8X194_2006

Item No. 24179 NACE International Publication 8X194 (2006 Edition) This Technical Committee Report has been prepared by NACE International Task Group 301* on Refinery H2S Pressure Vessels: Revision of NACE Publication 8X194: Report Materials and Fabrication Practices for New Pressure Vessels Used in Wet H2S Refinery Service © December 2006, NACE International This NACE International (NACE) technical committee report 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 from manufacturing, marketing, purchasing, or using products, processes, or procedures not included in this report. Nothing contained in this NACE report 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 report should in no way be interpreted as a restriction on the use of better procedures or materials not discussed herein. Neither is this report intended to apply in all cases relating to the subject. Unpredictable circumstances may negate the usefulness of this report in specific instances. NACE assumes no responsibility for the interpretation or use of this report by other parties. Users of this NACE report are responsible for reviewing appropriate health, safety, environmental, and regulatory documents and for determining their applicability in relation to this report prior to its use. This NACE report 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 report. Users of this NACE report 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 report. CAUTIONARY NOTICE: The user is cautioned to obtain the latest edition of this report. NACE reports are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE reports are automatically withdrawn if more than 10 years old. Purchasers of NACE reports may receive current information on all NACE International publications by contacting the NACE FirstService Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 281/228-6200). FOREWORD The objective of this technical committee report is to provide a state-of-the-art overview of the materials selection, fabrication, postweld heat treatment (PWHT), inspection, and testing practices that have recently been applied to new pressure vessels (referred to in this report as equipment) destined for use in wet hydrogen sulfide (H2S) refinery service. This report is intended as a technical resource for material manufacturers, fabricators, and users involved in the specification and fabrication of new equipment used in wet H2S refinery services. Many of the practices discussed in this report were identified in informal industry surveys of refiners, process licensors, and engineering contractors conducted in 1991 by NACE Work Group (WG) T-8-16g and in 2004 by NACE Task Group (TG) 301. This information has been supplemented by the experiences of the work group and task group members and their colleagues. In this report the term “user” refers to the end user of the equipment, i.e., refiners or engineering contractors acting on behalf of refiners during equipment design, purchase, and installation. This report makes extensive use of the terms “some users,” “many users,” and “most users.” These terms were adopted by the work group and task group to give a qualitative feel to the types of user responses received in the informal surveys and follow-up user comments received during the preparation of the report. There is no accurate quantitative correlation between these terms and the actual responses and comments received other than that the progression from “some” to “most” indicates, in the opinion of the task group, a trend from the minority to the majority of users. The titles and source information of the codes, specifications, and standards cited or discussed in ___________________________ *Chair Terrell T. Phillips, Fluor Corporation, Sugar Land, Texas. NACE International this report or the appendixes are provided in Appendix A rather than listed in footnotes throughout the report. Confining this important source document information to one appendix should help readers who have any interest in further research. The intent of the practices reviewed in this report has been to minimize the susceptibility to several forms of lowtemperature (ambient to 150°C [300°F]) hydrogen damage that have occurred when fabricated carbon steel (CS) equipment has been exposed to corrosive refinery environments containing wet H2S. These damage mechanisms have been reported to include sulfide stress cracking (SSC), hydrogen blistering, hydrogen-induced cracking (HIC), and stress-oriented hydrogen-induced 1 cracking (SOHIC). Background information on refining industry practices that have been used to prevent SSC of hard welds is provided in NACE Standard RP0472, which was developed in response to a number of SSC failures that occurred in hard weld deposits in CS equipment in the late 1960s. In addition, a form of alkaline stress corrosion cracking (ASCC) commonly referred to as “carbonate cracking” has been identified in some wet H2S environments, mainly overhead streams in fluid catalytic cracking units (FCCUs) and some process water-handling 1,2,3 equipment. ASCC damage mechanisms are not covered in this report, but are defined and discussed, along with SCC, hydrogen blistering, HIC, and SOHIC, in NACE Standard RP0296. Also, Appendix A of American Petroleum Institute (API) RP 945 provides a concise overview of the cracking mechanisms, including figures showing typical crack morphologies. From the 1991 and 2004 informal surveys, it was determined that many users have selectively specified materials, fabrication, inspection, and testing practices for new equipment after considering and evaluating some of the following factors: • • • • • • • • • • • • • • • • • Experience with similar equipment; Type of process unit involved; Type of equipment involved; Process environment, including but not limited to: Total sulfide concentration in the aqueous phase; Potential for hydrogen activity; pH value of aqueous phase; Cyanide concentration in aqueous phase; CO2 (carbonate) concentration in aqueous phase; Ammonium bisulfide concentration in aqueous phase; Amount of aqueous phase; Temperature; Pressure; and Upset, start-up, and shut-down conditions, including steamout. Corrosion control program to be used; Future inspection requirements; Life-cycle cost; and • NACE International Safety and economic risk based on consequence and probability of failure. It is beyond the scope of this report, and available industry experience, to fully address all of these factors and their impact on the materials of construction and fabrication practices that have been used for new equipment; therefore, for the purpose of this report, TG 301 has developed a simplified scheme by creating three general categories of service. This approach is further described in the section of the report titled Categories of Service. Many of the practices reviewed and discussed in this report, particularly the use of special clean steel plate materials in severe refinery environments, have been shown to have mixed success by extensive plant experience; therefore, even with the use of these practices, damage to CS equipment in severe wet H2S environments continues to be a concern for users. Some refineries have had some degree of success in mitigating the effects of wet H2S environments on CS equipment by the use of water washing, polysulfide injection, or corrosion inhibitors. Some experiences when using such methods are reviewed and discussed in Appendix B. One established method of preventing damage in wet H2S environments has been the use of corrosion-resistant alloy cladding or weld overlay. The experiences and benefits of these methods are reviewed and discussed in Appendix C. Appendix C also includes information on the use of other types of liners such as organic thin-film coatings, cement linings, and thermal spray coatings. These types of liners have been used for the protection of previously operated equipment but have generally not been used for new construction. Most users have used a corrosion-resistant alloy cladding or weld overlay when a liner has been specified. Appendix D contains comparative equipment costs for different materials of construction used in wet H2S service. A significant percentage of the problems found during inservice inspection of CS equipment in wet H2S environments has been found to be the direct or indirect result of pre-existing fabrication flaws. Many of the practices reviewed and discussed in this report have been specified by users to improve the overall quality of fabrication. By employing these practices, users have attempted to reduce the extent and frequency of in-service inspections, make inspection results easier to interpret, and reduce the overall costs associated with performing inspections and making repairs. This report was originally prepared by WG T-8-16g, a component of TG T-8-16 on Cracking in Wet H2S Environments. It was revised in 2006 by TG 301 on Refinery Wet H2S Pressure Vessels: Revision of NACE 23 NACE International Publication 8X194. TG 301 is sponsored administratively by Specific Technology Group (STG) 34 on Petroleum Refining and Gas Processing and sponsored by STG 32 on Oil and Gas Production—Metallurgy. This report is NACE International published by NACE under the auspices of STG 34. It is one of many committee activities that have been sponsored by STG 34 related to the general problem of cracking of CS equipment in wet H2S refinery services. NACE technical committee reports are intended to convey technical information or state-ofthe-art knowledge regarding corrosion. In many cases, they discuss specific applications of corrosion mitigation technology, whether considered successful or not. Statements used to convey this information are factual and are provided to the reader as input and guidance for consideration when applying this technology in the future. However, these statements are not intended to be recommendations for general application of this technology, and must not be construed as such. INTRODUCTION This report reviews and discusses materials selection, fabrication, PWHT, inspection, testing, and corrosion control practices that have been used for recently manufactured new equipment destined for use in wet H2S refinery environments. Some users choose to take a risk-based assessment approach to the application of the following service categories to new equipment using individual plant operating experience when available. For the purpose of this report, it has been assumed that the equipment was designed and built to the ASME Boiler and Pressure Vessel Code (BPVC), Section VIII, Division 1 or Division 2. Piping and atmospheric storage tanks are excluded from the scope of this report. RISK-BASED ASSESSMENT Risk-based principles have been used to help users make decisions concerning materials selection and fabrication practices for equipment. Evaluation of risk has used industry standard approaches such as those found in API RP 580 and API Publication 581 or similar procedures and methodologies unique to the user. In either case, the risk assessment process addresses the likelihood of cracking and the consequence of failure. Materials selection options evaluated have included whether to use steels with special chemistry controls such as carbon equivalent (CE) and microalloy limits to specify HIC-resistant steel, or to use stainless steel (SS) cladding (1) or solid SS (duplex SS or UNS S30000 series [300 series] SS) equipment. Fabrication decisions have included whether special welding procedures addressing preheat, heat input, and/or other factors are used, whether and at what conditions to postweld heat treat equipment, and whether 100% weld inspection is performed to help determine whether fabrication flaws are present prior to placing equipment in service. Several factors have been considered in assessing the probability of low-temperature hydrogen damage of equipment exposed to wet H2S service. The severity of ___________________________ Metals and Alloys in the Unified Numbering System, a joint publication of ASTM International (ASTM), 100 Barr Harbor Drive, West Conshohocken, PA 19428-2959, and SAE International (SAE), 400 Commonwealth Drive, Warrendale, PA 15096-0001. (1) the environment (e.g., the expected level of H2S or NH4HS) and the presence of other crack-promoting agents (e.g., cyanides) are significant factors considered by most users. The strength of material specified has also been considered. For example, some users assign a lower likelihood of cracking to a lower-strength material (e.g., 414 MPa [60,000 psi] tensile strength) than to a higher-strength material (e.g., 482 MPa [70, 000 psi] tensile strength). Another factor is the experience in the exposure environment of existing equipment when replacing or revamping existing units. Finally, whether PWHT of the equipment has or will be used is a factor considered by most users. Operating environments change with time because of changes in feed stock, debottlenecking, temperature changes, etc. The concentration of H2S where vapor streams first come into contact with water is also considered by most users. Stream conditions are typically analyzed and risk assessments reevaluated as these environments change during equipment operating lives. 3 NACE International CATEGORIES OF SERVICE Background Generally, when specifying materials and fabrication practices for new equipment, most users have classified refinery process environments in which the concentration of total sulfide is greater than 50 ppmw in the aqueous phase as wet H2S service. In addition, some users have reported applying some of the practices discussed in this report to process environments with lower concentrations of total sulfide, specifically in cases in which experience has shown wet H2S cracking or blistering to have occurred in equipment exposed to a comparable process environment or operated under comparable upset, start-up, or shut-down conditions. Industry survey results have not established a concentration of H2S below which cracking or blistering problems have not occurred. In the absence of operating experience or more relevant information, Figures 1 and 2 of NACE Standard MR0175/ISO 15156 have sometimes been used as a guideline on process environments that could cause SSC. 4 Petrie and Moore provide examples of this approach. Additional guidance regarding susceptibility to SCC in refining services is also contained in NACE Standard MR0103. Several methods are used to estimate the H2S concentration in the aqueous phase. In existing plants, actual measurements of H2S (and other contaminants) in condensed waters are used to evaluate severity of exposure. Petrie and Moore describe one method based 5 on Henry's Law, and Newman provides an easy graphical method for a wide range of temperatures and concentrations of ammonia (NH3). For the purpose of this report, three general categories of refinery wet H2S service are outlined. These categories were developed from reported user experiences and practices, along with a fundamental understanding of the cracking mechanisms experienced in the process service or environment. Category 1 service has been used in the report to represent a low potential, Category 2 service a moderate potential, and Category 3 service a high potential for low-temperature hydrogen damage in wet H2S refinery environments. These three categories are used in this report to differentiate between practices that have been applied by some users, based on process environment or service, type of equipment, or history. Some equipment known to contain wet H2S are found in crude and vacuum distillation units, FCCU fractionation and light ends recovery sections, delayed coking unit (DCU) fractionation and light ends recovery sections, hydroprocessing unit separation and fractionation sections, sour water stripper overhead systems, and amine unit regenerator and contactor systems. Equipment examples NACE International are wetted sections of drums, heat exchanger shells, and air cooler header boxes, including heads and vapor sections in the condensing zone, and equipment or sections of equipment where an aqueous phase may or could accumulate. Category 1 Service New CS equipment in Category 1 service has been regarded by most users to present a low potential for SSC in weld heat-affected zones (HAZs) and negligible potential for SOHIC in weld HAZs or base metal HIC or blistering. Experience has shown that CS equipment used in this category of service has not been susceptible to severe wet H2S cracking or blistering problems. The principal damage to equipment in this category of service has been SSC as a result of hard HAZ microstructures or hard weld metal. Some users have also judged this category of service applicable to equipment or parts of equipment in more severe process environments that could be easily inspected and possibly repaired on a frequent basis without significant risk to plant safety or production. Some users have also judged this category of service applicable to some types of equipment provided with some protection from the process environment by water washing, polysulfide injection, the use of a corrosion inhibitor, or the application of a nonmetallic coating. These methods of mitigating the cracking potential of CS equipment in wet H2S environments are discussed further in Appendixes B and C. Users have characterized wet H2S Category 1 service in one or more of the following ways: Process Environment Some users have used the following process environments to characterize Category 1 service: Typically a process temperature between ambient and 150°C (300°F) and: • • • • • Low or no potential for hydrogen flux activity as a result of aqueous corrosion; Aqueous phase with 7.6, and HCN >20 ppmw; or • Aqueous phase with > 2 wt% NH4HS; or • Aqueous phase with > 6 wt% NH4HS; or • Conditions defined in API 581 for severe service. History Equipment with significant SSC, SOHIC, HIC, or blistering problems or comparable equipment in a similar service with such problems. MATERIALS OF CONSTRUCTION Background The purpose of this section of the report is to review chemistry and strength grade restrictions, heat-treatment conditions, inspection, and testing requirements that have been frequently specified by users for CS pressure-retaining components in wet H2S service. With the exception of heattreatment condition and ultrasonic examination, many of the general practices described below have typically been used for pressure-retaining components in all categories of service. In addition, special “clean steel” plate manufactured to improve resistance to blistering, HIC, and SOHIC is described in the second subsection. Most users have indicated that standard ASME SA-516 plate material, supplied in accordance with the general practices given below, has provided satisfactory performance when used for equipment in Category 1 service. Some users have indicated that internally coated standard ASME SA-516 plate material and “HIC” ASME SA-516 plate material has provided satisfactory performance when used for equipment in Category 2 service. Some users have indicated that “HIC” ASME SA-516 plate material and standard ASME SA-516 plate material clad with UNS S30000 series SS in accordance with ASME SA-264 have provided satisfactory performance when used for equipment in Category 3 service. General Practices Material Specifications for Equipment Fabrication Many users have utilized ASME material specifications that require the steel to be fully killed (except thin-wall heat exchanger tubing), that set specified limits on residual elements, and that allow user control of the CE as a supplementary requirement. Commonly used material specifications (by product form) that meet these criteria are as follows: • • • • • • Plate: ASME SA-516 grade 55, 60, 65, or 70 Pipe: ASME SA-106 grade B or ASME SA-333 grade 1 or 6 Forgings: ASME SA-105 or ASME SA-350 grade LF1 or LF2 or ASME SA-266 class 1 Fittings: ASME SA-234 grade WCB or ASME SA-420 grade WPL6 Castings: ASME SA-216 grade WCA, WCB, or WCC or ASME SA-352 grade LCA, LCB, or LCC Tubing: ASME SA-179 or ASME SA-214 Some users have also specified that thin-wall heat exchanger tubing be supplied as fully killed steel. In such cases, ASME SA-210 grade A-1 has sometimes been used. 6 6 NACE International Bolt Materials Many users have utilized ASME bolt materials with hardness controlled to 22 HRC (237 HBW) maximum for wetted internal low-alloy steel bolting directly exposed to wet H2S environments. Material specifications commonly used to meet this criterion are ASME SA-193 grade B7M or ASME SA-320 grade L7M. Alternatively, some users have specified bolt materials in accordance with NACE Standard MR0103. Chemical Analysis To verify steel chemistry and CE, many users have specified that welded CS pressure-retaining components be supplied with a Certified Material Test Report (CMTR). Many users have required that chemical analysis results, as reported on the CMTR, include the unspecified elements chromium (Cr), columbium (Cb) (also known as niobium [Nb]), nickel (Ni), vanadium (V), molybdenum (Mo), and copper (Cu). Most of these elements are required to calculate the CE. Limits on these unspecified elements are provided in the applicable ASME material specification. Many users have reported trying to specifically avoid the use of CS materials with deliberate additions of microalloying elements because of potential HAZ (2) microstructure and hardness problems. It has been shown that the effect of Cb and V on HAZ hardness is dependent on the carbon level in the steel and welding heat input. Pipeline steels with carbon 0.12 wt% to be limited to Cb ≤0.01 wt% or V ≤0.02 wt% with Cb + V ≤0.015 wt% to control HAZ hardness 9,10 without PWHT. When Cb + V are present at higher levels in steels with carbon >0.12 wt%, PWHT at 635°C (1,175°F) for 2 h minimum of welds made with low heat input is specified by some users to reduce HAZ hardness 10,11 below 248 HV10. Carbon Equivalent For welded components, many users have specified a controlled base material CE as one step in the control of the weld HAZ microstructure and hardness. However, a minimum CE is necessary to impart the minimum specified tensile strength to the base material. A commonly specified maximum CE value for CS pressure___________________________ In sour oil and gas pipelines and flowlines there have been many successful applications of carbon steels containing deliberate additions of microalloying elements, e.g., Cb + V + titanium (Ti) 0.12 wt carbon and microalloyed in the range of 0.015 wt