NACE SP0296_2010

Standard Practice

Detection, Repair, and Mitigation of Cracking in Refinery Equipment in Wet H2S Environments

This NACE International standard represents a consensus of those individual members who have reviewed this document, its scope, and provisions. Its acceptance does not in any respect preclude anyone, whether he or she has adopted the standard or not, from manufacturing, marketing, purchasing, or using products, processes, or procedures not in conformance with this standard. Nothing contained in this NACE International standard is to be construed as granting any right, by implication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, or product covered by Letters Patent, or as indemnifying or protecting anyone against liability for infringement of Letters Patent. This standard represents minimum requirements and should in no way be interpreted as a restriction on the use of better procedures or materials. Neither is this standard intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this standard in specific instances. NACE International assumes no responsibility for the interpretation or use of this standard by other parties and accepts responsibility for only those official NACE International interpretations issued by NACE International in accordance with its governing procedures and policies which preclude the issuance of interpretations by individual volunteers. Users of this NACE International standard are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this standard prior to its use. This NACE International standard may not necessarily address all potential health and safety problems or environmental hazards associated with the use of materials, equipment, and/or operations detailed or referred to within this standard. Users of this NACE International standard are also responsible for establishing appropriate health, safety, and environmental protection practices, in consultation with appropriate regulatory authorities if necessary, to achieve compliance with any existing applicable regulatory requirements prior to the use of this standard. CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may be revised or withdrawn at any time in accordance with NACE technical committee procedures. NACE International requires that action be taken to reaffirm, revise, or withdraw this standard no later than five years from the date of initial publication and subsequently from the date of each reaffirmation or revision. The user is cautioned to obtain the latest edition. Purchasers of NACE International standards may receive current information on all standards and other NACE International publications by contacting the NACE International FirstService Department, 1440 South Creek Dr., Houston, Texas 77084-4906 (telephone +1 281-228-6200).

Revised 2010-03-13 Revised 2004-02-12

Reaffirmed 2000-09-13 Approved 1996-03-30

NACE International 1440 South Creek Drive

Houston, Texas 77084-4906 +1 281-228-6200

ISBN 1-57590-013-0

2010, NACE International

NACE SP0296-2010 (formerly RP0296-2004)

Item No. 21078

Copyright NACE International Provided by IHS under license with NACE

Not for ResaleNo reproduction or networking permitted without license from IHS

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Foreword

NACE International Task Group T-8-16, Cracking in Wet H2S Environments, was formed in 1988 to conduct an organized study on the incidence and mechanisms of cracking in pressure vessels operating in refinery wet hydrogen sulfide (H2S) environments. Specific objectives were to (a) define the nature and extent of the problem by means of an industry survey; (b) define mechanisms for the type of cracking found, to be accomplished primarily through a literature survey; (c) establish inspection guidelines for existing vessels; and (d) develop repair and mitigation guidelines for cracked vessels. Four work groups were formed to address these tasks. In 1990, a fifth work group was formed with a fifth objective, (e) to investigate material specifications and fabrication practices for new pressure vessels. This standard practice summarizes objectives (a), (c), and (d) listed above. A technical committee report (NACE Publication 8X294)1 was issued to address objective (b). Finally, objective (e) was handled by another technical committee report (NACE Publication 8X194).2 This standard is intended for use primarily by refinery corrosion and materials engineers and inspection, operations, and maintenance personnel. Information and guidance presented in this standard reflect the work of many individuals representing numerous companies worldwide. The titles and source information of the codes, specifications, and standards referred to or discussed in this standard are provided in Appendix A (nonmandatory) rather than listed in footnotes throughout the standard. Confining this information to one appendix should help readers who have any interest in further research. This standard was originally prepared in 1996 by former Task Group (TG) T-8-16, Cracking in Wet H2S Environments. It was reaffirmed in 2000 by Group Committee T-8, and revised in 2004 and 2010 by TG 268, Wet H2S Cracking in Petroleum Refinery Pressure Vessels. TG 268 revised this standard in 2010 to address a number of items raised by Specific Technology Group (STG) 34 members as well as to respond to revisions in other applicable NACE standards such as SP0472.3 The original emphasis of this standard was on pressure vessels, and this emphasis remains. However, with this revision, some limited information on piping has been included at the request of TG 268 members and other members of STG 34. TG 268 is administered by STG 34, Petroleum Refining and Gas Processing. This standard is issued by NACE International under the auspices of STG 34.

In NACE standards, the terms shall, must, should, and may are used in accordance with the definitions of these terms in the NACE Publications Style Manual. The terms shall and must are used to state a requirement, and are considered mandatory. The term should is used to state something good and is recommended, but is not considered mandatory. The term may is used to state something considered optional.

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ii NACE International

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NACE International Standard Practice

Detection, Repair, and Mitigation of Cracking in Refinery

Equipment in Wet H2S Environments

Contents 1. General ............................................................................................................................ 1 2. Mechanisms of Cracking ................................................................................................. 2 3. Inspection for Cracking ................................................................................................... 4 4. Repair of Cracked or Blistered Equipment .................................................................... 11 5. Mitigation Considerations for Operation ........................................................................ 14 References ........................................................................................................................ 15 Bibliography ...................................................................................................................... 16 Appendix A: Cited Codes, Specifications, and Standards ................................................ 17 Appendix B: Nature and Extent of ProblemResults from 1990 T-8-16a Survey ........... 19 Appendix C: Typical Cracks Found in Wet H2S Environments ......................................... 25 FIGURES Figure C1: SSC in HAZ of head-to-shell weld of FCCU absorber tower. The crack is on the ASTM A 516-70 shell side. The numbers in the photograph are Knoop hardness values. (nital etch) ................................................................................................................................ 25 Figure C2: Hydrogen blister in ASTM A 516-70 amine contactor/water wash tower. ...... 26 Figure C3(a): Hydrogen blisters on ID surface of amine contactor/water wash tower. ... 27 Figure C3(b): Cross-section of plate shown in upper photo illustrating HIC (stepwise cracking). ........................................................................................................................... 27 Figure C4: SOHIC in soft base metal extending from the tip of SSC in a hard HAZ of a repair weld in the shell of a primary absorber (deethanizer) column in an FCCU gas plant. The ASTM A 212-B steel shell was given PWHT at original fabrication, but the repair weld was not. (nital etch) ....................................................................................... 28 Figure C5: ASCC (carbonate cracking) of non-PWHT ASTM A 285-C steel shell of FCCU main fractionator overhead accumulator. Cracking was found near welds in the lower portion of vessel. ............................................................................................................... 29 TABLES Table B1: Overall Summary .................................................................................................. 19 Table B2: Cracking Reported by Company .............................................................................. 20 Table B3: Cracking by Process Unit ................................................................................. 20 Table B4: Cracking vs. Operating Temperature ............................................................... 21 Table B5: Cracking vs. H2S Concentration ....................................................................... 21 Table B6: Cracking vs. Steel Specification ........................................................................ 22 Table B7: Cracking vs. Steel Grade ................................................................................. 22 Table B8: Cracking vs. PWHT .................................................................................................. 22 Table B9: Cracking vs. Blistering History .................................................................................. 23 Table B10: Cracking vs. Weld Repairs...................................................................................... 23 Table B11: Depth of Cracking ........................................................................................... 23 Table B12: Crack Penetration ................................................................................................... 24 Table B13: Disposition of Cracked Pressure Vessels ....................................................... 24

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Section 1: General 1.1 This standard is intended to be a primary source of information on cracking in wet H2S petroleum refinery environments and provides guidelines on the detection, repair, and mitigation of cracking of existing carbon steel refinery equipment in wet H2S environments.

1.1.1 For the purposes of this standard, the term equipment refers to pressure vessels and piping made of carbon steel plate material. Refinery pressure vessels include items such as, but not limited to, columns or towers, heat exchangers, drums, reboilers, and separators. 1.1.2 Limited cracking has been noted in seamless piping; therefore, the information in this standard concentrates on longitudinally seam-welded pipe fabricated from plate. 1.1.3 Information on fabrication and inspection practices for new pressure vessels (never in service) is in NACE Publication 8X194.

1.2 For the purposes of this standard, the term wet H2S environments includes, but is not limited to, refinery process environments known to cause wet H2S cracking resulting from hydrogen entry into the steel, as defined in NACE Standard MR0103.4 Some environmental conditions known to cause wet H2S cracking are those containing an aqueous phase and:

(a) > 50 ppmw total sulfide content in the aqueous phase; or (b) 1 ppmw total sulfide content in the aqueous phase and pH < 4; or (c) 1 ppmw total sulfide content and 20 ppmw free cyanide in the aqueous phase and pH > 7.6; or (d) > 0.3 kPa absolute (0.05 psia) partial pressure H2S in the gas phase associated with the aqueous phase of a process.

However, the threshold total sulfide content in the aqueous phase required for cracking to occur has not been clearly established. Therefore, selective application of this standard may be appropriate when experience has indicated the presence of cracking or blistering in comparable service, regardless of total sulfide content. Alkaline environments such as alkanolamine solutions that contain sulfides and carbonate-containing sour waters also are included in the term wet H2S environments and thus are within the scope of this standard. Two forms of alkaline stress corrosion cracking (ASCC) are commonly found in these alkaline wet H2S environments. Amine stress corrosion cracking (commonly referred to as amine cracking) can occur in amine service under certain conditions, which are discussed in API(1) RP 945.5 Alkaline carbonate stress corrosion cracking (commonly referred to as carbonate cracking) can occur in alkaline carbonate-containing sour waters under certain conditions. NACE Publication 341086 describes where carbonate cracking has occurred in process equipment in petroleum refining service, the refining communitys current theory(ies) on the conditions and mitigation techniques that may have an impact on this type of cracking, and analytical and inspection techniques that have been used to address the issue. 1.3 Increased industry attention to the potential for cracking of carbon steel pressure vessels began in 1984 with the rupture of a monoethanolamine (MEA) absorber tower at a Lemont, Illinois refinery. The ensuing explosion and fire resulted in fatalities and extensive damage to the facility.7 In response to this incident, NACE Task Group T-8-14, Stress Corrosion Cracking of Carbon Steel in Amine Solutions, was formed in the fall of 1984. An industry survey to determine the nature and extent of the cracking problem was conducted by T-8-14. The results of the T-8-14 effort have been reported separately.8 (1)American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005-4070.



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1.4 In 1988, some new results on vessel inspections and the cracking found were reported to the industry.9 Among the significant findings was the observation that cracking problems were occurring in other wet H2S environments, not just in MEA. It was further reported that inspection techniques commonly used at the time (visual, liquid penetrant, and dry magnetic particle testing) were not sensitive enough to find these cracks. In response to this new information, NACE Task Group T-8-16, Cracking in Wet H2S Environments, was formed in the spring of 1988. Work Group T-8-16a conducted a survey of cracking experiences in wet H2S environments to better identify the extent of the problem. Appendix B (nonmandatory) summarizes the 1990 T-8-16a survey findings.

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Section 2: Mechanisms of Cracking 2.1 The objective of this section is to define the terms used to describe cracks that occur because of exposure to wet H2S environments and describe the mechanisms of cracking. Photographs of typical cracks found in wet H2S environments are shown in Appendix C (nonmandatory). 2.2 Definitions

2.2.1 Sulfide Stress Cracking (SSC): Cracking of a metal under the combined action of tensile stress and corrosion in the presence of water and H2S. SSC is a form of hydrogen stress cracking resulting from absorption of atomic hydrogen that is produced by the sulfide corrosion process on the metal surface. SSC usually occurs more readily in high-strength steels or in hard weld zones of steels. (See Figure C1.) 2.2.2 Hydrogen Blistering: The formation of subsurface planar cavities, called hydrogen blisters, in a metal resulting from excessive internal hydrogen pressure. Growth of near-surface blisters in low-strength metals usually results in surface bulges. Hydrogen blistering in steel involves the absorption and diffusion of atomic hydrogen produced on the metal surface by the sulfide corrosion process. The development of hydrogen blisters in steels is caused by the accumulation of hydrogen that recombines to form molecular hydrogen at internal sites in the metal. In its molecular state, hydrogen is too large to diffuse through the steel. Typical sites for the formation of hydrogen blisters are large nonmetallic inclusions, laminations, or other discontinuities in the steel. This differs from the voids, blisters, and cracking associated with high-temperature hydrogen attack. Hydrogen blistering is much more common in plate materials used for pressure vessels or longitudinally seam-welded pipe than in seamless pipe materials or forgings. (See Figure C2.) 2.2.3 Hydrogen-Induced Cracking (HIC): Stepwise internal cracks that connect adjacent hydrogen blisters on different planes in the metal, or to the metal surface (also known as stepwise cracking). No externally applied stress is needed for the formation of HIC. In steels, internal cracks that may develop (sometimes referred to as blister cracks) tend to link with other cracks by a transgranular plastic shear mechanism. This occurs because of internal pressure resulting from the accumulation of hydrogen. The link-up of these cracks on different planes in steels has been referred to as stepwise cracking to characterize the nature of the crack appearance. HIC is commonly found in steels with (a) high impurity levels that have a high density of large planar inclusions, and/or (b) regions of anomalous microstructure produced by segregation of impurities and alloying elements in the steel. Because HIC is caused by the same fundamental mechanism that causes hydrogen blistering, it also is much more common in plate materials used for pressure vessels or longitudinally seam-welded pipe than in seamless pipe materials or forgings. (See Figure C3.) 2.2.4 Stress-Oriented Hydrogen-Induced Cracking (SOHIC): Arrays of cracks, aligned nearly perpendicular to the stress, that are formed by the link-up of small HIC cracks in steel. Tensile stress (residual or applied) is required to produce SOHIC. SOHIC is commonly observed in the base metal adjacent to the heat-affected zone (HAZ) of a weld, oriented in the through-thickness direction. SOHIC may also be produced in susceptible steels at other high stress points such as from the tip of mechanical cracks and defects, or from the interaction of hydrogen blisters on different planes in the steel. (See Figure C4.) 2.2.5 Alkaline Stress Corrosion Cracking (ASCC): Cracking of a metal produced by the combined action of corrosion in an aqueous alkaline environment containing H2S, CO2, and tensile stress (residual or applied). The



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cracking is branched and intergranular in nature, and typically occurs in non-stress-relieved carbon steels. This form of cracking has often been referred to as carbonate cracking when associated with alkaline carbonate-containing sour waters, and as amine cracking when associated with alkanolamine treating solutions. NACE Publication 34108 discusses carbonate cracking and API RP 945 discusses amine cracking. ASCC may occur in both vessels and piping. (See Figure C5.)

2.3 Environmental Parameters Affecting Cracking 2.3.1 Several cracking mechanisms in wet H2S environments, including SSC, hydrogen blistering, HIC, and SOHIC, are related to the absorption and permeation of hydrogen in steels. The key variables involved in hydrogen permeation in steels are pH and the composition of the service environment. Typically, the hydrogen permeation flux in steels has been found to be minimal in neutral solutions (pH 7), with increasing flux at both lower and higher pH values. Corrosion at low-pH values is caused by H2S, whereas corrosion at high-pH values is caused by increasing concentrations of ammonium bisulfide (higher ammonia levels in H2S-dominated environments). 2.3.2 Hydrogen permeation has also been found to increase with increasing H2S partial pressure and with the presence of cyanide at alkaline pH levels. 2.3.3 SSC susceptibility increases with increasing H2S partial pressure. Based on investigations in oil and gas production environments, 0.3 kPa absolute (0.05 psia) and greater partial pressure of H2S in the presence of free water may produce SSC in susceptible steels. 2.3.4 ASCC can occur over a wide range of temperatures, but susceptibility appears to increase with increasing temperature. ASCC generally occurs in alkaline solutions with a pH in the 8 to 11 range, but its occurrence is highly dependent on the solution composition. This form of cracking has occurred in refinery services such as sour water streams and alkanolamine solutions containing H2S and CO2. ASCC is promoted by carbonates in the presence of weak sulfiding agents such as thiosulfate and thiocyanate. The mode of cracking involves local anodic dissolution of iron at breaks in the normally protective corrosion product film on the metal surface. Laboratory tests have shown that cracking occurs in a relatively narrow range of electrochemical potential that corresponds to a destabilized condition of the protective film. This film destabilization occurs at very low ratios of the sulfide concentration to the carbonate/bicarbonate concentration in the solution, and is possibly affected by a number of contaminants in the solution.10,11 This form of cracking is not directly associated with the above-mentioned forms of hydrogen-related damage. However, in sour waters and alkanolamine services containing H2S, cracking as a result of HIC, SOHIC, and SSC is possible, in addition to ASCC.

2.4 Material Parameters Affecting Cracking of Carbon Steels in Wet H2S Environments

2.4.1 Sulfide Stress Cracking

2.4.1.1 SSC has not generally been a concern in the carbon steel base metals typically used for pressure vessels and piping in refinery wet H2S environments because these steels generally have a tensile strength less than 620 MPa (90 ksi). 2.4.1.2 Carbon steel weld metal is generally considered resistant to SSC if its hardness is limited to 200 HBW maximum in corrosive petroleum refining environments in accordance with NACE SP0472.3 However, weldments (weld metal, HAZ, and adjacent base metal zones subject to residual stresses from welding) may contain localized zones of high hardness. SSC in carbon steel weldments frequently is limited to hard HAZs of the last weld pass, which are not tempered by subsequent weld passes. Data show that, depending on the severity of the service environment, small hard regions of up to 248 HV (237 HBW) can be tolerated without the occurrence of SSC. The Rockwell Superficial Hardness equivalent to 248 HV is 70.5 HR15N. These values are a direct conversion from the 22 HRC maximum specified in NACE Standard MR0103 for ferritic materials to be used in petroleum refining environments.



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2.4.1.3 SSC has generally not occurred in seamless carbon steel piping that has been welded from one side only because it does not contain hard weldments that are exposed to the process on the inside diameter (ID) of the piping. The initial weld pass is usually tempered by the subsequent weld passes, which helps to control the hardness.

2.4.2 Hydrogen Blistering and Hydrogen-Induced Cracking

2.4.2.1 Hydrogen blistering and HIC have been encountered in the lower-strength carbon steels plate materials typically used in refinery wet H2S environments for pressure vessels and longitudinally seam-welded piping. 2.4.2.2 These cracking mechanisms are associated with the formation of hydrogen blisters caused by an accumulation of molecular hydrogen at internal laminations, nonmetallic inclusions, or other discontinuities in the steel. Reducing the inclusion level of the steel by lowering the sulfur content increases the resistance to hydrogen blistering and HIC. In addition, control of sulfide inclusion morphology by calcium or rare earth metal additions to produce a spheroidal sulfide shape, in conjunction with use of lower-sulfur steels, has been found to increase resistance to hydrogen blistering and HIC. 2.4.2.3 Base metal heat treatments, such as normalizing or quenching and tempering above 593 C (1,100 F), increase resistance to crack growth.

2.4.3 Stress-Oriented Hydrogen-Induced Cracking

2.4.3.1 Generally, the material parameters affecting hydrogen blistering and HIC are expected to apply to SOHIC. 2.4.3.2 Susceptibility to SOHIC is increased by increasing local tensile stresses. Notch-like weld discontinuities and/or local differences in microstructure present in the area of a weldment may increase the localized stresses. Postweld heat treatment (PWHT) is expected to reduce the susceptibility to SOHIC when it is influenced by residual stress. PWHT can also reduce local HAZ hardness, thereby reducing the possibility for SSC, which can initiate SOHIC. 2.4.3.3 SOHIC has been found in pressure vessels constructed with conventional steels in refinery wet H2S environments. In laboratory tests, SOHIC has been produced in a variety of steels. In severe hydrogen-charging laboratory tests, SOHIC has also been produced in steels processed to optimize resistance to HIC.

2.4.4 Alkaline Stress Corrosion Cracking

2.4.4.1 ASCC has occurred in a variety of steels. Field experience to date has not indicated any significant correlation between susceptibility to ASCC and steel properties or product form. 2.4.4.2 Susceptibility to ASCC increases with increasing tensile stress level. Areas of deformation resulting from cold forming or localized high residual stresses in weldments are more prone to ASCC. Surface discontinuities, especially in areas adjacent to welds, often serve as initiation sites for ASCC because they act as localized stress raisers. ASCC can be effectively controlled by PWHT and proper heat treatment after cold forming.

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Section 3: Inspection for Cracking

3.1 The objective of this section is to provide guidelines on inspection for cracking of existing carbon steel pressure vessels and piping made from carbon steel plate in petroleum refinery wet H2S environments. Where appropriate, guidelines are also included for piping.



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3.2 The scope of this section is the inspection of weldments. This includes pressure-retaining circumferential, longitudinal, and nozzle welds, and internal attachment welds to the pressure boundary. 3.3 Inspection guidelines for new pressure vessels (never in service) are beyond the scope of this standard. However, initial inspection of new vessels during fabrication with methods of comparable sensitivity to anticipated in-service inspection methods is of significant value in assessing subsequent inspection results. 3.4 These guidelines incorporate risk-based principles to determine the need and frequency for inspection. (Risk is defined as the likelihood [or probability] of failure times the consequence of failure.) See API RP 58012 and API RP 581.13 Also included are guidelines for inspection personnel qualifications, nondestructive examination (NDE) procedures, areas of inspection, surface preparation, inspection techniques, acceptance criteria, reporting of results, and reinspection. 3.5 Application of these inspection guidelines shall be made by engineers and/or inspection personnel who are knowledgeable in the technical aspects of this section. 3.6 Inspection Priorities and Intervals

3.6.1 Each refinery should prioritize equipment in wet H2S environments. When prioritization is done, the ranking for equipment shall consider the consequences of a leak or a failure on the surrounding area, operating conditions (temperature, pressure, and contents), criticality of the equipment, and the fabrication, inspection, and repair history. Priorities can be established by assessing the risk that cracking represents to the refinery. Evaluation of risk should use industry-approved approaches such as those in API RP 580, API RP 581, ASME(2) PCC-3,14 or similar procedures/methodologies unique to the owner/user. Regardless of the approach used, the risk assessment process shall address the likelihood of cracking and the consequence of failure. 3.6.2 Some factors that should be considered when assessing the likelihood of cracking and blistering in wet H2S environments are the following. These guidelines are based on survey data, literature information, and industry experience.

(a) History of cracking and blistering. Equipment with a history of blistering is more likely to be cracked. Also, equipment in service comparable to that of other equipment that has cracked is more likely to be cracked. (b) Materials, fabrication, and repair history. Equipment without PWHT or those with non-postweld-heat-treated repairs should be given higher priority when setting inspection requirements. NACE Publication 8X194 provides some background information on materials and fabrication practices typically used for vessels in wet H2S service. (c) Type of vessel. Trayed columns or drums in which an aqueous phase can condense, splash, or accumulate are more susceptible to cracking and blistering. Vapor spaces where condensation occurs or where sections are intermittently wetted are often the most severely damaged. (d) Type of piping. Piping fabricated from plate material, such as large-diameter, longitudinally seam-welded piping, is potentially susceptible to wet H2S cracking similar to vessels. The plate material used to fabricate longitudinally seam-welded pipe is similar to that used to fabricate pressure vessels. Seamless piping, forgings, and castings are generally considered to be resistant to wet H2S cracking. Although several factors have been identified to explain this favorable experience with these product forms, a frequently cited reason is the shape and distribution of impurities in these product forms. However, for seamless piping, the fabrication history, environment, and experience should be considered because some instances of wet H2S cracking of seamless piping have been reported.

(2) ASME International (ASME), Three Park Avenue, New York, NY 10016-5990.



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(e) Severity of the process environment. Equipment in the following environments should be considered more susceptible to cracking or blistering. A process temperature between ambient and 149 C (300 F), and:

high total sulfide content in the aqueous phase (generally > 2,000 mg/L [2,000 ppmw]) and pH above 7.8; or

total sulfide content > 50 mg/L (50 ppmw) in the aqueous phase and pH < 5.0; or presence of free cyanide > 20 mg/L (20 ppmw) in the aqueous phase; or alkaline environments with potential for cracking by other mechanisms such as ASCC (e.g., amine

cracking, carbonate cracking); or other environments with high potential for hydrogen activity as a result of aqueous corrosion.

(f) Type of process unit. The data presented in Table B3 of Appendix B may be useful in prioritizing inspection of equipment in various process units. In addition, the following list highlights specific areas within certain process units in which significant cracking in wet H2S environments has been found:

catalytic cracking unit fractionation and light ends recovery sections, especially in the overhead

systems; hydrocracking and hydrotreating unit separation and fractionation sections; coker fractionation and light ends recovery sections, especially in the overhead systems; sour water stripping unit overhead systems; and alkanolamine acid gas removal unit contactor (absorber), rich amine flash drum, stripper

(regenerator), and stripper bottoms and overhead systems.

3.6.3 Some of the factors that should be considered when assessing the consequences of failure or leakage are as follows:

(a) Nature of the process fluid (e.g., tendency to form a vapor cloud, flammability, combustibility, and toxicity); (b) Total release inventory; (c) Autorefrigeration tendency of the fluid (e.g., liquefied petroleum gas [LPG]), which could result in brittle fracture; (d) Potential impact on plant operations and/or surrounding community; (e) Total pressure on the system; and (f) Leak scenario vs. rupture scenario.

3.6.4 Changes to the operating conditions or processing scheme can change the susceptibility to cracking and possibly the consequences associated with cracking. Such changes shall be considered when establishing both initial and reinspection practices.



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3.7 Extent of Inspection 3.7.1 Pressure Vessels

3.7.1.1 The extent of initial inspection shall be sufficient to provide a representative sample of the various areas of concern. The areas of concern include longitudinal, circumferential, and nozzle welds, and internal attachment welds to the pressure boundary. For those pressure vessels warranting inspection based on prioritization, the intent of inspection should be based on the risk the vessel represents to the owner/user. If environmental cracks are found, the inspection coverage shall be increased as necessary to adequately define the extent of cracking. 3.7.1.2 Areas to be inspected should specifically include repair or vessel alteration welds. 3.7.1.3 Areas to be inspected shall also include portions of the vessel that exhibit visible blistering or significant corrosion in close proximity to weldments. 3.7.1.4 In pressure vessels such as distillation columns or towers that include various environments, the inspection shall focus on areas considered more susceptible to cracking (e.g., cooler areas in which an aqueous phase may be present).

3.7.2 Piping

3.7.2.1 Longitudinally seam-welded piping made from plate shall be considered for inspection if the risk of cracking is unacceptably high using the same risk-based assessment considerations described for pressure vessels. If the risk assessment justifies an inspection, the inspection shall include longitudinal seam welds and also should include butt welds. If indications are found, the inspection shall be extended to establish the severity and extent of cracking. 3.7.2.2 Seamless piping, castings, and forgings are usually exempted from inspection for wet H2S cracking based on experience. Where inspection is deemed necessary by an appropriate expert, the extent of inspection shall be specified.

3.8 Inspection Methods

3.8.1 Several NDE techniques can be used to detect cracks and blisters in pressure vessels. These include wet fluorescent magnetic particle testing (WFMT), ultrasonic testing (UT) (including shear wave, longitudinal wave, time-of-flight diffraction [TOFD], and phased array [PA]), acoustic emission (AE) testing, alternating current field measurement (ACFM), eddy current testing (ECT), wet or dry magnetic particle testing (MT), liquid penetrant testing (PT), and visual methods (VT). The usefulness of these methods is dependent on the tightness, severity, and location of cracks, as well as proper application of the method, which includes a reasonable understanding of its benefits and limitations. The results of all of these techniques are technician-dependent. The following additional guidelines are provided on some of these NDE techniques used for detecting cracks in equipment exposed to wet H2S environments. 3.8.2 Wet Fluorescent Magnetic Particle Testing

3.8.2.1 For surface-breaking cracks, WFMT is sensitive, demonstrates reproducible results, and is one of the most commonly used methods for internal pressure vessel inspection. 3.8.2.2 Surfaces to be inspected shall be prepared to a finish that will facilitate inspection and not mask indications. In order to perform a satisfactory WFMT inspection, the surface of the weld and adjacent base metal for a distance of about 150 mm (6 in) on both sides should be cleaned of all scale and residue. Care should be taken to ensure that the surface preparation method does not deform the metal surface and mask



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indications. Abrasive blasting to a near-white finish in accordance with NACE No. 2/SSPC(3)-SP 1015 should be performed. Other methods, such as high-pressure water or CO2 blasting, may be used if they provide a suitable surface for inspection. In some instances, the use of flapper disc polishing has been necessary to enhance the detection sensitivity of fine, tight cracks. 3.8.2.3 Alternating current (AC) yoke WFMT should be used instead of direct current (DC) or prod methods. DC methods are not as sensitive for surface-breaking cracks and prod methods may leave arc strikes that, if not ground out, can serve as crack initiators. 3.8.2.4 AC yoke WFMT is a sensitive technique that may detect discontinuities not detected by other NDE methods. Some indications may be irrelevant. A representative number and type of indications shall be evaluated to determine their relevance and severity. 3.8.2.5 Surface preparation, magnetic particle materials, magnetic testing equipment, processing techniques, sequence of operation, levels of magnetizing fields, etc., should be monitored periodically to ensure proper inspection. Methods for checking system performance and sensitivity are detailed in ASME SE-70916 or equivalent. 3.8.2.6 Based on limited laboratory data and field experience, concern exists that in certain instances, removal of protective scales associated with surface preparation for WFMT may increase the likelihood of cracking when the vessel is returned to service.17 Depending on the severity of the environment and specific startup conditions, a short period of higher-than-normal hydrogen flux that could lead to cracking in a susceptible base metal or weldment may occur. 3.8.2.7 Limitations exist on the use of WFMT for the detection of cracking in wet H2S environments. These include:

(a) WFMT requires internal vessel access, and some areas of the vessel may be inaccessible. Piping is most often not available for internal inspection except in the case of large-diameter lines that may be made from plate; (b) WFMT may not detect subsurface cracks; (c) Surface preparation removes protective scales and requires cleanup; (d) WFMT can reveal many small irrelevant indications; and (e) Costs and time constraints are associated with removal of internals (e.g., trays).

3.8.3 Ultrasonic Testing

3.8.3.1 UT methods (manual or automated) may be used to detect surface cracking, subsurface cracking, and hydrogen blistering, for inspection on-stream and for nonintrusive inspection from the external surface. UT methods used include shear wave, longitudinal wave, TOFD, PA, and combinations of these UT methods. UT can be used to evaluate blister size and depth and detect deeper surface-connected defects (greater than 3.18 mm [0.125 in] deep). Other than destructive grinding of cracks, UT is the most frequently used method for sizing cracks for fitness-for-service evaluations. The use of external UT can alleviate potential future hydrogen-charging concerns associated with cleaning ID surfaces for WFMT, as stated in Paragraph 3.8.2.6. 3.8.3.2 Limitations on the use of UT methods for the detection of cracking and blistering in wet H2S environments exist. Achieving consistently reliable interpretation of results is difficult because of weld geometry, joint design, shadowing effect of multiple defects, and the need for more highly qualified NDE

(3) The Society for Protective Coatings (SSPC), 40 24th St., 6th Floor, Pittsburgh, PA 15222-4656.



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personnel experienced in the detection of cracking in wet H2S environments. Potential cost and time constraints include external scaffolding, insulation removal and replacement, surface preparation (e.g., grinding weld crowns), and slow production rates. 3.8.3.3 Carefully planned and executed automated UT procedures can provide some advantages in mapping specific areas, compared to manual UT, especially when follow-up inspection for crack growth is anticipated. 3.8.3.4 External shear wave UT should be used to inspect the weldments in piping.

3.8.4 Acoustic Emission Testing

3.8.4.1 AE testing is a global inspection method that may be used to detect surface-breaking cracks, subsurface cracks, and blisters. AE testing is typically used when the equipment is subjected to higher than normal tensile loading, normally accomplished by hydrostatic testing, pneumatic testing, or in-service pressurization above normal operating pressure. AE testing can be used both for inspection on-stream and for nonintrusive inspection from outside the equipment during a shutdown. 3.8.4.2 During AE testing, defect growth is detected by an AE sensor array attached to the external surface of the equipment. The AE sensors transmit signals to a central computerized data collection system. The data are evaluated using software developed for this purpose. 3.8.4.3 Limitations on the use of AE testing for the detection of damage in wet H2S environment exist. These include:

(a) AE testing detects only cracks that are active during the conditions of the test. Therefore, the absence of AE indications does not ensure that the equipment is free of discontinuities. (b) AE testing methods currently used in the refining industry cannot discriminate the type or nature of the defect and cannot determine the defect size or exact location (although zonal location is possible). (c) AE testing is a sensitive technique with a relatively high occurrence of false indications (or over-calls). These can result from rain hitting the sensors, mechanical rubbing/squeaking of equipment internals or attachments, flange leaks, etc. AE testing personnel must be aware of and take into account potential extraneous influences and their effect on test results. (d) AE testing requires considerable skill and experience on the part of the personnel conducting the test and evaluating the data. The availability of both AE testing hardware and qualified personnel can be limited. (e) A stress analysis may need to be performed to ensure that the components of interest are adequately stressed during the test.

3.8.4.4 Because of the limitations stated above, AE testing should not be used as a stand-alone inspection method for the detection of cracking in wet H2S environments. Follow-up inspection with other appropriate NDE techniques shall be performed on any significant AE source area that potentially represents a location of cracking. When AE testing is used as a global screening technique, it should be used in conjunction with other NDE methods.

3.8.5 Alternating Current Field Measurement

3.8.5.1 ACFM is an electromagnetic technique that can be used to detect and size surface-breaking cracks in ferrous materials. The method can be applied through thin coatings and does not require extensive surface preparation.



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3.8.5.2 ACFM is best used as a screening tool for rapid detection of cracking along welds and/or HAZs with little or no surface preparation. It can be used in lieu of WFMT. 3.8.5.3 The sensitivity of ACFM to cracks decreases with an increase in the coating thickness and loose scale on the examination surface. ACFM can size crack length reliably. It can also assess the depths of nonbranched through-wall oriented cracks. However, its crack-depth sizing can yield erroneous values when ACFM is applied on highly branched, closely spaced, or tilted (i.e., not exactly in the through-wall direction) cracks, such as cracks resulting from ASCC. 3.8.5.4 ACFM data interpretation is much more complicated than WFMT. Highly skilled, experienced operators are essential to the success of ACFM inspection. 3.8.5.5 Application of the ACFM technique requires access to the internal (process) surfaces of the equipment.

3.8.6 Eddy Current Testing

3.8.6.1 ECT can be used to detect surface-breaking cracks. The method can be applied through thin coatings and does not require extensive surface preparation. 3.8.6.2 ECT is best used as a screening tool. It can be used in lieu of WFMT. It is not effective in finding very shallow cracks (less than about 1.5 mm [0.06 in] deep). 3.8.6.3 Increasing coating or scale thickness decreases the sensitivity of ECT. 3.8.6.4 ECT data interpretation is simpler than interpreting ACFM results. However, skilled operators are required to obtain accurate results. 3.8.6.5 Application of ECT requires access to the internal (process) surfaces of the equipment.

3.9 NDE Personnel Qualifications

3.9.1 NDE personnel performing nondestructive examinations shall be those recognized by the owner/user as having been trained in accordance with ASNT(4) SNT-TC-1A18 or equivalent, to a minimum of Level I. Interpretation of indications detected by NDE methods should be made by personnel trained to a minimum of Level II or equivalent. Refinery inspectors interpreting results and following up on repair procedures should be certified to ANSI(5)/API 510,19 ANSI/API 570,20 ANSI/NBBPVI(6) NB-23,21 ASME PCC-2,22 or other applicable industry code or standard. 3.9.2 Personnel interpreting results, especially characterization and sizing, should be familiar with the features of these cracking mechanisms to minimize errors in interpretation.

3.10 NDE Procedures

3.10.1 NDE procedures for crack detection by methods outlined in Paragraph 3.8.1 shall be in accordance with the appropriate article in Section V of the ASME Boiler and Pressure Vessel Code23 (e.g., Article 5 for UT, Article 7 for MT), or other applicable industry code or standard. In addition, special procedures may be required for detection and sizing of environmental cracking. 3.10.2 NDE procedures should be developed and approved by personnel with a demonstrated understanding of potential damage morphologies and with certification to ASNT Level III, or other qualified personnel.

(4) American Society for Nondestructive Testing (ASNT), P.O. Box 28518, 1711 Arlingate Lane, Columbus, OH 43228-0518. (5) American National Standards Institute (ANSI), 25 West 43rd St., 4th Floor, New York, NY 10036. (6) National Board of Boiler and Pressure Vessel Inspectors (NBBPVI), 1055 Crupper Avenue, Columbus, OH 43229-1183.



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3.11 Determining the Extent and Magnitude of Cracking and Blistering

3.11.1 A representative number and type of linear indications shall be explored for length and depth, using appropriate methods such as grinding, arc gouging followed by grinding, or UT sizing techniques. 3.11.2 A UT survey of areas with hydrogen blisters or cracks should be made to determine the extent of subsurface blistering, HIC, and/or SOHIC. The area adjacent to welds shall be targeted for this inspection.

3.12 Analysis of Inspection Results Based on the extent and magnitude of cracking and hydrogen blistering, an evaluation of the need for repair shall be made by engineers or inspection personnel who are recognized by the owner/user as qualified to make such evaluations. This evaluation may include a fitness-for-service analysis in accordance with a recognized methodology such as API 579-1/ASME FFS-124 or equivalent. API 579-1/ASME FFS-1 includes a part titled, Assessment of Hydrogen Blisters and Hydrogen Damage Associated with HIC and SOHIC. Discontinuities judged to be allowable by such an evaluation may remain in the equipment with no repairs required. Increased monitoring or mitigation may be necessary.

3.13 Records

Permanent records of inspection results should be maintained for the life of the equipment. The location, orientation, length, and depth of significant indications, blisters, and cracks should be documented.

3.14 Reinspection

3.14.1 Reinspection intervals should be based on the risk that the equipment represents to the owner/user, recognizing prior inspection results, disposition of indications, weld repairs or alterations, changing process conditions, processing scheme, or requirements of ANSI/API 510 or other applicable industry code or standard. In general, if the risks are such that reinspection is warranted, the reinspection should be done using techniques discussed in this standard. 3.14.2 In assessing risk, other issues to be considered include possible growth of subsurface damage, possible accelerated hydrogen flux caused by surface cleaning prior to inspection, and changes to the process environment that may change the hydrogen-charging rate.

________________________________________________________________________

Section 4: Repair of Cracked or Blistered Equipment

4.1 The objective of this section is to provide guidelines for the repair of existing carbon steel equipment that has experienced cracking and/or hydrogen blistering when exposed to a petroleum refinery wet H2S environment. Decisions on the type of repair and procedure shall be made by engineers or inspection personnel who are recognized by the owner/user as qualified to make such evaluations. 4.2 All repairs shall be performed in accordance with ANSI/API 510 for vessels, ANSI/API 570 for piping, National Board Inspection Code (NBIC), ASME PCC-2, or another recognized industry code or standard. All welding procedure specifications, procedure qualifications, and welder performance qualifications shall be in accordance with the requirements of the ASME Boiler and Pressure Vessel Code, Section IX25 or other applicable industry code or standard. 4.3 In some cases, grinding or welding operations can cause cracks to initiate or propagate because of the hydrogen-charged nature of the steel. In such instances, a hydrogen bake-out procedure involving heating the area to diffuse atomic hydrogen should be used to aid reparability. Molecular hydrogen trapped in blisters and HIC typically does not dissociate at temperatures below full PWHT temperatures. Some owner/users heat the vessel or



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piping to a temperature above 204 C (400 F) and hold for up to four hours. Although no standard calculations exist, based for example on Ficks law, to determine the efficacy of bake-out treatments, much longer holding times and higher temperatures may be needed to reduce the diffusible hydrogen content to prevent subsequent cracking during repairs. For example a 25 mm (1 in) thick plate may require three hours at 426 C (800 F) or six hours at 315 C (600 F) to reach 1 ppm of residual hydrogen. Hydrogen flux monitor may be considered for use in determining what hydrogen bake-out is sufficient. Bake-out temperatures up to those required for full PWHT may be used for holding times shorter than specified for PWHT. 4.4 Repair of Hydrogen Blisters

4.4.1 Hydrogen blisters may be evaluated in accordance with the provisions of API 579-1/ASME FFS-1, an equivalent fitness-for-service document, or applicable industry code or standard. If it is determined that hydrogen blisters are present to the extent that repairs are necessary, the following options may be used.

4.4.1.1 Surface blisters less than 50 mm (2 in) in diameter may be drilled to relieve the internal pressure. Appropriate caution shall be taken to protect the operator from injury during hydrogen venting. An engineering analysis shall be performed prior to drilling blisters larger than 50 mm (2 in) in diameter to ensure that the remaining net section of metal will hold the internal pressure. 4.4.1.2 Blistered steel plates may be removed from the vessel and replaced with new steel. Hydrogen bake-out in accordance with Paragraph 4.3 may be required prior to thermal cutting or welding. CAUTIONARY NOTE: Hydrogen blisters are typically filled with molecular hydrogen, which will not diffuse during the bake-out described in Paragraph 4.3 or during PWHT. As a result, the blisters may grow or rupture during the bake-out or PWHT. In addition, molecular hydrogen remaining in blisters after the bake-out may cause cracking during subsequent repair or PWHT. High-temperature hydrogen attack may also result from PWHT.26

4.5 Removal of Cracks

4.5.1 Cracks may be evaluated in accordance with the provisions of API 579-1/ASME FFS-1, an equivalent fitness-for-service document, or an applicable industry code or standard. When crack removal is determined to be necessary, cracks may be removed by any suitable method (e.g., grinding or arc gouging). If arc gouging or another method that will heat the steel above its lower critical temperature is used, subsequent grinding shall be used to remove all heat-affected material. 4.5.2 The excavated area should be reinspected with WFMT to ensure that all cracks have been removed. 4.5.3 Once the cracks have been removed, the need for weld repair shall be determined based on the minimum required wall thickness or an engineering fitness-for-service analysis. Local areas thinned beyond the corrosion allowance may be acceptable under some conditions, such as those outlined in ANSI/API 510, API 579-1/ASME FFS-1, or other applicable industry code or standard.

4.6 Blend Grinding Repairs

The cavities formed by removing the cracks that are not subsequently weld repaired shall be contoured to eliminate notches in accordance with the provisions of API 579-1/ASME FFS-1 or other applicable industry code or standard. An appropriate taper or radius is recommended to avoid sharp edges that could act as stress raisers and lead to further cracking, or confuse interpretation of subsequent UT inspections.

4.7 Weld Repairs

4.7.1 If weld repairs are determined to be necessary, they shall be made in accordance with a recognized code such as ANSI/API 510, ANSI/API 570, or other applicable industry code or standard.



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4.7.2 Preheat should be applied to the repair area when deemed necessary. When possible, the preheat should be applied from the outside of the vessel and measured on the inside. This method of applying preheat ensures that the required temperature has been achieved through the full material thickness. 4.7.3 Low-hydrogen welding electrodes should be used and handled in accordance with ASME SFA-5.1,27 or other applicable industry code or standard, and the electrode manufacturers recommendations to minimize the potential for delayed hydrogen (cold) cracking. 4.7.4 Arc strikes should be removed by blend grinding. 4.7.5 The repair area should be given a PWHT in accordance with the ASME Boiler and Pressure Vessel Code, Section VIII,28 Division 1 or Division 2 as appropriate, or other applicable industry code or standard after welding, especially if PWHT was performed in original fabrication. Heat treatment at lower temperatures (below 593 C [1,100 F]) for longer times, as allowed by the ASME code, should not be used.

4.7.5.1 Certain microalloying elements that can be present in pressure vessel steels can retard the softening effect of PWHT. When microalloying elements are known to be present, consideration should be given to increasing the PWHT temperature such that suitable softening of the weld and HAZ is accomplished. 4.7.5.2 PWHT of vessels containing blisters or HIC can result in additional cracking. See the cautionary note in Paragraph 4.4.1.2. 4.7.5.3 As an alternative to conventional PWHT, welding techniques that soften the HAZ, such as temper bead welding in accordance with ANSI/API 510, may be used. This may control HAZ hardness, but has no significant impact on residual stress levels, which often govern SSC and ASCC. Consideration may also be given to the mitigation techniques outlined in Section 5.

4.7.6 Repair weld hardness control shall be in accordance with methods and procedures in NACE SP0472 suitable for the repair welding being performed, which may include the following:

(a) Weld deposit hardness control. This control impacts SSC concerns resulting from high weld hardness, but may not ensure freedom from SOHIC or ASCC. (b) Thermal methods and preproduction weld procedure thermal-related reporting and controls. The thermal methods are cooling time control, PWHT control, and temper bead welding. (c) Preproduction weld procedure HAZ hardness controls and testing for the weld deposit.

Some procedures in NACE SP0472 may have limited applicability for repair welds, such as the following:

(a) Base metal chemistry control. The base metal chemistry and susceptibility to wet H2S damage is fixed because the repair is to existing equipment that has experienced damage. However, this may be used as part of repair in accordance with NACE SP0472 where new material is being used as part of the repair. (b) Preproduction weld procedure HAZ hardness controls and testing for the base material. Implementing this method effectively for the base material requires the procedure to be qualified with materials closely matching those of the component being repaired. This may not be feasible for a repair. (c) Preproduction weld procedure base metal chemistry controls and reporting.

4.7.7 The repair area should be reinspected after welding and, when specified, PWHT. When delayed hydrogen (cold) cracking is a concern, a minimum interval of 48 hours should be provided between welding and final inspection for repairs that do not undergo PWHT immediately after welding, or not at all. Delayed cracking can take some time to present itself, but owner/users often do not wait the full 48 hours. Any new cracks or



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defects found should be repaired according to the steps outlined above. If a subsequent welded repair is required (repair of a repair), other remedial steps (e.g., hydrogen bake-out or higher preheat temperature) should be considered. 4.7.8 Radiographic testing (RT) or UT according to ASME Boiler and Pressure Vessel Code, Section VIII or other applicable industry standard should be considered for major repairs. RT, however, is not very sensitive for detecting smaller, tighter cracks. 4.7.9 Permanent records of repairs should be maintained for the life of the vessel. All relevant information, such as location, size, and depth of repair, repair method, preheat temperature (if any), and PWHT temperature and hold time (if any), should be recorded.

4.8 Replacing a section of the vessel or replacing the entire vessel are acceptable options to performing repairs. Replacement of piping is likewise an acceptable repair. Where size permits, seamless piping should be used instead of longitudinally seam-welded piping.

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Section 5: Mitigation Considerations for Operation

5.1 The objective of this section is to outline several methods that may be used to decrease the likelihood or severity of cracking in wet H2S environments.

5.1.1 To the extent that modifications are acceptable from a process standpoint, process changes that may decrease the likelihood of cracking include control of water carry-over into downstream equipment, dilution or removal of corrosive constituents by water washing, or use of additives. The use of additives, such as polysulfide or other corrosion inhibitors, or the use of water washing to reduce concentrations of ammonium bisulfide and cyanide in the aqueous phase, have been shown to reduce hydrogen permeation at alkaline pH levels. Polysulfide may provide a resistant corrosion product film and it converts cyanides in the aqueous phase into thiocyanates. (NOTE: Polysulfide does not react with cyanides in the gas phase.) 5.1.2 Corrosion inhibitors injected into the process stream may decrease the corrosion reaction, which tends to lower the cathodic evolution of atomic hydrogen and hence lower the potential for hydrogen entry into the steel and subsequent blistering and cracking. 5.1.3 Organic or inorganic coatings may be used as a barrier to corrosion. Care should be taken to select a suitable coating that will perform in the process environment and during shutdown operations such as depressurizing and steam-out. Periodic inspection and maintenance of the coating should be performed over the life of the equipment to ensure continuing protection. If coating deterioration is evident, consideration should be given to inspecting the internal steel surfaces periodically for cracking. 5.1.4 A corrosion-resistant alloy in the form of cladding, weld overlay, or strip lining can be applied to the equipment interior as a permanent corrosion barrier.

5.1.4.1 Plate that is clad by the hot-rolling or explosive-bonding process can be used for replacement parts of existing equipment. 5.1.4.2 Weld overlay can be applied in situ or installed as a replacement part. Weld overlay should not be applied directly to the surfaces of materials containing cracks or hydrogen blisters. 5.1.4.3 Attachment of strip lining by welding can also be used to cover existing areas of equipment. Periodic inspection and maintenance of strip lining should be performed over the life of the equipment to ensure protection. Cracking of the strip-lining attachment welds because of issues such as differential expansion may result in process fluids entering the gap between the lining and the base metal. Subsequent cracking of the base metal beneath the lining can occur as a result of exposure to wet H2S. Additionally,



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cracking into the base metal at the termination point of the strip lining has been shown to occur in laboratory testing.29 This latter issue has not been shown to be a significant problem in actual service, however.

5.1.5 An on-stream corrosion-monitoring program may be used to detect corrosion activity that may produce conditions leading to cracking. This also helps to determine whether certain corrosion control methods, such as chemical injection (e.g., polysulfide injection) or water washing, are effective. The corrosion-monitoring program may include corrosion coupons and/or corrosion probes, hydrogen probes, and UT measurements.

________________________________________________________________________

References 1. NACE Publication 8X294 (latest revision), Review of Published Literature on Wet H2S Cracking of Steels Through 1989 (Houston, TX: NACE). 2. NACE Publication 8X194 (latest revision), Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service (Houston, TX: NACE). 3. NACE SP0472 (formerly RP0472) (latest revision), Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in Corrosive Petroleum Refining Environments (Houston, TX: NACE). 4. NACE Standard MR0103 (latest revision), Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments (Houston, TX: NACE). 5. API RP 945 (latest revision), Avoiding Environmental Cracking in Amine Units (Washington, DC: API) 6. NACE Publication 34108 (latest revision), Review and Survey of Alkaline Carbonate Stress Corrosion Cracking in Refinery Sour Waters (Houston, TX: NACE) 7. H.I. McHenry, D.T. Read, T.R. Shieves, Failure Analysis of an Amine-Absorber Pressure Vessel, MP 26, 8 (1987): p. 18. 8. J.P. Richert, A.J. Bagdasarian, C.A. Shargay, Stress Corrosion Cracking of Carbon Steel in Amine Systems, MP 27, 1 (1988): p. 9. 9. R.D. Merrick, Refinery Experiences With Cracking in Wet H2S Environments, MP 27, 1 (1988): p. 30. 10. J.H. Kmetz, D.J. Truax, Carbonate Stress Corrosion Cracking of Carbon Steel in Refinery FCC Main Fractionator Overhead Systems, CORROSION/90, paper no. 206 (Houston, TX: NACE). 11. H.U. Schutt, Intergranular Wet Hydrogen Sulfide Cracking, MP 32, 11 (1993): pp 55-60. 12. API RP 580 (latest revision), Risk-Based Inspection (Washington, DC: API). 13. API RP 581 (latest revision), Risk-Based Inspection Technology (Washington, DC: API). 14. ASME PCC-3 (latest revision), Inspection Planning Using Risk-Based Methods (New York, NY: ASME). 15. NACE No. 2/SSPC-SP 10 (latest revision), Near-White Metal Blast Cleaning (Houston, TX: NACE). 16. ASME SE-709 (latest revision), Standard Guide for Magnetic Particle Examination (New York, NY: ASME). 17. API Publication 939-A, Research Report on Characterization and Monitoring of Cracking in Wet H2S Service (Washington, DC: API).



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18. ASNT SNT-TC-1A (latest revision), Personnel Qualification and Certification in Nondestructive Testing (Columbus, OH: ASNT). 19. ANSI/API 510 (latest revision), Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration (New York, NY: ANSI and Washington, DC: API). 20. ANSI/API 570 (latest revision), Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems (New York, NY: ANSI and Washington, DC: API). 21. ANSI/NBBPVI NB-23 (latest revision), National Board Inspection Code (New York, NY: ANSI and Columbus, OH: NBBPVI). 22. ASME PCC-2 (latest revision), Repair of Pressure Equipment and Piping (New York, NY: ASME). 23. ASME Boiler and Pressure Vessel Code, Section V (latest revision), Nondestructive Examination (New York, NY: ASME). 24. API 579-1/ASME FFS-1 (latest revision), Fitness for Service (Washington, DC: API and New York, NY: ASME). 25. ASME Boiler and Pressure Vessel Code, Section IX (latest revision), Welding and Brazing Qualifications (New York, NY: ASME). 26. J.L. Hau, C.H. Molina, Hydrogen Damage Inspection and Evaluation of H2S Absorber Column, CORROSION/92, paper no. 446 (Houston, TX: NACE, 1992). 27. ASME SFA-5.1 (latest revision), Specification for Carbon Steel Electrodes for Shielded Metal Arc Welding (New York, NY: ASME). 28. ASME Boiler and Pressure Vessel Code, Section VIII (latest revision), Rules for Construction of Pressure Vessels (New York, NY: ASME). 29. API Publication 939-B (latest revision), Repair and Remediation Strategies for Equipment Operating in Wet H2S Service (Washington, DC: API).

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Bibliography Bartz, M.H., and C.E. Rawlins. Effects of Hydrogen Generated by Corrosion of Steel. Corrosion 4, 5 (1948): p.

187. Berkowitz, B.J., and H.H. Horowitz. The Role of H2S in the Corrosion and Hydrogen Embrittlement of Steel.

Journal of Electrochemical Society 129, 3 (1982): p. 468. Bulla, J.T., and J.T. Chikos. Case HistoryFCCU Absorber Deethanizer Tower Hydrogen Blistering and Stepwise

Cracking. CORROSION/89, paper no. 264. Houston, TX: NACE, 1989. Cayard, M.S., R.D. Kane, L. Kaley, and M. Prager. Research Report on Characterization and Monitoring of

Cracking in Wet H2S Service. API Publication 939. Washington, DC: API, October 1994. Gutzeit, J. Process Changes for Reducing Pressure Vessel Cracking Caused by Aqueous Sulfide Corrosion. MP

31, 5 (1992): p. 60.



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Hildebrand, E.L. Aqueous Phase H2S Cracking of Hard Carbon Steel WeldmentsA Case History, Proceedings API, vol. 50 (III). Washington, DC: API, 1970: p. 593.

Kotecki, D.J., and D.G. Howden. Weld Cracking in a Wet Sulfide Environment, Proceedings API, vol. 53 (III).

Washington, DC: API, 1973: p. 573. Kotecki, D.J., and D.G. Howden. Wet Sulfide Cracking of Submerged Arc Weldments, Proceedings API, vol. 52 (III).

Washington, DC: API, 1972: p. 631. Merrick, R.D., and M.L. Bullen. Prevention of Cracking in Wet H2S Environments. CORROSION/89, paper no.

269. Houston, TX: NACE, 1989. Neill, W.J. Jr. Prevention of In-Service Cracking of Carbon Steel Welds in Corrosive Environments. Materials

Protection and Performance 10, 8 (1971): p. 33. Schuetz, A.E., and W.D. Robertson. Hydrogen Absorption, Embrittlement, and Fracture of Steel. Corrosion 13, 7

(1957): p. 437t. Schutt, H.U. New Aspects of Stress Corrosion Cracking in Monoethanolamine Solutions. MP 27, 12 (1988): p. 53. Van Gelder, K., M.J.J. Simon Thomas, and C.J. Kroese. Hydrogen Induced Cracking: Determination of Maximum

Allowed H2S Partial Pressures. Corrosion 42, 1 (1986): p. 36. ________________________________________________________________________

Appendix A

Cited Codes, Specifications, and Standards (Nonmandatory)

This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein.

ASME International Boiler and Pressure Vessel Code Section II, Part C Specifications for Welding Rods, Electrodes, and Filler Metals Section V Nondestructive Examination Section VIII Rules for Construction of Pressure Vessels Section IX Welding and Brazing Qualifications SE-709 Standard Guide for Magnetic Particle Examination PCC-2 Repair of Pressure Equipment and Piping PCC-3 Inspection Planning Using Risk-Based Methods ASTM International(7) A 53/A 53M Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated, Welded and Seamless (7) ASTM International (ASTM), 100 Barr Harbor Dr., West Conshohocken, PA 19248-2959.



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A 70 Specification for Low and Intermediate Tensile Strength Carbon Steel (withdrawn 1947replaced by A 285/A 285M)

A 106/A 106M Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service A 201 Specification for Carbon-Silicon Steel Plates of Intermediate Tensile Ranges for Fusion-Welded

Boilers and Other Pressure Vessels (withdrawn 1967replaced by A 515/A 515M) A 212 Specification for High Tensile Strength Carbon-Silicon Steel Plates for Boilers and Other Pressure

Vessels (withdrawn 1967replaced by A 515/A 515M) A 285/A 285M Standard Specification for Pressure Vessel Plates, Carbon Steel, Low- and Intermediate-Tensile

Strength A 515/A 515M Standard Specification for Pressure Vessel Plates, Carbon Steel, for Intermediate- and Higher-

Temperature Service A 516/A 516M Standard Specification for Pressure Vessel Plates, Carbon Steel, for Moderate- and Lower-

Temperature Service NACE International MR0103 Materials Resistant to Sulfide Stress Cracking in Corrosive Petroleum Refining Environments NACE No. 2/SSPC-SP 10 Near-White Metal Blast Cleaning SP0472 Methods and Controls to Prevent In-Service Environmental Cracking of Carbon Steel Weldments in

Corrosive Petroleum Refining Environments American Society for Nondestructive Testing (ASNT) SNT-TC-1A Personnel Qualification and Certification in Nondestructive Testing American Petroleum Institute (API) ANSI/API 510 Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration ANSI/API 570 Piping Inspection Code: In-Service Inspection, Rating, Repair, and Alteration of Piping Systems API 579-1/ASME FFS-1 Fitness-for-Service API RP 580 Risk-Based Inspection API RP 581 Risk-Based Inspection Technology National Board of Boiler and Pressure Vessel Inspectors (NBBPVI) NB-23 National Board Inspection Code (NBIC)



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Appendix B Nature and Extent of ProblemResults from 1990 T-8-16a Survey

(Nonmandatory)

This appendix is considered nonmandatory, although it may contain mandatory language. It is intended only to provide supplementary information or guidance. The user of this standard is not required to follow, but may choose to follow, any or all of the provisions herein.

B1 The objective of this section is to report the frequency and severity of cracking of existing carbon steel pressure vessels in petroleum refinery wet H2S environments. B2 Survey of Inspection Results

B2.1 A survey was conducted in 1990 by Work Group T-8-16a to determine the nature and extent of cracking problems in wet H2S environments in the petroleum refining industry. Insufficient information was reported about the type of cracking found to correlate cracking incidence with cracking mechanism. In addition to asking for crack inspection results, the survey requested information about original fabrication details, service environment, prior inspection history, and disposition of cracked vessels (e.g., type of repairs, replacement). B2.2 The use of various inspection techniques, such as visual inspection for hydrogen blisters and magnetic particle testing and liquid penetrant testing for crack detection, was reported. However, most of the inspections for cracks were performed using WFMT, which is a very sensitive inspection technique for detection of surface discontinuities. Therefore, in addition to detecting service-related cracks, a number of linear indications that may have been discontinuities present from original fabrication, repair, or alteration of the pressure vessels were found. Subsurface cracks may not be detected by this method. Reporting of discontinuities was not uniform; some companies reported all discontinuities, some excluded obvious fabrication discontinuities, and others excluded very shallow indications that could easily be ground out. In the context of this appendix, the terms cracks and cracking refer to all linear indications reported by the survey respondents.

B2.3 Survey responses covering inspection results for almost 5,000 pressure vessels were received. Overall, cracking was reported in 26% of the inspected pressure vessels, as shown in Table B1.

Table B1

Overall Summary

Number of Pressure Vessels Inspected 4,987 Number of Pressure Vessels Cracked 1,285 Cracking Incidence 26%

B2.4 Cracking incidence reported by different companies varied from a low of 10% to a high of 73%. The cracking incidence reported by each company is shown in Table B2.



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Table B2 Cracking Reported by Company

Company Number

Inspected % Cracked

A 45 47 B 1,358 13 C 968 11 D 55 15 E 179 20 F 104 43 G 85 21 H 129 34 I 172 16 J 71 10 K 141 73

L + Misc. 1,680 41

B2.5 The task group believes that a number of factors have influenced the wide disparity in cracking incidence reported by various companies, although not all were factors considered in the survey. These include, but are not limited to, differences in (1) surface preparation prior to inspection; (2) extent of inspection; (3) reporting of cracks, e.g., whether fabrication flaws or shallow indications were excluded; (4) process units inspected; (5) crude feed compositions; and (6) original fabrication practices. B2.6 Cracking was reported in pressure vessels in essentially all refinery process units with wet H2S environments. Table B3 shows the cracking incidence in each of the common refinery process units. B2.7 Cracking incidence varied from a low of 18 to 19% in crude units and coker fractionation units to a high of 45% in fluid catalytic cracking unit (FCCU) light-ends sections. Other process units also experiencing high cracking incidence include FCCU fractionation (41%), liquefied petroleum gas (LPG) (41%), and atmospheric light ends (38%).

Table B3 Cracking by Process Unit

Process Unit Number

Inspected % Cracked

Crude Coker Fractionation

300 44

18 19

Vacuum Amine Other

71 574 364

21 21 23

Hydrotreating Sulfur Recovery Hydrocracking

Sour Water Stripper Amine/Caustic

368 96 156 132 811

25 27 28 28 29

Coker Light Ends Flare

Catalytic Reformer

91 23 134

30 30 34

Atmospheric Light Ends

140 38

FCCU Fractionation LPG

252 49

41 41

FCCU Light Ends 704 45



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B2.8 Some companies reported that a significant percentage of cracking detected in FCCU fractionation was carbonate cracking, a form of ASCC in alkaline sour waters with high carbonate/bicarbonate concentration. Cracking was also prevalent in amine and caustic services. B2.9 The survey data show no strong correlation between cracking incidence and operating temperature. Throughout the entire range of operating temperatures, the cracking incidence only varied between 23% and 37%, as shown in Table B4. The highest cracking incidence occurred in the 65 to 93 C (150 to 200 F) operating temperature range.

Table B4

Cracking vs. Operating Temperature

Operating Temperature C F

Number Inspected

% Cracked

< 38 < 100 284 23 3865 100150 926 34 6593 150200 385 37 93121 200250 312 33 121149 250300 237 27

> 149 > 300 356 29 B2.10 In general, cracking incidence increased with increasing H2S concentration in the water phase, as shown in Table B5. The most noteworthy observation is the 17% cracking incidence for pressure vessels in services containing less than 50 mg/L (50 ppmw) H2S dissolved in an aqueous phase. This is considered a high rate for a service environment previously thought not to be a concern. However, inclusion of fabrication-related discontinuities in some of the survey responses probably had an impact on this cracking incidence. The practical difficulty of measuring actual concentration of H2S in the aqueous phase, especially at low concentrations, also might have had an impact. In addition, upset conditions with higher H2S concentrations may have produced the cracking encountered in the cases with low reported H2S concentrations.

Table B5

Cracking vs. H2S Concentration

H2S Concentration (mg/L [ppmw])

Number Inspected

% Cracked

< 50 94 17 50250 309 23 250500 35 26

5001,000 76 36 1,0002,500 134 27 2,5005,000 83 45 5,00010,000 137 42

> 10,000 378 39 B2.11 The cracking incidences for refinery pressure vessels fabricated from the most commonly used ASTM specification steel materials are listed in Table B6. No correlation between cracking incidence and the specification of the steel plates used for fabrication of pressure vessels in wet H2S service was apparent. It was evident that the cracking incidence in pipe steels, such as ASTM A 53 and A 106, was much lower than that in plate steels.



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Table B6 Cracking vs. Steel Specification

ASTM Steel

Specification Number

Inspected % Cracked

A 70 230 20 A 201 102 32 A 212 277 30 A 285 907 29 A 515 293 36 A 516 681 27 A 53 129 9 A 106 103 12

B2.12 The cracking incidences for refinery pressure vessels fabricated from steel plates of the commonly used steel grades (with corresponding minimum tensile strength) are listed in Table B7. No trend between cracking incidence and plate steel grade was apparent. The lowest cracking incidence was experienced with Grade 60 materials, but this was based on far less data than those for Grades 55 and 70.

Table B7

Cracking vs. Steel Grade

Steel Grade(A) Number Inspected % Cracked Grade 55 1,187 28 Grade 60 202 22 Grade 65 35 31 Grade 70 1,085 31

(A) Steel grade levels correspond to minimum tensile strength requirements (e.g., ASTM A 285 Grade C is included in Grade 55).

B2.13 The cracking incidences for the two most common plate steel materials were 29% for A 285 Grade C, and 27% for A 516 Grade 70. Among the steel plate materials for which at least 100 inspection results were reported, the highest cracking incidence (36%) was experienced by pressure vessels fabricated with ASTM A 515 Grade 70 steel. B2.14 Table B8 lists the cracking incidence for pressure vessels with and without PWHT. The cracking incidence for pressure vessels with PWHT (25%) was only marginally lower than that for pressure vessels without PWHT (30%). The survey data included some fabrication flaws, as well as hydrogen blistering and HIC that would not be expected to benefit from PWHT. PWHT would be expected to be beneficial for resistance to SSC, SOHIC, and ASCC.

Table B8

Cracking vs. PWHT

Pressure Vessel Condition

Number Inspected

% Cracked

Non-PWHT 2,325 30 PWHT 1,132 25

B2.15 A strong correlation between cracking incidence and the hydrogen blistering history of the pressure vessel was evident, as shown in Table B9. Pressure vessels with a history of hydrogen blistering had approximately twice the cracking incidence (54%) of pressure vessels with no prior history of blistering (25%).



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Table B9 Cracking vs. Blistering History

Pressure Vessel

Condition Number

Inspected % Cracked

No Blisters 2,256 25 Blisters 216 54

B2.16 The presence of weld repairs in pressure vessels did not appear to have a significant effect on cracking incidence, as shown in Table B10. Pressure vessels with prior weld repairs had only a marginally higher cracking incidence (30%) than pressure vessels without weld repairs (27%).

Table B10

Cracking vs. Weld Repairs

Pressure Vessel Condition

Number Inspected

% Cracked

No Weld Repairs 2,022 27 Weld Repairs 506 30

B2.17 The maximum depth of cracking reported is shown in Table B11. Only 38% of the cracked pressure vessels experienced cracking with a maximum depth of less than 3.18 mm (0.125 in). Conversely, more than 60% of the cracked pressure vessels experienced cracking deeper than 3.18 mm (0.125 in). Approximately 20% of the cracked pressure vessels had cracking deeper than 9.53 mm (0.375 in).

Table B11

Depth of Cracking

Crack Depth mm in

Number of Vessels

Percent

< 1.59 < 0.0625 83 12 1.593.18 0.06250.125 185 26 3.184.78 0.1250.188 67 10 4.786.35 0.1880.250 124 18 6.359.53 0.2500.375 99 14 9.5312.7 0.3750.500 45 6 12.719.1 0.5000.750 77 11 19

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