API RP 939-C-2009 pdf download.Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries.
1 Scope This recommended practice (RP) is applicable to hydrocarbon process streams containing sulfur compounds, with and without the presence of hydrogen, which operate at temperatures above approximately 450 °F (230 °C) up to about 1000 °F (540 °C). A threshold limit for sulfur content is not provided because within the past decade significant corrosion has occurred in the reboiler/fractionator sections of some hydroprocessing units at sulfur or H 2 S levels as low as 1 ppm. Nickel base alloy corrosion is excluded from the scope of this document. While sulfidation can be a problem in some sulfur recovery units, sulfur plant combustion sections and external corrosion of heater tubes due to firing sulfur containing fuels in heaters are specifically excluded from the scope of this document. 2 Normative References The following referenced documents are indispensable for the application of this document. For dated references, only the edition cited applies. For undated references, the latest edition of the referenced doucment (inlcuding any amendments) applies. API 510, Pressure Vessel Inspection Code: Maintenance Inspection, Rating, Repair, and Alteration API 570, Piping Inspection Code: Inspection, Repair, Alteration, and Rerating of In-service Piping Systems API Recommended Practice 571, Damage Mechanisms Affecting Fixed Equipment in the Refining Industry API Recommended Practice 578, Material Verification Program for New and Existing Alloy Piping Systems API Recommended Practice 580, Risk-Based Inspection API Recommended Practice 581, Risk-Based Inspection Technology API Standard 579-1/ASME 1 FFS-1-2007, Fitness-For-Service 3 Definitions and Acronyms For the purpose of this document, the following definitions apply. 3.1 Definitions 3.1.1 low-alloy steels Steels that contain 1 to 9 % Cr and 0.5 to 1 % Mo. 3.1.2 low-silicon-containing carbon steels Steels that contain less than 0.10 wt % Si, the minimum limit for ASTM A106 piping.
3.1.3 material operating envelope MOE Documentation describing limits related to unit and equipment specific process parameters for the given materials of construction. Operation within the limits should not adversely affect the mechanical integrity of the equipment and piping. An MOE also defines process monitoring tasks to assure that operating conditions are maintained within the established parameters. 3.1.4 mils/yr Corrosion rate expressed as 1 mil/yr = 0.001 in./yr; 40 mils = 1 mm. 3.1.5 spec break or specification break The location where a lesser alloy content material is joined or mated up to a higher alloy content material, i.e. 5Cr to carbon steel. 3.1.6 sulfidation Corrosion of metal resulting from reaction with sulfur compounds in high-temperature environments such that a surface sulfide scale forms often with sulfur penetrating somewhat below the original thickness. The term sulfidic corrosion is consistent with this definition. In this document, sulfidation does not refer to extensive internal attack below the original wall thickness as may occur at temperatures in excess of 1000 °F (538 °C). 3.2 Acronyms CML corrosion monitoring location formerly known as TML Cr chromium H 2 hydrogen H 2 S hydrogen sulfide Mo molybdenum Ni nickel PMI positive materials identification PWHT post-weld heat treatment RT radiographic testing (inspection), a.k.a. gamma ray or X-ray inspection S sulfur Si silicon UT ultrasonic testing (inspection) 4 Basics of Sulfidation Corrosion Sulfidation corrosion, also often referred to as sulfidic corrosion, is not a new phenomenon, but was first observed in the late 1800s in a pipe still (crude separation) unit, due to the naturally occurring sulfur compounds found in crude oil. When heated for separation, the various fractions in the crude were found to contain sulfur compounds that corroded the steel equipment.
When hydroprocessing was introduced in the 1950s, changes in the corrosion behavior of construction materials were noted. This led to the recognition that a different sulfidation corrosion behavior resulted under hydroprocessing conditions which typically involve the presence of hydrogen. Empirical industry data as well as laboratory research indicates that the sulfidation corrosion rate is a function of a variety of factors including: temperature, the total sulfur concentration, the types of sulfur compounds present, the type of stream (e.g. light gas or heavy oil), the velocity (or flow regime), heat transfer conditions, the presence or absence of hydrogen, and the material of construction.