992 hic-ssc-sohic nace test

CORROSION–Vol. 55, No. 11 1101

CORROSION ENGINEERING SECTION

0010-9312/99/000243/$5.00+$0.50/0© 1999, NACE International

Submitted for publication March 1999; in revised form, June1999. Presented as paper no. 430 at CORROSION/99, April 1999,San Antonio, TX.

* Fontana Corrosion Center, The Ohio State University, Columbus,OH 43210. Present address: Saudi Aramco, Consulting ServicesDepartment, E-7640, EOB, PO Box 12198, Dhahran 31311, SaudiArabia.

** Fontana Corrosion Center, The Ohio State University, Columbus,OH 43210.

*** CC Technologies Laboratories, Inc., Dublin, OH 43016.(1) UNS numbers are listed in Metals and Alloys in the Unified

Numbering System, published by the Society of AutomotiveEngineers (SAE) and cosponsored by ASTM.

Susceptibility of Conventional Pressure VesselSteel to Hydrogen-Induced Cracking and Stress-Oriented Hydrogen-Induced Cracking in HydrogenSulfide-Containing Diglycolamine Solutions

M.A. Al-Anezi,* G.S. Frankel,** and A.K. Agrawal***

ABSTRACT

Hydrogen-induced cracking (HIC) and stress-orientedhydrogen-induced cracking (SOHIC) tests were conductedon a conventional type A516-70 (UNS K02700) pressurevessel steel exposed to hydrogen sulfide (H2S)-containingdiglycolamine (DGA) gas-sweetening environments. Base-lineHIC and SOHIC tests were conducted in NACE TM0284-96Solution A. For the SOHIC tests, four-point double-beamspecimens were stressed to 60%, 80%, or 100% of the yieldstrength of the steel to study the effect of applied stress. Testconditions included solutions containing 70 wt% DGA and500 ppm H2S to ≥ 0.45 M-H2S/M-DGA and temperatures of25°C, 45°C, and 80°C. Corrosion rates of the steel were cal-culated from weight loss of the HIC specimens to comparethe severity of the test environment with the actual serviceenvironment. Cracks were characterized in terms of cracklength ratio (CLR), crack thickness ratio (CTR), and crack sen-sitivity ratio (CSR). Results indicated that conventional typeA516-70 pressure vessel steel was not susceptible to HIC orSOHIC in various H2S-containing DGA solutions at the tem-peratures studied.

KEY WORDS: hydrogen sulfide, hydrogen-induced cracking,stress-oriented hydrogen-induced cracking, diglycolamine,pressure vessel steel

INTRODUCTION

Various types of cracking associated with hydrogenare seen in pressure vessel steel such as typeA516-70 (UNS K02700)(1) exposed to a wet-sour envi-ronment. Hydrogen-induced cracking (HIC), sulfidestress cracking (SSC), and stress-oriented hydrogen-induced cracking (SOHIC) are schematicallyrepresented in Figure 1 and are summarized below.

HIC occurs in low-strength steel (typically< 80 ksi [550 MPa] such as type 516-70) duringexposure to wet hydrogen sulfide (H2S) environments.It mainly occurs because of the buildup of internalpressure caused by the accumulation of molecularhydrogen at nonmetallic inclusions and other trapsites. HIC includes blisters near the surface of thesteel plate and internal cracks that propagate in astepwise or straight mode.1-2 HIC results in cracksthat are created parallel to the rolling direction ofthe steel plate without the effect of external appliedstress.

SSC is hydrogen embrittlement cracking thatoccurs in high-strength and/or high-hardness steelsunder the influence of an external tensile stress andis caused by absorption of hydrogen from wet H2Scorrosion.1 According to NACE standard MR0175, thesteel has to have a hardness level > 22 Rockwell Chardness (HRC) and to be exposed to wet-sour envi-ronments containing 0.05 psia partial pressure of

1102 CORROSION–NOVEMBER 1999


H2S for SSC to occur.3-4 This hardness level canbe found in high-strength steel or in a hard heat-affected zone (HAZ) near a weld. The crack mode istypically transgranular, and SSC cracks initiatingat hard HAZ usually stop when they reach the softbase metal.1

SOHIC is a special form of HIC that occurs inlow-strength steels under the action of externalstress. Like HIC, SOHIC occurs in soft steels, butresidual or applied stress and usually a stress raiserare required. In actual service, the stress raiser isoften the tip of a SSC crack that occurs in the hardHAZ of a weld metal and terminates in the soft region(Figure 1).5 SOHIC is characterized by the formationof a stacked array of cracks. Each individual crackis HIC that is oriented parallel to the rolling direc-tion, but the stack is perpendicular to the appliedstress associated with the stress raiser. The plasticstrain field around the notch provides a preferredlocation of HIC, producing the stacked array. Linkageof the HIC cracks of the SOHIC eventually will occurby small cracks that are perpendicular to the stressdirection.

Type A516-70 pressure vessel steel commonlyhas been used for fabricating process equipment innatural gas plants that use diglycolamine (DGA) as asweetening agent. Steel alloyed for inclusion shapecontrol, which renders it resistant to HIC, has beenconsidered for the equipment. Cost savings can re-sult from the use of conventional steel. The objectiveof this research was to identify the environmentalconditions under which conventional steel can beused safely.

The NACE TM-0284 standard has been usedsince 1984 to test for the susceptibility of pipelineand pressure vessel steels to HIC.6 The test methodinvolves exposing unstressed steel specimens toeither a 5% sodium chloride (NaCl) + 0.5% acetic acidsolution (CH3COOH) or an artificial seawater solu-tion.6 The test solution has to be deaerated witheither nitrogen or argon and then saturated with H2S.The standard does not represent the actual wet-sourservice conditions nor state any acceptance or rejec-

tion criteria.6 It is used mainly for comparison of thedegree of susceptibility to HIC for different steels. Amaximum crack length ratio (CLR) of 15% has beenused by some companies in the industry to qualifysteel for use of pipelines in wet-sour service applica-tions.6-7 Merrick and Bullen reported that there hasnot been any SOHIC failure of pressure vessel steelsthat had a CLR value < 15%.8 However, recentevidence suggests that SOHIC can occur in cleansteels.9

Cayard and Kane have classified pressure vesselsteels into four different types according to heattreatment, sulfur content, and susceptibility toHIC.10-11 Conventional steels commercially are pro-duced in normalized or hot-rolled conditions, andcontain > 0.010 wt% S. Low-sulfur conventionalsteels contain 0.003% S to 0.010% S. These twotypes of steels are very susceptible to HIC (e.g., typeA516-70).11-12 The ultra-low sulfur advanced steelshave < 0.002% S and are rather resistant to HIC,especially when inclusion shape control is practiced.They are fabricated by the latest steel manufacturingtechnologies such as thermomechanical control pro-cessing (TMCP) or accelerated cooling techniques.10-11

They have very low carbon content and form ferrite/bainite homogenous microstructures with very lim-ited to no banding.10-11 So-called HIC-resistant steelsare certified only by the manufacturer as “HICtested”. They are actually conventional steels (e.g.,A516-70) that are fabricated in the normalized condi-tion but contain < 0.002% S and Ca addition. Thesesteels may not be immune totally to HIC and couldcrack in a severe wet-sour environment.10-11

Selection of the safest and most economical steelto be used in H2S-containing DGA service is critical.Field experience has proven that H2S-containing DGAservice is not an aggressive HIC environment. Thenotion that DGA might inhibit the aggressive natureof H2S should not be surprising since DGA acts as asweetening agent by binding to H2S. Fully killed typeA516-70 steel is susceptible to HIC in NACETM0284-96 Solution A, which is used to qualifysteels for use in sour service. This steel should bereevaluated for use in the milder DGA service by test-ing in the actual service environment. If this steel isfound adequate for DGA service, approximately 30%to 60% of the total capital cost of a gas plant couldbe saved by avoiding the use of more expensive HIC-resistant steel.8,13

In the present study, fully killed type A516-70steel in the normalized condition with a sulfur con-tent of 0.014 wt% was tested. Specimens wereexposed to a mixture of 70 wt% DGA + 30 wt% H2Oat different temperatures and H2S concentrations.Effects of temperature on general corrosion of steeland chemical instability of DGA were noticed at hightemperature. SOHIC tests were performed at 60%,80%, and 100% of the yield strength (YS) of the steel.

FIGURE 1. Schematic of HIC, SSC, and SOHIC.



EXPERIMENTAL PROCEDURES

A summary of the test matrix for the HIC andSOHIC specimens tested in NACE TM0284-96 Solu-tion A and DGA solutions is given in Table 1. Fifteendifferent conditions were examined including nineSOHIC and six HIC tests. All conditions were dupli-cated at least once. The specimens that were testedin the TM0284-96 Solution A represent the base-linefor HIC and SOHIC tests. Results of the specimenstested in the DGA solutions were used to evaluatethe steel for field service. Test variables in the DGAsolutions spanned a wide range of conditions, andthe most aggressive conditions were much moresevere than service requirements. As this investiga-tion proceeded, it became clear that very aggressivetest conditions would be needed to generate cracks,and the originally planned test matrix was modifiedto include more severe combinations of temperature,stress, and H2S loading.

Pressure vessel steel HIC and SOHIC specimenswere obtained from a commercial vendor. The compo-sition in wt% was 0.23% C, 0.014% S, 0.20% Si,1.05% Mn, 0.007% P, 0.035% Al, balance Fe. Thecomposition and mechanical properties (YS: 65 ksi[450 MPa], tensile strength: 81 ksi [560 MPa], andelongation: 21%) fell within the specification for typeA 516-70 standard pressure vessel plates. Since thesulfur concentration was > 0.01, it was considered tobe high-sulfur steel. The measured hardness of thetested steel was 82 HRB. The microstructure wasferrite and pearlite, which is typical for normalized

steel. Figure 2 shows a typical elongated MnS inclu-sion in the steel microstructure. Gaps could beobserved between the matrix and some manganoussulfide (MnS) inclusions. Such gaps were strong trapsites for hydrogen.

HIC coupons were 100 mm by 20 mm by 16 mm.These dimensions of the HIC specimens are specifiedin NACE TM0284-96, although the specified thick-ness of the coupons depends upon thickness of theplate material. All six surfaces of each specimen wereabraded with 320-grit paper to provide a reproduc-ible surface finish.

There is no standard test for SOHIC, but theprotocol set forth by Cayard, et al., was adopted.14

A pair of notched rectangular beams bolted togethermade a double-beam (DB) SOHIC couple (Figure 3).The beams were machined to dimensions describedin a paper by Cayard, et al.14 The length, width, andthickness of each DB beam were 30.5 cm, 3.8 cm,and 1.6 cm, respectively. Beams were oriented suchthat their lengths were parallel to the rolling direc-tion of the plate. Electrodischarge machining (EDM)was used to machine a notch across the tension sur-face of each beam. The notch was perpendicular tothe applied stress and rolling direction. This orienta-tion may be less susceptible to SOHIC than theperpendicular orientation with stresses perpendicu-lar to the rolling direction. The notch radii and depthsranged from 0.12 mm to 0.14 mm and 2.12 mm to2.24 mm, respectively, as reported by the vendor.

Solution A in the NACE TM-0284-96 standardwas used to test HIC and SOHIC specimens to estab-

TABLE 1Experimental Matrix for HIC and SOHIC Tests

in NACE TM0284-96 Solution A and H2S/DGA, Corrosion Rate of HIC Samples,and Crack Ratios of Samples that Exhibited Cracking. Corrosion Rates of SOHIC Samples were not Determined.

Average Average Average AverageCorrosion Rate ± CLR ± CTR ± CSR ±

Applied Standard Standard Standard StandardConcentration T t Stress Deviation Deviation Deviation Deviation

Solution of H2S in DGA (°C) (h) Test Type (% YS) (mpy) (%) (%) (%)

TM0284 N/A(A) 25 168 SOHIC 60 N/A 71.9 + 21.3 16.6 ± 4.0 1.2 ± 0.4TM0284 N/A 25 96 SOHIC 80(B) N/A 29.3 ± 11.3 6.9 ± 2.5 0.2 ± 0.1TM0284 N/A 25 90 SOHIC 100(B) N/A 43.6 ± 16.0 13.8 ± 2.0 0.5 ± 0.2TM0284 N/A 25 96 HIC N/A 32.2 ± 0.6 49.5 ± 23.4 7.0 ± 3.5 0.5 ± 0.5TM0284 N/A 45 96 HIC N/A 27.3 ± 2.7 6.7 ± 12.7 0.4 ± 0.7 0.1 ± 0.2

DGA 500 ppm 45 168 SOHIC 100 N/A 0 0 0DGA 0.64 M/M 45 168 SOHIC 100 N/A 0 0 0DGA 0.45 M/M 80 168 SOHIC 60 N/A 0 0 0DGA 0.85 M/M 80 168 SOHIC 80 N/A 0.9 ± 1.8 0.4 ± 0.8 0.02 ± 0.03DGA 0.46 M/M 80 168 SOHIC 100 N/A 0 0 0DGA 500 ppm 90 168 SOHIC 100 N/A 0 0 0DGA 0.50 M/M 25 168 HIC N/A 0.14 ± 0.04 0 0 0DGA 500 ppm 45 168 HIC N/A 0.15 ± 0.01 0 0 0DGA 0.64 M/M 45 168 HIC N/A 0.50 ± 0.05 0 0 0DGA 0.50 M/M 80 168 HIC N/A 14.9 ± 0.4 0 0 0

(A) Not applicable. (B) Bolts failed in test.



lish a base-line for cracking susceptibility of typeA516-70. This solution consists of 5 wt% NaCl +0.5% glacial CH3COOH in deionized water. The initialand final solution pH values were 2.8 and 3.7,respectively. This solution was saturated with H2S,producing high levels of hydrogen charging into thepressure vessel steel. NACE TM0284-96 requires thatthe ratio of the volume of the solution to the totalsurface area of the test specimens be ≥ 3 mL/cm2.The standard solution required to immerse the DBspecimens fully was 4 L for the test cell (kettle) used,so the ratio of the volume of the standard TM0284-96Solution A to the exposed area of the two SOHICspecimens was 5.85 mL/cm2. The volume of solutionrequired to immerse three HIC specimens was 2 L.The ratio of solution volume to the exposed surfacearea was 8.50 mL/cm2. Test samples were placed inthe test cell and then the argon-deaerated solutionwas introduced. Saturation of the solution with H2Swas done in the kettle at a rate of 200 mL/min for1 h/L of the solution. The test cell was airtight andwas maintained at a positive pressure by keeping a

continuous flow of H2S to prevent any oxygen ingressduring testing. The test cell was maintained at tem-peratures of ≈ 25°C or 45°C.

Chemically pure DGA was diluted with deionizedH2O to make 70 wt% DGA + 30 wt% H2O. The solu-tion was prepared and argon-deaerated in a 5-Lcarboy. Saturation of the DGA solution with H2S, toobtain 0.45 M-H2S/M-DGA or higher was carriedout at a very slow flow rate. This was followed byrepeated shaking and weighing of the carboy tomake sure that the required H2S concentration wasachieved. An aliquot of 0.45 M H2S/M DGA solutionwas diluted in DGA + H2O solution to obtain500 ppm H2S in DGA solution. H2S concentrationin DGA was measured at room temperature and nobubbling of H2S was performed on DGA solutionduring the test.

DB SOHIC specimens were stressed by applyinga deflection value based on:14

d =2Sa 3L – 4a

3Et (1)

where d is deflection, S is desired outer fiber stress, ais the distance between the spacer and bolt centerlines (108 mm), t is thickness of each specimen(16 mm), E is modulus of elasticity (2.9 x 107 psi or200 GPa for type A516-70), and L is the distancebetween bolt center lines (267 mm). SOHIC sampleswere tested at 60%, 80%, and 100% YS (which is65 ksi or 450 MPa ). DB specimens were cleaned bymethanol (CH3OH) and acetone (CH3COCH3) beforeand after deflection was applied. Specimens weredeflected and then immediately placed in the cell fortesting. Any specimen for which the desired loadinglevel was exceeded accidentally was rejected.Washers, bolts, and spacers used in the SOHICspecimens were made of carbon steel to avoid anygalvanic corrosion.

All experiments in H2S-containing solutions wereperformed in a special laboratory that is properlyequipped with the requisite safety features.

The tested HIC specimens were sectioned inaccordance with the procedure described in NACETM0284-96. Each HIC test generated three speci-mens, and each SOHIC test generated two beams.Cayard, et al., recommended that two sections fromeach beam of the tested SOHIC specimen shouldbe analyzed.14

The degree of cracking in each section was calcu-lated in terms of CLR, crack thickness ratio (CTR),and crack sensitivity ratio (CSR). These calculationswere performed per NACE TM0284-96 standard pro-cedure. CLR is the sum of the crack length of eacharray divided by the width of the section and multi-plied by 100%. CTR is the sum of the crack thicknessof each crack array divided by the thickness of the

FIGURE 2. SEM micrograph of a MnS inclusion in the type A516-70steel. Note that the sample is rotated such that the rolling direction isnot horizontal, but along the axis of the inclusion.

FIGURE 3. Schematic of the double-beam samples used for theSOHIC tests.



section and multiplied by 100%. The CSR is the sumof the effective cracked area of each crack arraydivided by the area of the section and multiplied by100%. Cracks that were separated by < 0.5 mm wereconsidered single cracks. NACE TM0284-96 crackmeasurement procedure was valid for HIC andSOHIC, but it does not specify the fail or pass values.Crack measurements were performed using an auto-mated image analysis system. Ninety sections wereexamined and evaluated for cracks.

Further details about this work were recordedelsewhere.15

RESULTS

Average corrosion rates of the HIC specimensexposed to NACE and DGA solutions are shown inTable 1. The corrosion rate in standard NACETM0284-96 Solution A, at 25°C, was 32.2 mpy. At45°C in the same solution, the corrosion rate waslower, 27.3 mpy. The corrosion rate of specimens ex-posed to H2S-containing DGA solutions was very lowexcept for the case of 0.50 M-H2S/M-DGA at 80°C,which exhibited a corrosion rate of 14.9 mpy. Thishigh corrosion rate, which is similar in magnitude tothat in the NACE solution, was accompanied by achange in DGA appearance. This solution changedfrom yellow to black during testing as the tempera-ture increased past 70°C. This change in color alsowas observed for the SOHIC tests in the same solu-tion. The corrosion rate of the SOHIC beams tested inDGA solution containing only 500 ppm of H2S at90°C was not measured, but no change in the colorof DGA was observed. The change resulted from com-bined effects of temperature and H2S.

Figure 4 is a micrograph that shows stepwisecracking of a section removed from a HIC sample ex-posed to the standard NACE TM0284-96 Solution Aat 25°C for 96 h. The CLR, CTR, and CSR values ofthe nine sections removed from the same three HICspecimens are shown in Table 1. CLR values rangedfrom 28.4% to 104.2% with an average of 49.5%. Thehigh CLR value indicated that the tested, fully killed,type A516-70 steel was susceptible to HIC in NACETM0284-96 Solution A as expected. Table 1 showsthat the crack ratios dropped sharply when thetemperature of the standard NACE solution was in-creased to 45°C. Only four of the nine sectionsexamined from specimens tested in this condition ex-hibited cracking, so the standard deviation was large.CLR values at 45°C in NACE TM0284-96 Solution Aranged from 0% to 36.8% with an average of 6.7%.Figure 5 is a micrograph that shows stepwise crack-ing of a section removed from a HIC sample exposedto NACE solution at 45°C.

None of the metallographic sections from theHIC specimens tested in H2S-containing DGA solu-tions showed any cracking. The tested conditions

included temperatures ranging from 25°C to 80°Cand 500 ppm H2S to 0.64 M-H2S/M-DGA.

Metallographic examinations indicated that allDB SOHIC specimens tested in standard NACETM0284-96 Solution A exhibited various degrees ofcracking under the notch. Stacking of internal blis-ters under the notch was observed in all SOHICspecimens tested at 60%, 80%, and 100% YS. TheSOHIC specimens that were stressed up to 60% ofthe yield strength for 168 h had higher crack ratiosthan the specimens stressed to 80% and 100% YS.This is believed to be because the bolts on the SOHICspecimens that were stressed up to 100% and 80%YS failed after 90 h and 96 h of exposure, respec-tively. Figure 6 shows SOHIC cracks that developedat the notch of a SOHIC specimen tested at 60% YS.

FIGURE 4. Photomicrograph of stepwise cracking of a HIC specimenexposed to NACE TM0284-96 Solution A for 96 h at 25°C, unetched.

FIGURE 5. Photomicrograph of stepwise cracking of a HIC specimenexposed to NACE TM0284-96 Solution A for 96 h at 45°C, unetched.



The CLR for the SOHIC beams tested at 60% YSranged from 56.5% to 101.7%, with an average of71.9%. The CLR of the DB specimen tested at 80%YS ranged between 14.0% and 40.7%, with an aver-age of 29.3%. The CLR of the DB specimen tested at100% YS ranged from 26.8% to 65.3%, with an aver-age of 43.6 %.

SOHIC specimens tested in DGA solutions attemperatures < 80°C with H2S concentrations up to0.64 M-H2S/M-DGA, and loaded at stresses rangingfrom 60% to 100% YS showed no indication ofSOHIC. One beam exposed to 0.85 M-H2S/M-DGA at

a test temperature of 80°C and stressed at 80% YSshowed cracking ~ 15.64 mm away from the EDMnotch (Figure 7). The ends of this crack bent awayfrom the rolling direction, similar to the cracks foundin SOHIC tests in the NACE TM0284-96 Solution A,suggesting that it was SOHIC. The crack array was0.36 mm below the surface of the beam and had alength and width of 0.92 mm and 0.28 mm, respec-tively. The CLR of this section was 3.5%. No crackingwas seen in the other three sections for samplestested in this condition, so the average CLR given inTable 1 was 0.9%, and the standard deviation waslarge. Recall that HIC specimens exposed to the satu-rated H2S-containing DGA solution at 80°C exhibiteda high corrosion rate.

An aliquot of the 0.85 M-H2S/M-DGA solutionafter the 80°C SOHIC test was sent for analysis ofpossible amine degradation. The analysis showedthat the concentration of the DGA solution was re-duced from 70 wt% to 64.1 wt%. The concentrationof H2O stayed the same at 30 wt%. The H2S concen-tration in the solution was 0.61 M-H2S/M-DGA. Theanalysis was not exhaustive, and more work isneeded to understand the change in the color of thesaturated DGA at high temperatures.

DISCUSSION

NACE TM0284-96 Solution A is a very corrosiveenvironment that has tremendous hydrogen chargingcapability at room temperature. The corrosion rateand CLR were very large for type A516-70 steel inthis solution at 25°C. The corrosion rate droppedslightly when the test temperature was increasedfrom 25°C to 45°C. This could have been caused by areduction in H2S concentration in the NACE testsolution with increased temperature. The effect of thetemperature increase on HIC was much stronger asthe average CLR of the tested specimens decreasedfrom 49.5% at 25°C to 6.7% at 45°C. Also, all ninemetallographic sections of specimens tested at 25°Cshowed extensive cracking, whereas five out of ninesections at 45°C exhibited no cracking at all. Therelationship between the increase in test temperatureand the reduction in the severity of HIC suggests thatthe hydrogen concentration in the steel was signifi-cantly reduced. The reduction in hydrogenconcentration was a result of the decrease in thecorrosion rate and H2S concentration at the highertemperature. It is also possible that a more protectiveiron sulfide scale formed at the higher test tempera-ture, but no analysis was performed. Theseobservations indicated that reduced cracking in anacidic environment containing no corrosion inhibi-tors can be achieved by increasing the servicetemperature, but not over 60°C or 80°C.

The DB samples stressed from 60% to 100% YSand immersed in NACE TM0284-96 Solution A exhib-

FIGURE 6. Photomicrograph showing stacking of SOHIC cracks atthe root of the EDM notch in a specimen tested at 60% YS in NACETM0284-96 Solution A for 168 h at 25°C, unetched. Arrow indicateslinking of stacked cracks.

FIGURE 7. Photomicrograph showing cracks developed at locationdistant from the EDM notch in a SOHIC specimen stressed at 80%YS and exposed to 0.85 M-H2S/M-DGA solution for 168 h at 80°C,unetched.



ited extensive SOHIC. Specimens stressed at 60% YShad higher CLR, CTR, and CSR values than thosestressed at either 80% or 100% because of prematurefailure of the bolts on the beams stressed at 80%and 100% YS. The array of cracks in all SOHIC speci-mens exposed to the NACE solution was perpendicu-lar to the applied stress. Each individual crack foundin the DB specimens was a HIC crack oriented in therolling direction. The plastic strain associated withthe stress field near the notch promoted hydrogenentry and formation and HIC growth. The strain fieldprovided a preferred location for HIC, producing astacked array.

Results of the base-line tests using NACETM0284-96 Solution A indicated that type A516-70steel was susceptible to HIC and SOHIC. This sup-ports the fact that fully killed steel contains verystrong trap sites for hydrogen, such as elongatedMnS inclusions, and to a lesser extent, aluminumoxide (Al2O3) stringers, which make the material verysusceptible to hydrogen cracking.16 The results areimportant because they indicate that the materialused in this study was susceptible to HIC andSOHIC, and any evidence of a lack of cracking inDGA solution was a real effect of the environment.

In contrast to the NACE solution, the H2S-containing DGA solution resulted in very low corro-sion rates and almost no cracking of type A516-70steel. This was strong evidence that DGA service isnot aggressive and that fully killed steel may be suit-able for service without inclusion shape control. Thequestion remains as to the severity of the test condi-tions relative to real service conditions. There wereseveral reasons why the test may be considered to bemore severe than service conditions. Before consider-ing that issue, however, the relatively high corrosionrate and observation of cracking in the one DGAsolution at high temperature with high-H2S loadingmust be addressed.

The corrosion rate of the steel at 80°C and0.5 M-H2S/M-DGA was 14.9 mpy. In actual serviceconditions, the typical corrosion rate of conventionalsteel has been reported to be 4.3 mpy.17 This indi-cates that this particular environment was muchmore severe than the actual service conditions. Thissolution turned dark, as did the solution in the0.85 M-H2S/M-DGA SOHIC test at 80°C, whichresulted in cracks in one section of one sample. It ispossible that the combinations of H2S concentrationand temperature in these tests were so severe thatthe corrosion rates were very high, and that thechange in the solution appearance was a result of thehigh dissolution rate. However, it is also possiblethat the DGA degraded at the high test temperature,thereby resulting in a more aggressive environment.Analysis of a sample from the SOHIC test found thatthe DGA concentration dropped from 70 wt% to64 w%, and the H2S concentration decreased to

0.64 M/M-DGA, probably as a result of heating tothe high test temperature. The H2O concentration inthe solution remained the same at 30 wt%. Giventhat the DGA concentration only decreased by asmall amount, it is likely that the aggressiveness ofthe solution was simply a result of the high tempera-ture and H2S concentration rather than DGAdegradation. Recall that the SOHIC solutions at 45°Cwith 0.45 M-H2S/M-DGA and at 90°C with 500 ppmH2S were not aggressive in that no cracking wasobserved, and the solutions did not turn black. Theaggressiveness of DGA solutions at high temperaturewith high H2S concentration clearly resulted in ahigh corrosion rate and cracking susceptibility ofsteel specimens. However, this observation was notrelevant to service because the test conditions wereso much more severe than actual service conditions.As mentioned above, the very aggressive test condi-tions were examined in an effort to generate crackssince no cracks formed in most DGA solutions. It willbe shown now that even the milder test conditionsthat did not result in high corrosion and crackingwere more severe than actual service conditions.

Seubert and Wallace simulated the actual serviceconditions in gas-sweetening plants.18 They showedthat the corrosion rate of conventional steel was≈ 4.7 mpy in 70% DGA + 30% H2O solution, with anacid gas loading of 0.30 M/M-DGA at 80°C. Further-more, the corrosion rate increased with increasingconcentration of DGA, at constant acid gas loadingvalue because the total amount of acid gas presentincreased. In actual service, the maximum gross acidgas (carbon dioxide [CO] and H2S) loading in richDGA is 0.4 M-acid-gas/M-DGA.19 The amount of H2Spresent in DGA depends on the CO2:H2S ratio. Thismeans that the maximum concentration of H2S inDGA will not reach 0.4 M/M because of the presenceof CO2 in natural gas streams. In this project, CO2 waseliminated from the solution so that the concentrationof H2S in the saturated DGA was much higher thanthat in actual service. It also was higher than that inthe NACE solution. The minimum concentration ofH2S in the saturated DGA solution was 0.45 M-H2S/M-DGA. This value corresponded to 1.0 ppm by105 ppm H2S in DGA and H2O solution, compared toa maximum of 2,100 ppm H2S in the NACE solution.

For SOHIC to occur, a stress raiser such as a tipof SSC in the hard HAZ usually initiates first.8 Previ-ous work proved that carbon steel of hardness> 22 HRC, which is susceptible to SSC as stated inNACE MR0175, did not crack by SOHIC in any acidgas-containing DGA solutions.3 However, the samesteel cracked in acid-gas-containing monoethanolamine (MEA) solution.3 The SOHIC tests in this in-vestigation were done with a purposely added notch,which assumed the presence of a stress raiser. Thiscondition might not have occurred in actual servicebecause of the absence of SSC.



SOHIC tests were performed at 60%, 80%, and100% YS. The ASME Pressure Vessel code, SectionVIII, Table WCS-23, allows type A516-70 to be sub-jected to primary stresses up to 46% of its specifiedminimum yield stress.20 The primary stress calcula-tion is based mainly on the hoop stress and theinternal pressure. The secondary stresses include thebending stresses from the weight of the vessel, windloading, and local stresses from piping attachment.Weld residual stresses can be high, however, thevessels are generally post-weld heat-treated for stressrelief. Other secondary stresses are small comparedto the hoop stress but could increase the total stress.Many materials that would pass the test at 46% YSmight fail in the actual service because of the accu-mulation of the factors described. Beams stressed upto 60% YS should represent the actual field stressconditions, but the 80% and 100% of YS are extremecases and much more severe than the worst loadingsituations.

An investigation performed by Kowaka, et al.,using samples with the edges coated to restricthydrogen entry, showed that as long as the hydrogenconcentration at the center of the specimen was≥ 90% of the surface hydrogen concentration, anycracks that were going to appear did appear.21 Thetest data indicated that testing beyond 96 h did notchange the ranking of steels and saturation withhydrogen would occur between 30 h and 60 h for25 mm thick specimens. Samples that did exhibitcracks at 48 h or 96 h simply showed longer andwider cracks after 192 h or 336 h. Their investigationconfirmed that steel that did not crack in 96 h alsoshowed no cracking even after 336 h. These findingssuggest that results of this study may be used topredict long-term performance of steel in DGAenvironments.

All tested specimens were immersed fully inNACE and DGA solutions, with all sides, includingthe edges, exposed to the solution. The characteristicdiffusion length during a 168-h test time could beestimated from (4Dt)1/2, where D is the diffusion coef-ficient of hydrogen in steel and t is the exposuretime. Assuming D = 10–6 cm2/s, this length is 1.6 cm,which is essentially equal the sample thickness of1.6 cm. This means that the sample was saturatedwith hydrogen by the end of the test. This conditionwas much more severe than actual service condi-tions, where only one side of the pressure vessel isexposed to the service environment and there is aconcentration gradient of hydrogen across the wall ofthe vessel from a high value at the inner surface tozero at the outer surface. Only the steel near the in-ner surface of a DGA contactor equilibrates with theservice environment and has the maximum possiblehydrogen concentration. This indicates that if thespecimens are not susceptible to cracking in H2S-containing DGA in 168 h exposure time, they will

probably not develop any new cracks even after manyyears of service.

Based on the gas industry purchase specifica-tions, any steel exhibiting > 15% CLR in NACETM0284-96 Solution A will be disqualified for use inwet-sour service.7 The CLR of the tested HIC speci-mens in NACE solution was 49.5%. Also, the CLR forthe tested SOHIC specimens at 60% YS was 71.9%.Therefore, based on the gas industry practice, thetested type A516-70 pressure vessel steel couldhave been rejected for use in any wet H2S-containingenvironment. However, it was shown that the condi-tions of this test were far more severe than thosefound in DGA service. The steel preformed well inDGA environments that were more severe than actualservice because of the high amine concentrationand H2S loading in the tested DGA solutions; thefull immersion of the tested specimens comparedto the one-sided exposure met in the actual fieldoperation; and the high applied stresses in theSOHIC tests. The corrosion of conventional steelused in service is also much less than the testedspecimens. Results of the tests suggest that thetested steel was not susceptible to either HIC orSOHIC at conditions more aggressive than theactual service environment.

This study showed that NACE TM0284-96 Solu-tion A is a very aggressive environment and does notrepresent actual gas plant service conditions usingDGA. Results of this project proved that even if thesteel was susceptible to HIC or SOHIC in the stan-dard solution, it might not fail in actual service. Also,results showed that H2S-containing DGA solutionwas not a severe sour service environment eventhough it contains a much higher H2S concentrationthan the NACE solution and the actual servicestreams. The change in behavior of this susceptiblesteel from high crack ratios in NACE solution to zeroin the DGA solutions is clear evidence that the DGAis not a severe HIC or SOHIC environment. Therefore,the tested, fully killed, conventional type A516-70pressure vessel steel is likely an adequate materialfor DGA contactors.

CONCLUSIONS

❖ Type A516-70 fully killed steel was tested in thestandard NACE TM0284-96 Solution A and DGA so-lutions with varying temperatures, applied stresses,and H2S loading. This steel may be adequate for DGAservice.❖ The steel exhibited a high corrosion rate and wasvery susceptible to HIC and SOHIC in the standardNACE TM0284-96 Solution A at 25°C, though thecorrosion rate and cracking susceptibility decreasedat 45°C.❖ In DGA solutions, corrosion rates were low and nocracking was observed for a wide range of tempera-



tures and H2S concentrations at 25°C. Only underconditions of high temperature and high H2S concen-tration were high corrosion rates observed. Evenunder these severe conditions, no cracking wasobserved in HIC samples and only one section ofSOHIC samples exhibited cracking.

ACKNOWLEDGMENTS

The authors acknowledge D. McIntyre for invalu-able input into this research. Helpful discussionswith G. Koch also are appreciated. This work wasfunded by Saudi Aramco.

REFERENCES

1. R.D. Merrick, “An Overview of Hydrogen Damage to Steel at LowTemperature,” MP 28 (1989): p. 53-55.

2. S. Deshimaru, O. Tanigawa, Y. Mishiro, “Ultralow Sulfur andCalcium-Treated A516 Grade 70 Steel Plate for Sour Service,”in Serviceability of Petroleum, Process, and Power Equipment(New York, NY: ASME, 1992), p. 155-162.

3. NACE Standard MR0175-98, “Standard Material Requirements:Sulfide Stress Cracking Resistant Metallic Materials for OilfieldEquipment” (Houston, TX: NACE, 1998), p. 1-34.

4. A. Brown, C.L. Jones, “Hydrogen-Induced Cracking in PipelineSteels,” Corrosion 40 (1984): p. 330-336.

5. R.D. Merrick, “Refinery Experience with Cracking in Wet H2SEnvironments,” MP 27 (1988): p. 30-36.

6. NACE Standard Test Method TM0284-96, “Evaluation of Pipe-line and Pressure Vessel Steels for Resistance to Hydrogen-Induced Cracking” (Houston, TX: NACE, 1997), p. 1-10.

7. “Materials System Specification for Sour, Wet Service Linepipe”(Dhahran, Saudi Arabia: Saudi ARAMCO, 1996), p. 1-17.

8. R.D. Merrick, M.L. Bullen, “Prevention of Cracking in Wet H2SEnvironments,” CORROSION/89, paper no. 1,634 (Houston,TX: NACE, 1989).

9. M.S. Cayard, R.D. Kane, L. Kaley, M. Prager, “Research Reporton Characterization and Monitoring of Cracking in Wet H2S Ser-vice,” API Publication 939, 10 (1994).

10. M.S. Cayard, R.D. Kane, “Characterization and Monitoring ofCracking of Steel Equipment in Wet H2S Service,” CORROSION/95, paper no. 329 (Houston, TX: NACE, 1995).

11. M.S. Cayard, R.D. Kane, Corrosion 53 (1997): p. 227-233.12. A.L. Cummings, F.C. Veatch, A.E. Keller, “Corrosion and Corro-

sion Control Methods in Amine Systems Containing H2S,”CORROSION/97, paper no. 341 (Houston, TX: NACE, 1997).

13. NACE International Task Group T-8-16, “Materials and Fabri-cation Practices for New Pressure Vessels Used in Wet H2SRefinery Service” (Houston, TX: NACE, 1994).

14. M.S. Cayard, R.D. Kane, M. Prager, “New Test Specimen andMethodology for Evaluation of Steels for Resistance to SOHIC,”CORROSION/97, paper no. 051 (Houston, TX: NACE, 1997).

15. M.A. Al-Anezi, “The Susceptibility of Conventional ASTM A516-70 to HIC and SOHIC in H2S-Containing DGA Environment,”(Master’s thesis, Ohio State University, 1998).

16. E.M. Moore, J.J. Warga, “Factors Influencing Hydrogen Crack-ing Sensitivity of Pipeline Steels,” in H2S Corrosion in Oil andGas Production — A Compilation of Classic Papers, eds., R.N.Tuttle, R.D. Kane (Houston, TX: NACE, 1981), p. 936-942.

17. Unpublished data, Saudi Aramco Corp.18. M.K. Seubert, G.D. Wallace, “Corrosion in DGA Gas Treating

Plants,” CORROSION/86, paper no. 622 (Houston, TX: NACE,1986).

19. “Diglycolamine Agent (DGA) Brand of 2-(2-aminoethoxy)ethanol,”Huntsman Corporation Technical Bulletin (Austin, TX: Hunts-man Corporation, 1995).

20. ASME Pressure Vessel Code, Section VIII (New York, NY: ASME,1995).

21. M. Kowaka, F. Terasaki, S. Nagata, A. Alkeda, “The Test Methodof Hydrogen-Induced Cracking of Rolled Steels under WetHydrogen Sulfide Environment,” Sumitomo Search 14 (1975):p. 36-85.

CORROSION RESEARCH CALENDAR

CORROSION is a technical research journal devoted to furthering the knowledge of corrosion science andengineering. Within that context, CORROSION accepts notices of calls for papers and upcoming research grants,meetings, symposia, and conferences. All pertinent information, including the date, time, location, and sponsorof an event should be sent as far in advance as possible to: Angela Jarrell, Managing Editor, CORROSION,PO Box 218340, Houston, TX 77218-8340. Notices that are not accompanied by the contributor’s name, daytimetelephone number, and complete address will not be considered for publication.

1999

November 12-18 — Society forProtective Coatings Annual Meeting —Houston, TX; Contact Dee Boyle, 412/281-2331.

* November 14-18 — 2nd InternationalConference on Processing Materials forProperties — San Francisco, CA; ContactAlexander Scott, Phone: 418/776-9000;Fax: 412/776-3770.

November 14-18 — SSPC99, TheIndustrial Protective CoatingsConference and Exhibit — Houston, TX;Contact Dee Boyle, 877/281-7772, ext.202.

November 21-24 — AustralasianCorrosion Association Corrosion andPrevention Conference — Sydney,Australia; Contact Sally Nugent, Phone:+03 9809 5266; Fax: +03 9809 5344.

* November 22-24 — NACE India Section,5th National Convention and CorrosionAwareness Day Celebration — NewDelhi, India; Contact A.S. Khanna,Phone: +91 22 5767891; E-mail:[email protected].

November 30-December 2 — Power-Gen International 1999 — New Orleans,LA; Contact Rick Conley, Phone: 918/831-9727; Fax: 918/831-9834.

* December 7-9 — 7th AnnualNew Orleans Offshore CorrosionConference — New Orleans, LA; ContactLinda Crosier, 504/561-4646.

2000

* January 6-7 — SIEO/NACE Symposium— Sun Valley, ID; Contact Jerry Cullum,208/375-1463.

* February 29-March 2 — NACE NorthernArea Western Conference — Saskatoon,SK, Canada; Contact Harvey Rea, 306/345-8419.

March 8-10 — PCE 2000, The AnnualConference and Exhibition forProtective and Marine Coating Work —Genoa, Italy; Contact Dave Malli, 412/431-8300, or +39 (0) 10 570 4948.

* March 26-31 — CORROSION/2000 —Orlando, FL; Contact NACE, 281/228-6200.

* Sponsored or cosponsored by NACEInternational.

992 hic-ssc-sohic nace test

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