API RP 581 - 3rd Ed.2016 - Add.2-2020 - Risk-Based Inspection Methodology

2.B-34 API RECOMMENDED PRACTICE 581
2.B.4.5 Tables
Table 2.B.4.1—High Temperature H 2 S/H 2 Corrosion—Basic Data Required for Analysis
Basic Data
Material of construction
Type of hydrocarbon present
(naphtha or gas oil)
Maximum temperature (°C:°F)
H 2 S content of the vapor (mole %)
Comments
Determine the material of construction of the equipment/piping.
The Couper–Gorman corrosion rate curves are dependent on the type of
hydrocarbon stream present [95, 100] . There are two categories as follows
1) Naphtha refers to those hydrocarbon streams of both light and heavy
naphtha as well as light distillates (streams typically boiling at <430 °F);
2) Gas oil refers to those hydrocarbon streams that include distillate,
atmospheric gas oils, resid, and other heavier process hydrocarbons
(streams typically boiling at >430 °F).
Determine the maximum process temperature.
Determine the H 2 S content in the vapor.
Note that mole% = volume % (not wt%)
Table 2.B.4.2—High Temperature H 2 S/H 2 Corrosion—Estimated Corrosion Rates for Carbon Steel,
1 Cr-0.2 Mo, 1 Cr-0.5 Mo, 1.25Cr-0.5Mo, 2.25Cr-1Mo, and 3Cr-1Mo (mpy)
H 2 S
(mole %)
Type of
Hydrocarbon
Temperature (°F)
425 475 525 575 625 675 725 775 825 875 925 975
0.002
0.0035
0.008
0.035
0.08
0.30
0.75
1.0
Naphtha 1 1 1 1 2 3 4 6 8 10 14 18
Gas oil 1 1 1 2 3 5 7 10 14 20 26 34
Naphtha 1 1 1 2 4 6 8 12 16 22 29 37
Gas oil 1 2 3 4 7 11 16 22 31 41 55 71
Naphtha 1 1 2 3 5 7 11 15 21 29 38 50
Gas oil 1 2 4 6 9 14 21 29 41 55 73 94
Naphtha 1 2 3 5 9 13 19 27 38 51 67 87
Gas oil 2 4 6 10 16 25 36 51 71 96 130 170
Naphtha 1 2 4 7 10 16 23 33 46 62 82 110
Gas oil 2 4 8 13 20 30 44 63 87 120 160 200
Naphtha 2 3 6 10 15 23 34 48 66 90 120 150
Gas oil 3 6 11 18 29 44 64 91 130 170 230 300
Naphtha 2 4 7 11 17 26 38 54 75 100 130 170
Gas oil 4 7 12 21 32 49 72 100 140 190 250 330
Naphtha 3 5 8 13 21 32 47 67 93 130 170 220
Gas oil 5 9 15 26 40 61 89 130 180 240 310 410