The Equipment Design Process
359
5. Adjustments in process conditions
6. Removal of sulfur and other impurities
Materials selection. The corrosion table for specific metals and alloys can be
used to guide the selection of various corrodents for the conditions that will
occur in the refinery.
For sections of the refinery subjected to high-pressure hydrogen at elevated
temperatures, such as the hydrocracking, the empirical Nelson curves and
the appropriate ASME codes are used. The Nelson curve is used and recommended by the American Petroleum Institute (API), and it is updated from
time to time. To check the latest edition, contact the API (1220 L Street NW,
Washington, DC 20005-4070).
The applicable ASME Boiler and Pressure Vessel Code is Section VIII,
Divisions 1 and 2, and provides the design limits for steels in high temperature and pressure service.
Because of its insidious nature, hydrogen attack is difficult to detect in onstream equipment. The initial stages can only be detected by metallographic
examination of samples cut off the equipment, whereas severe damage can
be detected on-stream by ultrasonic measurements.
Low-temperature hydrogen is equally insidious but can usually be controlled by modifications in process conditions. Washing the process streams
with water to remove some of the corrodents or adding corrosion inhibitors
can sometimes alleviate the problem. Recommended practices have been
developed by the API and NACE to minimize the susceptibility of welds to
cracking from low-temperature hydrogen attack. Experience indicates that a
weld hardness of less than Brinell 200 is satisfactory for refinery equipment
in severe environments. Welds greater than 200 Brinell should be given a
tempering heat treatment.
Refinery equipment that handles strong acids and bases requires special
corrosion protection, as in the chemical industry. Similarly, the cooling and
boiler water treatments are basically the same as those practiced in the utilities industry, as discussed in the section on water treatment and supply systems. Corrosive vapor and acid condensates containing carbon dioxide, sulfur
dioxide, and hydrogen sulfide are encountered in other processing units, such
as distillation towers. Methods of treatment are by inhibitors and materials
selection, using economics in finalizing the decision-making process.
Sulfur compounds are especially troublesome, causing corrosion and poisoning catalysts. Hydrogen sulfide may be a dissolved component of the
crude oil or formed in the distillation furnaces, hydrosulfurization units, or
hydrocrackers. Both the organic sulfur and hydrogen sulfide are corrosive
to carbon steel above 500ºF (ASTM STP-558). For sulfur removal, the products or the crudes are treated catalytically with high-pressure, high-temperature hydrogen. The mixture of H 2 S and H 2 requires special precautions
359
5. Adjustments in process conditions
6. Removal of sulfur and other impurities
Materials selection. The corrosion table for specific metals and alloys can be
used to guide the selection of various corrodents for the conditions that will
occur in the refinery.
For sections of the refinery subjected to high-pressure hydrogen at elevated
temperatures, such as the hydrocracking, the empirical Nelson curves and
the appropriate ASME codes are used. The Nelson curve is used and recommended by the American Petroleum Institute (API), and it is updated from
time to time. To check the latest edition, contact the API (1220 L Street NW,
Washington, DC 20005-4070).
The applicable ASME Boiler and Pressure Vessel Code is Section VIII,
Divisions 1 and 2, and provides the design limits for steels in high temperature and pressure service.
Because of its insidious nature, hydrogen attack is difficult to detect in onstream equipment. The initial stages can only be detected by metallographic
examination of samples cut off the equipment, whereas severe damage can
be detected on-stream by ultrasonic measurements.
Low-temperature hydrogen is equally insidious but can usually be controlled by modifications in process conditions. Washing the process streams
with water to remove some of the corrodents or adding corrosion inhibitors
can sometimes alleviate the problem. Recommended practices have been
developed by the API and NACE to minimize the susceptibility of welds to
cracking from low-temperature hydrogen attack. Experience indicates that a
weld hardness of less than Brinell 200 is satisfactory for refinery equipment
in severe environments. Welds greater than 200 Brinell should be given a
tempering heat treatment.
Refinery equipment that handles strong acids and bases requires special
corrosion protection, as in the chemical industry. Similarly, the cooling and
boiler water treatments are basically the same as those practiced in the utilities industry, as discussed in the section on water treatment and supply systems. Corrosive vapor and acid condensates containing carbon dioxide, sulfur
dioxide, and hydrogen sulfide are encountered in other processing units, such
as distillation towers. Methods of treatment are by inhibitors and materials
selection, using economics in finalizing the decision-making process.
Sulfur compounds are especially troublesome, causing corrosion and poisoning catalysts. Hydrogen sulfide may be a dissolved component of the
crude oil or formed in the distillation furnaces, hydrosulfurization units, or
hydrocrackers. Both the organic sulfur and hydrogen sulfide are corrosive
to carbon steel above 500ºF (ASTM STP-558). For sulfur removal, the products or the crudes are treated catalytically with high-pressure, high-temperature hydrogen. The mixture of H 2 S and H 2 requires special precautions