Damage Control: Sulfidation and High-Temperature H2/H2S Corrosion Detection

Editor’s Note: This regular column offers practical insights into various damage mechanisms affecting equipment in the O&G, petrochemical, chemical, power generation, and related industries. Readers are encouraged to send us suggestions for future topics, comments on the current article, and raise issues of concern. All submissions will be reviewed and used to pick topics and guide the direction of this column. We will treat all submissions as strictly confidential. Only Inspectioneering and the author will know the names and identities of those who submit. Please send your inputs to the author at damagecontrol@inspectioneering.com.

Introduction

Sulfidation (sulfidic corrosion) can detrimentally impact the functional life of pressure components constructed of carbon steel and other alloys, operating in sulfur-containing process environments at elevated temperatures. In general, sulfidation corrosion is delineated into two distinct categories (considered to be separate damage mechanism variants in process environments with sulfidation-causing sulfur species): hydrogen (H₂)-free and hydrogen-containing service conditions [1-3]. While these two categories, both described herein, are a function of process constituents (specifically, the presence of hydrogen), they are both diffusion-based, non-aqueous, corrosion mechanisms occurring at elevated temperatures. From a terminology perspective, sulfidic corrosion in H₂-free service environments is referred to as conventional “sulfidation” herein. Moreover, sulfidic corrosion coupled with H₂-containing process conditions is typically referred to as “high-temperature H₂/H₂S corrosion” [1-3]. This nomenclature is adopted in this article. Additionally, practical operating experience suggests that sulfidation of iron-based alloys in H₂-free process environments will generally become non-trivial at temperatures above 500°F (260°C), although the exact minimum temperature threshold required to initiate damage has been contested over the years. This assertion is predicated on the absence of naphthenic acid corrosion. Also, mercaptan corrosion (e.g., in condensate service) has been reported below 500°F. The commonly cited industry operating metal temperature threshold for high-temperature H₂/H₂S corrosion is 450°F (230°C) [1].

Some of the earliest documented examples of sulfidation corrosion arose in the latter part of the nineteenth century in crude separation units, where it was understood at the time that naturally occurring sulfur-containing organic compounds in crude oil contributed to this corrosion phenomenon [1]. Furthermore, this often-aggressive damage was believed to be facilitated when various crude fractions (produced during the heating process for separation) were observed to cause corrosion of steel equipment, supporting the assertion that the reaction of the sulfur-containing compounds was the primary driver of corrosion and ultimately equipment failures. Subsequently, with the dawn of fluid catalytic cracking (FCC) and coking processes, sulfidation corrosion began to affect more refinery equipment [4,5]. Furthermore, when hydroprocessing technology was introduced, along with catalytic reforming, in the 1940s and 1950s, new observations in the corrosion behavior (including unprecedented damage progression rates) of refinery equipment were identified [6]. This eventually led to the realization that different sulfidation corrosion behavior was generated under hydroprocessing conditions that typically involve the presence of H₂ (that were not previously observed in crude separation or other conventional sulfidation scenarios). By the 1990s, several owner-users reported unconventional sulfidation damage in equipment subject to H₂-free (and very low sulfur) process environments. Specifically, fractionation and distillation piping components and reboiler furnace tubes, downstream of hydrotreaters and hydrocrackers, exhibited noteworthy sulfidation damage. As discussed herein, these operating experiences led to the evolution of modern sulfidation and high-temperature H₂/H₂S damage prediction tools.

While sulfidation corrosion damage has been observed in pressure equipment since the late 1800s, it endures as a costly and relevant damage mechanism in the oil refining industry today, as continued leaks and component failures (leading to unplanned outages and lost production) persist. Moreover, sulfidation (and high-temperature H₂/H₂S corrosion) also adversely affects a substantial number of equipment items, including pressure vessels and piping systems (across multiple process units) in a typical refinery [7]. Further complicating this damage mechanism is the reality that over the last few decades, global economic pressures and refining practices have resulted in many owner-users processing numerous different crude varieties in any given year (including sour and higher acid crudes). As such, refineries that processed a consistent blend of a particular crude in the past could often base future corrosion rate predictions on previous operating experience; however, the shift in refining practices has minimized the accuracy, or even feasibility, of establishing accurate sulfidation corrosion predictions based on historical operating data. Additionally, meaningful quantification/validation of the actual sulfidation corrosion rates experienced while processing a specific crude variety can be challenging and is often impractical [1]. 

This installment of Damage Control will outline useful background information on sulfidation (and high-temperature H₂/H₂S corrosion), including typical damage mechanism morphology and fundamentals, examples/case studies of related equipment failures, susceptible process units and locations, critical parameters that influence damage proclivity, and commonly utilized inspection methods/practical detection considerations. Furthermore, understanding the corrosion reaction principles and typical damage characteristics of sulfidation corrosion is imperative for plant inspection, engineering, and reliability/maintenance personnel working in the refining industry. Special emphasis mechanical integrity (SEMI) programs intended to manage the risk associated with sulfidation also require a thorough understanding of the damage mechanics and nuances related to this complex damage mechanism.