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216 Gas Pun3cation

amine exchangem should be located upstream of the rich amine level control valve to minimize
acid gas evolution inside the exchangers, and the rich amine should be on the tube side. If the
ledrich amine exchangers are stacked, rich amine should flow up through the tubeside of the
bottom exchanger to the tubeside of the upper unit.

Erosion-Corrosion of Lean Amine Pumps

To minimize turbulence and erosion-corrosion of the lean amine pump impeller and cas-
ing, Sheilan and Smith (1984) recommend a minimum of 8 to 9 pipe diameters of straight
pipe upstream of the pump suction. As shown in Figure 3-1, lean amine pumps should be
located downstream of the leadrich amine exchanger because the hot lean amine solution
leaving the regenerator is often near its boiling point at the elevation corresponding to the
lean amine pump suction. Placing the lean amine pump downstream of the leadrich
exchanger ensures that the lean amine is subcooled and, therefore, less subject to gas evolu-
tion when it enters the pump. Cooling the lean amine solution also raises the solution pH
(see Figure 3-4) and makes the solution less corrosive (see Figure 3-6).

Erosion-Corrosion of Pressure Let-Down Valves

To reduce erosion-corrosion of pressure let-down valves downstream of absorbers, Graff
(1959) recommends the use of carbon steel bodies with type 316 SS intemals and stellited
trim when the valve pressure drop is above 7 to 14 bar (100 to 200 psi). Scheirman (1976)
recommends carbon steel globe body valves with stellited 316 SS intemals, but also suggests
that valves be selected with the maximum feasible valve body size in order to minimize the
amine velocity through the valve body.
Cracking of Carbon Steel in Amine Service

Background
Four carbon steel cracking mechanisms in alkanolamine gas treating units have been iden-
tified. Reviews of these cracking mechanisms have been provided by Menick (1989), Buch-
heim (1990), Gutzeit (1990), and in API 945 (MI, 1990). The first three cracking mecha-
nisms are associated with the entry of atomic hydrogen into the carbon steel lattice. These
three cracking mechanisms are known as sulfide stress cracking (SSC), hydrogen-induced
cracking (HIC), and stress-oriented hydrogen induced cracking (SOHIC). All three of these
cracking mechanisms require the production of atomic hydrogen in an aqueous-HzS solution.
While there is no established lower H2S concentration limit, industry practice has been to
assume that aqueous solutions containing more than 50 ppmw HzS can lead to cracking
(NACE, 1994B). In the vapor phase, a commonly used threshold for SSC is an H2S partial
pressure of 0.34 kPa (0.05 psia). The three cracking mechanisms are distinguished from each
other by what entraps the atomic hydrogen inside the metal lattice, whether it recombines to
form molecular hydrogen, the orientation and features of the resulting cracks, and the correc-
tive measures required to minimize each type of cracking. The fourth mode of cracking is
alkaline stress corrosion cracking (ASCC). It is thought that ASCC is caused by a film rup
ture mechanism. Stressed areas such as heat-affected zones slip, breaking the passive film
and exposing bare steel, which corrodes to form cracks. The passive film reforms, but resid-
ual stresses cause the film to rupture again, leading to more corrosion. Repetition of this