| This article is part 1 of a 3-part series on Wet H2S Damage. |
| Part 1 | Part 2 | Part 3 |
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
Aqueous phase process environments containing sulfur and specifically, hydrogen sulfide (H2S), are generally referred to as sour environments or sour service [1]. H2S is a flammable, colorless gas that poses a process safety risk to plant personnel due to its toxicity. Furthermore, H2S (and sulfur) can occur naturally or can be generated from common oil and gas production/refining methods. H2S contributes to corrosion mechanisms such as high temperature sulfidation (H2/H2S corrosion) and acidic sour water corrosion; however, the cracking mechanisms associated with hydrogen charging in wet H2S environments are the focus of this Damage Control series. Wet H2S damage can detrimentally affect the load-carrying capacity of pressure retaining equipment and can manifest itself in numerous forms of material degradation, including the following:
- Hydrogen blistering
- Hydrogen induced cracking (HIC)
- Stress-oriented hydrogen induced cracking (SOHIC)
- Sulfide stress cracking (SSC)
Wet H2S damage is complex and often misunderstood because the overall propensity for these damage mechanisms is governed by different controlling metallurgical and environmental variables. Furthermore, each form of wet H2S damage exhibits distinctive morphologies, introduces varying levels of risk, and ultimately can promote different failure modes. Damage propagation rates can also be difficult to predict and can be accelerated by minor changes in process environments. This article will summarize the fundamentals of these wet H2S-related damage mechanisms, discuss operating conditions and other factors influencing damage progression, and present the typical damage characteristics and morphologies of each mechanism. Additionally, this article will offer some practical inspection guidance and will discuss common locations predisposed to wet H2S damage on typical pressure equipment. A case study of a notable industry failure caused by different forms of wet H2S damage will also be reviewed.
In general, wet H2S damage affects carbon and low-alloy steels most notably in the oil and gas industry, although H2S can also be present in process environments in the mining, food processing, pulp and paper, wastewater treatment, and power generation industries. H2S is more soluble in crude oil than in water, and H2S concentrations of 100 – 200 ppm are relatively common in typical crudes [2]. Furthermore, any equipment subject to wet H2S process conditions can be susceptible to damage under certain scenarios. It is believed that some of the first industry experiences with different forms of wet H2S damage occurred in the 1950s in both the U.S. and Canadian oil fields [1]. In some of these early documented cases, sour environment corrosion occurred within approximately one month of equipment installation. These unfavorable operating experiences led to the use of corrosion inhibitors to extend equipment service life. Even today, wet H2S damage continues to afflict pressure vessels, tanks, piping, and other equipment in the oil and gas and related industries. Understanding the different types of wet H2S damage, identifying which process units and equipment are most prone to such damage, and establishing appropriate inspection plans for in-service equipment can mitigate costly unplanned outages and equipment failures.
Wet H2S Chemical Reactions and Damage Mechanics
The primary reactions that lead to the presence of H2S in oil and gas reservoirs are bacterial sulfate reduction (BSR) and thermochemical sulfate reduction (TSR) [3]. At high pressures, sulfanes are formed in the gas phase by the dissolution of elemental sulfur. When pressure is decreased (e.g., during oil/gas extraction and production), these gaseous sulfanes dissociate to form elemental sulfur, and in the presence of water, form H2S. Sulfur can also be formed due to an oxidation reaction of H2S by air or by other oxides (e.g., iron oxide). This reaction can be detrimental to steels because sulfur can contribute to corrosion, and it produces water, which increases the corrosivity of H2S [1]. Additionally, the solubility of sulfur in water generally increases with temperature: for example, approximately 10 ppm – 20 ppm at 77°F (25°C) and approximately 50 ppm at 122°F (50°C) [1]. Furthermore, the dissolution of sulfur in water produces H2S and sulfuric acid. This reaction tends to occur relatively slowly at ambient temperatures, but nevertheless can generate sufficient H2S to cause damage.
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