview, in Process Industries Corrosion - The Theory ar~Pmctice, Moniz, B.J. and Pollock, W. I., editors, NA(;E International, Houston, TX, 1986, p. 184.

3. Nielsen, R. B., et al., Corrosion in Refiner~ .krnine Systems, CORROSION/95, paper no. 571,NACE International, Houston, TX.

4. Dupart, M. S. et al., Part 1 - Understanding Corrosion in Alkanolamine Gas Treating Plants,Hydrocarbon Processing, April, 1993, pp. 75-80

50 Blanc, C. et al, The Part Played by Degradation Products in the Corrosion of Gas SweetenirlgPlants Using DEA and MDEA. 1982 Laurance W id Gas Conditioning Conference Proceedings, TheUniversity of Oklahoma, Norman, Oklahoma, 1982!.

3!)zf7

Table 1: Estimated Level of Fluid FIOWTurbulence Experienced by the Coupons

Coupons ] Descriptions ] Level of Turbukm:e I Equivalent I%w Rate,

1 0.5 m/s flow cell medium-higt-~

I2 I 0.8 m/s flow cell I medium- high I 1-2 mls

I I 1I 3 1.6 mls flow cell high 2 mls

I4 I 2.1 m/s flow cell I high I 2-3 mls5 gas phase low :

F

nil6 gas/liquid interface low

Table3: Corrosion Rates for Mediwn/ElighTurbulenceAreaCoupons

I Test ] 0.5 I 0.8 I 1.6 \ 2.1 I Coupon /Couponl Coupon I Coupon lCouponl Coupanl Couponl

t

In/s lm/slIn/slm/s F2 F3 F4 F5 I F6 I F7 I F81 0.09 0.13 I 0.10 I 0.10 0.11 I 0.07: ] 0.11 0,09 0.08 0.08 0.10 I2 0.06 0.06 0.073 0.23 0.25 0.234 0.84 0.96 1.025 0.19 0.96 1.00 z .; ~:~6 0.14 0.11 0.11 0.13 0.05 o.09_7 0.53 0.54 0.54 0.53 0.13 0.068 0.09 0.15 0.16 0,17 0.14 o.089 0.98 1.24 0.51 0,43 0,45 o.2010 0.04 0.03 0.04 0,12 0,22 0.01

N/A: not available

Table 4: Plant Actual Corrosion and Correlation to Lab Testing

Location Loading, Temp. Flow -CoI rosion Corrosion Comparable Comparable Labmollmol c Velocity, Rate. Rate, Plant Lab Test ~db Coupon Corros on

rnls In SIection Coupon, Rate,lr mfy lnlrlly mmlv

Piping: Ffash Drum 0.8 78 high averdge 2 , 2.5 to 3 Test 5 Coupon 4 or 2 to (-to Lean-Rich maxinum 9 F2

ExchangerPiping: Regenerator lean 128 high avl#rage ltol.5 Test 9 Coupons 1-4 0.4 tlfl

to Lear-Rich 025, 1.24Exchanger mm irnum

_l.oPiping: Reboiler to semi- 128 medium- 05tol.o 0.5 to 1 Test 9 Coupons 1-4 0.4 tlfl

Regenerator lean high 1.24Absorber 0.8 78435 low :).5 N/A Test 5 Coupons 5-8 0.2-0.5

~ lean 128 low 1).5 NIA Test 9 Coupons 5-8 o.2-o,r

Reboiler Tubes semi- 130 medium- 1 NIA Test 9 Coupons 1-4 0.4 tinlean high and F2 1.24

Table 5: Corrosion {;ontrol Alternatives

Operating Inhibition Slip stream Red: iming Selective CRAS Metallizing

;

AU CRASEnvelope Filtration

normal not required effective effective not required not required not requir,;d

slightly effective eflcctive effective effective not required not requiredagmessive

mildly partially effective not effective ej~ ctive effective effective not requir:dag~ressive

very not effective not effective parttidlij effective partially effective effective effectiveaggressive

39:!19

F8

F

Gas

Gas

Gas = 25% vo

Liquid = 75% vo

P

Pressure VesselQ$

2.1 m/s

0.8 m\s

1.6 m/s

.

.

I

3

T3

7

14

16

Figure 1: Flow loop schematic

392qo

I3

2,5

2

1.5

1

0.5

0

\ ~Eg _+_ 0.8 mol/mol loadingI

t n nl -m-m-m n . .m 9 m

. I

0 203 4CKI 603 803 1O(DTune, days

Figure 2: Calculation of corrosion rates for twodifferent envelopes

203 1403 1603 1803 2~