API RP 939-C-2019 pdf free download
API RP 939-C-2019 pdf free download.Guidelines for Avoiding Sulfidation (Sulfidic) Corrosion Failures in Oil Refineries.
Sulfidation corrosion, also often referred to as “sulfidic corrosion,” continues to be a significant cause of leaks in piping and equipment within the refining industry. The objective of this recommended practice (RP) is to provide a better understanding of sulfidation corrosion characteristics and give practical guidance to inspectors and maintenance, reliability, project, operations, and corrosion personnel on how to address sulfidation corrosion in petroleum refining operations. Examples of failures are discussed to highlight the common causes. The methods used to control and inspect for sulfidation corrosion are summarized. The data herein are a compilation of information extracted from published technical papers, industry information exchanges (NACE and API), and contributions from several owner/ operators. Some refining companies have developed proprietary methods to predict sulfidation corrosion, and these were not made available as part of this effort. There are two separate and distinct mechanisms of sulfidation corrosion. One occurs where H 2 is present in addition to the sulfidation-causing sulfur species, as is common in many refining processes, such as hydrotreating and hydrocracking. The other occurs in the absence of H 2 (hydrogen free) in processing units that do not employ H 2 as a component of the process. They both are non-aqueous, diffusion-based corrosion mechanisms that occur at elevated temperature. There is considerable debate in the industry as to the correct threshold temperature for hydrogen-free sulfidation, and in a change in this edition, the API 571 threshold of 500 °F (260 °C) for hydrogen-free services is adopted herein. Experience has shown that little significant corrosion will occur at operating temperatures below 500 °F for hydrogen-ree sulfidation services without the influence of naphthenic acid corrosion.
3.1.1 common corrosion system and circuits Typically, the piping and equipment that is organized into corrosion systems, sometimes referred to as loops, that have similar expected damage mechanisms. A system may be the overhead system of a tower. A circuit is a subset of a system, and the term “common corrosion circuit” indicates that corrosion rates and other damage would be expected to have similar likelihood and would have similar process conditions. 3.1.2 hydrogen free H 2 free Processes where H 2 is not intentionally added. There may be trace amounts of H 2 present but are in services such as crude/vacuum units, fluidized catalytic cracking (FCC), cokers, etc. 3.1.3 integrity operating window IOW Established limits for process variables (parameters) that can affect the integrity of the equipment if the process operation deviates from the established limits for a predetermined amount of time. This documentation describes 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 IOW can also define process monitoring tasks to ensure that operating conditions are maintained within the established parameters. NOTE Guidance on setting and using IOWs is given in API 584. 3.1.4 killed steel Steel that has been completely deoxidized by the addition of an agent, such as Si or aluminum (or other methods such as vacuum treatment), before casting, so that there is practically no evolution of gas during solidification. Killed steels are characterized by a high degree of chemical homogeneity and freedom from porosity.
Sulfidation corrosion, also often referred to as “sulfidic corrosion,” is not a new phenomenon but was first observed in the late 1 800s in a pipe still (crude separation) unit, due to the naturally occurring sulfur-containing organic compounds found in crude oil. When heated for separation, the various fractions separated from the crude were found to cause corrosion of the steel equipment as a result of reaction with the sulfur-containing compounds. With the advent of FCC and coking processes, sulfidation corrosion was also experienced in these units [1 ] [2] . When hydroprocessing was introduced in the 1 950s, 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 that typically involve the presence of H 2
