API RP 939-C:2009 pdf download

API RP 939-C:2009 pdf download.Guidelines for Avoiding Sulfidation(Sulfidic) Corrosion Failures in Oil Refineries.
6.3.3.4 Stripping Steam
The degree of stripping does not significantly affect sulfidation in light oil hydrotreaters. However, steam injection to shorten furnace residence time can be a major contributor to sulfidation corrosion in heavy oil hydrotreaters and hydrocrackers. The effect of the stripping steam may be two-fold: a primary effect may be that the shorter residence time does not allow the sulfur vapors to evolve and disengage, so that more corrosion occurs further downstream in the hotter sections of columns and piping circuits that might otherwise be expected to be sulfur-free.
7 Practical Guidelines for Avoiding Sulfidation Corrosion Failures
This section first covers actions that refineries can take to avoid failures due to sulfidation corrosion of existing equipment, emphasizing inspection planning and strategy. Then, materials selection considerations for new equipment are covered.
7.1 For Existing Units and Components
There are a number of steps that refineries can take to limit the likelihood of a sulfidation corrosion failure.
7.1.1 Create and Implement an Inspection Plan for Components in Sulfidation Corrosion Service
The first step is to create an inspection plan. Equipment operating at conditions under which H2-free sulfidation or H2/ H2S corrosion can occur must be identified. Based on factors such as the consequence of failure, the anticipated corrosion rate, and the past inspection results, a plan is devised consisting of an inspection date, scope, method and interval for follow-up inspection. API 581 contains tables that can be used to estimate possible corrosion rates. In most cases, sulfidation corrosion is generalized, so an effective inspection can consist of targeted point thickness readings. The following are some issues that may need to be considered when planning inspections.
— Increases in operating temperatures and operating severity over many years can lead to unexpected increases in corrosion rates.
— The partitioning effect of sulfur compounds into certain streams; heavier streams may contain more and different sulfur types.
— Flow regime or stratification in horizontal lines, heater tubes, and deadlegs. The top of the tube or pipe may corrode more because of H2S vapor blanketing and in heaters higher temperature. Vertical heater tubes are prone to accelerated corrosion on the top return bends and bottom fired heaters may experience more corrosion on the hotter bottom surfaces. Vertical deadlegs can also be prone due to chimney effects, leading to accumulation of higher concentrations of sulfidation corrosion causing species. Finned tubes may operate hotter and corrode more than adjacent unfinned tubes.
— High-velocity areas and injection points may be more prone to corrosion due to flashing and turbulence that reduces the adherence of the protective scale. Notable areas are the hydrogen injection points in hydrotreaters, around control valves, and downstream of orifice plates.
— High-temperature line supports can act as cooling fins, if the component operates above the peak of the sulfidation corrosion curve. A support can act as a cooling fin and lead to locally higher corrosion in the cooler part of the line, such as in an FCC reactor overhead line.
— Specification breaks, i.e. where a higher alloy adjoins a lower alloy. There is no “galvanic” effect, but these locations tend to be areas where the lower alloy may be marginal.
lf UT readings are taken at high temperature, special probes, couplants, and calibration techniques are needed toaccount for the difference of sound velocity vs temperature. Properly qualified procedures and technicians arerequired if readings are to be taken with the piping hot. If monitoring known areas of active corrosion, a goodpractice is to take baseline readings cold (i.e.during a shutdown) followed by a set of baseline readings at hightemperature right after start-up, so that subsequent in-service readings can be compared more easily.RT is a verycommon and highly effective inspection technique for small bore piping. Where localized corrosion is suspected,line or area scanning (manual or automated) UT and profile RT are used.
b) Other Methods. Other commercially available techniques that can be used to detect sulfidation include thefollowing; however, most are newer and even more operator sensitive.