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Item No. 24222 NACE International Publication 34103

This Technical Committee Report has been prepared by NACE International Task Group 176 on Prediction Tools for Sulfidic Corrosion.

Overview of Sulfidic Corrosion In Petroleum Refining

© February 2004, NACE International

This NACE International 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 NACE reports are subject to periodic review, and may be revised or withdrawn at any time without prior notice. NACE reports are automatically withdrawn if more than 10 years old.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 Membership Services Department, 1440 South Creek Drive, Houston, Texas 77084-4906 (telephone +1 281/228-6200).

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Foreword

The objective of this report is to provide a document to help predict corrosion rates and point out areas of vulnerability in the distillation equipment associated with hydroprocessing units. It is intended for use by corrosion engineers and fixed-equipment inspectors. The report summarizes recent 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. This technical committee report was prepared 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 is issued by NACE International under the auspices of STG 34.

Introduction

High-temperature sulfidic corrosion 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. Sulfidic corrosion was first encountered in refineries in crude distillation units, thermal and catalytic cracking plants, thermal reforming, and coking units where the crude oil and its fractions were processed at temperatures exceeding 500°F (260°C).1 Steel alloys containing 5% chromium (Cr) or greater (i.e., 7% Cr, 9% Cr, and 12% Cr, in this order), were found to have increasing resistance to sulfidic corrosion. Over time, empirically based corrosion prediction curves were

generated and improved based on refinery experiences. These curves are still useful to this day for refining processes containing significant quantities of sulfur compounds.2 In the 1940s and 1950s, the advent of refining processes that utilized hydrogen, such as catalytic reforming and hydroprocessing, introduced another facet to sulfidic corrosion. It was observed that for sulfidic services containing hydrogen, steel alloys containing up to 9% Cr were, at best, only slightly more corrosion resistant than carbon steel (CS).1 Sulfidic corrosion in the presence of H2 is often referred to as H2-H2S corrosion. Much

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research was done and some of this work was published. A separate set of corrosion prediction curves for H2-H2S conditions were compiled and published and are still generally useful.3 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 sulfidic corrosion in equipment such as piping and reboiler furnace tubes in fractionation and distillation facilities downstream from hydrotreaters and hydrocrackers.4 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 Task Group 176, Prediction Tools for Sulfidic Corrosion. Literature Search Results Most of the scientific literature on sulfidic corrosion deals with temperatures well in excess of 800°F (427°C), and in vapor environments of sulfur, mixed gases (O2-S2), or H2-H2S.5 Published papers of direct application to the refining industry have been based mostly on data collected from pilot-plant and actual-plant experiences. In fact, the two papers most often cited are experientially based.2,3 Little fundamental research that furthers the understanding of the thermodynamics and kinetics of sulfidic corrosion for the temperature range and process conditions of primary interest to petroleum refining has been published. A brief summary of the current understanding of high-temperature sulfidic corrosion is provided in the following sections. For a more in-depth study of sulfidic corrosion, the reader is directed to the resources listed in the bibliography. Sulfidic Corrosion in Hydrogen-Free Environments—Mechanism of Sulfidic Corrosion Many studies have shown that sulfidation of steel alloys initially follows a parabolic rate law that becomes linear after a short period.5,6,7 For plain 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 should be, had stoichiometry been achieved. 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 layer of Fe1-xS.8 As Cr content of the alloy is increased, the inner layer tends toward a single-phase sulfo-spinel FeCr2S4. It is generally thought that this sulfo-spinel scale is more stable and more protective than Fe1-

xS.9 Four distinct steps have been identified for the sulfidation mechanism.10,11 These steps are: (1) 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 (Fe--> Fe++ + 2e-), thus reducing the concentration of cation vacancies and electron holes. 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 rate-limiting step.7,11,12 Studies have shown that some sulfur compounds more readily absorb (or chemisorb) into the sulfide scale than even H2S, and thus exhibit greater corrosion rates when compared to H2S.11,13 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.11 The diffusion flux of cation vacancies and electron holes through the spinel phase (FeCr2S4) is less than through the Fe1-xS, slowing step (3) and thus limiting corrosion rates.14 H2, though, promotes the decomposition of various absorbed sulfur compounds (step [2]) counteracting the influence of Cr.11 This is thought to be a reason that Cr-steel alloys are no more resistant to H2-H2S corrosion than plain CS. Alloy Performance in High-Temperature Sulfidic Environments (H2-Free) The modified McConomy curves have been generally useful for predicting corrosion rates for various steel alloys in refining process streams based on total sulfur present.2,15 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 hydrocrackers. This will be discussed further in this committee report. The original McConomy curves were published in 1963 and were based on an industry survey done by the API(1) Subcommittee on Corrosion.16 Many data points were from furnace tube corrosion rates that may have been based on process stock temperature and thus not have accurately represented the true metal, or inside surface, temperature. Regardless of the reason, they were found to be overly conservative and were later modified.2 These

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

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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) are still widely used today and are included for reference in Appendix A. They form the basis for the sulfidic corrosion rate determination tables found in API Publication 581.17

Plain CS is resistant to sulfidic corrosion up to about 500°F (260°C). 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 plain CS alloys that were silicon-killed have exhibited a modest increase in sulfidic corrosion resistance compared to plain CS materials that were not silicon-killed due to a higher silicon (Si) content. Generally, corrosion rates can be high at temperatures above 600°F (315°C) for all plain CS. Low-Cr steels (1 to 3% Cr) are generally not selected to combat sulfidic corrosion. The modified McConomy curves show a minor benefit over CS, but there were only a few data points available to draw the original curve.16 There is not much published experience with these alloys in sulfidic conditions, and some laboratory studies show no improvement over CS.18 Steels containing 5 to 9% Cr are commonly used for high-temperature sulfidic environments such as those found in crude distillation units and delayed cokers. 5% Cr steel is generally resistant up to about 650°F (343°C), and 9% Cr steel is generally resistant to 750°F (399°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. 12% Cr is generally considered to be resistant to sulfidic corrosion in many applications in the absence of H2 and is often used as vessel cladding, pump cases, and pump impellers. It is used to a lesser extent as pump and valve body castings, and as 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. 18/8 stainless steel alloys exhibit excellent resistance to sulfidic corrosion and have been used in severe services such as furnace tubes and furnace transfer lines. 18/8 stainless steel alloys subject to high-temperature service >700°F (>371°C) are susceptible to sensitization. This condition does not affect sulfidic corrosion performance, but does render the alloys susceptible to polythionic acid stress corrosion cracking (PTA SCC) when the equipment is cooled and exposed to moist, aerated conditions. Refer

to NACE Standard RP017019 for more information on PTA SCC and its prevention. Sulfidic Corrosion in Hydrogen-Hydrogen Sulfide Environments—Mechanism of H2-H2S Corrosion The composition and morphology of the iron sulfide scales formed in H2-H2S environments have been shown to be essentially the same as those formed by H2-free sulfidic corrosion.7 However, the reason for the disparate performance of alloys such as 5% Cr in sulfidic non-H2 and H2-H2S services has not been clearly established. Some have postulated that the reason for higher corrosion rates in the lighter distillate, H2-H2S services was due to the absence of coke formation and the subsequently less protective scale that forms.1,9 It has also been suggested 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.9,13 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.9,10,11 As mentioned earlier, it was pointed out that 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). 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 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 (1) and (2).3

Low-Cr Steels (0 to 9% Cr) CR = FCrFGFS × 2.681 × 105 × e(-10,720/[t + 460]) × (CH2S) (0.1540 - 0.05891× log C

H2S) (1)

Where: CR= corrosion rate mpy (0.0254 mm/y) FCr = factor dependent on the Cr content of the steel (%Cr) FCr = 10 –0.01900 × (% Cr)

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%Cr FCr %Cr FCr 0 1.000 5 0.804 1 0.957 6 0.769 2 0.916 7 0.736 3 0.877 8 0.704 4 0.840 9 0.675

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%. High-Cr Steels CR = FTFS × 2.8145 × 104 × e(-9,644/[t + 460]) × (CH2S) (0.14645) (2) Where: FT = factor dependent on steel type (18/8, FT = 0.166; 12% Cr, FT = 1.0). Note that values for FT have been corrected from the actual values in the cited paper. Generally, 18/8 stainless steel 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.9 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 due to the high ratio of the volume of iron sulfide corrosion scale formed to the volume of the corroded iron substrate.7,11 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 the newly exposed scale surface of the inner scale.20 The cracks, fissures, and spalls also provide avenues for corrosive sulfur compounds to directly reach the steel surface, bypassing several of the steps outlined above, and thus accelerating corrosion rates.14 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. 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 mechanisms.2,10,21 It is commonly thought that in some process plants, coke deposits, or even heavy hydrocarbon molecules, can seal cracks and fissures in the scale, helping to strengthen the scale, thus providing more resistance to wear or removal.9,16,15,22

4

Hydroprocessing—Process Overview

Hydroprocessing is a general term used to describe certain types of oil refining processes that utilize high temperatures, high-pressure 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.

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FIGURE 1: Typical flow scheme for the stripping and fractionation section of a hydrotreater.

These types of processes are often used upstream from hydrocrackers, 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. For two-stage hydrocrackers, there are two basic configurations: intermediate distillation and tail-end distillation. 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.

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 are 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 can occur 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.

Hydrotreater Reaction Section

H2S Stripper

H2S

Splitter Column

First-Stage Hydrotreater

H2S Stripper

H2S

Second-Stage Hydrocracker

Tail-End Distillation

Light HC

Splitter Column Stabilizer

Column

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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 can be several variations of the flow scheme in the distillation section of the process unit.

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 due to 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 off gases 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, and 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).

Second-StageHydrocracker

First-Stage Hydrotreater

H2S Light HC

Products

Splitter Column

ToppingColumn

Intermediate Distillation

Single-Stage

Hydrocracker

Stabilizer

H2S Light HC

Fractionator

Splitter

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Sulfidic Corrosion in Distillation and Fractionation Facilities Downstream from Hydroprocessing Units Historical Overview In 1961, the API Subcommittee on Corrosion conducted a survey to gather high-temperature sulfidic corrosion rate data on the hydrogen-free hydrocarbon portions of desulfurizing processes.16 Respondents provided data on 20 separate units, and corrosion rate vs. temperature data were plotted for various materials of construction (CS through 18/8 stainless steel). 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 high-temperature sulfidic corrosion 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 and 3.3 mm/y) for 4 to 6% Cr steels operating between 650º and 775ºF (343° and 413°C). Alloys in this group would normally be expected to corrode at rates less than 20 mpy (0.50 mm/y) in this temperature range. All material groups from CS to 18/8 stainless steel exhibited similar broad data scatter. Excerpts from the NACE information exchange minutes (REFIN•COR) are included in Appendix C.4 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 with CS. 9% Cr reportedly offered some improvement, but UNS(2) S34700 (type 347 stainless steel) or UNS S32100 (type 321 stainless steel) was successfully used in the worst cases. Corrosion has been 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 maybe even H2 can 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 sulfidic corrosion 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. NACE Task Group (TG) 176 Survey Results and Observations

The task group received 14 completed survey responses with corrosion rate and process data in varying detail. 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, and include several pertinent entries gathered from REFIN•COR. 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 has been identified. (6) The role of hydrogen in the corrosion mechanism in

these facilities is still unclear. Effects of Alloying on Sulfidic Corrosion 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, the modified McConomy, 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 sulfidic corrosion. Six surveys reported data for 5% Cr, mostly in the stabilizer reboiler furnace and the inlet and

___________________________

(2)Metals and Alloys in the Unified Numbering System (latest revision), a joint publication of ASTM International and the Society of Automotive Engineers Inc. (SAE), 400 Commonwealth Dr., Warrendale, PA 15096.

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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 replaced. 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 not be drawn. Performance of 9% Cr steel was mixed. Five surveys contained data for 9% Cr steel. Two reported low 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 may be noted, however, that two surveys reported short-term (two-year) corrosion rate data that may be 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 stainless steel 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 sulfidic corrosion rates in areas of high velocity and turbulent flow is not a new phenomenon;23 however, these reported cases appeared to be particularly aggressive in relation to the

overall circuit. In these cases, when sulfidic corrosion might not have been adequately anticipated, standard thickness measurement location (TML) placement probably did not consider the possibility of aggressive localized corrosion. Effect of Flow Regime in Furnace Tubes 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 sulfidic corrosion rates occur on the fire side of the tube. Consequently, inspection measurements are taken on the fire side, but that may miss 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 may exhibit higher corrosion rates. However, most convection tubes are finned or studded to improve heat transfer, and the inside film temperature may be 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 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 reported a total sulfur value and 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 preponderance of a specific sulfur type to break down and form H2S.13 Subsequent work, however, showed that mercaptans and disulfides can be corrosive, and may be more aggressive than H2S.11 This can be difficult to know for certain,

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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 were not readily available for identification, and most refiners did not have a specific need to know these data in order to control the process or had 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, the 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 may be possible that hydrogen is present in great 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 can be 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 can cause significant corrosion.

Gaps in Data and Plans for Future Work Following is a list of gaps identified in the data generated and reviewed during the compilation of this report, and items for future study by the task group. (1) Relative corrosiveness of various sulfur species

• Theory of mercaptan reversion • Determination of what species hydrotreating and

hydrocracking catalysts may form • Recommended practices for sampling and testing (identification)

(2) Role of hydrogen at relatively low partial pressure

• Level of H2 dissolved in oil coming from separators (3) Understanding of sulfidic corrosion mechanism

• Focus on the temperature range 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 • Thermodynamics of FeCr2S4 spinel phase—is it

stable in this range? • Kinetics—what is, or are, the rate-limiting steps? • 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 H2 on corrosion is understood, can these curves be combined?

(5) Data for the broad ranges of those alloys and

conditions being used in modern refineries • In terms of the Couper-Gorman and the McConomy curves

(6) Concept that all 18/8 stainless steels are equal in

terms of sulfidic corrosion. (7) Data concerning greater range of temperature and

ranges of H2 and H2S pressures • Better describe corrosion in modern refining processes

ghd

ro

9

References

1. NACE Publication 56-7, “Collection and Correlation of High Temperature Hydrogen Sulfide Corrosion Data,” Houston, TX: NACE, 1956. Also published in Corrosion 12, 5 (1956): pp. 213t-234t. 2. J. Gutzeit, “High Temperature Sulfidic Corrosion of Steels,” Process Industries Corrosion—The Theory and Practice, eds. B.J. Moniz, W.I. Pollock (Houston, TX: NACE, 1986).

3. A.S. Couper, J.W. Gorman, “Computer Correlations to Estimate High Temperature H2S Corrosion in Refinery Streams,” Materials Protection and Performance 10, 1 (1971): pp. 31-37. 4. REFIN•COR (latest revision) (Houston, TX: NACE). 5. G.Y. Lai, “Sulfidation,” High-Temperature Corrosion of Engineering Alloys (Materials Park, OH: ASM International,(3) 1990).

___________________________

(3)ASM International (ASM), 9639 Kinsman Road, Materials Park, OH 44073-0002.

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10

6. D.J. Young, “The Sulfidation of Iron and It’s Alloys,” Reviews on High-Temperature Materials 4, 4 (1990): pp. 299-346. 7. E.W. Haycock, “Mechanism of Sulfidation of Iron and Iron Alloys in H2S and H2S/H2 Mixtures,” High Temperature Metallic Corrosion of Sulfur and Its Compounds (Pennington, NJ: ECS,(4) 1970): pp. 110-117. 8. S. Mrowec, K. Przybylski, “Defect and Transport Properties of Sulfides and Sulfidation of Metals,” High Temperature Materials and Processes 6, 1 and 2 (1984): pp. 1-79. 9. W.S. Sharp, E.W. Haycock, “Sulfide Scaling Under Hydrorefining Conditions,” API Transactions, Division of Refining, held May 1959 (Washington, DC: API). 10. Z.A. Foroulis, “High Temperature Degradation of Structural Materials in Environments Encountered in the Petroleum and Petrochemical Industries: Some Mechanistic Observations,” Anti-Corrosion 32, 11 (1985): pp. 4-9. 11. C. Husen, “High-Temperature Corrosion by Organic Sulfur Compounds,” High Temperature Metallic Corrosion of Sulfur and Its Compounds (Pennington, NJ: ECS, 1970): pp. 186-207. 12. F. Hugli, C.M. Hudgins Jr., R. Delahay, “Mechanism of the Iron-Hydrogen Sulfide Reaction at Elevated Temperature,” API Transactions, Division of Refining, held May 1958 (Washington, DC: API). 13. A.S. Couper, “High Temperature Mercaptan Corrosion of Steels,” Corrosion 19, 11 (1963): pp. 396t-401t. 14. M. Schütze, “Sulfidation,” in Materials Science and Technology: A Comprehensive Treatment; Corrosion and Environmental Degradation 1 (2000): pp. 113-119.

15. ASM Metals Handbook, Vol. 13 – Corrosion (Materials Park, OH: ASM International, 1987), pp. 1270-1273. 16. 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, in Philadelphia, PA, held in May 1963 (Washington, DC: API). 17. API Publication 581 (latest revision), “Base Resource Document on Risk-Based Inspection” (Washington, DC: API). 18. S. Mrowec, T. Walec, T. Werber, “High-Temperature Sulfur Corrosion of Iron-Cr Alloys,” Oxidation of Metals 1, 1 (1969): pp. 93-120. 19. NACE Standard RP0170 (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). 20. R. Burgel Handbuch Hochtemperatur-Werkstofftechnik, Grundlagen, Werkstoffbeanspruchungen, Hochtemperaturlegierungen (Braunschweig: Vieweg Verlag, 1998), p. 355 21. E.N. Skinner, J.F. Mason, J.J. Moran, “High Temperature Corrosion in Refinery and Petrochemical Service,” Corrosion 16, 11 (1960): pp. 593t-600t. 22. A.S. Couper, A. Dravnieks, “High Temperature Corrosion by Catalytically Formed Hydrogen Sulfide,” Corrosion 18, 8 (1962): pp. 291t-298t. 23. G.R. Port, “Hydrogen Sulfide Corrosion in a Distilling Unit,” Proceedings of the 26th Midyear Meeting of API 41, 3 (1961): pp. 20-28.

___________________________ (4)The Electrochemical Society, Inc. (ECS), 65 South Main Street, Building D, Pennington, NJ 08534-2839.

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11

Appendix AModified McConomy Curves

0.01

0.1

1

10

100

500 525 550 575 600 625 650 675 700 725 750 775

Temperature (F)

Cor

rosi

on R

ate

(mpy

)

CS

1 - 3 Cr

4 - 6 Cr

7 Cr

9 Cr

12 Cr

18/8

Total Sulfur Content 0.6 wt%

Temperature °F (°C = 5/9 [°F - 32])

FIGURE A1: Sulfidic Corrosion Prediction in Absence of

H2

1 m

py

= 0.

0254

mm

/y

Co

rro

sio

n R

ate

(mp

y)

APPENDIX A Modified McConomy Curves

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12

APPENDIX B Corrosion Prediction Curves for H2-H2S Service3

Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1 m

py

= 0.

0254

mm

/y)

F

IGU

RE

B2:

Eff

ect

of

tem

per

atu

re a

nd

H2S

co

nte

nt

on

h

igh

-tem

per

atu

re H

2S-H

2 co

rro

sio

n o

f C

S (

gas

oil

des

ulf

uri

zers

).

Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1 m

py

= 0.

0254

mm

/y)

F

IGU

RE

B1:

Eff

ect

of

tem

per

atu

re a

nd

H2S

co

nte

nt

on

hig

h-t

emp

erat

ure

H2S

-H2

corr

osi

on

of

CS

(n

aph

tha

des

ulf

uri

zers

).

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Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1 m

py

= 0.

0254

mm

/y)

F

IGU

RE

B3:

Eff

ect

of

tem

per

atu

re a

nd

H2S

co

nte

nt

on

h

igh

-tem

per

atu

re H

2S-H

2 co

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f 5C

r-1/

2Mo

ste

el

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hth

a d

esu

lfu

rize

rs).

Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1 m

py

= 0.

0254

mm

/y)

F

IGU

RE

B4:

Eff

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of

tem

per

atu

re a

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H2S

co

nte

nt

on

hig

h-t

emp

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H2S

-H2

corr

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5Cr-

1/2M

o

stee

l (g

as o

il d

esu

lfu

rize

rs).

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14

Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1

mp

y =

0.02

54 m

m/y

)

FIG

UR

E B

5: E

ffec

t o

f te

mp

erat

ure

an

d H

2S c

on

ten

t o

n

hig

h-t

emp

erat

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H2S

-H2

corr

osi

on

of

9Cr-

1Mo

ste

el

(nap

hth

a d

esu

lfu

rize

rs).

Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1 m

py

= 0.

0254

mm

/y)

F

IGU

RE

B6:

Eff

ect

of

tem

per

atu

re a

nd

H2S

co

nte

nt

on

hig

h-t

emp

erat

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H2S

-H2

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on

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1Mo

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eel (

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oil

des

ulf

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).

ACE International

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NACE International

15

Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1 m

py

= 0.

0254

mm

/y)

F

IGU

RE

B8:

Eff

ect

of

tem

per

atu

re a

nd

H2S

co

nte

nt

on

hig

h-t

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H2S

-H2

corr

osi

on

of

18C

r/8N

i st

ain

less

ste

el.

Tem

per

atu

re °

F (

°C =

5/9

[°F

- 3

2])

(1 m

py

= 0.

0254

mm

/y)

F

IGU

RE

B7:

Eff

ect

of

tem

per

atu

re a

nd

H2S

co

nte

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on

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APPENDIX C Summary of REFIN•COR Excerpts

Reports of sulfidation in hydrodesulfurization 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 hydrodesulfurization 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: • 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.

• 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.

• 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.

• 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.

• 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.

• A point was made that mercaptan corrosion is not

restricted to hydrocrackers. Reboilers of light ends towers of cat crackers can also see sulfidation caused by mercaptans and has seen corrosion of 5% Cr tubes of a shell and tube heat exchanger.

• A fractionator furnace of a diesel hydrodesulfurization

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 650º to 725ºF (343º to 385ºC). Because no good curves exist to predict corrosion, operators tend to rely on experience and empirical modifications to the McConomy curves.

• 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 uses stainless steel after pressure letdown to the fractionator because of entrained hydrogen in this stream. No threshold level of hydrogen was given.

• 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 (alloy 825).

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

• 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 on the piping were performed since 1970, corrosion was assumed to have been uniform over a 25-year period. Subsequent inspections of the last stainless steel 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.

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• A response was that even though one would not think it possible, this process stream has a considerable amount of hydrogen in it. This is a heavy oil stream so there are not a lot of light ends in this system. At 100 psig (690 kPa), calculations would indicate that some

H2S and light ends would be present but the majority of the pressure would be created by the partial pressure of hydrogen. This is one of those in-between cases in which the stream is not hydrogen-free, when one would use the McConomy curves, but it is not up to the Couper-Gorman curves when there is significant hydrogen.

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18

APPENDIX D Survey Data Summary

Table D1: 2000 NACE Survey Data for Carbon Steel

T ºF (ºC) Corrosion Rate (CR) Average mpy (mm/y)

CR Maximum mpy (mm/y)

[S] [H2S] [mercaptan] Comments

Stabilizer Feed Piping N/A 125 (3.18) 0.13 wt% Residuum desulfurize

690 to 720ºF (366 to 382º C)

120 (3.05) PH2S = 6.7 to 8.3 psia (46 to 57 kPa abs)

Hydrocracker

550 to 600ºF (288 to 316ºC)

25 (0.64) PH2S = 0.4 psia (2.8 kPa abs)

Catalytic cracker feedhydrotreater. PH2 = 2psia (138 kPa abs)

450 to 500ºF (232 to 260ºC)

25 (0.64) PH2S = 0.6 psia (4.1 kPa abs)


450 to 500ºF (232 to 260ºC)

25 (0.64) PH2S = 2.2 psia (15 kPa abs)


Stabilizer Bottoms Piping 530ºF (277ºC)

1.5 (0.04) 6.9 (0.18) 14 ppm Maximum CR reportetower bottoms to pumsuction elbow 24 in. (6cm) diameter

500ºF (260ºC)

<2 (0.05) <20 ppm

500 to 575ºF (260 to 302ºC)

3 (0.08) 0.01 wt% avg. 0.18 wt% max.

620ºF (327ºC)

45 (1.1) 80 (2.0) 2 ppm(A) Majority of readings reported at elbows

430ºF (221ºC)

11 (0.28) 330 ppm (total)

320 ppm 2 ppm Corrosion rate over 30years and varying cruslates. Sulfur and H2Scontent was high. SeTable D6.

560ºF (293ºC)

5 (0.1) 9 (0.2) 2 ppm Maximum CR reportedownstream from flow

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19




control valve 525 to 625ºF (274 to 329ºC)(B)

3 (0.08) 18 (0.46) 100 ppm Maximum CR reported10-in. (25-cm) elbow before 14-in. (36-cm) furnace inlet header

Stabilizer Reboiler Furnace Tubes 585ºF (307ºC)(C)

3.7 (0.09) 5.6 (0.14) 14 ppm

560ºF (293ºC)(C)

2 (0.05) <20 ppm Maximum CR from convection section retubends

550ºF (288ºC)

3 (0.08) 12 (0.30) <1 ppm Stabilizer bottoms sheland tube heat exchang(HX) (heating medium not reported)/CR for sh

620ºF (327ºC)

20 (0.51) 37 (0.94) 2 ppm(A) Radiant crossover piping/T reported at 595ºF (313ºC) in and 655ºF (346ºC) outlet soused 620ºF (327ºC)

655ºF (346ºC)(C)

10 (0.25) 25 (0.64) 2 ppm(A)

450ºF (232ºC)(D)

25 (0.64) 330 ppm (total) 320 ppm 2 ppm Top two horizontal convection inlet tubes had localized corrosionin top half of tube. Furnace modeling showed this is where vaporization begins. Leto failure.

530°F (277°C)(C)

200 (5.08) 330 ppm (total) 320 ppm 2 ppm

760°F (404°C)(E)

15 (0.38) 25 (0.64) 5 ppm

725°F (385°C)(E)

5 (0.1) 15 (0.38) 100 ppm Horizontal tubes

725°F (385°C)(E)

50 (1.3) 100 ppm Corrosion was most aggressive on the top half of the horizontal tuand that was the locatioof failure

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700°F (371°C)(C)

4 (0.1) 25 (0.64) Failure in roof radianttube, in top half of tubPostulated that mechanism may havebeen H2-H2S corrosio

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

7.5 (0.19) 14 ppm

560°F (293°C)

2 (0.05) 6.5 (0.17) <20 ppm CR reported slightly higher in elbows

550°F (288°C)

7 (0.2) 11 (0.28) <1 ppm

710ºF (377ºC)

20 (0.51) 44 (1.1) 2 ppm(A) Maximum CR reporte6-in. (15-cm) elbows.CR worse in smaller-diameter piping. 14-i(36-cm) elbows maximum CR reporte16 mpy (0.41 mm/y)

760ºF (404ºC)

12 (0.30) 27 (0.69) 5 ppm

680ºF (360ºC)

25 (0.64 34 (0.86) 2 ppm

550 to 650ºF (288 to 343ºC)(F)

2 (0.05) 11 (0.28) 100 ppm

720ºF (382ºC)

40 (1.0) 3 ppm

Recycle Splitter Bottoms Piping 535ºF (279ºC)

5.2 (0.13) 8.3 (0.21) 21 ppm Maximum CR at pumdischarge elbow

480ºF (249ºC)

1 (0.02) 2 (0.05) <20 ppm

495 to 575ºF (257 to 302ºC)

4 (0.1) 10 (0.25) 0.01 wt% 0.18 wt% max.

Hydrocracker (2nd-stage)

530ºF (277ºC)

5 (0.1) 15 (0.38) <1 ppm Maximum CR for 6-in(15-cm) piping, but reported higher velocin 8-in. (20-cm) piping

ational

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21




to 9 mpy [0.08 to 0.2mm/y])

700ºF (371ºC)

29 (0.74) 85 (2.2) 4.4-9.4 ppm Maximum CR reporton 6-in. (15-cm) elboHigh CR ranged fromto 51 mpy (0.56 to 1.mm/y) at 18-in. (46-celbows in pump discharge spool

720ºF (382ºC)

9 (0.2) 45 (1.1) 5.1 ppm Maximum CR reporttee of pump dischargheader. 28 mpy (0.7mm/y) CR reported fpump warm-up line (higher velocity). Cirmax. ~20 to 25 mpy (0.51 to 0.64 mm/y)

710ºF (377ºC)

<10 (0.25) 18 (0.46) 17 ppm 14- to 24-in. (36- to 6cm) piping at pump suction and dischargMaximum CR in strapipe

670ºF (354ºC)

<10 (0.25) 31 (0.79) 17 ppm Piping downstream ftie-in with cooler streMaximum CR similarstraight pipe, tees, aelbows

500ºF (260ºC)

<10 (0.25) 16 (0.41) 17 ppm Maximum CR reportelbows

Recycle Splitter Reboiler Furnace 580ºF (304ºC)(C)

5.2 (0.13) 6.8 (0.17) 21 ppm Radiant section tube

490ºF (254ºC)(C)

1 (0.02) 5.5 (0.14) <20 ppm Convection section t

550ºF (288ºC)(C)

3 (0.08) 9 (0.2) < 1 ppm Radiant section tube

700ºF (371ºC)(D)

9 (0.2) 21 (0.53) 4.4-9.4 ppm Convection section t

700ºF (371ºC)(D)

21 (0.53) 52 (1.3) 4.4-9.4 ppm Crossover piping

835 to 882ºF (446 to

45 (1.1) 90 (2.3) 4.4-9.4 ppm Radiant tubes

ternational

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472ºC)(G) 740ºF (393ºC)(D)

18 (0.46) 27 (0.69) 5.1 ppm Convection section tubes. Maximum CRreported at return ben

820ºF (438ºC)(G)

20 (0.51) 70 (1.8) 5.1 ppm Radiant section tubes

700ºF (371ºC)(E)

11 (0.28) 23 (0.58) 17 ppm Convection section tu

730ºF (388ºC)(D)

10 (0.25)

Recycle Splitter Reboiler Outlet Piping 580ºF (304ºC)

0.9 (0.02) 2.9 (0.07) 21 ppm

490ºF (254ºC)

1 (0.02) 2.5 (0.06) <20 ppm

550ºF (288ºC)

4 (0.01) 10 (0.25) < 1 ppm

710ºF (377ºC)

10 (0.25) 24 (0.61) 4.4-9.4 ppm Maximum CR reporte6-in. (15-cm) elbows.Larger-diameter elbohad lower CR (maximCR = 17 mpy (0.43 mm/y) for 18-in. (46-cells; max. CR = 16 m(0.41 mm/y) for 24-in(61-cm) ells. Straighpipe even lower (maxCR 11 mpy [0.28 mm

760ºF (404ºC)

<5 (0.1) <5 (0.1) 5.1 ppm

730ºF (388ºC)

<10 (0.25) <10 (0.25) 17 ppm

Columns 620ºF (327ºC)

<5 (0.1) 8 (0.2) 2 ppm(A) Stabilizer column

650ºF (343ºC)

2 (0.05) 5 (0.1) 5 ppm Stabilizer column

700ºF (371ºC)

<10 (0.25) 125 (3.18) 0.218 wt% < 2 ppm < 2 ppm Stabilizer column/maCR in flash zone at reboiler return. (also

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G

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reported 220 ppm disulfide, 0.13 wt% thiophenes)

700ºF (371ºC)

<5 (0.1) <5 (0.1) 4.4-9.4 ppm Splitter column

710ºF (377ºC)

<5 (0.1) <5 (0.1) 5.1 ppm Splitter column

750ºF (399ºC)

5 (0.1) 25 (0.64) 5.1 ppm Splitter column/max. in area of transfer lineinlet “flash zone.” Als10 to 15 mpy (0.25 to0.38 mm/y) reported ishell at downcomers

710ºF (377ºC)

2 (0.5) 5 (0.1) 17 ppm Splitter column

650ºF (343ºC)

8 (0.2) 30 (0.76) 17 ppm Splitter column inlet nozzles—localized corrosion on downstreside of nozzle to weldneck flange weld

See footnotes at the bottom of Table D5.

Table D2: 2000 NACE Survey Data for 1 to 3% Cr

T ºF (ºC) Corrosion Rate (CR)

Average mpy (mm/y)



750ºF (399ºC)(E)

10 (0.25) 18 (0.46) 17 ppm Splitter reboiradiant tubesCr-0.5% Mo


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NACE International

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sover

E

—shock

E

tubes E

iping E

E

tubes F

tubes. r H2S

rted for n the higher .5 wt% a set be he

less

F

tubes. F

tubes. F

tubes. F

tubes. F

iping. F

iler G

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24

Table D3: 2000 NACE Survey Data for 4 to 6 % Cr




620ºF (327ºC) in and 710ºF (377ºC) outlet

10 (0.25) 23 (0.58) 2 ppm(A) Stabilizer reboiler furnaceconvection to radiant crospiping

620ºF (327ºC) in and 710ºF (377ºC) outlet

19 (0.48) 28 (0.71) 2 ppm(A) Stabilizer reboiler furnaceconvection/bottom 2 rowstubes

710ºF (377ºC)(C)

18 (0.46) 56 (1.4) 2 ppm (A) Stabilizer reboiler radiant

710ºF (377ºC)

16 (0.40) 29 (0.74) 2 ppm (A) Stabilizer reboiler outlet p

700ºF (371ºC)(D)

<5 (0.1) 9 (0.2) 4.4-9.4 ppm Recycle splitter reboiler

590ºF (310ºC)(C)

7 (0.2) 35 (0.89) 330 ppm (total)

320 ppm 2 ppm Stabilizer reboiler radiant

460ºF (238ºC)(H)

5 (0.1) 700 to 1,200 ppm

Stabilizer reboiler radiantFor Survey F, these higheconcentrations were repoa several-year period wherefinery was processing asulfur crude slate (1.8 to 2S). They presented a datfrom a study of furnace tucorrosion for this period. Tprevalent crude slate hadsulfur (0.8 to 1.5 wt% S).

505ºF (263ºC)(H)

8 (0.2) 700 to 1,200 ppm

Stabilizer reboiler radiant[see comment above]

540ºF (282ºC)(H)

10 (0.25) 700 to 1,200 ppm


565ºF (296ºC)(H)

20 (0.51) 700 to 1,200 ppm


590ºF (310ºC)(H)

43 (1.1) 700 to 1,200 ppm


590ºF (310ºC)

25 (0.64) 330 ppm (total)

320 ppm 2 ppm Stabilizer reboiler outlet p

650ºF <10 (0.25) 26 (0.66) 5 ppm Stabilizer bottoms to rebo

E International

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(343ºC) heater/pump discharge spo760ºF (404ºC)(E)

10 (0.25) 25 (0.64) 5 ppm Stabilizer reboiler radiant tubes/areas of corrosion arsporadic and show no trendpass to pass. 6 of 12 passshow little or no corrosion lo

710ºF (377ºC)

<5 (0.1) 21 (0.53) 5 ppm Stabilizer reboiler outlet piping/max CR at elbows atees

650ºF (343ºC)

<10 (0.25) 30 (0.76) 5 ppm Stabilizer bottoms piping tosplitter column/max. CR at elbow

600ºF (316ºC)(C)

10 (0.25) 12 (0.30) 2 ppm Stabilizer reboiler convectiotubes—horizontal

680ºF (360ºC)(C)

17 (0.43) 20 (0.51) 2 ppm Stabilizer reboiler radiant tuvertical

720ºF (382ºC)(C)

40 (1.0) 3 ppm Stabilizer reboiler furnace t

610ºF (321ºC)(D) to 640ºF (338ºC)(C)

46.7 (1.19) 0.05 wt% Stabilizer reboiler convectiosection. Bottom row of tubes/max. CR along top ofhorizontal tubes in bottom r(lowest row of shock tubes)


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

Survey/Source

iler t tubes

B

iler t m data

E

r es (short ears)

F

iler H

bilizer t tubes 220 ppm wt%

L

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and tube tubes

D

ction F

t tubes F

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26

Table D4: 2000 NACE Survey Data for 9% Cr



[S] [H2S] [mercaptan] Component

560ºF (293ºC)(C)

<1 (0.03) <20 ppm Stabilizer rebofurnace radian

710ºF (377ºC)(C)

<10 (0.25) 15 (0.38) 2 ppm(A) Stabilizer rebofurnace radiantubes/short-ter(2 years)

720ºF (382ºC)(D)

15 (0.38) 32 (0.81) 5.1 ppm Splitter reboileconvection tubterm data—2 y

680ºF (360ºC)

<1 (0.03) 1 (0.03) 2 ppm Stabilizer rebooutlet piping

700ºF (371ºC)(C)

25 (0.64) 0.218 wt % <2 ppm <2 ppm Diesel HDS stareboiler radian(also reported disulfides, 0.13thiophenes)


Table D5: 2000 NACE Survey Data for 18/8 Stainless Steel

T ºF (ºC) Corrosion Rate (CR)

Average mpy (mm/y) CR Maximum mpy (mm/y)

[S] [H2S] [mercaptan] Component

550ºF (288ºC)

Nil Nil <1 ppm

Stabilizer bottoms shell HX/CR for UNS S32100

450ºF (232ºC)(D)

<5 (0.1) <5 (0.1) 330 ppm (total)

320 ppm

2 ppm Stabilizer reboiler convetubes (UNS S34700).

590ºF (310ºC)(C)

<5 (0.1) 10 (0.25) 330 ppm (total)

320 ppm

2 ppm Stabilizer reboiler radian(UNS S34700).

(A) 2 ppm H2S reported downstream at splitter for Unit E (B) T reported as 525 to 625°F (274 to 329°C). (C) Furnace outlet T, not tubeskin or film. (D) Furnace inlet T (E) Calculated max. film T (F) Temperature reported as 550 to 650°F (288 to 343°C) (G) Skin temperatures (H) Actual stock temperature from pass outlet TI—corrosion rates are the average of the tubes within the temperature range.

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R for Carbon Steel mpy rted in Survey

for 4 to 6% Cr steel)

g./50 (1.3) max

120 (3.05)

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Table D6: Summary of Sulfur Analysis Test Methods Reported

Survey Stabilizer Bottoms [S]

Splitter Bottoms [S]

Test Method Maximum C(mm/y) Repo

A 14 ppm 21 ppm UV Fluorescence—Total S. 8.3 (0.21) B ≤ 20 ppm ≤ 20 ppm Test method not reported. 6.5 (0.17) C 0.01 wt% avg.

0.18 wt% max. 0.01 wt% avg. 0.18 wt% max.

X-ray method—Total S. 10 (0.25)

D <1 ppm <1 ppm Test method not reported. Sulfur content reported as mercaptan (RSH).

15 (0.38)

E 2 ppm 4.4 to 9.4 ppm

Test method not reported. Stabilizer bottoms reported as H2S. Splitter bottoms reported as total S.

90 (2.3)

330 ppm (total) 5.1 ppm Test method not reported. Stabilizer bottoms—320 ppm H2S, 2 RSH, and 8 ppm as “other” sulfur not specified. Total S reported for splitter bottoms.

200 (5) F

700 to 1,200 ppm

Process modeling. Reported as H2S. This data represents a several year period when this refiner (F) was processing a different, higher total S crude slate.

43 (1.1) (CR

G (1) 5 ppm (1) 7.7 ppm (2) 17 ppm (3) 10 to 88 ppm

(1) Reactive analysis (2) X-ray (3) Oxidation technique Total S

31 (0.79)

H 2 ppm Process modeling. Reported as H2S. 34 (0.86) I 100 ppm Test method not reported. Total S. 18 (0.46) avJ 3 ppm Test method not reported. Reported as H2S. 75 (1.9) K ≤ 0.05 wt% Test method not reported. 46.7 (1.2) L 0.218 wt% Test method not reported. 0.13 wt% thiophenes, 220 ppm

disulfides, ≤2 ppm RSH, ≤2 ppm H2S. 125 (3.18)

M 0.13 wt% Test method not reported. Reported as H2S. This data represents the stabilizer feed piping.

125 (3.18)

N 6.7 to 8.3 psia (46 to 57 kPa)

Test method not reported. Reported as H2S partial pressure. Total pressure reported was 340 to 355 psi (2,344 to 2,448 kPa). This data represents the stabilizer feed piping.

100 (2.54) to

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NACE International

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Max. - 1961 APIQuestionaire

Avg. - 2000 NACESurvey

Max. - 2000 NACESurvey

Original McConomyCurve for 0.6% Total S

Modified McConomyCurve for 0.6%TotalSulfur

Modified McConomyCurve adjusted for 400ppmw Total S

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No reproduction or netw

orking permitted w

ithout license from IH

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28

0.1

1

10

100

1000

400 450 500 550 600 650 700 750 800 850 900

Temperature (F)

Co

rro

sio

n R

ate

(mp

y)

Temperature ºF (ºC = 5/9 [ºF - 32])

FIGURE E1: Sulfidic Corrosion of Carbon Steel Hydroprocessing/Desulfurizing—H2-Free

1961 API Questionnaire and 2000 NACE Survey

APPENDIX E NACE Task Group 176 Survey Results

1 m

py

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0254

mm

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International

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NACE International

. - 1961 APIestionnaire

x. - 1961 APIestionnaire

uper Gorman mol% H2S



. - 2000CE Survey

x. - 2000CE Survey

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

29

0.1

1

10

100

1000

400 450 500 550 600 650 700 750 800 850 900

Temperature (F)

Co

rro

sio

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(mp

y)

AvgQu

MaQu

Co0.1

Co0.5

Co1.0

AvgNA

MaNA

Temperature °F (ºC = 5/9 [ºF - 32])

FIGURE E2: Sulfidic Corrosion of Carbon Steel Hydroprocessing/Desulfurizing—H2-Free


1 m

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00

Avg. - 1961 APIQuestionnaire

Max. - 1961 APIQuestionnaire

Original McConomyCurve 0.6% Total S

Modified McConomyCurve 0.6% Total S

Couper Gorman 0.1 mol% H2S





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30

1

10

100

1000

450 500 550 600 650 700 750 8

Temperature (F)

Co

rro

sio

n R

ate

(mp

y)


FIGURE E3: Sulfidic Corrosion of 1 to 3% Cr Steel Hydroprocessing/Desulfurizing—H2-Free


1 m

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Max. - 1961 APIQuestionaire



300-1200 ppm H2S -Radiant Reboiler Tubes

Original McConomyCurve for 0.6% Total S

Modified McConomy for0.6% Total S

Modified McConomyCurve adjusted for 400ppmw SExpon. (300-1200 ppmH2S - Radiant ReboilerTubes)

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1

10

100

1000

450 500 550 600 650 700 750 800

Temperature (F)

Co

rro

sio

n R

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(mp

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1 m

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Avg. - 2000 NACE Survey

Max. - 2000 NACE Survey



Couper Gorman 1 mol% H2S

300-1200 ppm H2S -Radiant ReboilerTubes

Expon. (300-1200ppm H2S - RadiantReboiler Tubes)

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1

10

100

1000

450 500 550 600 650 700 750 800

Temperature (F)

Co

rro

sio

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(mp

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1 m

py

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Modified McConomyCurve 0.6% Total S




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Novoa, Josefina

Not for R

esale, 06/28/2007 12:09:03 MD

TN



IHS

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33

1

10

100

1000

450 500 550 600 650 700 750 800

Temperature (F)

Cor

roso

ion

Rat

e (m

py)


FIGURE E6: Sulfidic Corrosion of 7% Cr Steel Hydroprocessing/Desulfurizing—H2-Free


1 m

py

= 0.

0254

mm

/y

Co

rro

sio

n R

ate

(mp

y)

NACE International

vg. - 1961 APIuestionnaire

ax. - 1961 APIuestionnaire

riginal McConomyurve 0.6% Total S

odified McConomyurve 0.6% Total S

ouper Gorman .1 mol% H2S



vg. - 2000 NACEurvey

ax. - 2000 NACEurvey

Copyright N

AC

E I

Provided by IH

S under license w

ith NA

CE

Licensee=T

EC

NA

/5935100001, User=

Novoa, Josefina

Not for R

esale, 06/28/2007 12:09:03 MD

TN



IHS

34

0.1

1

10

100

450 500 550 600 650 700 750 800

Temperature (F)

Cor

rosi

on R

ate

(mpy

)

AQ

MQ

OC

MC

C0

C0

C1

AS

MS


FIGURE E7: Sulfidic Corrosion of 9% Cr Steel Hydroprocessing/Desulfurizing—H2-Free


1 m

py

= 0.

0254

mm

/y

Co

rro

sio

n R

ate

(mp

y)

nternational

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

NACE International

800

Copyright N

AP

rovided by IHS


AC

ELicensee=

TE

CN

A/5935100001, U

ser=N

ovoa, JosefinaN

ot for Resale, 06/28/2007 12:09:03 M

DT


orking permitted w


S

35

0.1

1

10

100

450 500 550 600 650 700 750

Temperature (F)

Cor

rosi

on R

ate

(mpy

)




ModifiedMcConomy Curve0.6% Total S





FIGURE E8: 12% Chromium Steel Combined Data 1961 API Questionnaire and 2000 NACE Survey

1 m

py

= 0.

0254

mm

/y

Co

rro

sio

n R

ate

(mp

y)

CE

International

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

750 800

Copyr

Provided by IH

S under license w

ith NA

CE

Licensee=T

EC

NA

/5935100001, User=

Novoa, Josefina

Not for R

esale, 06/28/2007 12:09:03 MD

TN



IHS

NACE International

36

0.1

1

10

100

400 450 500 550 600 650 700

Cor

rosi

on R

ate

(mpy

)Avg. - 1961 APIQuestionnaire


OriginalMcConomy Curve0.6% Total SMod. McConomyCurve 0.6% TotalSCouper Gorman 0.1 mol% H2S



Avg. 2000 NACESurvey

Max. - 2000NACE Survey

1 m

py

= 0.

0254

mm

/y

Co

rro

sio

n R

ate

(mp

y)


FIGURE E9: 18/8 Stainless Steel Combined Data 1961 API Questionnaire and 2000 NACE Survey

ight NA

CE

International

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

nace 34103

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