NACE 34103

Abstract

<strong>Introduction</strong> <br>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 &#176;F (538 &#176;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. <br>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 oil and its fractions were processed at temperatures exceeding 500 &#176;F (260 &#176;C).1 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 still useful to this day for refining processes containing significant quantities of sulfur compounds.² <br>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 separate set of corrosion prediction curves for H₂-H₂S conditions was compiled and published and is 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. <br>By the 1990s, several refiners began to report sulfidation 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 TG 176, Prediction Tools for Sulfidic Corrosion. <br>Despite ongoing efforts, sulfidation continues to be significant risk in the refining industry. American Petroleum Institute (API)⁽¹⁾ RP 939-C⁵ 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 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. <br>⁽²⁾ American Petroleum Institute (API), 1220 L St. NW, Washington, DC 20005.