2 BAKER PETROLITE Supplement to Materials Performance, March 2002

Breakthrough Solutionsfor Corrosion Control byChemical Treatment

Chemical processing is one of the most challenging industries for effec-tive corrosion prevention and control. Aging equipment, new productformulations, environmental concerns, and strict budgets requirecorrosion control programs that are designed for specific situations byhighly skilled professionals. This is especially true of the chemical treat-

ment industry, which not only protects the production and delivery systems forthe world’s fuel sources but also produces plastics and other materials essentialto the infrastructure.

The following pages feature technical articles that describe some of the lat-est developments in chemical corrosion control. One article discusses how re-searchers modified a model used to predict erosion-corrosion caused by par-ticle impingement by including the effect of inhibitors. Another explores a casein which type 316 stainless steel reboiler tubes and a regeneration tower expe-rienced unusually high rates of corrosion in an amine unit. Other articles de-scribe the effects of corrosion and hydrate inhibitors in subsea oil and gas pro-duction, a study involving molecular modeling of mackinawite to betterunderstand corrosion inhibition in hydrogen sulfide (H2S) environments, andhow spectroscopic ellipsometry can be used to characterize films on inhibitedmild steel surfaces.

Corrosion prevention systems will continue to evolve as researchers fromindustry, government, and academia discover more effective, economical waysto protect metals and plastics without adverse environmental consequences.Organizations that keep pace with these cutting-edge developments will ulti-mately improve operations, reduce costs, and successfully compete in a con-tinuously changing world.

CONTRIBUTORS

Fred Addington

Keith A. Bartrip

Samuel E. Campbell

Lynn M. Frostman

Vladimir Jovancicevic

Weidong Li

Sunder Ramachandran

Vu Thieu

Mark B. Ward

TABLE OF CONTENTS

3 Corrosion and Hydrate Inhibitor Interactionfor Deepwater Production

8 Corrosion Control in Amine Systems with 316Stainless Steel

14 Inhibitors Reduce Piping Wear Caused byParticle Impingement

18 Spectroscopic Ellipsometry—A Techniquefor Studying the Corrosion InhibitionMechanism

21 Molecular Modeling of Mackinawite toStudy Corrosion and Inhibition in Sour GasEnvironments

EDITORIAL

M A N A G I N G E D I T O RGRETCHEN A. JACOBSONT E C H N I C A L E D I T O R

JOHN H. FITZGERALD III, FNACES TA F F W R I T E R

MATTHEW V. VEAZEYA S S I S TA N T E D I T O R

APRIL SEARS

GRAPHICS

M A N A G E R , G R A P H I C SE. MICHELE SANDUSKY

ADMINISTRATION

N A C E E X E C U T I V E D I R E C T O RD I R E C T O R — P U B L I C AT I O N S

JEFF H. LITTLETONP U B L I C AT I O N S A D M I N I S T R AT I V E A S S I S TA N T

SUZANNE MORENO

ADVERTISING

A D V E R T I S I N G C O O R D I N AT O RSTACIA L. HOWELL

R E G I O N A L A D V E R T I S I N G S A L E SR E P R E S E N TAT I V E S

NELSON & MILLER ASSOCIATESNEW YORK/NEW ENGLAND/PHILADELPHIA AREA–

914/591-5053

THE KINGWILL CO.CHICAGO/CLEVELAND AREA–847/537-9196

THE KELTON GROUP–ATLANTA AREA–404/252-6510

MEDIA NETWORK EUROPE–EUROPE–00 44 20 7834 7676

NACE INTERNATIONAL CONTACT INFORMATIONPhone: 281/228-6200 Fax: 281/228-6300

E-mail: msd@mail.nace.org Web site: www.nace.org

EDITORIAL ADVISORY BOARDEugene Bossie

Corrpro Companies, Inc.John P. Broomfield

Corrosion ConsultantRaul A. Castillo

The Dow Chemical Co.Irvin Cotton

Arthur Freedman Associates, Inc.Arthur J. Freedman

Arthur Freedman Associates, Inc.Orin Hollander

Holland TechnologiesW. Brian Holtsbaum

CC Technologies, Inc.Otakar JonasJonas, Inc.

Ernest KlechkaCorrMet Engineering Services

Joram LichtensteinCorrosion Control Specialist, Inc.

George D. MillsGeorge Mills & Associates International, Inc.

James “Ian” MunroCorrosion Service Co., Ltd.

John S. Smart, IIIJohn Smart Consulting Engineers

L.D. “Lou” VincentCorrpro Companies, Inc.

mation. Some LDHIs allow hydrates toform but control the nucleation andcrystallization process, thereby inhib-iting hydrate plugging. Field tests haveproven that LDHIs mitigate hydrateplugging.2-3

Corrosion rates are the greatest atthe wellhead and other high-tempera-ture points, and at points of highershear such as encountered at the riser.Corrosion may still occur, however, atlower temperatures encountered at the

In deepwater oil and gas produc-tion, integrity management andflow assurance are critical issues.System integrity, including corro-sion and flow assurance issuessuch as hydrate plugging, must be

addressed. Specialty chemicals, includ-ing corrosion inhibitors (CIs) and hy-drate inhibitors (HIs), may be used toconquer these problems. The interac-tion among chemicals under all oper-ating conditions influences chemicalperformance.

To explore the interaction betweenHIs and CIs, Baker Petrolite studied atypical deepwater condition of low tem-perature at which hydrates and carbondioxide (CO2) corrosion are known tooccur. Researchers conducted HI and CIperformance experiments under low-and high-shear conditions in the pres-ence of hydrates. They measured theeffects of CI, methanol, low-dosage HI(LDHI), and combinations of chemicalson the corrosion rate. In addition, theyexplored the role of erosion caused byhydrate formation.

Natural Gas Hydratesand Corrosion

Natural gas hydrates can threatenany production system that encounterslow temperatures and high pressures.1

During normal production operations,hydrates can plug a flowline with littleor no warning. Transient operations,such as shut-ins and startup, are morevulnerable because temperatures tendto be lower, pressures can be higher,and water has time to accumulate inlow spots. Some speculate that hydrateparticles, which are solids, may alsocontribute to erosion and erosion-corrosion.

Traditional methods of inhibitinghydrate plugging prevent hydrate for-mation altogether. They include insu-lating the flowline to keep producedfluids warm, injecting thermodynamicinhibitors such as methanol (CH3OH)to lower the hydrate-stability tempera-ture, and/or blowing the system downto low pressures during shut-ins.

LDHIs serve as an alternative to ther-modynamically preventing hydrate for-

Corrosion andHydrate InhibitorInteraction forDeepwaterProductionSAMUEL E. CAMPBELL, WEIDONG LI, VU THIEU, AND LYNN M. FROSTMAN,Baker Petrolite Corp.

In subsea oil and gas production, corrosionand hydrate inhibitors are used for

chemical treatment because of the severe conditionsencountered. Performance is traditionally measuredseparately because low carbon dioxide (CO2) corrosionrates occur at temperatures where hydrates form andmay plug flowlines. Under certain conditions, however,hydrate formation can alter the rate of metal losscaused by changes in fluid chemistry and potentiallyresult in erosion and erosion-corrosion. This articlediscusses the effects of corrosion inhibitors, methanol(CH3OH), and low-dosage hydrate inhibitors (LDHIs) onthe measured corrosion rate under low- and high-shearconditions in the presence of hydrates.

CO2 CORROSION AND

EROSION MODELINGThe CO2 corrosion models from de

Waard and Milliams were used bothwith and without flow corrections todetermine an estimated uninhibited orblank corrosion rate.5-7 The basic formof the correlation is:

Log (Vcor) = 5.8 - 1710 / T + 0.67 log (PCO2) (1)

where Vcor = corrosion rate (mm/year); T = temperature (kelvin); andPCO2

= partial pressure of CO2 (bar).To assess potential erosional effects

of hydrates in the presence of corro-sion, the models consider the role oferosion on a qualitative basis. The con-trolling factors include particle size,particle shape, particle density, particlehardness, flow rate, and fluid viscos-ity.8-9 The degree of subcooling, rate ofnucleation, and the presence of an in-hibitor control particle size and shape.

Experimentation and ResultsTests were conducted to determine

hydrate inhibition effectiveness,chemical compatibility of HIs and CIs,and corrosion inhibition effectiveness.

TESTING FOR HI EFFECTIVENESSA “rocking cell” gas hydrate test ap-

paratus, which consists of a high-pres-sure sight glass cell containing a stain-less steel (SS) ball, was used to confirmthe presence of hydrates and the effec-tiveness of chemical HIs both with andwithout CI present. The cell wascharged with brine and oil and pres-surized to the desired level with a gasmixture.

Rocking the cell in a temperature-controlled bath simulated flow condi-tions; holding the cell static simulatedshut-in conditions. The cell was checkedperiodically for hydrate formation bytaking pressure readings and visuallyobserving it through the sight glass.Table 1 lists the specific test conditions.

During testing, three HIs (A, B, andC) and a CI (D) were used. Chemical Ais a proprietary LDHI. Chemical B ismethanol, a thermodynamic HI. Chemi-cal C is a second proprietary LDHI.Chemical D is a proprietary CI specifi-cally designed for deepwater inhibition.

FIGURE 1

Predicted hydrate stability curve for an experimental system.

FIGURE 2

Orientation of HSAT coupons. Left: Rotating metal loss coupons within cooling coil and electro-chemical coupons outside coil. Right: Rotating coupon mount.

TABLE 1

TEST FLUIDS ANDCONDITIONS FOR HYDRATEINHIBITOR TESTS

locations most favorable to hydrateformation. System conditions andmodeling have been successfully usedto select effective chemical CIs.4 Ifchemical means are used to mitigatehydrate and corrosion concerns, thetwo treatments must work in harmony.

The Theory Behind theExperimentation

HYDRATE MODELINGA thermodynamic gas hydrate stabil-

ity curve, which predicts the pressureand temperature at which gas hydrateswill be stable, can be generated for agiven hydrocarbon composition withthe Multiflash™ gas hydrate modelingsoftware from Infochem. The degree ofsubcooling experienced for a particularfield situation can be determined.Subcooling, which is the differencebetween the hydrate stability tempera-ture and actual operating temperature,gives a measure of the severity of thehydrate problem.

2,000

0

1,500

1,000

500

0 10 20 30 40 50 60 70 80

Temperature (°F)

Pre

ssur

e (p

si)

Test ConditionsT = 40°F P = 1,200 psi

Subcooling = ~25°F

Oil Gulf of Mexico black oilBrine Synthetic 1.5wt% NaCl brineWater Cut 50%Gas 87% C1, 5% C3, 8% CO2Filled to 1,400 psigRocking ~1,150 psig and 40°F

A HI ranking system was developedto describe the HIs’ performance in therocking cell tests. A ranking of A, B, or Cwas considered a “pass,” representingeither the absence of hydrates at the endof a test (A) or the formation of hydratesthat remained small, dispersed, and non-adherent at the end of a test (B and C).D or F rankings were considered a “fail,”representing evidence of high-viscosityphases or hydrates sticking to the glassor ball, forming a plug, or freezing theball in place.

Table 2 presents the results of therocking cell tests. In the absence of HI(cell 1), a hydrate plug formed. In thepresence of an excess of methanol (cell4), no hydrates formed and the fluidsremained mobile. In the presence ofLDHI A (cells 2 and 3), hydratesformed—as evidenced by a drop in cellpressure—but the particles remainedsmall, well dispersed, and nonadherent.Adding 25 ppm of CI D did not alter theperformance of the LDHI A. Thesubcooling in these tests was on theborderline of the maximum subcoolinglimit of LDHI C. As a result, poor perfor-mance was shown with and without CID (cells 5 and 6).

In studying HI effectiveness, the re-searchers also analyzed the oil used inthe testing and calculated the composi-tion of the four phases (gas, aqueous,oil, and hydrate) for the test conditions.They also plotted a hydrate stabilitycurve of pressure vs temperature (Fig-ure 1). Based on thermodynamic mod-eling, the cells at 40°F (4°C) weresubcooled by 25°F (–4°C).

Testing for ChemicalCompatibility of HIs and CIs

When applied subsea, productionchemicals must pass an extensiveseries of system compatibility and sta-bility tests. Combined chemical treat-ments must also meet the same crite-ria. To determine the compatibility ofHIs and CIs used to treat the same sys-tem, the company conducted physicalcompatibility, capillary stability, andmaterials compatibility tests.

PHYSICAL COMPATIBILITYBlends of HI A and CI D were stud-

ied at 40°F and 140°F (60°C) for 7 days.The blends were miscible and stableat the ratios tested: 0.64, 0.75, 1.24,5.81, and 7.5 vol% CI D in LDHI A. Allblends remained bright and clear, withno phase separation, precipitates, haz-ing, or qualitative changes in viscosity.

CAPILLARY STABILITYThe capillary test, which is designed

to determine if a product can be safelyinjected via a downhole capillary orsubsea umbilical, involved placing acapillary apparatus consisting of an800 ft by 0.055 in. (244 m by 0.14 cm)

inner diameter (ID) SS coil in a tem-perature-controlled oven. The pressuredrop across the coil, including the out-let filter, was measured continuously.Any increase in viscosity, solids depo-sition, or tendency to plug resulted ina rising differential pressure across thecapillary column.

The coil was flushed with 1.24 vol%CI D in LDHI A, heated to 145°F (63°C),and pressurized to ~5,000 psig. Pres-sure drop across the coil was measuredat a steady flow of 0.5 mL/min for sev-eral hours. The column was then shutin for 7 days. On restart, the pressure

TABLE 2

HYDRATE INHIBITOR ROCKING CELL PERFORMANCE TESTS

FIGURE 3

HSAT blank corrosion rates at 40°F with hydrates present as a function of rotation rate. Weight lossat the highest rotation rate is unavailable because of decoupling of the drive shaft.

Cell 1 2 3 4 5 6Oil 6 mL Gulf of 6 mL Gulf of 6 mL Gulf of 6 mL Gulf of 6 mL Gulf of 6 mL Gulf of

Mexico Mexico Mexico Mexico Mexico Mexicoblack oil black oil black oil black oil black oil black oil

Brine 6 mL of 1.5 6 mL of 1.5 6 mL of 1.5 3 mL of 1.5 6 mL of 1.5 6 mL of 1.5wt% NaCl wt% NaCl wt% NaCl wt% NaCl wt% NaCl wt% NaCl

HI None 1.5 wt% 1.5 wt% 3 mL 1.7 wt% 1.7 wt% LDHI A LDHI A MeOH LDHI C LDHI C

CI None None 25 ppm CI D None None 25 ppm CI D

Observations Grade = F Grade = B Grade = B Grade = A Grade = D Grade = D–overnight,continuousrocking at40°F

30

25

20

15

10

5

00 5 10 15 20

Linear Velocity (ft/s)

Cor

rosi

on R

ate

(mpy

)

Weight LossLPR Electrochemistry

immersion phase (32 days), and afterthe drying phase. The inhibitors per-formed similarly to methanol for nylon11 and PTFE. Buna N is not a suitableelastomer with LDHI A and CI D.

TESTING FOR CI EFFECTIVENESSThe high-speed autoclave test

(HSAT) was conducted to determinethe effectiveness of the chemical treat-ments for corrosion inhibition usingtwo measuring techniques—linear po-larization resistance (LPR) to determinethe instantaneous corrosion rate andweight loss to determine the averagecorrosion rate. The HSAT wasequipped with both electrochemicaland rotating coupons and pressurizedto 1,400 psi (9,653 kPa) at 70°F (21°C).Figure 2 shows photographs of thecoupon configuration in the HSAT.System temperatures during the test-ing ranged from 40 to 100°F (38°C),and changes in pressure were moni-tored accordingly. The device operatedat rotational speeds of 60 to 2,000 rpm,corresponding to linear velocities of0.58 to 19.2 ft/s (0.2 to 6 m/s) at thecoupon surface. Shear stresses variedfrom 40 to greater than 1,000 Pa overthe surface of the coupon.

The first series of tests measuredsystem corrosivity, with neither hy-drate nor CI present, as a function oftemperature and rotational velocity.Figure 3 illustrates the blank corrosionrate as a function of linear velocity at40°F by electrochemistry and weightloss when hydrates are present. Hy-drate formation prevented the highestvelocity point (19.2 ft/s) from beingmaintained for more than a short pe-riod of time, generating sufficient flowresistance to decouple the magneticdrive shaft. Electrochemical corrosionrate measurements could still be made,but average weight loss measurementscould not be taken at the highest rota-tional velocity.

At the lowest rotation speed (0.58 ft/s), the corrosion rates in the presenceof HIs A, B, and C and CI D were mea-sured as a function of temperature.Under hydrate formation conditions, allof the treatments provided greater than90% corrosion inhibition. However, as

FIGURE 4

Percent corrosion protection as a function of linear velocity at 40°F underhydrate formation conditions.

drop was closely monitored at a steadyflow of 0.5 mL/min for several hours.Subsequently, the filters were removedand examined for deposits. Effluentfrom the column was examined visu-ally for changes in appearance and, inmost cases, performance-tested in therocking hydrate cells.

Criteria for passing a capillary testinclude steady differential pressureacross the coil prior to shut-in, nospikes in differential pressure onrestart, equivalent (within 5 psi [34kPa]) differential pressures across thecoil prior to and after the shut-in pe-riod, no deposits on the filters, no vi-sual change in effluent, and good efflu-ent performance in rocking cellhydrate tests.

TABLE 3

METAL COMPATIBILITY(140°F, 14 DAYS)

TABLE 4

ELASTOMER COMPATIBILITY

found for a second capillary test per-formed with a blend of 5.81 vol% CI Din LDHI A.

MATERIALS COMPATIBILITYMaterials compatibility is important

to the proper selection of subsea treat-ment chemicals. In this work, triplicatetest specimens of several metals andplastics were tested for compatibilitywith LDHI A and CI D.

Table 3 shows that LDHI A and CI Dare compatible with the metals C1018(UNS G10180) and type 316 SS (UNSS31600). Weight measurements of themetallic coupons were made to deter-mine mass loss. The coupons were alsoexamined under a microscope tocheck for pitting or other forms of lo-calized corrosion that can increase theregular corrosion rate by orders of mag-nitude—often without significantly af-fecting weight loss. The appearance ofthe chemicals was also observed forany color changes or precipitates.

Table 4 presents the materials com-patibility results for the plastics tested.Hardness measurements were madeprior to immersion, at the end of the

Test resultsshowed that pres-sure drop beforeand after shut-inwas steady andconsistent, withno pressure spikeson restart. The ef-fluent appearedunchanged com-pared to the un-treated fluid. Efflu-ent samples priorto and after capil-lary testing passedHI performancetests. The sameresults were

Chemical C1018 316 SS

LDHI A 1.79 mpy 0.01 mpy

CI D 0.13 mpy 0.05 mpy

Chemical Nylon 11 Buna N PTFE

LDHI A –8.0% wt +4.8% hardness –13.0% wt +16.9% hardness –0.1% wt 0% hardness

CI D –7.7% wt +6.3% hardness –8.1% wt +21.9% hardness +0.05% wt 0% hardness

the temperature was increased and thehydrates melted, LDHI A and methanolbecame less efficient at corrosion pro-tection. In contrast, LDHI C, CI D, andCI D with LDHI A maintained excellentinhibition. As a function of increasedtemperature, methanol and LDHI A lostcorrosion inhibition properties.

At 40°F under hydrate formationconditions, the corrosion protectionwas measured as a function of rota-tional velocity. Figure 4 graphically pre-sents the results. Although the blankcorrosion rate (Figure 3) is relativelyunaffected by changes in the rotationrate, the corrosion inhibition proper-ties of the system are appreciably dif-ferent as the rate increases. A clear dis-tinction exists between CIs specificallydesigned for high-velocity conditionsthat maintain a high degree of protec-tion (>99%) and the HIs that decline incorrosion control performance as ve-locity increases.

Figure 5 presents the electrochemi-cally measured corrosion rate for 1.7%LDHI A and 25 ppm of CI D. The cor-rosion rate for CI D starts low and re-mains low. For LDHI A, the corrosionrate slowly decreases to a similar valueover a period of 12 h.

Combined Use of LDHIsand CIs in Subsea Systems

Hydrate performance testing and sys-tems compatibility testing show thatspecific CIs and LDHIs are effectivewhen used together in the samedeepwater system. LDHI A and CI D con-trolled both hydrates and corrosionwhen in the same fluids under the testedconditions. Mixtures of the two chemi-cals produced no instability or materialincompatibility issues. Combinations ofLDHIs and CIs are currently being usedsuccessfully in the Gulf of Mexico.

The Role of Erosionand Corrosion

One of the primary interests instudying corrosion at 40°F is to deter-mine the role of hydrate particles inerosion and erosion-corrosion. Evenunder blank conditions, the research-

hydrates form, the pressure decreasesand results in a lower total system pres-sure and lower corrosion rates causedby lower partial pressure of CO2. Find-ings indicate that the de Waard modelmay not directly apply once hydratesform in solution.

ConclusionsAlthough methanol, corrosion inhibi-

tors, and LDHIs independently resultedin corrosion rate reductions in this study,they function by different mechanisms.A specifically tailored CI more effectivelyprotects metal surfaces than a LDHI ormethanol. CI, LDHI, and methanol dif-fer in their response to increasing shearand increasing temperature. True CIsmaintain performance as conditions be-come more severe, but HI performancediminishes against corrosion. CIs alsorespond more rapidly than LDHIs,which can be a significant issue in up-set conditions. When used together insubsea systems, however, certain LDHIsand CIs can optimize control of hydrateformation and metal loss.

References1. E.D. Sloan, Clathrate Hydrates of Natural Gases,

2nd ed. (New York, NY: Marcel Dekker Inc., 1998).

2. L. Frostman, “LDHI’s for Prevention of Hydrate

Plugs in Deepwater Systems,” 2000 SPE Annual Tech-

nical Conference and Exhibition, paper no. 63122

(Dallas, TX: SPE, 2000).

3. L. Frostman, J. Przybylinski, “Successful Appli-

cations of LDHI’s,” 2001 SPE International Symposium

on Oilfield Chemistry, paper no. 65007 (Houston, TX:

SPE, 2001).

4. S. Ramachandran, M. Ward, K. Bartrip, Y. Ahn,

“CI Considerations for Deepwater Systems,” 1999 SPE

International Symposium on Oilfield Chemistry, paper

no. 50758 (Houston, TX: SPE, 1999).

5. C. de Waard, U. Lotz, D.E. Milliams, Corrosion

47 (1991): p. 976.

6. C. de Waard, U. Lotz, “Prediction of CO2 Cor-

rosion of Carbon Steel,” CORROSION/93, paper no.

69 (Houston, TX: NACE, 1993).

7. C. de Waard, U. Lotz, A. Dugstad, “The Influ-

ence of Liquid Flow Velocity on CO2 Corrosion: A

Semi-Empirical Model,” CORROSION/95, paper no.

128 (Houston, TX: NACE, 1995).

8. J. Shadley, S. Shirazi, E. Dayalan, M. Ismail, E.

Rybicki, Corrosion 52, 9 (1996): p. 714.

9. J. Shadley, S. Shirazi, E. Dayalan, E. Rybicki, “Ve-

locity Guidelines for Preventing Pitting of Carbon Steel

Piping When the Flowing Medium Contains CO2 and

Sand,” CORROSION/96, paper no. 15 (Houston, TX:

NACE, 1996).

TABLE 5

BLANK CORROSION RATE IN HSAT

FIGURE 5

The evolution of corrosion inhibition as measured by LPR at 40°F with a6.2 ft/s (1.9 m/s) linear velocity.

ers observed nolocalized or lead-ing-edge metalloss on the cou-pons in the HSATtests, and the mea-sured corrosionrates did not indi-cate erosion.

As Table 5 dem-onstrates, the deWaard model pre-dicts a corrosionrate greater than isobserved when hy-drates form. As hy-drates form, thecorrosion rate theo-retically should in-crease as a resultof increased salin-ity. However, as

10

8

6

4

2

0

0 10,000 20,000 30,000 40,000

Cor

rosi

on R

ate

(mpy

)

1.7% LDHI A25 PPM CI D

Temperature Predicted de Waard6 Predicted de Waard7 Measured (°F) 1993 (mpy) 1995 (mpy) (mpy)

40 33.9 73.2 14.170 83.5 87.4 38.5

100 181 96.9 103

Time (s)

Corrosion Control inAmine Systems with

316 Stainless SteelFRED ADDINGTON, Baker Petrolite Corp.

DAVID HENDRICKS, The Hendricks Group

Some process operators attemptto mitigate the corrosion ofstainless steels (SS) by applyingthe same methods used to con-trol corrosion of carbon steel(CS). SS and CS, however, react

differently to the corrosive conditionspresent in an amine system. CS tendsto form a passive iron sulfide (FeS) filmthat can be enhanced by corrosion in-hibitors. SS do not react with the sulfidebecause of the tenacious iron/chromeoxide film on the metal surface. In re-ducing environments such as amineunits, no oxygen is available in the sys-tem to repair breaks in the oxide film.

The following case history addressesthe failure of type 316L SS (UNS S31603)reboiler tubes and regenerator tower inan amine unit, Baker Petrolite’s work inanalyzing the failure and the operatingefficiency of the amine system, and thecorrective actions recommended by thecompany and implemented by the op-erator to reduce corrosion rates to ac-ceptable levels.

Case HistoryTHE PROBLEM

The regeneration section of theamine unit was experiencing unusuallyhigh corrosion rates of type 316L SS.The unit had significant damage, in-cluding a through-wall regenerator col-umn failure, failure of the rich/lean andregenerator/reboiler exchanger tubes,significant heat transfer fouling, andgreater-than-expected amine losses.The operator asked the service com-pany to determine the root cause of theaggressive corrosion occurring insideprocess equipment associated with theacid gas removal unit and to improvethe unit operation.

The reboiler has a thermal siphondesign with an internal weir, which isdesigned to ensure that the tubes arecontinuously submerged in liquids. Fig-ure 1 presents the basic flow diagramof the unit and identifies the materialsof construction.

Process ParametersThe amine system was designed to

process a sour gas stream with a gastemperature of 70 to 85°F (21 to

Unusually high corrosion rates of type 316Lstainless steel (SS) (UNS S31603) were prevalent

in the regeneration section of an amine unit. This casehistory describes the failure of the unit’s type 316L SSreboiler tubes and regenerator tower as well as themeasures taken to reduce corrosion rates to acceptablelevels. The mitigation program combined process control,chemical inhibition, and mechanical redesign to reducecorrosion rates to <1 mpy (25.4 µm/y).

FIGURE 1

Amine system diagram with materials of construction.

CSType 316 SSTitanium

Sweetgas

Sourgas

Rich surge

Rich amine

Lean amine

Lean surge

ReclaimerReboiler

Reflux drum

Claus unit

Filte

r

Cont

acto

r

Filte

r

Rege

nera

tor

39°C). Temperatures >95°F (35°C)promote amine losses through evapo-ration, diminish hydrogen sulfide (H2S)stripping efficiencies, and result inhigher concentrations of liquid hydro-carbon impurities. Lean solution tem-perature to the contactor is controlled2 to 5°F above the temperature of theincoming gas stream. Lean solution,consisting of monoethanolamine(MEA) and steam condensate, removesacid gases such as H2S, carbon dioxide(CO2), and hydrogen cyanide (HCN),minimizing the environmental impactof using the gas as fuel for various plantfurnaces. The concentration of MEA isspecified to be maintained at 15%;however, the solution was permitted tofluctuate between 8 and 30% while op-erating with reboiler steam leaks. Theregenerator overhead temperature is230°F (110°C), and the column is main-tained at a pressure of 10 to 12 psig (69to 83 kPa).

Corrosion Control HistoryDuring the first year of operation,

corrosion rates in the unit were deter-mined by measuring metal levels in thecirculating rich and lean amine solu-tions. Corrosion inhibition was at-tempted with additives placed in theamine by the manufacturer. A CSweight-loss coupon was inserted intothe rich amine stream and showed nosignificant activity. Filters in the richand lean amine streams requiredchanging after 50 h of service, how-ever, as a result of plugging by corro-sion products.

Scope of CorrosionFigures 2 and 3 show examples of

the type and severity of corrosion dam-age experienced by the amine unitequipment.

Type 316L SS reboiler tubes failedafter 11 months of service. Pitting be-gan on the outside diameter (OD) ofthe tubes, affecting the top four rows.A new tube bundle constructed of316L SS was installed. This bundlefailed after 7 months of service with asimilar corrosion profile and was re-paired. The 316L SS rich/lean ex-changer tubes failed from the insidediameter (ID) (rich amine side) after 1

year of service and were replaced withtitanium tubes. Corrosion caused athrough-wall leak to develop on the316L SS plate of the regenerator col-umn after 1 year of service. After in-spection of the entire vessel interior, a20-ft (6-m) section of the column wasreplaced with 316L SS plate. The CSreclaimer experienced significant foul-ing and level control problemsthroughout the first 2 years; however,an inspection revealed no significantcorrosion on the vessel or tubes.

SOLUTIONSeveral steps were taken to deter-

mine the operating efficiency of the sys-tem and the rate of metal degradation,including sample evaluation, corrosionmonitoring, system design review, re-view of considerations regarding corro-sion in amine solutions, and laboratoryfailure analysis.

Sample Evaluation andCorrosion Monitoring

Samples were evaluated from areasother than those under surveillance bythe plant. The additional samples in-cluded lean amine, rich amine,reclaimer bottoms, reflux stream, andsteam condensate used for solutionmakeup. The service company also in-stalled tube-type electrical resistanceprobes of various appropriate metal-lurgies with coupons mounted on aspecial flow shield installed on the endof the probes. This was done at criticallocations throughout the plant, includ-ing the reboiler inlet and outlet, thereboiler/reclaimer common vapor re-turn line, and the regenerator columnwall (in the area replaced because ofexcessive corrosion).

Each of the four new probes wasconnected to data-recording instru-ments to allow trending and correla-tion of the corrosion rate with othersystem events. A digital control systemin the amine unit made it possible totrend various plant parameters. Evalu-ation of the unit trends yielded the fol-lowing observations:• Liquid levels in the contactor andre-claimer fluctuated wildly.• Reclaimer thermal cycles were notbehaving as designed.

FIGURE 2

A section of the type 316L SS regenerator towerexhibiting “mesa” corrosion.

FIGURE 3

A section of the reflux distributor with preferen-tial weld heat-affected zone (HAZ) corrosion.

• The liquid level inside the regenera-tor was not maintained adequately.• The steam inlet temperature to thereboiler was excessive.• The steam flow to the reboiler wasbelow the recommended rate.

System Design Reviewand Response

A review of the system flow dia-grams revealed that the control valve

maintaining therich amine level inthe bottom of thecontactor was lo-cated in the richamine flow up-stream of the rich/lean exchangers.The pressure

began to experience corrosion; thisresulted in multiple tube failures.

Corrosion in Amine SolutionsCorrosion in lean and rich amine so-

lutions has been studied extensively.1-6

Minimizing corrosion in amine units in-volves a holistic approach.7 An aggres-sive corrosive condition is rarely re-solved by changing a single operationalor process parameter. Most studies havefocused on minimizing corrosion of CSbecause it is the most frequently usedmaterial in amine units. Austenitic SS(i.e., types 304 SS or 316 SS [UNS S30400and UNS S31600]) have been used inhotter sections of amine units, eitherwhere corrosion cannot be controlledor where the use of SS would allowgreater flexibility in unit operation. Areview of available literature suggeststhat austenitic SS generally providesgood service in all but the most severeenvironments.8-11 When excessive corro-sion has occurred, it has often been as-sociated with excessive temperaturesand high heat stable acid salt (HSAS) con-tent. Corrosion of austenitic SS tubes hasoccurred in amine reboilers using high-pressure steam or when upper-rowtubes become starved and overheated.

A review of amine solution analysesindicated that the lean amine solutionexceeded generally accepted targetsfor contaminants and degradationproducts established by various re-searchers and end users based on ex-perience.2,4 Generally accepted guide-lines call for maintaining HSAS levels<2%, with some guidelines stating atarget of <1%.8

It was difficult to apply amine con-taminant target levels to the reboiler andregenerator corrosion problem since theestablished contaminant levels havebeen derived to limit corrosion of CScomponents. Initial efforts at processcontrol to minimize the regenerator andreboiler corrosion focused on reducingHSAS levels. HSAS precursors and theregenerator/reboiler operation werealso investigated, based on their poten-tial contribution to HSAS levels and sys-tem corrosion.

FIGURE 4

FIGURE 5

Failed reboiler tube sample exhibiting general corrosion.

EDS analysis results of reboiler tube sample.

drops associated with flow through thevalve caused acid gas evolution in theflowing rich amine stream, and nucle-ate boiling on the exchanger tube sur-faces. The plant personnel respondedto this condition by removing one ofthe three rich/lean exchangers fromservice to lower the solution tempera-ture at the effluent of the exchangers.This required adding more heat to thesystem through the reboiler to main-tain gas-stripping efficiency in the re-generator. The reboiler tube bundle

An aggressive corrosive

condition is rarely

resolved by changing a

single operational or

process parameter.

HSAS PrecursorsHigh formate, thiocyanate, and thio-

sulfate (M2S2O3) levels in the aminesolution suggested that oxygen from anunknown source might have been en-tering the amine unit. Oxygen in anMEA solution contributes to formate,thiosulfate, and cyanate HSAS forma-tion.3 Oxygen is also known to pro-mote formation of formic, acetic, andoxalic acids (HCOOH, CH3COOH, andHOOCCOOH·2H2O) in MEA, which iswhy deaerated water is recommendedfor MEA solution makeup.

Other compounds that may havecontributed to HSAS formation includecarbon monoxide (CO) in the processgas stream and a reaction of oxygenwith H2S to form sulfur dioxide (SO2).CO specifically would contribute toformate production, while SO2 wouldpromote sulfate salt formation.

Regenerator/Reboiler OperationRegenerator operation should at-

tempt to strip acid gases on the traysinstead of in the reboiler. If regenera-tor internal pressures are insufficient,inadequate stripping will occur andexpose the reboiler to increased acidgas concentrations.

Reboiler operation can contributeto acid gas breakout in the vapor space.Acid gas breakout containing formicacid can cause high concentrations offormic acid on tube surfaces, creatingaggressive corrosion. Conditions thatcan contribute to acid gas breakout arehigh tube metal temperatures and/orlow solution levels. A low regeneratorliquid level could result in hydrostatichead pressures that are insufficient toflood thermosyphon reboilers. Re-boiler tube metal temperatures werealso investigated, based on steam pres-sures and flows, and found to be inexcess of 320°F (160°C).

Laboratory Failure Analysisof Reboiler Tube

The service company conducted alaboratory analysis on several type 316LSS reboiler tubes that had failed becauseof general corrosion. The samples, takenfrom U-tubes, contained lean amine so-

lution on the shell side and steam on thetube side. They had been on upper-rowtubes located next to the steam inletsection of the tubesheet.

Several procedures were used toanalyze the reboiler tube samples, in-cluding visual observations, energy dis-persive spectroscopy (EDS), chemicalanalysis, and metallographic observa-tions using mounted and polishedspecimens.

Visual ObservationsFigure 4 shows a failed tube sample

as it appeared when removed from ser-vice, illustrating areas of general cor-rosion. The corroded area was unusualbecause the corrosion appeared tostop at a specific distance below theOD surface and followed the circum-ferential shape of the tube sample. Inuncorroded areas, the sample was cov-ered with a thin, adherent green scale.The tube sample ID was in good con-dition with no observed general/pit-ting corrosion or hard water deposits.The electric resistance weld (ERW) didnot exhibit significant corrosion.

EDS AnalysisFigure 5 shows EDS analysis results

of the green scale/deposits on the tubesample OD. The OD deposits werecomposed primarily of chromium andoxygen, probably combined as a chro-mium oxide corrosion scale. The analy-sis detected some sodium and siliconas well as lesser quantities of other basemetal elements such as iron, nickel,and molybdenum. The understatedpresence of iron was most likely dueto the single surface anlysis of the scalelayer rather than a more thoroughcross-sectional view normally exam-ined. Constituents of a corrosion/pro-cess scale tend to migrate into non-homogenous layers so the EDStechnique requires greater care to fullycharacterize the composition.

Chemical AnalysisChemical analysis results showed

that the tube sample met the chemicalcomposition requirements for ASTMA24912 Gr. TP 316.

Metallographic ObservationsFigures 6 through 8 illustrate the mi-

crostructure of the tube sample at vari-ous locations of interest. Figure 6 de-picts an interface between corrodedand uncorroded areas. No microstruc-tural features were observed thatwould account for the specific pattern,shape, or depth of the OD corrosion.

Figure 7 shows the bottom of an ODcorroded area. Again, the microstruc-ture exhibited no features that wouldexplain the peculiar corrosion pattern.No evidence of stress corrosion crack-ing (SCC) was observed.

Figure 8 shows the autogenousweld. The weld contained a dendritic

FIGURE 6

Micrograph of reboiler tube sample (ODcorrosion) showing the interface betweencorroded and uncorroded areas.

FIGURE 7

Micrograph of reboiler tube sample (ODcorrosion) showing equiaxed austenitic grainswith scattered nonmetallic inclusions.

FIGURE 8

Micrograph of reboiler tube sample at theautogenous weld.

structure, suggesting that the tube wasnot sufficiently cold-worked and heat-treated during mill processing to ho-mogenize the microstructure (per therequirements of ASTM A249).

RESULTS

Reboiler Tube Sample CorrosionCharacteristics

Examination of the reboiler tubesample showed that it had experiencedloss of passivation and rapid generalcorrosion. Although the corrosion pat-tern was unusual, no microstructuralor chemical composition anomalieswere observed that would have con-tributed to the corrosion. The weldevidently had been improperly heat-treated, but it was not corroded.

Austenitic SS typically corrode be-

cause of pitting, based on the tenaciouschromium oxide scale that forms ontheir surfaces. In aggressive (highlyreducing) environments where passiv-ity is lost, types 304 SS and 316 SS cansuffer general corrosion; in such cases,corrosion rates can be high. An auste-nitic SS such as type 316 SS typicallyloses passivity in strong reducing ac-ids, in moderately corrosive acids athigh temperatures, or in aqueous solu-tions with insufficient oxidizing capac-ity to maintain the oxide film.

AMINE SOLUTIONANALYSES REVIEW

A review of amine solution analysesreports suggested that the high levelsof formates containing HSAS in the cir-culating amine stream likely caused thecorrosion. In certain conditions, for-

mate salts can produce low percent-ages of free formic acid. Type 316 SSnormally resists all concentrations offormic acid up to the atmospheric boil-ing point; however, at higher tempera-tures or in solutions of low oxidizingcapacity, type 316 SS can corrode athigh rates.

If sufficiently sensitized by grainboundary carbide precipitation, types304 SS and 316 SS can also suffer inter-granular corrosion (IGC) in hot organicacid solutions. IGC may have partiallyaccounted for the observed preferentialweld-seam corrosion in the reboiler andrich/lean exchanger tubes. Other richamine contaminants that are normallycontrolled to prevent excessive corro-sion of CS—including high-acid-gas load-ings and CO2 to H2S ratios—are typicallynot corrosive to type 316 SS. As a result

FIGURE 9

Iron level in lean amine decreased with improved reclaimer operation andcontrol.

FIGURE 10

Amine usage rate loss decreased with improved reclaimer level controland reduction of foam-inducing solids.

FIGURE 11

HSAS in rich amine decreased with improved reclaimer efficiency.

FIGURE 12

Corrosion rates of type 316L SS at the reboiler inlet and outlet.

Iron Level(ppm)

8-Point MovingAverage

Reclaimer BundleCleaning Limit

600

500

400

300

200

100

0

Time (weeks)

Daily MEAUsage (gal)

7-Point MovingAverage Limit Limit

Vol

ume

(gal

)

Time (weeks)

Heat Stable Salt (wt%) Limit12

10

8

6

4

2

0

Time (weeks)Time (30-day increments)

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

35

30

25

20

15

10

5

0

Par

ts p

er M

illio

nw

t%

Cor

rosi

on R

ate

(mpy

)

of low chloride concentrations in theamine solution, chlorides were notconsidered a contributing factor in theaccelerated corrosion. Chlorides alsopromote chloride SCC, pitting, or crev-ice corrosion, none of which accom-panied the general corrosion experi-enced by the tube sample.

RECOMMENDATIONSVarious operating parameters, design

changes, and chemical additives wererecommended to address problems re-vealed in the investigation. The sampleanalysis showed very high levels ofamine solution contamination and indi-cated improper reclaimer operation.This contributed greatly to the corrosiveenvironment by introducing a concen-trated stream of contaminants into theamine solution through the reclaimer/reboiler vapor return line. Foaming andthe level control system’s inability torespond to the condition contributed touncontrolled reclaimer levels. To cor-rect this, the reclaimer level control cir-cuit was placed on manual control andan antifoam chemistry was added toeliminate liquid transfer through the va-por line.

CONCLUSIONSThe amount of corrosion products

in the stream decreased with improvedreclaimer operation and control (Fig-ure 9). Figure 10 shows that the rate ofamine loss from the unit decreased asthe reclaimer level control was im-proved and the foam-inducing solidsdiminished. Improved efficiency al-lowed the reclaimer to reduce theHSAS in the solution (Figure 11).

Stream analysis indicated that theamine-stripping capacity of the regen-erator was not sufficient as a result ofthe inadequate reboiler steam feedrate. The investigation also determinedthat reboiler tube skin temperatureswere excessive, based on thermal deg-radation of MEA. The steam pressureto the reboiler was decreased to lowerthe saturated steam temperature whilethe steam feed rate was increased. Thisallowed additional heat into the systemto enhance stripping efficiency in theregenerator without thermally degrad-ing the amine. A proprietary water-dispersible corrosion inhibitor wasadded to the circulating amine solutionto protect CS components.

During a subsequent outage, thecontactor level control valve was relo-cated to a position downstream of therich/lean exchangers and close to theamine inlet nozzle of the regenerator.This configuration provided a consis-tent backpressure on the rich aminesystem and permitted the addition ofmore heat through the rich/lean ex-changers without the risk of acid-gasevolution.

Corrosion in the amine unit wasbrought under control, with HSAS mea-suring <1 wt% and corrosion rates <1mpy, as shown in Figures 12 and 13.

The system filters remained in ser-vice for 2,000 h prior to replacement.

FIGURE 13

Properly controlling HSAS by reclaim-ing or replacing the amine solutionrather than exposing the system to anaggressive environment with a recon-ditioned, dirty solution during opera-tion is key to corrosion control inamine systems with SS equipment.

References1. H.L. Craig Jr., B.D. McLaughlin, “Corrosive

Amine Characterization,” CORROSION/96, paper no.

394 (Houston, TX: NACE, 1996).

2. J.C. Dingman, D.L. Allen, T.F. Moore, Hydro-

carbon Process. 45, 9 (1966): p. 285.

3. P.C. Rooney, M.S. DuPont, T.R. Bacon, Hydro-

carbon Process. July (1998): p. 109.

4. R.B. Neilson, K.R. Lewis, J.G. McCullough, D.A.

Hansen, “Corrosion in Refinery Amine Systems,” COR-

ROSION/95, paper no. 571 (Houston, TX: NACE,

1995).

5. A.L. Cummings, F.C. Veatch, A.E. Keller, “Cor-

rosion and Corrosion Control Methods in Amine Sys-

tems Containing H2S,” CORROSION/97, paper no. 341

(Houston, TX: NACE, 1997).

6. E. Williams, H.P. Leckie, MP 7, 7 (1968): p. 21.

7. R.G. Abry, M.S. DuPont, Hydrocarbon Process.

April (1995): p. 41.

8. P.C. Rooney, T.R. Bacon, M.S. DuPont, Hydro-

carbon Process. March (1996): p. 95.

9. A.J. MacNab, R. Treseder, MP 10, 1 (1971):

p. 21.

10. H.P.E. Helle, “Corrosion Control in Alka-

nolamine Gas Treating Absorber Corrosion,” CORRO-

SION/95, paper no. 574 (Houston, TX: NACE, 1995).

11. E.D. Montrone, W.P. Long, Chem. Eng. Janu-

ary (1971): p. 94.

12. ASTM A249, “Standard Specification for

Welded Austenitic Steel Boiler, Superheater, and Con-

denser Tubes” (West Conshohocken, PA: ASTM,

1996).

Corrosion rates of CS at the reboiler inlet and outlet.

The sample analysis

showed very high levels

of amine solution

contamination and

indicated improper

reclaimer operation.C

orro

sion

Rat

e (m

py)

Inlet to Reboiler (CS)

45

40

35

30

25

20

15

10

5

0

Time (30-day increments)

Outlet to Reboiler (CS)

Inhibitors ReducePiping Wear Caused

by ParticleImpingement

S. RAMACHANDRAN, M.B. WARD, K.A. BARTRIP, AND V. JOVANCICEVIC,Baker Petrolite Corp.

was modified to include the effect ofinhibitors. Laboratory experiment re-sults concluding that inhibitors canretard the effect of particle impinge-ment were then used to determine amodified constant for the impact of aparticle on the pipe in the presence ofa corrosion inhibitor. The researchersthen investigated the potential for in-creasing production for a given pipeconfiguration while reducing erosion-corrosion, comparing their findings tothe guidelines presented in API RP 14E.

Erosion-Corrosion andParticle ImpingementConsiderations

Previous studies have shown howoperating and environmental condi-tions affect erosion rates caused byparticle impingement.4-6 Factors thathave been found to relate the corro-sion rate to particle impingement in-clude:• Elbow geometries• Fluid velocities• Fluid properties• Particle diameters and densities• A constant that accounts for particleimpact on a given material. This con-stant will vary with changes in sandsharpness, geometry, material hard-ness, and an empirical factor that de-pends on the piping material.

Incorporating the assumptions andfindings of earlier work, the research-ers proposed a new equation to calcu-late erosion rates that include the ef-fect of inhibitor:

(1)

where h = erosion rate; Fi = inhibitionfactor; FM = an empirical material con-stant; FS = an empirical sand sharpnessfactor; FP = a penetration factor for dif-ferent materials; Fr/D = a penetrationfactor for different radii; W = sand pro-duction rate; QF = fluid productionrate; VL = characteristic impact of ve-locity; and D = ratio of pipe diameterin inches to a 1-in. (2.54-cm) pipe. Fi

can be easily determined for a varietyof conditions in laboratory experi-ments with and without the presenceof sand.

Corrosion inhibitors can retard erosion caused bymetal loss from particle impingement. This article

discusses how researchers modified a model used topredict erosion-corrosion caused by particle impingementby including the effect of inhibitors. Experimental resultsrevealed that two inhibitors mitigate metal loss producedby particle impingement, allowing for increasedproduction rates.

Erosion-corrosion, a piping wearphenomenon caused by flow-ing fluid disrupting or thinningthe protective film of corrosionproduct,1 compromises the in-tegrity of gas pipelines and de-

creases production capacity. Threemajor mechanisms cause pipingwear—chemical dissolution of thepipe, mechanical erosion caused byfluid flow, and impingement of par-ticles on the pipe wall. The AmericanPetroleum Instititute (API) RP 14E2 cal-culates an erosional velocity beyondwhich operation is not recommended.Subsequent studies have reviewed thebasis and source of the velocity guide-lines and determined different con-stants with the API RP 14E criteria.3-4

Baker Petrolite recently examinedthe effect of inhibitors on reducing pip-ing wear caused by particle impinge-ment. The research incorporated amethod of estimating such wear that

These experiments were performedin a rotating cage apparatus similar tothe slurry pot tester used by Clark.7

Clark found that the erosion rate inslurry pot testers can be described byEquation (2):

(2)

where k = a material constant; V = fluidvelocity; A = coupon area; and W =sand production rate. In the experi-ments using sand, the parameters A, V,and W were kept constant. Only typeand concentration of inhibitor varied.If erosion rates changed in the experi-ment, only k changed.

In the analysis, Fi was calculated fromthe ratio of the erosion rate with inhibi-tor (hi) to the erosion rate without in-hibitor (h), as shown in Equation (3).

(3)

Equation (3) was then used with anexperimentally measured Fi to assessthe impact of chemical inhibitors in afew oil- and gas-production scenarios.

Inhibitors Increase GasProduction

The researchers evaluated inhibitorsin a modified high-speed autoclave test(HSAT) with and without sand underdifferent temperatures and pressures.Also called a rotating cage test, theHSAT consists of an open-cage spindlecontaining flat, preweighed corrosioncoupons rotated at a set speed to gen-erate high local shear stresses on theleading edge of the coupons, the edgethat impinges on the fluid. A brine/hy-drocarbon mixture was added to theautoclave. After purging and evacua-tion to remove oxygen, a specific con-centration of inhibitor was added. Thestirrer was turned on, and the pressureand temperature were adjusted to testconditions. Upon completion of thetest, the apparatus was allowed to cool.The coupons were removed, in-spected, and reweighed. A corrosionrate was calculated for a specific testtime and weight loss.

COMPARISON OF API RP 14E ANDEQUATION (1) VELOCITY LIMITS

In a system containing only flowingliquid water, the erosional velocity,

FIGURE 1

Erosion-corrosion limits as computed from API RP 14E and Equation (1)for cases using no inhibitor.

1,000

100

10

1

0.1

0.01

0.0011 10 100

Superficial Gas Velocity (ft/s)

Sup

erfic

ial L

iqui

d V

eloc

ity (f

t/s)

API 14E (C = 100)

Equation (1) Fi = 1 no inhibitor

API 14E (C = 125)

API 14E (C = 250)

using the API RP14E criteria with100 as a constant, is12.6 ft/s (3.8 m/s).Normal flow looptesting often caninvolve velocitiesof ≥20 ft/s (6 m/s).The HSAT at 2,000rpm operates at ve-locities of 21.82 ft/s (6.7 m/s). The ve-locities above theAPI RP 14E ero-sional velocitiesare equivalent tothe API RP 14Econstants of 159and 173.

The researcherscompared the ve-locity limits sug-gested by equation (1) with no inhibi-tion (Fi = 1) to the velocity limits sug-gested by API RP 14E using differentconstants. Table 1 presents the physi-cal data for this case, which include val-ues for particle diameter, density, par-ticle production rate, particle sharpness,gas density, gas viscosity, liquid density,and liquid viscosity.

Figure 1 compares the different ve-locity limits by plotting superficial liq-uid velocity against superficial gas ve-locity. The velocity limits suggested byEquation (1) with no inhibitor appearas a continuous line. The dotted linesshow the limits suggested by API RP14E, with the constants of 100 and 125serving as conservative recommenda-tions for continuous intermittent ser-vice and 250 serving as the highestnumber recommended.

Above a certain superficial gas ve-locity at low liquid superficial veloci-ties, Equation (1) indicates that ero-sion-corrosion decreases as superficialliquid velocity increases. In these situ-ations, increasing the superficial liquidvelocity allows the formation of a pro-tective liquid film that retards the mo-mentum of a particle striking the sur-face. The applicability of Equation (1)stems from experimental results usingdifferent fluids, particles, and from ob-servations of failures.4-5

As Figure 1 shows, the limits sug-

gested by Equation (1) and API RP 14Eintersect. Therefore, API RP 14E is con-servative at low superficial gas veloci-ties and high superficial liquid veloci-ties, but misleading at high superficialgas velocities. The most misleadingpoint of the API RP 14E criteria is that,at high superficial gas velocities andlow superficial liquid velocities, reduc-ing the superficial liquid velocity willreduce the corrosion caused by par-ticle impingement. Equation (1) indi-cates that, in several instances, increas-ing the superficial liquid velocity willdecrease the amount of corrosion.

INHIBITOR PERFORMANCE AT250°F (121°C) AND 100 PSIA CO

2

HSAT tests were run at 250°F, 100psia carbon dioxide (CO2), and 2,000rpm. The mixture contained 75% syn-thetic brine and 25% Isopar® M.† Sand(Houston #5) was added at a 5% con-centration. The tests were typically runfor 20 hours. Figure 2 shows the gen-eral corrosion rates obtained from theexperiments with sand in the presenceof 100 ppm of Inhibitor A, 100 ppm ofInhibitor B, and 100 ppm of InhibitorC. The blank corrosion rate with sandwas 1,130 mpy (29 mm/y). Inhibitor Bshowed the best performance whileinhibitor A was marginally better than

†Trade name.

Inhibitor C.The inhibition of corrosion was fur-

ther investigated with and withoutsand using Inhibitors A and B. Figure 3shows the results of this investigation.The blank corrosion rates with andwithout sand were 1,130 and 830 mpy(21 mm/y), respectively. The resultsclearly show that Inhibitor B more dra-matically reduces the effects of ero-sion-corrosion than Inhibitor A. Inhibi-tor A becomes more effective at higherconcentrations but still lags behind theperformance of Inhibitor B. The resultsindicate that the minimum effectiveconcentration of Inhibitor A is ~3 to 5times higher than that of Inhibitor B.

The maximum penetration at theleading edge of the mild steel couponsin the experiments was measured us-ing an optical imaging system. Particleimpingement most likely occurs at thisedge because fluid streamlines canmeet the edge. As Table 2 presents,after 20 h of testing, the blank penetra-

tion in the presence and absence ofsand were 230 and 140 µm, respec-tively. Both Inhibitors A and B obtainedsignificant reduction in the maximumpenetration in the presence and ab-sence of sand. Inhibitor A reduced themaximum penetration by 65 and 75%;Inhibitor B reduced the maximum pen-etration by 91 and 96%. Compared togeneral corrosion inhibition, the reduc-tion in maximum penetration for bothproducts was somewhat lower. Thesurface roughness of coupons alsochanged from very rough to fairlysmooth in the presence of inhibitors.

To isolate the effect of erosion-cor-rosion, the researchers measured ero-sion rates as the difference in theweight loss rate with and without sand.Table 3 presents the erosion rates forInhibitors A and B as well as values forFi, which were calculated by usingequation (3). As Table 3 shows, usinginhibitors decreases the erosion rate.The inhibitor factors (Fi) for corrosion

FIGURE 2

General corrosion rates from high-speed autoclave tests with sand at250°F, 100 psia CO2, and 2,000 rpm.

1,200

1,000

800

600

400

200

0Blank 100 ppm

Inhibitor A100 ppm

Inhibitor B100 ppm

Inhibitor C

With 5% sand

Cor

rosi

on R

ate

(mpy

)FIGURE 3

General corrosion rates from high-speed autoclave tests with and withoutsand at 250°F, 100 psia CO2, and 2,000 rpm.

1,200

1,000

800

600

400

200

0Blank 100 ppm

Inhibitor A100 ppm

Inhibitor B

Cor

rosi

on R

ate

(mpy

)

With 5% sandWithout 5% sand

TABLE 1

PARAMETERS FOR CASESWITH NO INHIBITION

Quantity

Sand particle size 150 µmPipe diameter 2 in.Sand rate 10 lb/dayCorrosion allowance 5 mpyDensity of gas 7.21 lbm/ft3

Density of liquid 43.25 lbm/ft3

Viscosity of gas 0.0166 cpViscosity of liquid 0.5369 cp

caused by particle impingement varybetween 0.27 and 0.44, dependingupon the inhibitor and its concentra-tion.

EFFECT OF INHIBITOR ONEROSION-CORROSION LIMITSThe researchers examined the effect

of using inhibitors to prevent erosion-corrosion for the parameters in Table1. Tables 4 and 5 list superficial gas andliquid velocities that will prevent ero-sion-corrosion (>5 mpy [127 µm/y])for cases without inhibitor, with Inhibi-tor A at concentrations of 100 and 250ppm, and with Inhibitor B at a concen-tration of 100 ppm. Figure 4 illustratesthat inhibitors increase the allowablesuperficial gas and liquid velocities thatcan be used while avoiding erosion-corrosion for both gas and liquid sys-tems. This indicates that using inhibi-tors can increase the productioncapacity of a pipeline.

Table 4 shows the superficial liquid

TABLE 2

MAXIMUM PENETRATION AT THE LEADING EDGE OF THECORROSION COUPONS FOR INHIBITORS A AND B, WITH ANDWITHOUT SAND

Concentration Maximum PenetrationTreatment (ppm) (µm) RoughnessBlank with sand — 230 Very roughBlank without sand — 140 RoughInhibitor A with sand 250 85 RoughInhibitor A without sand 250 35 Fairly smoothInhibitor B with sand 100 20 Fairly smoothInhibitor B without sand 100 5 Smooth

velocity limits with and without inhibi-tor at a superficial gas velocity of 1 ft/s(0.3 m/s). Using an inhibitor in thiscase allows transportation of a liquidat superficial velocities 5.3 to 9.5%above the liquid velocities without in-hibitor. Gas systems typically have highsuperficial gas velocities with low su-perficial liquid velocities. The superfi-cial gas velocity limits at a very low liq-uid superficial velocity (0.001 ft/s[0.0003 m/s]) appear in Table 5. In thiscase, using inhibitor allows productionat superficial gas velocities 34 to 63%larger than without inhibitor.

ConclusionsA new equation of estimating the

corrosion that occurs due to particleimpingement using an inhibitor is pre-sented. Experimental results can beused to determine an inhibition factor,Fi, which can be applied in differentoil and gas production scenarios to es-timate erosion-corrosion limits. If ero-sion-corrosion is a limiting factor insituations with the parameters studied,applying Inhibitor B may be a cost-ef-fective means of enhancing productionwithout compromising asset integrity.

The researchers also concurredwith earlier findings that API RP 14E

FIGURE 4

Erosion-corrosion limits as computed from Equation (1) for cases using noinhibitor and Inhibitors A and B with Fi parameters from Table 3.

1,000

100

10

1

0.1

0.01

0.0015 10 15 20 25 30

35Superficial Gas Velocity (ft/s)

Sup

erfic

ial L

iqui

d Ve

loci

ty (f

t/s)

No inhibitor

100 ppm of Inhibitor A

250 ppm of Inhibitor A

100 ppm of Inhibitor B

TABLE 3

EROSION RATES AT 250°F AND 100 PSIPARTIAL PRESSURE FOR INHIBITORS A ANDB, WITH AND WITHOUT SAND

Concentration Erosion RateTreatment (ppm) (mpy) Fi

Blank — 294 1

Inhibitor A 100 128 0.44

Inhibitor A 250 125 0.43

Inhibitor B 100 79 0.27

TABLE 4

SUPERFICIAL LIQUID EROSIONAL VELOCITYLIMIT AT A SUPERFICIAL GAS VELOCITY OF 1.0FT/S(A)

Concentration Superficial(ppm) Liquid Velocity % Increase

Treatment Limit (ft/s) Over Blank

Blank — 97.7 0

Inhibitor A 100 102.9 5.3

Inhibitor A 250 103.0 5.4

Inhibitor B 100 107.0 9.5

(A) For a case with physical parameter values given in Table 1.

TABLE 5

SUPERFICIAL GAS EROSIONAL VELOCITYLIMIT AT A SUPERFICIAL LIQUID VELOCITY OF0.001 FT/S(A)

Concentration Superficial(ppm) Gas Velocity % Increase

Treatment Limit (ft/s) Over Blank

Blank — 8.49 0

Inhibitor A 100 11.4 34.3

Inhibitor A 250 11.5 35.5

Inhibitor B 100 13.9 63.7

(A) For a case with physical parameter values given in Table 1.

provides a falsesense of securityin some caseswhile unnecessar-ily limiting pro-duction in othercases. Includingthe effect of theexamined corro-sion inhibitors inerosion rate calcu-lations will signifi-cantly increasethe amount of gasthat can be safelytransported, ac-cording to themodel.

References1. Y.M. Ferng, Y.P. Ma, N.M. Chung, Corrosion

56 (2000): p. 116.

2. API RP 14E, “Recommended Practice for De-

sign and Installation of Offshore Production Plat-

form Piping Systems” (Washington, DC: API, 1991).

3. M.M. Salama, “An Alternative to API 14E Ero-

sional Velocity Limits for Sand Laden Fluids,” 1998

Offshore Technology Conference, paper no. 8898

(Houston, TX: OTC, 1998).

4. K. Jordan, “Erosion in Multiphase Production

of Oil & Gas,” CORROSION/98, paper no. 59 (Hous-

ton, TX: NACE, 1998).

5. B.S. McLaury, S.A. Shirazi, J.R. Shadley, E.F.

Rybicki, “How Operating And Environmental Con-

ditions Affect Erosion,” CORROSION/99, paper no.

34, (Houston, TX: NACE, 1999).

6. J.R. Shadley, S.A. Shirazi, E. Dayalan, E.F.

Rybicki, “Prediction of Erosion-Corrosion Penetra-

tion Rate in a CO2 Environment with Sand,” COR-

ROSION/98, paper no. 59 (Houston, TX: NACE,

1998).

7. H.M. Clark, “A Comparison of the Erosion

Rate of Casing Steels by Sand/Oil Suspensions,”

1990 Offshore Technology Conference, paper no.

6279 (OTC, 1990).

SpectroscopicEllipsometry—

A Techniquefor Studying the

Corrosion InhibitionMechanism

SAMUEL E. CAMPBELL, Baker Petrolite Corp.

Petrolite researchers are using theellipsometry technique to assess thefundamental properties of inhibitedmild steel surfaces.

Ellipsometry measures the changein the polarization state of light re-flected from the surface of a sample.Based on the measurement of two pa-rameters—psi (ψ) and delta (∆)—at anumber of wavelengths, several valu-able properties can be determined, in-cluding optical constants, film thick-ness, surface roughness, crystallinity,and composition.

Optical constants and film thicknessare determined by solving electromag-netic equations that describe the struc-ture of the interface.1-4 Compositionand molecular structure can be ob-tained by constructing a molecularmodel of the interface.5-7

In situ ultraviolet and visible spec-trum (UV-Vis) ellipsometry and ex situinfrared ellipsometry were used to mea-sure the optical constants and film thick-ness of freely corroding or inhibited mildsteel (C1018 [UNS G10180]). The CIsthat were used for this study were se-lected based upon water solubility andtheir performance in kettle tests.

Corrosion TestContinuous carbon dioxide (CO2)

sparged kettle tests were performed toselect CIs that provided greater than90% protection. Tests were run at100°F (38°C) in 1% sodium chloride(NaCl) brine for 20 h, with corrosionrates monitored by linear polarizationresistance (LPR), iron counts, andweight loss.

Figure 1 presents the kettle test re-sults using ethoxylated imidazoline com-pound (Chemical A) and a quaternaryamine-based inhibitor (Chemical B).Both inhibitors produced a rapid re-sponse on LPR, were soluble in 1% NaClbrine, and effectively inhibited corro-sion. The sulfur-based product (Chemi-cal C) performed poorly in this test.

In Situ UV-Vis EllipsometryMild steel (C1018) corrosion cou-

pons of 1.5-in. (3.8-cm) diameter wereplaced in a static liquid cell maintainedat room temperature. The coupons

Spectroscopic ellipsometry, which measures thechange in the polarization state of light reflected

from the surface of a sample, can be used to characterizeproperties of thin surface films. Corroding mild steelcoupons were studied in situ with a spectroscopicellipsometer to assess the rate of film growth with andwithout a corrosion inhibitor. Based upon molecularmodels, the combined corrosion product, inhibitor filmthickness, and optical constants of the film wereindependently fit as a function of time. Spectroscopicellipsometry was found to be an effective tool tocharacterize films on inhibited mild steel surfaces.

Determining the structure andcomposition of corrosion in-hibitor (CI) films on metalsurfaces is a focus of ongo-ing research into the fun-damental mechanism of cor-

rosion inhibition. Spectroscopicellipsometry is a technique that hasbeen used to characterize thin surfacefilm properties, including thickness,density, and optical constants. Baker

were polished in a series of steps to a“mirror” finish (using 0.5 µm alumina[Al2O3] powder).

The corrosion coupon sampleswere studied in situ with a spectro-scopic ellipsometer capable of acquir-ing 390 wavelengths from 380 to 1,000nm. Spectroscopic data were acquiredevery few seconds. The position of theliquid cell windows allowed theellipsometer to acquire data at a 70degree angle of incidence.

Optical ConstantsThe optical constants of the brine

(refractive index n′), modeled opti-cally, were determined by acquiringdata on a standard silicon oxide samplein 1% NaCl. Once the optical constantswere determined for the brine, theywere maintained when modeling theinhibited and corroding interface.

The optical constants of the 1%NaCl solution (Figure 2) were obtainedwith and without the corrosion inhibi-tors added in the test cell. At 200 ppm,Chemical A slightly increased the in-dex of refraction (n′). Chemical B didnot significantly change the brine op-tical properties up to 1,000 ppm.

The mild steel coupon optical con-stants in air were obtained by a directfit of the real and imaginary parts ofthe refractive index (n and k) at eachmeasured wavelength. This methoddid not allow separation of the steeland native oxide optical constants, pro-viding “pseudo” optical constants. Thepseudo optical constants, obtainedseparately for each metal coupon, gavea “before corrosion” baseline. Figure 3provides comparison data for each offour experiments.

Film ThicknessThe corrosion layer was modeled

mathematically using quantum me-chanics (including Drude Oscillator8).Corrosion layer optical constants com-bined the optical properties of the ox-ide and surface roughness, with andwithout a CI. In the experiments withan inhibitor, the film thickness con-sisted of corrosion product and CI,while surface roughness was deter-mined separately.

Corrosion inhibitor candidate performance at 50 ppm, 1% NaCl, and 100°F.

FIGURE 1

FIGURE 2

Optical constants for CO2 saturated brine (1% NaCl) with and without Inhibitor A.

The first C1018 coupon was sub-mersed into the brine, and ellipso-metric data acquisition began. After~12 min, 50 ppm of Chemical B wasadded to the solution. The optical con-stants and thickness of the corrosionlayer were fit independently to a spec-trum at each time interval (3 s). Figure4 shows the change in corrosion prod-uct layer thickness as a function oftime. The initial corrosion film thick-ness (without inhibitor) was 400 Å andgrew at a rate of 20 Å/min until 50 ppmof Chemical B was added at 12 min.After 2 to 3 min, the rate of film growth

dropped from 20 to <0.2 Å/min, stabi-lizing at 650 Å.

The second C1018 coupon was sub-mersed, and ellipsometric data acqui-sition began. After ~1 min, 50 ppm ofChemical A was added to the brine. Asin the prior case, the optical constantsand corrosion layer thickness were fitindependently to a spectrum at eachtime interval. Figure 5 shows thechange in corrosion product layerthickness as a function of time. Afterthe addition of 50 ppm of Chemical A,the corrosion layer growth ratedropped from 35 to 10 Å/min in the

1.00E+03

1.00E+02

1.00E+01

1.00E+00C

orro

sion

Rat

e (m

py)

Time (h)

0.0 5.0 10.0 15.0 20.0 25.0

Chemical AChemical BChemical CBlank

Blank200 ppm Chemical A

50 ppm Chemical B

200 ppm Chemical B

1.350

1.345

1.340

1.335

1.330

1.325

1.320

Inde

x of

Ref

ract

ion

n

200 400 600 800 1,000

Wavelength (nm)

first 15 min. The rate of film growthcontinued to decline for the remainderof the test. The film thickness, whichwas initially 40 Å, stabilized at ~500 Åafter 1 h.

The time-resolved spectroscopicellipsometry data showed both a slow-ing of the corrosion rate after inhibi-tors were added to the brine and therate at which inhibition was achievedby the changes in film thickness. Inthese experiments, the thickness of thecorrosion product, surface roughness,and CI layers were not determined in-dependently. By combining the CI andcorrosion product layers in the molecu-lar model, excellent fits were achievedto determine the corrosion ratesthrough thickness change.

Although both Chemicals A and Bshowed greater than 90% protection inthe kettle tests, the ellipsometry clearlydistinguished between the two inhibi-tors. Both provided inhibition, as evi-denced by a decreased film growthrate. Chemical B performed signifi-cantly better, however, allowing al-most no corrosion product layer

FIGURE 4

Corrosion product layer thickness as a function of time in the presence of50 ppm of Chemical B.

FIGURE 5

Change in corrosion product layer as a function of time in the presence of50 ppm of Chemical A.

FIGURE 3

Optical constants of the polished mild steel coupons prior to exposure tothe brine.

growth after inhibitor injection. In addi-tion, Chemical A exhibited a signifi-cantly slower response time than Chemi-cal B. In situ spectroscopic ellipsometricmeasurement provided an effectivemeans to quantify the actual rate of cor-rosion product layer growth.

ConclusionsThis work found that ellipsometry

can effectively measure growth ratesof inhibited and uninhibited mild steelsurfaces. Though the mathematicalmodels were unable to distinguish in-hibitor film thickness from corrosionproduct film thickness, the research-ers were able, through ellipsometry, todetermine that inhibitors reduced filmgrowth rate while maintaining an over-all inhibitor film thickness of less than50 Å (about two monolayers). Thecompany will continue its efforts to useellipsometry and other techniques tofurther understand the CI mechanismby obtaining real-time molecular levelmeasurements of inhibited corrodingsystems.

References1. J. Zerbino, O. Bulloes, S. Juanto, M. Miguez, J.

Vilche, A. Arvia, “Ellipsometry of Iron Hydrous Ox-

ide Layers Formed by Potentiodynamic Techniques,”

Thin Solid Films 233 (1993): pp. 74-76.

2. J. Hilfiker, R. Synowicki, J. Hale, C. Bungay,

“Spectroscopic Ellipsometry for Data Storage Appli-

cations,” Datatech (1998).

3. F. Kong, F. McLarnon, “Spectroscopic

Ellipsometry of Lithium/Polymer Electrolyte Inter-

faces,” J. Power Sources 89 (2000): pp.180-189.

4. B. Erne, F. Ozanam, M. Stchakovsky, D.

Vanmaekelbergh, J. Chazaluiel, “GaAs/H2O

2 Electro-

chemical Interface Studied In-Situ by Infrared Spec-

troscopy and Ultraviolet-Visible Ellipsometry—Part I:

Identification of Chemical Species,” J. Phys. Chem. B

104 (2000): pp. 5,961-5,973.

5. J. Harris, M. Bruening, “Electrochemical and In-

situ Investigation of the Permeability and Stability of

Layered Polyelectrolyte Films,” Langmuir 16 (2000):

pp. 2,006-2,013.

6. K. Chandrasekaran, M. Hill, W. Hamilton, H.

Nguyen, R. Collins, “Time Resolved Ellipsometric

Study of Electrochemically Deposited Photoresists,”

ACS Polym. Mat. Sci. & Eng. 74 (1996): pp. 381-382.

7. Y. Kim, D. Allara, R. Collins, K. Vedam, “Real-

Time Spectroscopic Ellipsometry Study of the Electro-

chemical Deposition of Polypyrrole Thin Films,” Thin

Solid Films 193/194 (1990): pp. 350-360.

8. M. Rigby, E.B. Smith, W.A. Wakehan, G.C.

Maitland, The Forces Between Molecules (Oxford,

U.K.: Clarendon, 1986).

3.5

3.0

2.5

2.0

1.5

1.0200 400 600 800 1,000

Wavelength (nm)

Inde

x of

Ref

ract

ion

n

Wavelength (nm)200 400 600 800 1,000

4.5

4.2

3.9

3.6

3.3

3.0

2.7

2.4

Extin

ctio

n C

oeff

icie

nt k

700

Film

Thi

ckne

ss (Å

)

0Time (min)

Substrate 1Substrate 2Substrate 3Substrate 4

Substrate 1Substrate 2Substrate 3Substrate 4

650

600

550500450

400350

10 20 30 40

50 ppmChemical B

40

Film

Gro

wth

Rat

e (Å

/min

)

30

20

10

0

–10

–200 20 40 60 80 100

Time (min)

50 ppmChemical A

molecular modeling and rules that de-termine energy as a function of intra-and intermolecular distances.3-4,6 Themodifications, represented mathemati-cally, include the following additions:• New harmonic bond stretch termfor iron-sulfur bonds• New harmonic bond angle termsfor iron-sulfur-iron and sulfur-iron-sul-fur angles• New nonbond off-diagonal term foriron-iron interactions• New van der Waals term for sulfur

The researchers also determined elec-trostatic charges on iron and sulfur for

To meet the challenge of pre-venting corrosion in sour gasenvironments, it is essential tobetter understand the corro-sion of iron in hydrogen sul-fide (H

2S) environments and

its inhibition. Previous research hasshown that measured corrosion ratesand the types of corrosion product lay-ers formed in sour gas environmentschange with H

2S concentration.1 For

example, at low concentrations, a pro-tective sulfide film forms on the ironsurface. At a slightly higher H

2S con-

centration, a nonprotective film forms,which is composed primarily ofmackinawite (Fe1+xS), an iron sulfidescale. One must study mackinawite tobetter understand corrosion in sour gasenvironments because its dissolutionrate governs the corrosion rate of car-bon steel (CS) in H

2S environments.2

Inhibitors, such as substitutedimidazolines and alkyl pyridine(C5H5N) quaternary amines, retardscale dissolution by binding to it andpreventing acidic attack of the scale.Thus, they are often used to controlcorrosion in sour gas systems. Re-searchers have used molecular model-ing to investigate the inhibition of CScorrosion in carbon dioxide (CO2) satu-rated brine solutions.3-6 They have alsoapplied theories of fracture mechanicsto molecular modeling to examine theonset of scale cracking.7

Taking into consideration the resultsof prior studies addressing H2S corrosionand its inhibition and working with apreviously reported crystal structure formackinawite,8 Baker Petrolite research-ers introduced a new force field thataccurately describes the mineral. Theyalso studied the binding of water and aquarternary ammonium salt withmackinawite. This work advances theuse of molecular modeling techniquesin examining corrosion and corrosioninhibition in H2S environments.

New Force Field RepresentsIron-Sulfur Interactions

The force field developed in thestudy to model mackinawite is a modi-fication of a force field used by thecompany. The earlier work applied

Molecular Modelingof Mackinawite toStudy Corrosion andInhibition in SourGas EnvironmentsS. RAMACHANDRAN, M.B. WARD, AND K.A. BARTRIP, Baker Petrolite Corp.

Different types of iron sulfide and ironcarbonate (FeCO3) product layers form in

sour gas environments. Mackinawite (Fe1+xS) is animportant iron sulfide scale that forms during corrosionin a hydrogen sulfide (H2S) containing environment. Itsdissolution has been found to be the rate-determiningstep during steel corrosion in sour systems. This articlediscusses a study in which molecular modeling, amethod previously successful in revealing themechanism of corrosion inhibition in carbon dioxide(CO2) systems, was used to examine mackinawite tobetter understand corrosion inhibition in H2Senvironments.

charges obtained for mackinawite withcharges for other iron-containing crys-tal structures. Table 2 presents thecharges for 1-benzyl-2, 6 dimethyl-pyridinium chloride.

Matched Experimental andMinimized Values

The parameters of the nonbond vander Waals terms for iron-iron interactionswere chosen to match the iron crystalstructure, lattice energy, and C11 elasticconstant. Table 3 shows the match be-tween experimental values and the val-ues obtained from minimization with thenew force field. Ensuring that the valuesmatched verified that the new force fieldrepresented metallic iron as well as ironsulfide, which is important for modelinginhibitor interactions with bare metalsurfaces.

Table 4 shows the fit of the mini-mized mackinawite crystal structurewith the experimentally determinedcrystal structure.

Mackinawite Crystal andSurface Structure

corrosion product.9 As Figure 1 de-picts, sulfur atoms compose the outer-most atoms of the mackinawite struc-ture. Consequently, the energetics ofreactants and inhibitors binding withthe outermost sulfur atoms dominateboth dissolution and surface attack.

Figure 2 shows the spacing betweenouter sulfur atoms for mackinawite onthe 001 surface. Surface coverage de-pends upon the spacing of bindinggroups on the surface and the size andstructure of the binding group. Theboxes in the figure show the latticespacing of possible two-dimensionalperiodic surface cells containing one,two, or three surface sulfur atoms.Table 5 presents the areas covered ineach arrangement.

Footprints of MoleculesStudied for Binding withMackinawite

Figure 3 presents a top view of dif-ferent molecules studied for bindingwith the 001 surface of mackinawitealong with the dimensions of the esti-mated footprint of each molecule. Thedimensions are liberal estimates of thefootprints and serve as first approxima-tions of the space required on themackinawite surface for each molecule.

FIGURE 1

Minimized crystal structure of mackinawite.

FIGURE 2

Surface structure of the 001 plane ofmackinawite with outer sulfur atoms anddifferent periodic arrangements to bind inhibitormolecules.

FIGURE 3

Top view of molecules studied for binding to the mackinawitesurface with approximate dimensions of their footprints onthe surface.

TABLE 1

CHARGES OF DIFFERENT SITES IN IRON-CONTAININGCRYSTAL STRUCTURES

Mackinawite Hematite Magnetite SideriteSite/Structure (Fe1+xS) (Fe2O3) (Fe3O4) (FeCO3)Fe2+ 0.82635 e No site 1.188 e 1.661 eFe3+ No site 1.317 e 1.245 e No siteS2– –0.82635 e No site No site No siteO2– No site –0.878 e –0.920 e No siteC in CO3

2– No site No site No site 0.490 eO in CO3

2– No site No site No site –0.717 e

the mackinawite crystal and chargesfor 1-benzyl-2, 6 dimethyl-pyridiniumchloride, one form of a quaternary am-monium pyridine salt studied in thisresearch. Functional groups followedthe convention of remaining electri-cally neutral. Table 1 compares the

TABLE 2

CHARGES FOR 1-BENZYL-2, 6DIMETHYLPYRIDINIUMCHLORIDE

Atom Charge (e)Cl –0.50N –0.34C attached to N 0.28C in (CH2) attached to N –0.008All H 0.144C (CH) –0.144C (CH3) –0.432

Figure 1 illustrates theminimized mackinawitecrystal structure, which con-sists of two-dimensionalsheets of iron and sulfur at-oms bound to each other.The box in Figure 1 showsthe lattice dimensions.

The most stable structureforms when the least ener-getic bonds break; therefore,the force field suggests thatthe 001 surface is moststable because longer, less-

energetic bonds break when formingthe 001 surface while shorter, stron-ger bonds remain undisturbed. Inde-pendently, other observers using x-raydiffraction have found a predominanceof 001 surfaces of mackinawite on the

001

S

FeFe

S

010000

S2–

5.20

7.367.36

3.68

3.68

12.75

11.30

11.30

8.034.75

4.81

3.41

H2O NH4Cl 1-benzyl-2.6 dimethylpyridinium chloride

Binding of Water withMackinawite

Water interacting with themackinawite surface provides com-plete coverage, with two molecules ofwater per unit cell. Figure 4 shows theminimized structure. The water mol-ecule closest to mackinawite has itsnegatively charged oxygen atom nearthe iron atoms of mackinawite at dis-tances of 2.59 and 2.50 Å. Also, its posi-tively charged hydrogen atoms areclose to the negatively charged sulfuratoms of mackinawite at distances of2.46 and 2.49 Å. The positive hydro-gen atoms of the water moleculeslightly further away from mackinawiteare located at a distance of 2.75 Å.

FIGURE 4

Minimized crystal structure of mackinawite with twomolecules of water.

FIGURE 5

Least-energy structure of 1-benzyl-2, 6 dimethylpyridiniumchloride on the 001 surface of mackinawite.

Binding of 1-Benzyl-2, 6 Dimethylpyrid-inium Chloride withMackinawite

Figure 5 illustrates thelowest energy structure ob-tained through annealed dy-namics, revealing that thepyridine ring of 1-benzyl-2, 6dimethylpyridinium chlo-ride does not follow a flatorientation with the 001mackinawite surface. In-stead, the ring adopts a 70-degree angle with the sur-face. The most favorablecorrosion-inhibition interac-tions are those in which thehydrogen atoms of the pyri-dine ring bind with the sur-face sulfur atoms ofmackinawite as shown inFigure 5.

ConclusionsThe research team devel-

oped a new force field to notonly model mackinawite, butalso to understand its stabil-ity. The ability to reproduceboth the experimental crystalstructure of mackinawite andthe pure iron crystal showsthat the force field repre-sents iron-sulfur interactionswell and may ultimately beused to explore other ironsulfides and inhibitors con-taining sulfur. Although thebinding of quaternary ammo-nium salts was initially stud-ied with 1-benzyl-2, 6dimethylpyridinium chlo-ride, the work is in a prelimi-nary stage and awaits furtherexploration of different con-

TABLE 3

EXPERIMENTAL ANDMINIMIZED VALUES FORTHE IRON CRYSTAL

Experimental MinimizedLattice Parametersa = b = c 2.8664 Å 2.8664 ÅLattice energy(kcal/mol) 94 94C11 elasticConstant (GPa) 237 239

TABLE 4

EXPERIMENTAL ANDMINIMIZED VALUESFOR MACKINAWITE

Experimental MinimizedLattice Parametersa = b 3.68 Å 3.68 Åc 5.05 Å 5.05 ÅInternal geometryFe-S 2.23 Å 2.23 ÅFe-S-Fe 71.3° 71.3°S-Fe-S 109.9° 109.8°

TABLE 5

AREA OF COVERAGE OF EACHPERIODIC ARRANGEMENTSHOWN IN FIGURE 2

Number ofSurface

Dimensions Sulfur Atoms Area Å2

3.68 Å x 3.68 Å 1 13.545.20 Å x 5.20 Å 2 27.063.68 Å x 7.36 Å 3 27.087.36 Å x 7.36 Å 4 54.17

3. S. Ramachandran, V. Jovancicevic, Corrosion55, 3 (1999): p. 259.

4. S. Ramachandran, V. Jovancicevic, M.B. Ward,“Understanding Interactions Between Corrosion In-hibitors and Iron Carbonate Films Using MolecularModeling,” CORROSION/99, paper no. 7 (Houston,TX: NACE, 1999).

5. S. Ramachandran, B.L. Tsai, M. Blanco, H. Chen,Y. Tang, W.A. Goddard III, Langmuir 12, 26 (1996):p. 6,419.

6. S. Ramachandran, B.L. Tsai, M. Blanco, H. Chen,Y. Tang, W.A. Goddard III, J. Phys. Chem. A 101, 1(1997): p. 83.

7. S. Ramachandran, S. Campbell, M.B. Ward, Cor-rosion 57, 6 (2001): p. 508.

8. R.A. Berner, Science 137 (1962): p. 669.9. D.W. Shoesmith, P. Taylor, M. Grant Bailey, and

D.G. Owen, J. Electrochem. Soc. 127 (1980): p. 1,007.

formations and molecules with differ-ent structures. The development of anaccurate force field for mackinawite isthe first step toward research involvingbinding energy studies, cohesive en-ergy studies, and elastic modulii stud-ies with inhibitors—all aimed at pre-venting corrosion in sour gasenvironments.

References1. J.B. Sardisco, W.B. Wright, E.C. Greco, Corro-

sion 19 (1963): p. 354.2. T.A. Ramanaryanan, S.N. Smith, Corrosion 46

(1990): p. 66.

001

000 100 010

2.752.49

2.46

2.502.50

HS

Fe

000010