API RP 941-2016 pdf download

API RP 941-2016 pdf download

API RP 941-2016 pdf download.Steels for Hydrogen Service at Elevated Temperatures and Pressures in Petroleum Refineries and Petrochemical Plants.
3.3 High Temperature Hydrogen Attack (HTHA) in a Liquid Hydrocarbon Phase HTHA can occur in a liquid hydrocarbon phase if it can occur in the gas phase in equilibrium with the liquid phase. For materials selection purposes (using Figure 1), hydrogen dissolved in liquid hydrocarbon should be assumed to exert a vapor pressure equal to the hydrogen partial pressure of the gas with which the liquid is, or was last, in equilibrium. Recent plant experience and testing of field-exposed specimens have shown that HTHA can occur under such conditions [10] . HTHA has been found in liquid-filled carbon steel piping downstream of a heavy oil desulfurization unit separator that was operating at hydrogen partial pressure and temperature conditions above the Figure 1 welded with PWHT carbon steel curve. Testing of field-exposed test specimens showed HTHA of both chrome-plated and bare carbon steel samples that were totally immersed in liquid [10] . Several HTHA failures were found in liquid-filled carbon steel piping not subject to PWHT downstream of gasoline desulfurization unit reactors that were operating at hydrogen partial pressures and temperatures below the welded and PWHT carbon steel curve as it appeared in Figure 1 in previous editions of this RP. See Annex F for more discussion of non-PWHT’d carbon steel. See Annex G for more discussion on how to calculate the hydrogen partial pressure in liquid-filled equipment and piping. 3.4 Base Material for Refractory-lined Equipment or Piping For cold-wall refractory-lined equipment or piping, there can be a risk of HTHA when: — the internal process conditions are above the relevant carbon steel curve of Figure 1, and — the refractory becomes degraded or there is gas bypass behind the refractory, resulting in a hot spot on the outer shell. The materials selection for the outer shell should consider the risk and possible severity of metal hot spots due to refractory damage.
A more reliable way of protecting the base metal in refractory-lined equipment with a risk of HTHA is to select materials resistant to the internal hydrogen partial pressure and predicted hot spot temperatures. The design can still take advantage of higher allowable stresses at the cooler refractory-protected temperatures to enable less wall thickness, while protecting the base metal from the potential of HTHA failure. 3.5 References and Comments for Figure 1 NOTE The data points in Figure 1 are labeled with reference numbers corresponding to the sources listed in 3.5.1. The letters in the figure correspond to the comments listed in 3.5.2. 3.5.1 References 1) Shell Oil Company, private communication to API Subcommittee on Corrosion. 2) Timken Roller Bearing Company, private communication to API Subcommittee on Corrosion. 3) F.K. Naumann, “Influence of Alloy Additions to Steel Upon Resistance to Hydrogen Under High Pressure,” Technische Mitieilungen Krupp, Vol. 1, No. 12, pp. 223–234, 1938.
3.5.2 Comments A) A section made of A106 pipe was found to be damaged to 27 % of its thickness after 5745 hours. Other pieces of pipe in the same line were unaffected. B) The damage was concentrated in the overheated section of a hot bent steel elbow. The unheated straight portions of the elbow were not attacked. C) In a series of 29 steel samples, 12 were damaged, while 17 were not. D) After 2 years exposure, five out of six pieces of carbon steel pipe were damaged. One piece of pipe was unaffected. E) Damage was concentrated in the weld and heat-affected sections of A106 pipe. Base metal on either side of this zone was unaffected. F) After 11 years of service, damage was found in the hot bent section of A106 pipe. Unheated straight sections were not affected. G) After 2 years of service, all parts of carbon steel pipe, including weld and heat-affected zone (HAZs), were satisfactory. H) After 4 years of service, weld and HAZs of A106 pipe showed cracks. J) After 31 years of service, a forging of 0.3C-1.3Cr-0.25Mo steel showed cracks 0.007 in. (0.2 mm) deep. K) Pipes of 1.25Cr-0.25Mo steel. L) After 4 years of service, a forging of 0.3C-1.3Cr-0.25Mo steel was unaffected. N) After 7 years of service, a forging of 0.3C-1.52Cr-0.50Mo steel showed cracks 0.050 in. (1.3 mm) deep.

The previous

API RP 939-C-2019 pdf download

The next

API RP 970-2017 pdf download

Related Standards