NACE 34103

Item No. 24222 NACE International Publication 34103 (2014 Edition) This Technical Committee Report has been prepared by NACE International Task Group (TG) 176,(1) “Sulfidic Corrosion: Prediction Tools.”

Overview of Sulfidation (Sulfidic) Corrosion in Petroleum Refining Hydroprocessing Units © June 2014, 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 NACE reports are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE reports are automatically withdrawn if more than 10 years old.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, 15835 Park Ten Place, Houston, Texas 77084-5145 (telephone +1 281-228-6200).

Foreword The objective of this report is to provide a document to help predict sulfidation rates and point out areas of vulnerability in the equipment associated with hydroprocessing units. It is intended for use by corrosion engineers and fixed-equipment inspectors. The report summarizes corrosion rate and materials of construction data collected from operating hydroprocessing units and compares them to previously developed corrosion rate curves, based on data from numerous refinery units. The scope of this report includes: Literature Search Results Sulfidation in Hydrogen-Free Environments—Mechanism of Sulfidation Corrosion Sulfidation in Hydrogen-Hydrogen Sulfide Environments—Mechanism of H2-H2S Corrosion Hydroprocessing—Process Overview Sulfidation in Distillation and Fractionation Facilities Downstream from Hydroprocessing Units Advances in Understanding Since the 2004 Publication of this Technical Committee Report (1)

Chair Brian Tkachyk, Suncor Energy, Calgary, AB, Canada

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NACE International This report does not include: A comprehensive review of all variables that affect sulfidation A comprehensive review of damage mechanisms other than sulfidation An overview of sulfidation in all refinery process units This technical committee report was originally prepared in 2004 by Task Group (TG) 176 on Prediction Tools for Sulfidic Corrosion, which is administered by Specific Technology Group (STG) 34 on Petroleum Refining and Gas Processing. It was revised in 2014 by TG 176. It is issued by NACE International under the auspices of STG 34.

NACE technical committee reports are intended to convey technical information or state-of-the-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.

Table of Contents Introduction ........................................................................................................................................3 Hydroprocessing—Process Overview................................................................................................7 Sulfidation in Distillation and Fractionation Facilities Downstream from Hydroprocessing Units .......9 References ......................................................................................................................................17 APPENDIX A: Modified McConomy Curves ....................................................................................20 APPENDIX B: Corrosion Prediction Curves for H2-H2S Service3 ...................................................21 APPENDIX C: Summary of REFIN•COR™ Excerpts ......................................................................25 APPENDIX D: Survey Data Summary and REFIN•COR™ Data (K) ...............................................28 APPENDIX E: NACE TG 176 Survey Results .................................................................................39 FIGURES Figure 1: Typical Flow Scheme for the Stripping and Fractionation Section of a Hydrotreater ..........7 Figure 2: Tail-End Distillation Process Flow Scheme for Two-Stage Hydrocrackers .........................8 Figure 3: Intermediate Distillation Process Flow Scheme for Two-Stage Hydrocrackers ..................8 Figure 4: Typical Distillation Flow Scheme for Single-Stage Hydrocracker........................................9 Figure A1: Sulfidic Corrosion Prediction in Absence of H2 ..............................................................20 Figure B1: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of CS (naphtha desulfurizers). .............................................................................................................21 Figure B2: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of CS (gas oil desulfurizers). ...............................................................................................................21 Figure B3: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 5Cr1/2Mo steel (naphtha desulfurizers). .........................................................................................22 Figure B4: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 5Cr1/2Mo steel (gas oil desulfurizers). ............................................................................................22 Figure B5: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 9Cr1Mo steel (gas oil desulfurizers). ...............................................................................................23 Figure B6: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 9Cr1Mo steel (naphtha desulfurizers). ............................................................................................23 Figure B7: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 12Cr SS..............................................................................................................................................24 Figure B8: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 18Cr/8Ni SS...............................................................................................................................24 Figure E1: Sulfidic Corrosion of Carbon Steel Hydroprocessing/Desulfurizing—H2-Free 1961 API Questionnaire and 2000 NACE Survey......................................................................39 Figure E2: Sulfidic Corrosion of Carbon Steel Hydroprocessing/Desulfurizing—H2-Free 1961 API Questionnaire and 2000 NACE Survey .....................................................................................40 Figure E3: Sulfidic Corrosion of 1 to 3% Cr Steel Hydroprocessing/Desulfurizing—H2-Free 1961 API Questionnaire and 2000 NACE Survey ..............................................................................41

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Figure E4: Sulfidic Corrosion of 5% Cr Steel Hydroprocessing/Desulfurizing—H2-Free 1961 API Questionnaire and 2000 NACE Survey .....................................................................................42 Figure E5: Sulfidic Corrosion of 4 to 6% Cr Steel Hydroprocessing/Desulfurizing—H2-Free 1961 API Questionnaire and 2000 NACE Survey ..............................................................................43 Figure E6: Sulfidic Corrosion of 7% Cr Steel Hydroprocessing/Desulfurizing—H2-Free 1961 API Questionnaire and 2000 NACE Survey .....................................................................................44 Figure E7: Sulfidic Corrosion of 9% Cr Steel Hydroprocessing/Desulfurizing—H2-Free 1961 API Questionnaire and 2000 NACE Survey .....................................................................................45 Figure E8: 12% Chromium Steel Combined Data 1961 API Questionnaire and 2000 NACE Survey.......................................................................................................................................46 Figure E9: 18/8 SS Combined Data 1961 API Questionnaire and 2000 NACE Survey ...................47 TABLES Table 1: % Cr Content of Steel for FCr ..............................................................................................6 Table 2: Commonly Used Sulfidation Rate Prediction Tools in Hydroprocessing Units ...................15 Table D1: 2000 NACE Survey Data for Carbon Steel ......................................................................28 Table D2: 2000 NACE Survey Data for 1 to 3% Cr..........................................................................34 Table D3: 2000 NACE Survey and REFIN•COR™ Data for 5% Cr(K) ............................................34 Table D4: 2000 NACE Survey Data for 9% Cr.................................................................................36 Table D5: 2000 NACE Survey Data for 18/8 SS ..............................................................................37 Table D6: Summary of Sulfur Analysis Test Methods Reported ......................................................38

Introduction The type of sulfidation described in this report is the corrosion of metal resulting from reaction with sulfur compounds in hightemperature environments such that a surface sulfide scale forms, often with sulfur penetrating somewhat below the original thickness. In this report, “sulfidation” does not refer to extensive internal attack below the original wall thickness that occurs at temperatures in excess of 1,000 °F (538 °C). The terms “sulfidic corrosion” and “high-temperature sulfidic corrosion” used in many refining industry technical references on this subject refer to this same damage mechanism and are considered equivalent for the purposes of this report. Sulfidation of carbon and low-alloy steel components has long been a recognized phenomenon in petroleum refineries. Crude oils often contain from 0.5 to 5 wt% sulfur in a variety of different sulfur compounds. Sulfidation was first encountered in refineries in crude distillation units, thermal and catalytic cracking plants, thermal reforming, and coking units where the crude 1 oil and its fractions were processed at temperatures exceeding 500 °F (260 °C). Steel alloys containing 5% chromium (Cr) or greater (i.e., 7% Cr, 9% Cr, and 12% Cr, in that order), were found to have increasing resistance to sulfidation. Over time, empirically based corrosion prediction curves were generated and improved based on refinery experiences. These curves are 2 still useful to this day for refining processes containing significant quantities of sulfur compounds. In the 1940s and 1950s, the advent of refining processes that utilized hydrogen, such as catalytic reforming and hydroprocessing, introduced another facet of sulfidation. It was observed that for sulfidation services containing hydrogen, steel alloys containing up to 9% Cr were, at best, only slightly more corrosion resistant than carbon steel (CS). Sulfidation in the presence of H2 is often referred to as H2-H2S corrosion. Much research was done and some of this work was published. A 3 separate set of corrosion prediction curves for H2-H2S conditions was compiled and published and is still generally useful. Several licensors and refining companies have their own methodology, or set of proprietary corrosion curves, that are used for material selection and corrosion rate prediction. By the 1990s, several refiners began to report sulfidation in equipment such as piping and reboiler furnace tubes in 4 fractionation and distillation facilities downstream from hydrotreaters and hydrocrackers. The corrosion was considered unusual in these instances because these facilities are considered to be H2-free, and the total sulfur content of the hydrocarbon stock was very low. In some cases, chromium-molybdenum (Cr-Mo) steels corroded at the same rates as CS. It was recognized that the existing corrosion prediction curves were inadequate for these specific circumstances, and efforts were made to better understand the problem. This led to the formation of NACE TG 176, Prediction Tools for Sulfidic Corrosion. Despite ongoing efforts, sulfidation continues to be significant risk in the refining industry. American Petroleum Institute (1) 5 (API) RP 939-C and this report describe many process and materials variables that can influence sulfidation. This complexity and the limitations of publicly available sulfidation rate prediction tools make highly accurate sulfidation wall loss (2)

American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005.

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NACE International

NACE International rate predictions difficult. In addition to sulfidation, there are other damage mechanisms that can occur in environments where sulfidation is active; a comprehensive discussion of these risks is outside the scope of this report. Literature Search Results

A brief summary of the current understanding of high-temperature sulfidation is provided in the following sections. For a more in-depth study of sulfidation, the reader is directed to the resources listed in the bibliography. Sulfidation in Hydrogen-Free Environments—Mechanism of Sulfidation Hydrogen-free services are defined as those in which hydrogen is not intentionally added as part of the process. In some streams, there are small amounts of hydrogen that were not intentionally added, but are liberated from cracking reactions in coking and fluid cat cracking units; however, for the purposes of this report, those streams are referred to as H2-free. Many studies have shown that sulfidation of steel alloys initially follows a parabolic rate law that becomes linear after a short 8,9 period. For CS, the scale that forms is a metal-deficient iron sulfide (Fe1-xS), meaning there are vacancies in the sulfide scale lattice where Fe atoms are usually located under normal stoichiometric conditions. Initial corrosion rates are high because the rate is only limited by mass transport of the corrosive species to the unprotected alloy surface. Once the sulfide scale forms, the corrosion rate slows because it becomes limited by the diffusion rate of the corrosive species through the scale. Steels alloyed with Cr exhibit a two-layered scale: a mixed inner layer of Fe1-xS plus a sulfo-spinel FeCr2S4 scale, and an outer 10 layer of Fe1-xS. As the Cr content of the alloy is increased, the inner layer tends toward a single-phase sulfo-spinel FeCr2S4. 11 It is generally thought that this sulfo-spinel scale is more stable and more protective than Fe1-xS. In alloys with greater than 2% Cr, the concentration of FeCr2S4 in the inner layer of scale is proportional to the Cr content of the alloy, with FeCr2S4 beginning to dominate the inner layer at 5% Cr. This means that alloys such as 5% Cr steel with Cr content close to 4% sometimes form less protective scale than those with slightly higher Cr content. At greater than 40% Cr, only the sulfo-spinel layer is present. 12,13

Four distinct steps have been identified in the sulfidation mechanism. (1)

These steps are:

Adsorption of the sulfur compounds on the scale surface.

(2) Catalyzed decomposition of the sulfur compounds, and inclusion of sulfur in the Fe1-xS scale lattice, resulting in the formation of additional cation vacancies and electron holes. (3)

Diffusion of cation vacancies and electron holes to the Fe1-x S/Fe interface.

(4) Reaction at the Fe1-xS/Fe interface. Fe “oxidizes” to form the scale, thus reducing the concentration of cation vacancies and electron holes; Fe → Fe

2+

-

+ 2e

(1)

The corrosion rate is normally limited by one of these steps. In H2-free environments, it is thought that step (1) or (2) is the 14 rate-limiting step. Studies have shown that some sulfur compounds more readily absorb (or chemisorb) into the sulfide scale 15 than even H2S, and thus exhibit greater corrosion rates when compared to H2S. Chromium in the steel reportedly poisons the catalytic decomposition of sulfur compounds (step [2]) and thus accounts for the improvement in corrosion resistance of steel alloyed with Cr. The diffusion flux of cation vacancies and electron holes through the spinel phase (FeCr2S4) is less than 16 through the Fe1-xS, slowing step (3) and thus limiting corrosion rates. Alloy Performance in High-Temperature Sulfidation Environments (H2-Free) The modified McConomy curves have been generally useful for predicting corrosion rates for various steel alloys in refining 17 process streams based on total sulfur present. However, these modified McConomy curves have been found to be nonconservative for some specific cases, such as fractionation and distillation facilities downstream from hydrotreaters and

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Most of the scientific literature on sulfidation deals with temperatures well in excess of 800 °F (427 °C), and in vapor 6,7 Published papers of direct application to the refining industry have environments of sulfur, mixed gases (O2-S2), or H2-H2S. been based mostly on data collected from pilot-plant and actual-plant experiences. In fact, the two papers most often cited are experientially based. Little fundamental research that furthers the understanding of the thermodynamics and kinetics of sulfidation for the temperature range and process conditions of primary interest to petroleum refining has been published.

NACE International hydrocrackers. For these environments, the curves published in API RP939-C, First Edition, Figure B.13 are more consistent with industry experience (see Table 2). This will be discussed further in this committee report. The original McConomy curves were published in 1963 and were 18 Many data points were from furnace tube based on an industry survey done by the API Subcommittee on Corrosion. corrosion rates that have been based on process stock temperature and thus have not accurately represented the true metal, or inside surface, temperature. Regardless of the reason, they were found to be overly conservative and were later modified. These so-called modified McConomy curves for several alloys (CS, 1-3% Cr, 4-6% Cr, 7% Cr, 9% Cr, 12% Cr, and 18% Cr/8% Ni [18/8] stainless steels [SS]) are still widely used today and are included for reference in Appendix A. They form the 19 basis for the sulfidation rate determination tables found in API RP581. CS is usually resistant to sulfidation up to about 500 °F (260 °C). Although some sulfidation is possible below this temperature and is commonly considered in design, the expected corrosion rates are normally low, considering corrosion allowance and design life normally applied to refinery equipment. Performance between 500 °F (260 °C) and 600 °F (315 °C) can be highly variable depending on several factors such as the types of sulfur compounds and their concentration, process stream flow conditions, and silicon content of the steel. Piping and equipment fabricated using low-silicon-containing carbon steel (< 0.10 wt% silicon) can experience increased sulfidation rates compared to carbon steel containing more than 0.10.wt% Si. API RP 939-C contains detailed information on sulfidation of low-silicon-containing carbon steel. Generally, corrosion rates are high at temperatures above 600 °F (315 °C) for all CS. Low-Cr steels (1 to 3% Cr) are generally not selected to combat sulfidation. The modified McConomy curves show a minor benefit over CS, but there were only a few data points available to draw the original curve. There is not much published 20 experience with these alloys in sulfidation conditions, and some laboratory studies show no improvement over CS. Steels containing 5 to 9% Cr are commonly used for high-temperature sulfidation environments such as those found in crude distillation units and delayed cokers. Generally, 5% Cr steel is resistant up to about 650 °F (340 °C), and 9% Cr steel is generally resistant to 750 °F (400 °C). However, 5% and 9% Cr steel furnace tubes have provided reliable service in crude distillation unit charge heaters and coker furnaces, which can have tube-skin metal temperatures that are even higher. Improvements in analytical methods and quality control have permitted steel manufacturers to make 5% Cr steels with Cr content closer to specification lower limits (typically 4.0%). Significant variability in the sulfidation resistance of 5% Cr steel has been reported as the chromium content has varied within the specification limits. Generally, 12% Cr steel is considered to be resistant to sulfidation in many applications in the absence of hydrogen, and is often used in vessel cladding, pump cases, and pump impellers. It is used to a lesser extent for valve body castings, and has been a piping and furnace tube material. Difficulty with casting and fabrication and in-service embrittlement concerns often exclude it from being considered for pressure-containing components.

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Stainless steel alloys of the 18/8 variety exhibit excellent resistance to sulfidation and have been used in severe services such as furnace tubes and furnace transfer lines. Stainless steel alloys of the 18/8 variety subject to high-temperature service > 700 °F (> 371 °C) are susceptible to sensitization. This condition does not affect sulfidation performance, but does render the alloys susceptible to polythionic acid stress corrosion cracking (PTA SCC) when the equipment is cooled and exposed to 21 moist, aerated conditions. Refer to NACE SP0170 for more information on PTA SCC and its prevention. Sulfidation in Hydrogen-Hydrogen Sulfide Environments—Mechanism of H2-H2S Corrosion

The composition and morphology of the iron sulfide scales formed in H2-H2S environments are essentially the same as those formed by H2-free sulfidation. However, the reason for the disparate performance of alloys such as 5% Cr in H2-free sulfidation and H2-H2S services has not been clearly established.

One suggestion is that in the presence of H2, other less corrosive sulfur compounds were converted into H2S, and the higher H2S concentrations were the reason for the increased corrosion rates. However, process-plant experience and laboratory tests have given contradictory or conflicting results showing that several of these other sulfur compounds (e.g., disulfides, mercaptans) are actually more corrosive than H2S. H2 promotes the decomposition of various absorbed sulfur compounds, counteracting the influence of Cr alloying additions and thus resulting in accelerated corrosion rates (step [2] in the four-step process). This is thought to be a reason that Cr-steel alloys are no more resistant to H2-H2S corrosion than CS. The poisoning effect of Cr on the catalytic generation of H2S (step [2] in the four-step process) is another possible reason why Cr steel alloys show better resistance to sulfidation in H2-free environments while showing only slight or minimal improvement in H2-H2S 22 corrosion.

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NACE International Alloy Performance in High-Temperature H2-H2S Environments Corrosion prediction curves published by Couper-Gorman provide reasonably good estimates of corrosion in H2-H2S environments. These curves are presented for reference in Appendix B. They form the basis for the H2-H2S corrosion rate determination tables found in API Publication 581. It is important to note that the area of the figures that is labeled “No Corrosion” is not fully correct. The curves are only true for carbon and low-alloy steels. Alloys with significant Cr content can corrode in these conditions, because the regions are defined by the stability of FeS and not Cr sulfides. The corrosion rate equations Couper-Gorman generated are given below in Equations (2) and (3). Low-Cr Steels (0 to 9% Cr) CR = FCrFGFS × 2.681 × 10 × e 5

(-10,720/[t + 460])

× (CH2S)

(0.1540 - 0.05891× log C ) H2S

(2)

Where: CR = corrosion rate in mpy (0.0254 mm/y) FG = factor dependent on whether the hydrocarbon is gas oil or naphtha: (naphtha, 1.000; gas oil, 1.896) FS = factor dependent on the source of data. See reference for discussion. (Published Couper-Gorman curves use FS = 1.000.) t = temperature in °F (°C = 5/9 [°F – 32]) CH2S = concentration of % H2S in process stream in mol%. –0.01900 × (% Cr) FCr = 10 FCr = factor dependent on the Cr content of the steel (% Cr), as shown in Table 1 below:

Table 1 % Cr Content of Steel for FCr

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% Cr 0 1 2 3 4

FCr 1.000 0.957 0.916 0.877 0.840

% Cr 5 6 7 8 9

FCr 0.804 0.769 0.736 0.704 0.675

High-Cr Steels CR = FTFS × 2.8145 × 10 × e 4

(-9,644/[t + 460])

× (CH2S)

(0.14645)

(3)

Where: FT = factor dependent on steel type (18/8, FT = 0.166; 12% Cr, FT = 1.0). Note that these values for FT have been corrected from the actual values in the cited paper. This is to match corrosion rates calculated using equation (2) with the reported and measured corrosion rates in the cited paper. Generally, 18/8 SS alloys are used in H2-H2S environments above 500 °F (260 °C) rather than CS or Cr-Mo steel alloys. Corrosion rates have been observed to be excessive in CS and low-Cr steel alloys, and the accumulation of corrosion scales have fouled and plugged process equipment. Corrosion rate has been shown to be a function of H2S partial pressure, but not H2 partial pressure. This is contradictory to comments that the presence/absence of H2 makes a difference, as shown by the different corrosion rate predictions between the Couper-Gorman and modified McConomy curves. Scale Spalling Iron sulfide scales are replete with cracks, fissures, and spalls that form because of the high ratio of the volume of iron sulfide corrosion scale formed to the volume of the corroded iron substrate. The volume increase during scale formation generates compressive stresses in the scale, which eventually cause spalling of the outer scale and a shift of the absorption process to 23 The cracks, fissures, and spalls also provide avenues for corrosive the newly exposed scale surface of the inner scale. sulfur compounds to directly reach the steel surface, bypassing several of the steps outlined above, and thus accelerating corrosion rates. In H2-H2S environments, carbon steel develops a fine-grained iron sulfide layer growing slowly inward and a coarse-grained iron sulfide layer growing more rapidly outward. The inner layer adheres rather well, but the outer layer tends to spall, especially on cooling. Both layers are Fe-deficient and the deficiency increases with temperature and reactive S partial pressure.

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NACE International Iron sulfide scales are susceptible to wear or removal in high-velocity or highly turbulent flow regimes in which the flowing high temperature fluid stream exerts a high shear stress on the scale surface, similar to lower-temperature, aqueous corrosion 24 mechanisms. It is commonly thought that in some process plants, coke deposits, or even heavy hydrocarbon molecules, are capable of sealing cracks and fissures in the scale, helping to strengthen the scale, thus providing more resistance to wear or 25 removal. Flow Regime Corrosion rates under liquid wetted services have been seen to be lower than those under vapor services. It is suggested that this is caused by the relatively low solubility of H2S in liquid hydrocarbon, and that the liquid hydrocarbon limits the adsorption of sulfur on the surface. Some refiners have adopted a six times reduction in predicted corrosion rate in the liquid phase where the original predicted corrosion rate is based on calculating an H2S partial pressure if the stream were vaporized.

Hydroprocessing—Process Overview Hydroprocessing is a general term used to describe certain types of oil refining processes that utilize high temperatures, highpressure hydrogen, and catalysts to achieve certain reactions. Hydrotreating Processes such as hydrotreating and hydrodesulfurizing are used to convert nitrogen- and sulfur-bearing compounds into ammonia (NH3) and H2S, which are then separated from the hydrocarbon stream. Hydrotreating is often done prior to sale, or prior to further processing in a catalytic reformer, fluidized catalytic cracking unit (FCCU), etc. Figure 1 illustrates a typical flow scheme for the stripping and fractionation section of a hydrotreater.

H2S

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H2S Stripper Splitter Column Hydrotreater Reaction Section

Figure 1: Typical Flow Scheme for the Stripping and Fractionation Section of a Hydrotreater These types of processes are often used upstream from the hydrocracking reactor(s) in a hydrocracker unit, a process unit used by many refiners to convert lower-value, heavy gas oils into higher-value products such as gasoline, jet fuel, and diesel oil. The catalysts used in the hydrocracking process are susceptible to poisoning and being rendered inactive by contact with sulfur and nitrogen. Hydrocracking Process Overview There are several different hydrocracking process flow configurations. One typical design incorporates a first stage in which the feed is hydrotreated to remove sulfur and nitrogen from the oil (with moderate cracking), then cracked in the second-stage hydrocracking section. Another common design has only a single-stage hydrocracking section. In both designs, the cracked products are separated in a downstream distillation system. There are a variety of distillation system designs. intermediate distillation and tail-end distillation.

For two-stage hydrocrackers, there are two basic configurations:

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NACE International In tail-end distillation (Figure 2), the first-stage effluent goes through an H2S stripper before being sent to the second stage. Second-stage effluent is then separated in the distillation section. The flow scheme is advantageous because the corrosive H2S is stripped away in the stripper column well upstream from the distillation section.

H2S H2S Stripper Stabilizer Column First-Stage Hydrotreater

Splitter Column

Second-Stage Hydrocracker

Tail-End Distillation

Figure 2: Tail-End Distillation Process Flow Scheme for Two-Stage Hydrocrackers

Figure 3 illustrates an intermediate distillation process flow scheme. Combined effluent from the first and second stages is fed to the distillation section. This often means more corrosive conditions exist in the distillation section because the H2S has not been stripped out upstream. Intermediate distillation design is often applied because a certain degree of hydrocracking sometimes occurs in the first stage. It is advantageous to separate out the light, cracked product from the first stage before sending the oil to the second-stage hydrocracker. H2S

Topping Column

First-Stage Hydrotreater

Products

Splitter Column Second-Stage Hydrocracker

Intermediate Distillation

Figure 3: Intermediate Distillation Process Flow Scheme for Two-Stage Hydrocrackers

Figure 4 illustrates a typical distillation flow design for a single-stage hydrocracker. As with two-stage hydrocrackers, there are several variations of the flow scheme in the distillation section of the process unit.

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NACE International

H2S Splitter

Single-Stage

Stabilizer

Hydrocracker

Fractionator

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Figure 4: Typical Distillation Flow Scheme for Single-Stage Hydrocracker

The effluent from a single-stage hydrocracker closely resembles the combined effluent from a two-stage hydrocracker with an intermediate distillation flow scheme. It contains H2S and other potentially corrosive sulfur compounds. In all cases, the primary corrosion concern in hydrocracker distillation facilities is sulfidation caused by exposure to H2S and other reactive sulfur compounds entrained in the stock. H2-H2S corrosion is typically not a concern because H2 is recovered upstream in separator vessels, and reused in the hydrotreating and hydrocracking reactors (note that the offgases from the strippers, stabilizers, and topping columns have some H2, ~10 vol%). Nomenclature in distillation units is often confusing. Names of the major columns vary from company to company, licensor to licensor, and location to location. Most often, the first column is called a topping column, stabilizer, rectifier, or even a surge vessel. Feed is heated before entering the column, and volatile compounds go overhead; the remainder exit from the bottom. There are no side-cut product streams on this column. The bottoms from the first column go to a second column; often called a splitter, isosplitter, recycle splitter, or fractionator. The product streams are distilled in this column. Often the bottoms stream from this column is the feed oil to the second-stage hydrocracker. Some plants have another splitter column downstream (e.g., jet splitter).

Sulfidation in Distillation and Fractionation Facilities Downstream from Hydroprocessing Units Historical Overview In 1961, the API Subcommittee on Corrosion conducted a survey to gather sulfidation rate data on the hydrogen-free hydrocarbon portions of desulfurizing processes. Respondents provided data on 20 separate units, and corrosion rate vs. temperature data were plotted for various materials of construction (CS through 18/8 SS). The author noted in his report that the questionnaires were incomplete on operating data such as sulfur content, pressure, velocity, flow regime, etc. Although there was “considerable scatter” of the data, they were combined with earlier published and reported data on sulfidation in nondesulfurizing processes and presented as the original McConomy curves. As reported, these curves were modified in 1986. The 1961 API survey reported on hydrogen-free hydrocarbon streams of desulfurizing processes and indicated high corrosion rates that deviated from what was considered normal experience for steel alloys, especially the low Cr steel alloys. For example, there were seven reports of average corrosion rates between 70 and 130 mpy (1.8 to 3.3 mm/y) for 4 to 6% Cr steels operating between 650 and 775 °F (343 to 413 °C). Alloys in this group would normally be expected to corrode at rates less

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NACE International than 20 mpy (0.50 mm/y) in this temperature range. All material groups from CS to 18/8 SS exhibited similar broad data scatter. Excerpts from the NACE information exchange minutes (REFIN•COR™) are included in Appendix C. Aside from a few entries made during the NACE 1960 Annual Conference, reports of high corrosion rates in CS and Cr steel began in the mid-1990s. Typically, reports concerned corrosion of feed furnace or reboiler furnace tubes and hot piping circuits associated with the fractionation or distillation columns. Typically, the stocks were gas oils, but also included several cases of diesel and naphtha desulfurizer fractionators, and one case of a catalytic cracker light ends tower reboiler. In many of these cases, upgrading to 5% Cr resulted in little or no reduction in corrosion rates relative to the rates observed (2) with CS. 9% Cr reportedly offered some improvement, but UNS S34700 (type 347 SS) or UNS S32100 (type 321 SS) was successfully used in the worst cases. Corrosion was described as being generally uniform, but also localized to areas of high velocity/turbulence in some cases. In the case of furnace tubes, there have been reports of accelerated corrosion on the hot fire side of the tube, and cases of accelerated corrosion on the top half of horizontal furnace tubes, where, presumably, H2S and perhaps even H2 concentrate in the vapor phase of stratified flow regimes. The corrosion mechanism was always referred to as sulfidation, as often evidenced by the presence of sulfide scales. H2S breakthrough from the upstream separator or desulfurizer was often blamed, but some recent reports have mentioned mercaptan corrosion. Mercaptans, being formed by hydroprocessing catalysts (mercaptan reversion) and not separated or stripped away, make their way to the fractionation/distillation sections causing sulfidation in the high-temperature regions of the process units. There was also mention of the possibility that there was enough entrained hydrogen with the hydrocarbon to cause H2-H2S corrosion. Some companies have used the fugacity of hydrogen to account for its actual chemical potential in the high-temperature and pressure environment. The fugacity of hydrogen is greater (and therefore the rate of sulfidation) than what the simple partial pressure would imply. This has been done for liquid-filled piping downstream from a heavy oil desulfurization unit separator, for example. The presence of dissolved hydrogen may increase sulfidation rates compared to hydrogen-free sulfidation environments. NACE TG 176 Survey Results and Observations The task group that produced the 2004 version of this report received 14 completed survey responses with corrosion rate and process data in varying detail. The survey data were collected in 2000. Twelve surveys were of distillation facilities downstream from hydrocracking units, and two were from fractionators downstream from diesel hydrodesulfurizers. The data are presented in Tables D1 through D6 in Appendix D, and graphically in Figures E1 through E9 in Appendix E. While a more recent survey has not been done, a few data points reported in REFIN•COR™ have been added to Table D3 in Appendix D. Several observations can be made based on data included in the survey responses: (1) Corrosion rates can be greater than predicted using either modified McConomy or Couper-Gorman curves. (2) Steel with 5% or even 9% Cr has been observed to corrode at rates as high as CS. (3) Corrosion can be locally aggressive, such as in areas of higher velocity or turbulent flow, or on the topside of horizontally oriented furnace tubes. (4) Corrosion rates can be high, even if total sulfur content is low (several parts per million [ppm]). (5) A variety of sulfur species have been identified. (6) The role of hydrogen in the corrosion mechanism in these facilities is still unclear. Effects of Alloying on Sulfidation Resistance The survey data are summarized in Tables D1 through D6 and shown graphically in Figures E1 through E9. The figures also include the data reported in the 1961 API survey for desulfurizing units, H2-free. The more recent data fall within the ranges previously reported. The original McConomy curves, the modified McConomy curves, and the Couper-Gorman curves for varying sulfur/H2S content have been drawn for reference. Upgrading to Cr-Mo steel alloys in hydrocracking and hydrotreating units often did not provide the expected improvement in resistance to sulfidation. Six surveys reported data for 5% Cr, mostly in the stabilizer reboiler furnace and the inlet and outlet piping. These data are summarized in Table D3 and show corrosion rates as high as 50 mpy (1.3 mm/y), approaching the corrosion rates reported for the CS components that the 5% Cr steel --`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

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Unified Numbering System for Metals and Alloys (UNS). UNS numbers are listed in Metals & Alloys in the Unified Numbering System, 10th ed. (Warrendale, PA: SAE International and West Conshohocken, PA: ASTM International, 2004).

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NACE International replaced. Data reported in REFIN•COR™ (2003C5.8-03) suggest that even higher corrosion rates are possible on 5% Cr. Several surveys reported good resistance of 5% Cr for a period of time after upgrading; but then higher corrosion rates associated with changing operation, primarily crude slate changes, increased furnace firing and circulation, and greater unit throughput. Others reported similar corrosion rates without any such period of low corrosion rates. Unfortunately, while these comments were made, the corresponding operating data (temperature, velocity, flow regime, and sulfur content) were not complete, and direct correlation could therefore not be drawn. Performance of 9% Cr steel was mixed. Five surveys contained data for 9% Cr steel. Two reported low maximum corrosion rates of approximately 1 mpy (0.03 mm/y), but three reported moderately high maximum corrosion rates of 15 to 32 mpy (0.38 to 0.81 mm/y). It is noted, however, that two surveys reported short-term (two year) corrosion rate data that are potentially skewed high. These were both for stabilizer reboiler furnace tubes in hydrocracker units. The other case was for 9% Cr stabilizer reboiler furnace tubes in a diesel hydrodesulfurizer with 0.218 wt% total sulfur. The 18/8 SS alloys have shown very good resistance to corrosion in these services. The highest corrosion rate reported was 8 to 10 mpy (0.2 to 0.25 mm/y) on the top half of a horizontal tube in a reboiler furnace. Several survey respondents, who upgraded from CS to 5% Cr or 9% Cr but still suffered high corrosion rates, reported upgrading to UNS S32100 or UNS S34700 with success (low corrosion rates). This parallels experience for H2 services and raises the question of the role of hydrogen in these cases of higher than expected corrosion rates of the Cr-Mo steels. It is probably true that some levels of H2 are always present and dissolved into the hydrocarbon phase. Equipment Affected by Corrosion Corrosion was most aggressive in the hot piping components and furnace tubes. There were several cases in which corrosion rates of the hot piping were equal to those reported for the furnace tubes. Some corrosion was reported in columns, but at significantly lower rates. Exceptions include several reports of high corrosion rates at nozzles and in one hydrodesulfurization (HDS) fractionator. Effect of Flow Regime in Piping Corrosion rates were generally higher in regions of high velocity or turbulence where high wall shear stresses would be expected. Several respondents reported higher corrosion rates at changes of direction (elbows, tees, return bends), in pump impellers, and in pump suction and discharge spools. Two respondents reported accelerated corrosion in the piping downstream from flow control valves, and another reported accelerated corrosion just downstream from an orifice plate. Accelerated sulfidation rates in 26 areas of high velocity and turbulent flow is not a new phenomenon. However, these reported cases appeared to be particularly aggressive in relation to the overall circuit. In these cases, when sulfidation might not have been adequately anticipated, standard thickness measurement location (TML) placement probably did not consider the possibility of aggressive localized corrosion.

There have been at least four documented cases of locally aggressive corrosion in the top 180° of horizontal furnace tubes. Some cases resulted in tube rupture and fires. Two cases were in the convection section, with one being localized to the top side of the bottom row of bare shock tubes, and the other being localized to the first two inlet rows of studded tubes. A third case involved a rupture at the 12 o’clock position on a radiant wall tube, and another case involved a rupture of a radiant roof tube at the 12 o’clock position. These are important cases to consider. Historically, the most aggressive sulfidation rates occur on the fire side of the tube. Consequently, inspection measurements are taken on the fire side, but that sometimes misses this type of attack. Also, convection section tubes are difficult to access and readings are taken at return bends. This has been considered a good area to inspect because it is a change in direction and sometimes exhibits higher corrosion rates. However, most convection tubes are finned or studded to improve heat transfer, and the inside film temperatures are even higher than predicted. The theory for the cause of corrosion along the top of horizontal tubes is that the flow regime is stratified, meaning there is liquid along the bottom and vapor along the top, allowing reactive sulfur species to concentrate more in the vapor phase, resulting in accelerated corrosion rates. In addition, the liquid layer at the bottom of the tube provides a diffusion barrier, resulting in lower corrosion rates. Metal temperatures could also be hotter at the top, if there is two-phase flow and a vapor exists in the top portion of the tube. Sulfur Analysis Methods and Identification One of the weak points in the data collected in the survey was a lack of quantitative sulfur content data. Most surveys did not report exact sulfur content, but instead reported sulfur levels to be in a range, or less than some value. Also, most surveys

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Effect of Flow Regime in Furnace Tubes

NACE International reported a total sulfur value; only a few surveys reported that the sulfur was H2S, mercaptan, or other sulfur species (disulfide, thiophene, etc.). When other sulfur species were reported, only two respondents made an attempt to identify the types. The types of sulfur species identified included H2S, C1 to C5 mercaptans, disulfides, and thiophenes. Without the inclusion of specific sulfur species, it was difficult to explain why some refiners had high corrosion rates and others reported rates that were comparably low, even when total sulfur levels were in the same range or lower. One probable and widely accepted explanation deals with reactive sulfur species and the tendency of a specific sulfur type to break down and form H2S. Subsequent work, however, showed that mercaptans and disulfides are usually corrosive, and are typically more aggressive than H2S. This is difficult to know for certain, because some sulfur analyses convert all of the sulfur to H2S. The reasons listed for unavailability of sulfur data were: •

the difficulty of obtaining representative samples

•

test methods not being readily available for identification

•

most refiners not having a specific need to know these data in order to control the process, or having a finished product specification that controlled sulfur to these low levels.

Table D6 lists the sulfur test methods reported in the surveys and gives a general understanding of the sulfur levels and maximum corrosion rates. Some of the methods work on the principle of introducing the sample into an oven at high temperatures and converting the sulfur to H2S. Ultimately, H2S is the type of sulfur measured, and the analysis assumes that all sulfur is converted to H2S. Based on the data in Table D6, refiners that reported even a few ppm of sulfur have experienced corrosion. The corrosion rate was dependent on the type and concentration of the sulfur species present, as well as the temperature, flow conditions, and perhaps other elements such as hydrogen. Those that reported 100 ppm total sulfur or more had a high likelihood of experiencing significant corrosion. Possible Effects of Hydrogen The gas streams from the stabilizer overhead system have been reported to contain 10 to 15 vol% hydrogen. It has been assumed that the stabilizer feed and bottoms streams are hydrogen-free, but it is possible that hydrogen is present in large enough quantities to affect the corrosion mechanism. Significant Findings The data collected by this task group, along with the data collected by the API committee back in the early 1960s, show that corrosion rates are sometimes high in the hydrogen-free portion of desulfurizing units, specifically fractionation and distillation facilities downstream from hydrotreaters and hydrocrackers. It is clear that while some units experience aggressive corrosion rates, many do not. In some cases, only a few ppm of sulfur has the ability to cause significant corrosion. Advances in Understanding Since the 2004 Technical Committee Report and Remaining Gaps in Data The following advances in understanding related to sulfidation in hydroprocessing units have been made since the 2004 publication of this report. (1) Relative corrosiveness of various sulfur species At least six sulfur species have been commonly identified as reactive (or active) with respect to sulfidation including elemental sulfur (vapor), H2S, mercaptans, organic sulfides, disulfides, and polysulfides. Thiophenes have been 27 commonly identified as less reactive. •

28,29

Theory of mercaptan reversion (or recombination)

Mercaptans can be formed in hydrotreating and hydrocracking reactors and sometimes show up in the effluent if the catalyst systems are not specifically designed to prevent it. That mercaptans form in a hydrotreater is counterintuitive until you recognize that the reactions are somewhat reversible. It is also worth noting that a small degree of hydrocarbon molecule cracking occurs over all hydrotreating catalysts, so the boundary between hydrotreating and hydrocracking is indistinct.

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NACE International The art of catalyst design and selection is to balance the dual functions of treating (metal catalyzed) and cracking (acid site is catalyzed) across the reactor. A mercaptan will be formed when olefinic cracking intermediates react with H2S rather than hydrogen. The conditions favoring this are cracking catalyst, high temperatures, and increased H2S/H2, all of which tend to be at the exit of a hydroprocessing reactor. The olefin is typically a byproduct from the catalyst/oil conversion chemistry or residual unsaturated feed compounds. Hence, units with more coker feed components are more susceptible to mercaptan recombination. In addition, units with higher feed sulfur and/or recycle gas H2S also cause a higher tendency of mercaptan recombination reactions. Mercaptans in the reactor effluent will tend to go with the liquid product rather than the gas and so appear in the naphtha, distillate, and gas oil fractions. Mercaptan recombination tends to materialize in the naphtha boiling range of these reactor effluent products, whether it is a naphtha, diesel, or gas oil unit. To varying degrees, this is expected in hydrotreaters that are operated for any level of conversion (cracking) and all hydrocrackers. In these units, the catalyst system is designed with a significant layer of hydrotreating catalyst designed to have minimal acid site activity and maximum desulfurization activity so that mercaptans do not appear in the naphtha or distillate fractions. Based on empirical evidence, relatively small concentrations of mercaptans (on the order of a few ppm) 30 sometimes lead to significant sulfidation rates. •

Determination of what species hydrotreating and hydrocracking catalysts usually form The catalyst kinetics of hydrotreaters and hydrocrackers are as different as the catalyst used. Hydrotreaters generally used Co-Mo or Co-Ni catalyst. A common primary kinetic controlling factor is the H2S partial pressure. As the reaction progresses, the H2S is purged from the system. With hydrogen and pressure conservation, the H2S is removed prior to reentry into the catalyst (as recycled hydrogen) to avoid a shifting of the reaction to lower efficiency. Newer hydrotreater reactions are shifting the order of the equipment, but have not eliminated the need for clean hydrogen with minimal H2S. Hydrocracker reactors use different catalysts and have different kinetics, which do not include sulfur levels. This allows the option of leaving the H2S in the reactor effluent until a later removal step. Because of this, downstream considerations evaluate the potential sulfidation problems that H2S concentration causes.

(2) Role of hydrogen at relatively low partial pressure •

Level of hydrogen dissolved in oil coming from separators Measured data have not been reported, but some have used fugacity calculations to estimate the effective hydrogen partial pressure in liquid hydrocarbon streams in equilibrium with a gas phase.

(3) Understanding of the sulfidation mechanism •

Focus on the temperature range of 500 to 800 °F (260 to 427 °C), in oil and mixed-phase service, especially the combined influence and possible synergy of flow regime (mechanical forces, e.g., wall shear stress) and corrosiveness. API 939-C describes many factors that influence or synergize with sulfidation to alter wall loss rates. For example, recent industry experience indicates that unusual flow regimes sometimes occur in deadlegs due to a thermo-siphoning effect, whereby a thermal gradient leads to a low or intermittent flow. This unexpected flow draws in new process material containing reactive sulfur compounds, leading to elevated concentrations of H2S in the deadleg vapor space. The result can be significantly higher corrosion rates in the vapor space compared to liquid-exposed piping.

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•

Thermodynamics of FeCr2S4 spinel phase Alloys such as 5% Cr steel with Cr content close to 4% sometimes form less protective scale than those with slightly higher Cr content. See the section titled “Sulfidation in Hydrogen-Free Environments—Mechanism of Sulfidation Corrosion” in this report for more detail.

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NACE International •

Role of coke and heavy hydrocarbons—determine whether they bind with the corrosion scale and enhance corrosion resistance

(4) Relationships between the Couper-Gorman and the McConomy curves •

If the influence of hydrogen on corrosion is understood, can these curves be combined? The influence of hydrogen on sulfidation and at relatively low hydrogen partial pressures such as those found in distillation and fractionation facilities downstream from hydroprocessing units has been related to its effect on sulfur activity. The idea is that in these lower-hydrogen partial pressure environments, increased hydrogen partial pressure reduces sulfur activity and therefore corrosion rates. At higher partial pressures of hydrogen normally associated with Couper-Gorman curves, this effect is not readily apparent. Because of fundamental differences in the data used to produce the Couper-Gorman and McConomy curves and continued uncertainty of the influence of hydrogen at all partial pressures, the curves cannot be practically combined.

(5) Concept that all 18/8 SS are equal in terms of sulfidation A difference in the sulfidation resistance between different grades of 18/8 SS has not been reported in industry literature. However, the various commercially available grades can have potentially large differences in their resistance to other damage mechanisms, such as PTA SCC or sigma phase embrittlement. (6) Sulfidation and naphthenic acid interaction Naphthenic acid corrosion (NAC) is a concern in hydroprocessing units upstream from reactors, especially if naphthenic acid content of the feed is high. Sulfidation prediction tools such as modified McConomy curves do not include the effect of naphthenic acid. Other commercially available tools can be used to predict corrosion in crude oils (and side cuts) in H2-free environments. In laboratory studies of NAC, researchers tend to find that unless reactive sulfur contents are very low, sulfidation dominates and that it is difficult to simulate NAC in the laboratory. In the absence of a good understanding of sulfidation and NAC interaction and a specific publicly available prediction tool, material selection focusing on NAC resistance is also beneficial for resisting sulfidation, since the most common materials used are high-Mo stainless steels, which are also resistant to sulfidation. Corrosion of low- and high-Cr steels in hydroprocessing units containing high sulfur and total acid number (TAN) streams with or without H2 remains a subject for further study and data collection; the availability of plant experience and data for these environments is limited. There are a number of different theories concerning corrosion mechanisms after the hydrogen injection point where 31 NAC is a potential concern, although currently available plant data are not able to prove a particular mechanism. Although there have not been any reported cases of NAC on 300 series SS downstream from the hydrogen injection point, this information is based on an informal survey and review of REFIN•COR™ information. The reason that high rates of NAC have not been reported downstream from the hydrogen injection point is not yet known. (7) Common use of sulfidation rate prediction tools in hydroprocessing units The process of predicting sulfidation rates for small oil companies without large research groups has frequently been a trial and error process. McConomy and Couper-Gorman curves and actual measured corrosion rates have commonly been used to predict “worst possible” corrosion rates. The desire has been to develop a predictor that would allow more accurate materials selection. The actual corrosion rate of the system is used to temper the results of any predictors. Ultrasonic testing, corrosion probes, and laboratory testing are used to focus efforts to find the most likely failure areas. In the refining industry, the two most commonly used, publicly available sulfidation rate prediction tools used in the past have been modified McConomy curves for H2-free sulfidation and Couper-Gorman curves for H2-H2S corrosion.

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Some theories concerning the effects of coking and the nature of the hydrocarbon phase are reported in API RP 939-C.

NACE International

The original McConomy curves were based on an industry survey and were later modified by a factor based on plant data. The Couper-Gorman curves were also based on an industry survey that includes the effect of H2 on the overall corrosion rate; however, the H2 partial pressures used for these curves are not clearly known, but generally believed to be relatively high. From these curves, corrosion rates of alloy steels are found to be higher in gas oil than in naphtha, keeping other factors the same. Typically, gas/oil hydrotreaters operate at higher pressures than naphtha hydrotreaters and more often than not contain a higher amount of H2 (higher treat gas purity). This suggests that a higher corrosion rate is observed at higher H2 partial pressure. A third set of curves has recently been published in API RP 939-C, Fig. B.13 for low H2 partial pressure, low H2S partial pressure H2S/H2 vapor corrosion. Original NACE curves (all vapor) for higher H2 partial pressure (API RP 939-C, Fig. B.11) were adjusted based on plant experience to develop curves for lower H2 partial pressure, with the belief that S activity resulting from H2S is greater at low H2 content. However, H2 partial pressure used for these curves is not clearly known. It is noted that these curves: • Indicate a higher sulfidation rate at low H2 partial pressure, contrary to API RP 939-C, Fig. B.11 or as might be inferred from the Couper-Gorman curves. •

Are limited to CS and alloy steels only (0 to 9% Cr).

These curves also predict the same corrosion rates for CS and 9% Cr for any given condition. These curves have been consistent with the industry experience of unusually high corrosion rates of alloy steels in or around stripper/stabilizer reboilers and hydroprocessing distillation columns at low H2S-low H2 conditions. Both modified McConomy and Couper-Gorman curves usually indicate low corrosion rates for this condition. The application of API RP 939-C Fig. B.13 for this special condition often suggests the use of 300 series SS, which Couper-Gorman has found consistent and satisfactory. A summary of commonly used sulfidation rate prediction tools in hydroprocessing units is given in Table 2. This attempts to include all major areas of hydroprocessing units such as hydrotreaters, hydrocrackers, etc. However, these units sometimes have different configurations that shift the corrosion mechanisms and selection of prediction tools to something different than described. For this reason, unit-specific review is done. This is also the case for equipment such as heat exchangers, where more than one corrosion mechanism applies and therefore more than one prediction tool is used.

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NACE International Table 2 Commonly Used Sulfidation Rate Prediction Tools in Hydroprocessing Units Corrosion Mechanism

Process Area

Feed before Injection Point

H2

H2-Free Sulfidation (Note 1)

Corrosion Prediction Tool

Modified McConomy

Comments

Industry experience is satisfactory and consistent with modified McConomy in the absence of H2.

Industry experience is satisfactory and consistent with CouperGorman. Use of API-939C Fig. B.13 is limited to 0 to 9% Cr steels and low H2 partial pressure only. H2 partial pressure of these curves is not clearly known.

H2 Injection Point to Reactor

H2-Free Sulfidation/H2H2S Corrosion (Note 1)

Modified McConomy/Cou per-Gorman

Reactor to Separator /s

H2-H2S Corrosion (Note 2)

Couper-Gorman

Industry experience is satisfactory and consistent with CouperGorman.

Separator to Reactor Effluent Air Cooler (REAC) (vapor before water wash) OR Reactor Effluent to REAC (before water wash)

H2-H2S Corrosion

Couper-Gorman

Industry experience is satisfactory and consistent with CouperGorman.

Separator/s to Stripper/Stabilizer (Liquid)

H2-Free Sulfidation/H2H2S Corrosion

Modified McConomy/Cou per-Gorman

Liquid can contain or not contain a significant amount of H2 depending on the unit configuration. Industry experience is satisfactory and consistent with the appropriate tool for the given corrosion mechanism.

For H2 injection upstream of feed/effluent exchangers, modified McConomy is also used in conjunction with other tools for the conditions of low H2S content and relatively low temperature and the worst case corrosion rate selected.

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NACE International

Industry has experienced unusual corrosion of alloy steels in reboilers, which is not well understood. Typically, modified McConomy curves are applicable for conditions of low H2S and negligible partial pressure of H2 in stripper/stabilizer bottoms. However, unusual corrosion suggests the possibility of high temperature H2-H2S in reboiler tubes where industry experience with 300 series SS is satisfactory and consistent with Couper-Gorman. API-939C Fig B.13 also seems to be consistent with industry experience of unusual corrosion of alloy steels; however, it is limited to 0 to 9% Cr steels only.

Stripper/Stabilizer Reboiler

H2-Free Sulfidation/H2H2S Corrosion

Modified McConomy/ CouperGorman/ API939C Fig. B.13

Stabilizer to Fractionator

H2-Free Sulfidation

Modified McConomy

Industry experience is satisfactory and consistent with modified McConomy in the absence of H2.

Stripper/Stabilizer to Products

H2-Free Sulfidation

Modified McConomy

Industry experience is satisfactory and consistent with modified McConomy in absence of H2.

Fractionator to Products

H2-Free Sulfidation

Modified McConomy

Industry experience is satisfactory and consistent with modified McConomy in absence of H2 at low total S and relatively lower temperatures.

Note 1: The potential interaction between sulfidation and NAC is usually considered. Note 2: It has been established in the industry that naphthenic acid is destroyed in the presence of H2 and catalyst in reactors. The following “Remaining Gaps in Data” were identified in the 2004 publication of this report and remain areas for further investigation:

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•

Recommended practices for sampling and testing (identification)

•

Kinetics—what is, or are, the rate-limiting steps?

•

Data for the broad ranges of those alloys and conditions being used in modern refineries in terms of the CouperGorman and McConomy curves. Data for alloys other than those mentioned in the 2004 report have not been reported, as these are not commonly used for sulfidation service in hydroprocessing units.

•

Data concerning greater range of temperature and ranges of H2 and H2S pressures to better describe corrosion in modern refining processes. Industry survey information gathered for the 2004 report was not updated for this revision, so newer types of units, such as ultra low sulfur diesel (ULSD) or other, more modern, higher-severity hydroprocessing units, are not included in the survey data.

References 1. G. Sorell, W.B. Hoyt, “Collection and Correlation of High-Temperature Hydrogen Sulfide Corrosion Data—A Contribution to the Work of NACE Task Group T-5B-2 on Sulfide Corrosion at High Temperatures and Pressures in the Petroleum Industry from the M.W. Kellogg Co.,” Corrosion 12, 5 (1956): p. 213. 2.

B.J. Moniz, W.I. Pollock, eds., “Process Industries Corrosion—The Theory and Practice” (Houston, TX: NACE, 1986).

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NACE International 3. A.S. Couper, J.W. Gorman, “Computer Correlations to Estimate High Temperature H2S Corrosion in Refinery Streams,” MP 10, 1 (1971): p. 31. 4.

REFIN•COR™ (latest revision) (Houston, TX: NACE).

5. API RP 939-C (latest revision), “Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries, First Edition” (Washington, DC: API). 6.

G.Y. Lai, “High-Temperature Corrosion of Engineering Alloys” (Materials Park, OH: ASM International,

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1990).

7. R.C. John, A.L. Young, A.D. Pelton, W.T. Thompson, “Sulfidation Corrosion in the Presence of Oxidizing Gases,” CORROSION/2004, paper no. 04532 (Houston, TX: NACE, 2004). 8.

D.J. Young, “The Sulfidation of Iron and its Alloys,” Reviews on High-Temperature Materials 4, 4 (1990): p. 299.

9.

E.W. Haycock, “High Temperature Metallic Corrosion of Sulfur and Its Compounds” (Pennington, NJ: ECS,

(4)

1970): p. 186.

10. S. Mrowec, K. Przybylski, “Defect and Transport Properties of Sulfides and Sulfidation of Metals,” High Temperature Materials and Processes 6, 1 and 2 (1984): p. 1. 11. W.S. Sharp, E.W. Haycock, “Sulfide Scaling under Hydrorefining Conditions,” API Proceedings, Division of Refining, held May 1959 (Washington, DC: API, 1959). 12. Z.A. Foroulis, “High Temperature Degradation of Structural Materials in Environments Encountered in the Petroleum and Petrochemical Industries: Some Mechanistic Observations,” Anti-Corrosion Methods and Materials 32, 11 (1985): p. 4. 13. A.S. Foroulis, ed., “High-Temperature Metallic Corrosion of Sulfur and its Compounds” (Pennington, NJ: ECS, 1970): pp.186207. 14. H. Arm, L. Hulett, M. Qureshi, F. Hugli, C.M. Hudgins Jr., R. Delahay, “Mechanism of the Iron-Hydrogen Sulfide Reaction at Elevated Temperature,” Journal of the Electrochemical Society 107, 4 (1960). 15. A.S. Couper, “High Temperature Mercaptan Corrosion of Steels,” Corrosion 19, 11 (1963): p. 396. 16. R.W. Cahn, P. Haasen, E.J. Kramer, eds., Materials Science and Technology: A Comprehensive Treatment; Corrosion and Environmental Degradation, Volume I (Hoboken, NJ: Wiley, 1998), p. 113. 17. S.D. Cramer, B.S. Covino Jr., eds., ASM Metals Handbook, Vol. 13A: Corrosion: Fundamentals, Testing, and Protection (Materials Park, OH: ASM International, 1987), p. 1270. 18. H.F. McConomy, “High-Temperature Sulfidic Corrosion in Hydrogen Free Environment,” presented at the meeting of the Subcommittee on Corrosion during the 28th Midyear Meeting of the American Petroleum Institute’s Division of Refining, Philadelphia, PA, held in May 1963 (Washington, DC: API). 19. API RP 581 (latest revision), “Risk-Based Inspection Technology” (Washington, DC: API). 20. S. Mrowec, T. Walec, T. Werber, “High-Temperature Sulfur Corrosion of Iron-Cr Alloys,” Oxidation of Metals 1, 1 (1969): p. 93. 21. NACE SP0170 (latest revision), “Protection of Austenitic Stainless Steels and Other Austenitic Alloys from Polythionic Acid Stress Corrosion Cracking During Shutdown of Refinery Equipment” (Houston, TX: NACE). th

22. E.H. Niccolls, J.M. Stankiewicz, J.E. McLaughlin, K. Yamamoto, “High Temperature Sulfidation Corrosion in Refining,” 17 International Corrosion Congress, Las Vegas, NV, held October 6-10, 2008 (Houston, TX: NACE, 2008).

23. R. Bürgel, H.J. Maier, T. Niendorf, “Handbuch Hochtemperatur-Werkstofftechnik: Grundlagen, Werkstoffbeanspruchungen, Hochtemperaturlegierungen und –Beschichtungen” (Braunschweig: Vieweg Verlag, 1998), p. 355.

(3) (4)

ASM International (ASM), 9639 Kinsman Road, Materials Park, OH 44073-0002. The Electrochemical Society (ECS), 65 S. Main St., Building D, Pennington, NJ 08534-2839.

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NACE International 24. E.N. Skinner, J.F. Mason Jr., J.J. Moran, “High-Temperature Corrosion in Refinery and Petrochemical Service,” Corrosion 16, 12 (1960): p. 85. 25. A.S. Couper, A. Dravnieks, “High-Temperature Corrosion by Catalytically Formed Hydrogen Sulfide,” Corrosion 18, 8 (1962): p. 291. 26. G.R. Port, “Hydrogen Sulfide Corrosion in a Distilling Unit,” Proceedings of API 41, 3 (1961): p. 20. 27. J. Gutzeit, “Crude Unit Corrosion Guide—A Complete How-To Guide” (Houston, TX: NACE, 2006). 28. Mark Archer, Suncor Energy, correspondence to Brian Tkachyk, Suncor Energy, Sept. 10, 2012. 29. Dorian Rauschning, February 28, 2013.

CRI

Catalyst

Company,

correspondence

to

Brian

Tkachyk,

Suncor

Energy,

30. J.D. Jong, N. Dowling, M. Sargent, A.M. Etheridge, A. Saunders-Tack, W.C. Fort, “Effect of Mercaptans and Other Organic Sulfur Species on High Temperature Corrosion in Crude and Condensate Distillation Units,” CORROSION/2007, paper no. 07565 (Houston, TX: NACE, 2007).

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31. C. Shargay, K. Moore, R. Colwell, “Survey of Materials in Hydrotreater Units Processing High TAN Feeds,” paper no. 07573 (Houston, TX: NACE, 2007).

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NACE International APPENDIX A Modified McConomy Curves

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1 mpy = 0.0254 mm/y Corrosion Rate (mpy)

This appendix is intended to provide supplementary information only, although it may contain mandatory or recommending language in specifications or procedures that are included as examples of those that have been used successfully. Nothing in this appendix shall be construed as a requirement or recommendation with regard to any future application of this technology.

Temperature °F (°C = 5/9 [°F - 32]) Figure A1: Sulfidic Corrosion Prediction in Absence of H2

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NACE International APPENDIX B 3 Corrosion Prediction Curves for H2-H2S Service

Figure B2: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of CS (gas oil desulfurizers). Figure B1: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of CS (naphtha desulfurizers).

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

This appendix is intended to provide supplementary information only, although it may contain mandatory or recommending language in specifications or procedures that are included as examples of those that have been used successfully. Nothing in this appendix shall be construed as a requirement or recommendation with regard to any future application of this technology.

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22

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Figure B3: Effect of temperature and H2S content on hightemperature H2S-H2 corrosion of 5Cr-1/2Mo steel (naphtha desulfurizers).

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

Figure B4: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 5Cr-1/2Mo steel (gas oil desulfurizers).

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

NACE International

23

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Figure B5: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 9Cr-1Mo steel (gas oil desulfurizers).

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

Figure B6: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 9Cr-1Mo steel (naphtha desulfurizers).

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

NACE International

24

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Figure B7: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 12Cr SS.

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

Figure B8: Effect of temperature and H2S content on high-temperature H2S-H2 corrosion of 18Cr/8Ni SS.

Temperature °F (°C = 5/9 [°F - 32]) (1 mpy = 0.0254 mm/y)

NACE International

NACE International APPENDIX C Summary of REFIN•COR™ Excerpts This appendix is intended to provide supplementary information only, although it may contain mandatory or recommending language in specifications or procedures that are included as examples of those that have been used successfully. Nothing in this appendix shall be construed as a requirement or recommendation with regard to any future application of this technology. Reports of sulfidation in HDS units began to appear in NACE Group Committee T-8 minutes as early as 1960. Starting in about 1994, comments regarding sulfidation in hydrocracker and HDS units began to appear with increasing regularity. CS materials that had operated for a number of years were suddenly being attacked. The following is an abbreviated description of the entries from REFIN•COR™: •

94F5.7-02 HDS Stripper Furnace Tubes—CS local thinning at four geometrically opposite locations was attributed to two-phase flow. Tubes were upgraded to 9% Cr and mixers were added.

•

95C5.10-06 Higher than historical corrosion rates were found in the distillation section of the desulfurizing stage of a hydrocracker. After 15 years of minimal corrosion, the CS reboiler circuit is now experiencing 50-mpy (1.3 mm/y) corrosion rates and higher in high-velocity, turbulent areas, and the bottom trays in the tower also are corroding.

•

95C5.10-07 Corrosion in a hydrocracker stripper reboiler furnace was reported. H2S carryunder was thought to be contributing to higher sulfur levels. The furnace tubes were upgraded to 5% Cr; however, unacceptable corrosion rates were still experienced. Based on this information and test pieces, the piping was upgraded to 9% Cr, which substantially reduced corrosion.

•

97F5.6-29 A hot oil corrosion problem in the fractionator section of a hydrocracker was thought to be the result of mercaptan reversion. Some hydrocracking catalyst can convert H2S to mercaptans and cause accelerated corrosion in the fractionator furnace reboiler and preheat circuit. Both carbon steel and 5% Cr experienced uniform corrosion with a mercaptan content of 4 to 5 ppmw. Corrosion rates were much higher on the hotter fire side of the tubes.

•

97F5.6-32 Another refinery echoed concerns of mercaptan corrosion in hydrocracker fractionator reboiler circuits. This refinery felt that there were two options: (1) control temperature below where sulfidation is a concern or (2) upgrade the metallurgy. In one unit, the fired fractionator reboiler tubes and associated piping were upgraded to UNS S32100. The corrosion could not be explained by H2S levels.

•

97F5.6-33 A point was made that mercaptan corrosion is not restricted to hydrocrackers. Reboilers of light ends towers of cat crackers also see sulfidation caused by mercaptans and has seen corrosion of 5% Cr tubes of a shell and tube heat exchanger.

•

97F5.6-34 A fractionator furnace of a diesel HDS unit experienced corrosion and progressed from carbon steel to 5% Cr, to 9% Cr, and finally to UNS S32100 or UNS S34700 before corrosion was controlled. It was reiterated that no hydrogen was present and corrosion was a result of H2S alone. However, over the years the temperature was raised from 650 to 725 °F (343 to 385 °C). Because no good curves exist to predict corrosion, operators tend to rely on experience and empirical modifications to the McConomy curves.

•

97F5.7-08 A comment from one refinery regarding corrosion of 5% Cr hot oil piping in a hydroprocessing unit, in which oil is taken directly off a hot low-pressure separator and sent directly to the fractionator, initiated a discussion. It was believed that the hydrogen content of this stream would be very low, but corrosion rates were similar to H2/H2S corrosion. Comments followed that indicated that significant hydrogen content could be expected in this process stream. Another refinery had corrosion problems with its 5% Cr piping, and subsequent scale analysis indicated a chloride layer, which could accelerate corrosion. This piping was upgraded to UNS N08825 (alloy 825). Yet another refinery used SS after pressure letdown to the fractionator because of entrained hydrogen in the stream. No threshold level of hydrogen was given.

•

97F5.7-09 A bitumen upgrader had corrosion problems with 5% Cr piping in a heavy gas oil (HGO) hydrotreater. Subsequent scale analysis indicated a chloride layer, which could accelerate corrosion. This piping was upgraded to UNS N08825.

•

99C5.7-10 The failure of a carbon steel roof tube in a second-stage reboiler furnace was reported. The furnace outlet temperature was 600 to 700 °F (316 to 371 °C), and it operated at 190 psig (1,300 kPa). Recycled H2-H2S levels were reported to be 35 ppmw. A horizontal tube ruptured along the top of the tube. The top of the tube was found to be

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NACE International

•

2000C5.8-07 A corrosion problem in a catalytic cracker feed hydrotreater was discussed. The unit was built in 1970 and had three separators: high, medium, and low. The low-pressure separator operates at 100 psig (690 kPa) and 500 °F (260 °C). A leak developed in the piping downstream from this separator to the first exchanger in 1995. Because no significant inspections of the piping were performed since 1970, corrosion was assumed to have been uniform over a 25 y period. Subsequent inspections of the last SS exchanger revealed that the carbon steel baffles had thinned from the original thickness of 0.5 in (13 mm) down to 0.25 in (6.4 mm). This prompted inspection of the downstream piping to the tower. The piping required replacement. Corrosion rates were determined to be 25 mpy (0.64 mm/y) since 1995. This appears to be a case of accelerated corrosion in an H2S stream without the presence of hydrogen. Another contributor could be the replacement of a preheat bundle that resulted in a 50 °F (28 °C) increase in temperature.

•

2000C5.8-08 A response was that even though one would not think it possible, this process stream had a considerable amount of hydrogen in it. This was a heavy oil stream, so there were not a lot of light ends in the system. At 100 psig (690 kPa), calculations would indicate that some H2S and light ends were present, but the majority of the pressure was created by the partial pressure of hydrogen. This was one of those in-between cases in which the stream was not hydrogen-free, when one would use the McConomy curves, but it was not up to the Couper-Gorman curves, used when there is significant hydrogen.

•

2003C5.8-03 A presentation was made on sulfidic corrosion of a stripper reboiler in a diesel-hydrodewaxing unit. The feed to this unit was diesel off the crude tower. It went through two-staged reactors. This was an example of process creep. The effluent from the reactor went through high- and low-pressure separators. The liquid from the low-pressure separator fed into a H2S stripper. The stripper bottoms went through a fired reboiler. It entered the convection section, through the radiant section, and back into the stripper tower. The heater tubes and the inlet and outlet piping were constructed of CS. There was a fire in August 2000, and it had been re-tubed with CS. After service for many years, the operating company added a new bed in the reactor and put in a different catalyst in the second reactor in 1999-2000. The heater burned down and was re-tubed in January 2001 with 5% Cr for both convection and radiant tubes. The operating company also replaced the outlet piping, which had also had corrosion, with 5% Cr. Meanwhile, the operating company had seen the temperature creeping up. The unit went back into service in January 2001. In 2002, after a little more than a year, the operating company found that the corrosion rates on the 5% Cr radiant tubes were about 3 mm/y (100 mpy). The presenter did not have any information on the sulfur content, but understood that there was supposedly no H2S in the stripper bottoms and very low in other sulfur species as well. It was the low-sulfur diesel out of the hydrodesulfurizing reactor. The temperature at the stripper bottom was initially at 1,040 to 650 °F (560 to 343 °C) and had crept up to more than 800 °F (425 °C) over a 2 y period. They had catalyst deactivation from some nitrogen in the feed and had to run the reactors hotter to maintain dewaxing. The rate had gone up to more than 5 mm/y (200 mpy) on these 5% Cr tubes. The average over the 2 y period was about 4 mm/y (140 mpy). The convection return bends saw corrosion rates of about 1 and 1.5 mm/y (40 and 60 mpy) on the outlet piping. For comparison, according to McConomy curves, corrosion rates should have been very low. Even at 800 °F (425 °C) and 4%-wt sulfur, the rates would be only 1 mm/y (40 mpy). The Couper-Gorman curve at 800 to 900 °F (425 to 480 °C) and a couple of thousand ppm H2S predicts a corrosion rate under 2.5 mm/y (100 mpy). The experience had been that in this type of service, people had gone with 9% Cr. Even with 9% Cr, corrosion rates were at 5 mm/y (200 mpy). Because it was not expected to see any significant improvement, it was recommended to go to SS. The heater only had one convection section on the top and two radiant passes on the bottom. The data appeared to suggest that corrosion was the highest at the high-heat-flux areas.

•

2003C5.8-11 A comment was made that in one company’s low-sulfur gasoline process, which was a slightly different process than conventional hydrotreaters, they were specifying 9Cr-1 Mo heater tubes because of the concerns that were presented in the TG 176 technical committee report. They, too had experienced short-term corrosion in their hydrocracker and hydrotreater stripper bottoms. When it was asked how many people were specifying 9% Cr, and how many planned to use SS for their low-sulfur gasoline and/or low-sulfur diesel projects, there were three responses for 9% Cr and two responses for SS.

•

2009C4.2-01, 2009C4.2-02 A question was asked: “When evaluating a hydrotreater/hydrocracker, which curves do people use for material selection for piping from the hydrogen injection to the reactor?” and “Are there theories on how much H2S conversion really occurs in the pipe between the hydrogen injection and the reactor?” It was mentioned that in some cases, the residence time in that line can be significant because of the length depending on the set up. Further questions were asked: “Are you using Modified McConomy curves under the assumption that you are getting little H2S conversion ahead of the reactor?” “Or are you using more of the Cooper-Gorman type of approach assuming H2S is present after the hydrogen is injected?” (Some companies use proprietary versions of something similar to the CooperGorman Curves.) “Is the corrosion more ‘Hydrogen Free’ or ‘Hydrogen Curves’?” “If hydrogen is clean hydrogen or sour

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severely corroded. Short-term corrosion rates were estimated to be 25 mpy (0.64 mm/y). It was postulated that H2/H2S concentrated in the top portion of the tube.

NACE International hydrogen, does it make a difference?” In his case, one company assumes the hydrogen has been treated and therefore it is not a very sour stream. They understand that every system is different, but wanted to get a feel for the general approach. A poll was taken and 3 people indicated they use Modified McConomy curves only; three indicated they use the CooperGorman type approach only; and 20 indicated they used both.

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Another company stated that they would use both. The issue with trying to use Cooper-Gorman is what value to use for H2S. They struggle with obtaining the information on the sulfur. It was stated that recently, in all the hydroprocessing units that they have built for the ultra-low sulfur projects, the issue has become moot because the process people don’t want any iron sulfide scales on the reactor beds. The justification to go SS is based on process needs, not on corrosion needs. He stated that they ended up with furnace coils and piping in this type of environment which are SS anyway. When they look back at existing units, they may still have 9% Cr or 5% Cr feed systems. Another company mentioned that there are considerations which need to be taken into account based on information from process people. Depending on the nature of the feed, the reactivity of the sulfur compounds can make a difference as to how much H2S is formed before the reactor. Any refractory sulfur compounds may not convert much of their sulfur content to H2S, whereas lighter, more reactive ones might convert more easily. So, the project often uses a rule of thumb. They often assume 10% of the sulfur converts and then compare the corrosion rates that way. •

2009C4.2-04 to 2009C4.2-07 A question was asked about what mechanism would there be other than thermal decomposition of sulfur compounds ahead of the furnace. The process is coming in with a certain H2S level, whether that’s high or low. It was questioned if there is an increase out of the furnace. Are there reactions forming more H2S? The response was that depending on the source of the stream, there may not be much H2S in the base case, especially if it’s coming through a stripper tower off a crude unit or something similar. It may be thermal related (He has not discussed the specifics with his folks about the mechanism), but there has to be a thermal component to it rather than just a decomposition reaction with the hydrogen. They do not have a lot of details of the mechanisms. A further response was that industry does know of some reactions going on in the absence of catalysts, especially the reaction with naphthenic acid groups. If there is much conversion of the sulfide to H2S, it wouldn’t make much sense to grade catalyst for catalyst activity to prove iron sulfide formation. That fact makes it look like the predominant reaction doesn’t start until the stream to be treated actually hits some catalyst. Another response was that the reactivity of the sulfur can vary significantly based on the feed source (crude). In reality, depending on the sulfur species you are trying to remove from the hydrocarbon, that will control the type of catalyst and operating conditions needed to achieve the sulfur removal you are targeting. This makes it difficult to determine how much H2S you are going to form upstream from the reactor or even to say that you are not going to form any.

•

2009CTW4.25-09 Comments were made about the sulfidation resistance of 5% Cr steel. Experience was shared for a unit with 5% Cr operating over 500 °F (260 °C) which was installed for the expected sulfidation corrosion resistance. Portions of that piping system (all at the same conditions) that corroded and portions which were unaffected. Through a very detailed review of the samples of the 5% Cr piping, it was found that when the chromium content was between 4 and 5%, it corroded and when the chromium content was above 5% (typically 5.2% but always in the range of 5 to 6) it was resistant to sulfidation. All of the samples fell within the allowed chromium content of the specification, which is 4 to 6% for 5% Cr steel. It was recommended that anyone considering the use of 5% Cr steel consider that it may not be as resistant as was intended or it must be specified to have a minimum chromium content. The use of 9% Cr, where one might otherwise use 5% Cr, can significantly reduce the risk of sulfidation.

•

2009CTW4.25-10, 2009CTW4.25-11 For a recent project, the issue of 5% Cr not necessarily having the same corrosion resistance as might be expected was discussed. The materials selection diagrams indicated that the piping should be 5% Cr and the client asked the project to guarantee 5% Cr minimum. They went out and tried to see if they could find this material and they found they could not guarantee it would meet the 5% Cr minimum requirements. Based on this, they changed the materials selection diagrams substituting 9% Cr for 5% Cr. The client indicated that they had data which indicated that the total life cost of UNS S30400 (304 SS) was less than that for 9% Cr due to the increased number of inspections and the post-weld heat treatment (PWHT) required for 9% Cr. In the end, the lines which were originally specified 5% Cr ended up being UNS S30400. A comment was made in agreement that 5% Cr is not a material that should be specified for refinery service.

•

2010C4.2-01, 2010C4.2-02 An issue in the fractionation section of a hydrocracker was described where the flow goes to a debutanizer, a heater, and then into a fractionator. After the heater, they are getting very high sulfidation rates, much higher than they would predict through the classical curves. They would like to understand what may be causing the corrosion. Could it be mercaptans or other sulfide species? They have reviewed NACE Publication 34103,

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NACE International “Overview of Sulfidic Corrosion in Petroleum Refining,” but want to go a little bit further from there to see if there are some limits which could/should be implemented, e.g. hydrogen sulfide limits. •

A response was that another company does not have a limit on the feed because from their point of view the composition is whatever the process people need at the heater. They look at what sulfur level is, but know that sulfur is going to be much more active and reactive than similar sulfur levels used in the typical Couper-Gorman or Modified McConomy curves. For the most part, they go straight to austenitic SS. On the fractionator bottoms, (after the heater, after the fractionators), she feels that the assumption can be made that there won’t be sulfidation corrosion, if the sulfur and H2S are very low in the cracked bottoms. The criteria they use is 1 ppm sulfur. If the sulfur is over 1 ppm H2S, they will consider that area to be susceptible to sulfidation corrosion. But process people hardly ever tell them that they are under 1 ppm hydrogen sulfide in the bottoms product, unless it is zero. If it is zero, they would not use alloy for sulfidation.

APPENDIX D (K) Survey Data Summary and REFIN•COR™ Data This appendix is intended to provide supplementary information only, although it may contain mandatory or recommending language in specifications or procedures that are included as examples of those that have been used successfully. Nothing in this appendix shall be construed as a requirement or recommendation with regard to any future application of this technology.

Table D1 2000 NACE Survey Data for Carbon Steel Temperature (T) °F (°C)

Corrosion Rate (CR) Average mpy (mm/y) Stabilizer Feed Piping

CR Maximu m mpy (mm/y)

N/A

125 (3.18) 120 (3.05)

690 to 720 °F (366 to 382 °C)

550 to 600 °F (288 to 316 °C)

25 (0.64)

450 to 500 °F (232 to 260 °C)

25 (0.64)

450 to 500 °F (232 to 260 °C)

25 (0.64)

[S]

[H2S]

0.13 wt% PH2S = 6.7 to 8.3 psia (46 to 57 kPa abs) PH2S = 0.4 psia (2.8 kPa abs) PH2S = 0.6 psia (4.1 kPa abs) PH2S = 2.2 psia (15 kPa abs)

[mercaptan]

Comments

Survey/Source

Residuum desulfurizer Hydrocracker

M

Catalytic cracker feed hydrotreater. PH2 = 20 psia (138 kPa abs) Catalytic cracker feed hydrotreater. PH2 = 30 psia (207 kPa abs) Catalytic cracker feed hydrotreater. PH2 = 108 psia (745 kPa abs)

REFIN•COR™ 2000C5.8-07

Maximum CR reported at tower bottoms to pump

A

N

REFIN•COR™ 2000C5.8-07

REFIN•COR™ 2000C5.8-07

Stabilizer Bottoms Piping 530 °F (277 °C)

1.5 (0.04)

6.9 (0.18)

14 ppm

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NACE International Temperature (T) °F (°C)

Corrosion Rate (CR) Average mpy (mm/y)

CR Maximu m mpy (mm/y)

[S]

[H2S]

[mercaptan]

Comments

Survey/Source

suction elbow 24 in (600 mm) diameter < 2 (0.05)

500 to 575 °F (260 to 302 °C)

620 °F (327 °C)

3 (0.08)

45 (1.1)

430 °F (221 °C)

< 20 ppm

B

0.01 wt% avg. 0.18 wt% max.

C

80 (2.0) 11 (0.28)

560 °F (293 °C)

5 (0.1)

9 (0.2)

525 to 625 °F (274 to 329 (B) °C)

3 (0.08)

18 (0.46)

330 ppm (total)

2 ppm(A) 320 ppm

2 ppm

2 ppm

100 ppm

Majority of readings reported at elbows Corrosion rate over 30 years and varying crude slates. Sulfur and H2S content was high. See Table D6 Maximum CR reported downstream from flow control valve Maximum CR reported at 10 in (250 mm) elbow before 14 in (350 mm) furnace inlet header

E F

H

I

Stabilizer Reboiler Furnace Tubes 585 °F (307 (C) °C) 560 °F (293 (C) °C)

3.7 (0.09)

550 °F (288 °C)

3 (0.08)

12 (0.30)

< 1 ppm

620 °F (327 °C)

20 (0.51)

37 (0.94)

2 ppm

(A)

655 °F (346 (C) °C) 450 °F (232 (D) °C)

10 (0.25)

25 (0.64)

2 ppm

(A)

25 (0.64)

5.6 (0.14) 2 (0.05)

14 ppm

A

< 20 ppm

330 ppm (total)

320 ppm

Maximum CR from convection section return bends Stabilizer bottoms shell and tube heat exchanger (HX) (heating medium not reported)/CR for shell Radiant crossover piping/T reported at 595 °F (313 °C) in and 655 °F (346 °C) outlet so used 620 °F (327 °C)

D

E

E 2 ppm

Top two horizontal convection inlet tubes had localized corrosion in top half of tube. Furnace modeling showed

29 Copyright NACE International Provided by IHS under license with NACE No reproduction or networking permitted without license from IHS

B

Licensee=Sabic Engineering and Project Mgmt/5951674001, User=Abbas, Qaisar Not for Resale, 11/16/2015 06:50:36 MST

F

--`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

500 °F (260 °C)

NACE International Temperature (T) °F (°C)

Corrosion Rate (CR) Average mpy (mm/y)

CR Maximu m mpy (mm/y)

[S]

[H2S]

[mercaptan]

Comments

Survey/Source

this is where vaporization begins. Led to failure. 530 °F (277 (C) °C) 760 °F (404 (E) °C) 725 °F (385 (E) °C) 725 °F (385 (E) °C)

700 °F (371 (C) °C)

15 (0.38)

200 (5.08) 25 (0.64)

330 ppm (total) 5 ppm

5 (0.1)

15 (0.38)

100 ppm

Horizontal tubes

I

50 (1.3)

100 ppm

Corrosion was most aggressive on the top half of the horizontal tube and that was the location of failure Failure in roof radiant tube, in top half of tube. Postulated that mechanism may have been H2-H2S corrosion

I

4 (0.1)

320 ppm

2 ppm

F G

25 (0.64)

REFIN•COR™ 99C5.7-10

Stabilizer Reboiler Outlet Piping 585 °F (307 °C) 560 °F (293 °C)

2 (0.05)

550 °F (288 °C) 710 °F (377 °C)

7 (0.2) 20 (0.51)

7.5 (0.19) 6.5 (0.17)

14 ppm

11 (0.28) 44 (1.1)

< 1 ppm

A

< 20 ppm

CR reported slightly higher in elbows 2 ppm(A)

760 °F (404 °C) 12 (0.30) 27 (0.69) 680 °F (360 °C) 25 (0.64 34 (0.86) 550 to 650 °F 2 (0.05) 11 (0.28) (288 to 343 (F) °C) 720 °F (382 °C) 40 (1.0) Recycle Splitter Bottoms Piping

5 ppm

535 °F (279 °C)

5.2 (0.13)

8.3 (0.21)

21 ppm

480 °F (249 °C) 495 to 575 °F

1 (0.02) 4 (0.1)

2 (0.05) 10 (0.25)

< 20 ppm 0.01 wt%

Maximum CR reported at 6 in (150 mm) elbows. CR worse in smaller-diameter piping. 14 in (350 mm) elbows maximum CR reported 16 mpy (0.41 mm/y)

D E

2 ppm

G H I

3 ppm

J

100 ppm

Maximum CR at pump discharge elbow Hydrocracker (2nd-

30 --`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

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B

Licensee=Sabic Engineering and Project Mgmt/5951674001, User=Abbas, Qaisar Not for Resale, 11/16/2015 06:50:36 MST

A

B C

NACE International Corrosion Rate (CR) Average mpy (mm/y)

CR Maximu m mpy (mm/y)

(257 to 302 °C)

[S]

[H2S]

[mercaptan]

0.18 wt% max.

530 °F (277 °C)

5 (0.1)

15 (0.38)

700 °F (371 °C)

29 (0.74)

85 (2.2)

4.4-9.4 ppm

720 °F (382 °C)

9 (0.2)

45 (1.1)

5.1 ppm

710 °F (377 °C)

< 10 (0.25)

18 (0.46)

17 ppm

670 °F (354 °C)

< 10 (0.25)

31 (0.79)

17 ppm

< 10 16 (0.41) (0.25) Recycle Splitter Reboiler Furnace

17 ppm

580 °F (304 (C) °C) 490 °F (254 (C) °C) 550 °F (288 (C) °C) 700 °F (371 (D) °C)

21 ppm

3 (0.08)

6.8 (0.17) 5.5 (0.14) 9 (0.2)

9 (0.2)

21 (0.53)

4.4-9.4 ppm

500 °F (260 °C)

5.2 (0.13) 1 (0.02)

Comments

stage) < 1 ppm

< 20 ppm < 1 ppm

Maximum CR for 6 in (150 mm) piping, but reported higher velocity in 8 in (200 mm) piping (3 to 9 mpy [0.08 to 0.2 mm/y]) Maximum CR reported on 6 in (150 mm) elbows. High CR ranged from 22 to 51 mpy (0.56 to 1.3 mm/y) at 18 in (460 mm) elbows in pump discharge spool Maximum CR reported in tee of pump discharge header. 28 mpy (0.71 mm/y) CR reported for pump warm-up line (higher velocity). Circuit max. ~20 to 25 mpy (0.51 to 0.64 mm/y) 14 to 24 in. (350 to 610 mm) piping at pump suction and discharge. Maximum CR in straight pipe Piping downstream from tie-in with cooler stream. Maximum CR similar in straight pipe, tees, and elbows Maximum CR reported in elbows

D

Radiant section tubes Convection section tubes Radiant section tubes Convection section tubes

A

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Survey/Source

Licensee=Sabic Engineering and Project Mgmt/5951674001, User=Abbas, Qaisar Not for Resale, 11/16/2015 06:50:36 MST

E

F

G

G

G

B D E

--`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

Temperature (T) °F (°C)

Temperature (T) °F (°C)

Comments

Survey/Source

4.4-9.4 ppm

Crossover piping

E

90 (2.3)

4.4-9.4 ppm

Radiant tubes

E

27 (0.69)

5.1 ppm

F

820 °F (438 20 (0.51) 70 (1.8) (G) °C) 700 °F (371 11 (0.28) 23 (0.58) (E) °C) 730 °F (388 10 (0.25) (D) °C) Recycle Splitter Reboiler Outlet Piping

5.1 ppm

Convection section tubes. Maximum CR reported at return bends Radiant section tubes Convection section tubes

580 °F (304 °C)

0.9 (0.02)

21 ppm

A

490 °F (254 °C)

1 (0.02)

< 20 ppm

B

550 °F (288 °C) 710 °F (377 °C)

4 (0.01) 10 (0.25)

2.9 (0.07) 2.5 (0.06) 10 (0.25) 24 (0.61)

760 °F (404 °C) 730 °F (388 °C)

< 5 (0.1) < 10 (0.25)

< 5 (0.1) < 10 (0.25)

5.1 ppm 17 ppm

620 °F (327 °C)

< 5 (0.1)

8 (0.2)

650 °F (343 °C) 700 °F (371 °C)

2 (0.05) < 10 (0.25)

5 (0.1) 125 (3.18)

5 ppm 0.218 wt%

700 °F (371 °C) 710 °F (377 °C)

< 5 (0.1) < 5 (0.1)

< 5 (0.1) < 5 (0.1)

4.4-9.4 ppm 5.1 ppm

700 °F (371 (D) °C) 835 to 882 °F (446 to 472 (G) °C) 740 °F (393 (D) °C)

Corrosion Rate (CR) Average mpy (mm/y) 21 (0.53)

CR Maximu m mpy (mm/y)

[S]

52 (1.3)

45 (1.1)

18 (0.46)

[H2S]

[mercaptan]

17 ppm

F G J

< 1 ppm 4.4-9.4 ppm

Maximum CR reported at 6 in (140 mm) elbows. Larger-diameter elbows had lower CR (maximum CR = 17 mpy (0.43 mm/y) for 18 in (460 mm) ells; max. CR = 16 mpy (0.41 mm/y) for 24 in (610 mm) ells. Straight pipe even lower (max. CR 11 mpy [0.28 mm/y])

D E

F G

Columns 2 ppm(A) < 2 ppm

< 2 ppm

Stabilizer column

E

Stabilizer column Stabilizer column/max. CR in flash zone at reboiler return. (also reported 220 ppm disulfide, 0.13 wt% thiophenes) Splitter column Splitter column

G L

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E F

--`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

NACE International

NACE International Temperature (T) °F (°C)

CR Maximu m mpy (mm/y)

[S]

750 °F (399 °C)

Corrosion Rate (CR) Average mpy (mm/y) 5 (0.1)

25 (0.64)

5.1 ppm

710 °F (377 °C) 650 °F (343 °C)

2 (0.5) 8 (0.2)

5 (0.1) 30 (0.76)

17 ppm 17 ppm

[H2S]

[mercaptan]

Comments

Survey/Source

Splitter column/max. CR in area of transfer line inlet “flash zone.” Also 10 to 15 mpy (0.25 to 0.38 mm/y) reported in shell at downcomers Splitter column Splitter column inlet nozzles—localized corrosion on downstream side of nozzle to weldneck flange weld

F

G G

--`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

See footnotes at the bottom of Table D5.

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NACE International Table D2 2000 NACE Survey Data for 1 to 3% Cr T °F (°C)

750 °F (E) (399 °C)

Corrosion Rate (CR) Average mpy (mm/y) 10 (0.25)

CR Maximum mpy (mm/y) 18 (0.46)

[S]

[H2 S]

[mercaptan]

17 ppm

Comments

Survey/Source

Splitter reboiler radiant tubes 1.25% Cr-0.5% Mo steel

G

See footnotes at the bottom of Table D5.

Table D3 (K) 2000 NACE Survey and REFIN•COR™ Data for 5% Cr T °F (°C)

620 °F (327 °C) in and 710 °F (377 °C) outlet 620 °F (327 °C) in and 710 °F (377 °C) outlet 710 °F (377 (C) °C) 710 °F (377 °C) 700 °F (371 (D) °C) 590 °F (310 (C) °C) 460 °F (238 (H) °C)

Corrosion Rate (CR) Average mpy (mm/y) 10 (0.25)

CR Maximum mpy (mm/y)

[S]

23 (0.58)

2 ppm

19 (0.48)

28 (0.71)

2 ppm

18 (0.46)

56 (1.4)

2 ppm

(A)

16 (0.40)

29 (0.74)

2 ppm

(A)

< 5 (0.1)

9 (0.2)

7 (0.2)

35 (0.89)

4.4-9.4 ppm 330 ppm (total)

[H2S]

[mercaptan]

Comments

Survey/Source

(A)

Stabilizer reboiler furnace convection to radiant crossover piping

E

(A)

Stabilizer reboiler furnace convection/bottom two rows—shock tubes

E

Stabilizer reboiler radiant tubes Stabilizer reboiler outlet piping Recycle splitter reboiler

E

Stabilizer reboiler radiant tubes Stabilizer reboiler radiant tubes. For Survey F, these higher H2S concentrations were reported for a several-year period when the refinery was processing a higher sulfur crude slate (1.8 to 2.5 wt% S). They presented a data set from a study of furnace tube corrosion for this period. The prevalent crude slate had less sulfur (0.8 to 1.5 wt% S). Stabilizer reboiler radiant tubes. [see comment above] Stabilizer reboiler radiant tubes. [see comment above]

F

320 ppm

5 (0.1)

700 to 1,200 ppm

505 °F (263 (H) °C)

8 (0.2)

540 °F (282 (H) °C)

10 (0.25)

700 to 1,200 ppm 700 to 1,200 ppm

2 ppm

34 --`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

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E E

F

F

F

NACE International

565 °F (296 (H) °C)

Corrosion Rate (CR) Average mpy (mm/y) 20 (0.51)

CR Maximum mpy (mm/y)

[S]

[H2S]

[mercaptan]

700 to 1,200 ppm 700 to 1,200 ppm 320 ppm

Comments

Survey/Source

Stabilizer reboiler radiant tubes. [see comment above] Stabilizer reboiler radiant tubes. [see comment above] Stabilizer reboiler outlet piping. Stabilizer bottoms to reboiler heater/pump discharge spool Stabilizer reboiler radiant tubes/areas of corrosion are sporadic and show no trend from pass to pass. 6 of 12 passes show little or no corrosion loss Stabilizer reboiler outlet piping/max CR at elbows and tees Stabilizer bottoms piping to splitter column/max. CR at one elbow Stabilizer reboiler convection tubes— horizontal Stabilizer reboiler radiant tubes—vertical Stabilizer reboiler furnace tubes Stabilizer reboiler convection section. Bottom row of tubes/max. CR along top of horizontal tubes in bottom row (lowest row of shock tubes) Stripper bottoms piping

F

590 °F (310 (H) °C)

43 (1.1)

590 °F (310 °C) 650 °F (343 °C)

25 (0.64) < 10 (0.25)

26 (0.66)

330 ppm (total) 5 ppm

760 °F (404 (E) °C)

10 (0.25)

25 (0.64)

5 ppm

710 °F (377 °C)

< 5 (0.1)

21 (0.53)

5 ppm

650 °F (343 °C)

< 10 (0.25)

30 (0.76)

5 ppm

600 °F (316 (C) °C)

10 (0.25)

12 (0.30)

2 ppm

680 °F (360 (C) °C) 720 °F (382 (C) °C) 610 °F (321 (D) °C) to 640 °F (338 (C) °C)

17 (0.43)

20 (0.51)

2 ppm

40 (1.0)

3 ppm

560 °F (293 °C) to 800 °F (427 °C) 560 °F (293 °C) to 800 °F+ (I) (427 °C) 560 °F (293 °C) to 800 °F+ (I) (427 °C)

15 (0.28)

(J)

(J)

100 to 143 (2.54 to (3.63)

(J)

(J)

Stripper reboiler radiant tubes

REFIN•COR™ 2003C5.20-06 (Attachment to 2003C5.8-03)

50 (1.27)

(J)

(J)

Stripper reboiler convection tubes

REFIN•COR™ 2003C5.20-06 (Attachment to 2003C5.8-03)

46.7 (1.19)

2 ppm

0.05 wt%

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F

F G

G

G

G

H

H J K

REFIN•COR™ 2003C5.20-06 (Attachment to 2003C5.8-03)

--`,```,,,,,,``,`,,,`,,,`````,,,-`-`,,`,,`,`,,`---

T °F (°C)

T °F (°C)

Corrosion Rate (CR) Average mpy (mm/y) 37 (0.94)

CR Maximum mpy (mm/y)

[S]

[H2S]

(J)

560 °F (293 °C) to 800 °F+ (I) (427 °C) (J) 560 °F (293 60 (1.52) °C) to 800 °F+ (I) (427 °C) See footnotes at the bottom of Table D5.

[mercaptan]

Comments

Survey/Source

(J)

Stripper reboiler convection return bends

REFIN•COR™ 2003C5.20-06 (Attachment to 2003C5.8-03)

(J)

Stripper reboiler outlet piping

REFIN•COR™ 2003C5.20-06 (Attachment to 2003C5.8-03)

Table D4 2000 NACE Survey Data for 9% Cr T °F (ºC)

560 °F (293 (C) °C) 710 °F (377 (C) °C)

Corrosion Rate (CR) Average mpy (mm/y)

CR Maximum mpy (mm/y)

[S]