Acid Gas Line Corrosion

[Hippo]

Hello. I could use some help on determining whether a CS line with 0.125" CA and PWHT is acceptable in an acid gas service. The acid gas composition is ~81wt% H2S, 5wt% water, 11wt% CO2, and the balance light hydrocarbons. The line operates at 15psig and 130degF. It is a saturated vapor. Any drop in temperature would condense sour water, which would contain ~3000ppm H2S. Salts are not expected to be present.

My experience has shown this line to be steam traced to prevent or minimize condensation from occurring. The lines are typically sloped of free draining to prevent any pockets of sour water from accumulating.

I am looking for justification for the steam tracing...experience, articles, standards, etc.

I appreciate any help on this.

Thanks,
Mark

 

[SJones]

thread798-148988

Steve Jones
Materials & Corrosion Engineer

http://www.pdo.co.om/pdo/

 

[0707]

About this subject please note the following:


“5.1.1.10 Sour Water Corrosion (Acidic)

5.1.1.10.1 Description of Damage.

a) Corrosion of steel due to acidic sour water containing H2S at a pH between 4.5 and 7.0. Carbon dioxide (CO2) may also be present.

b) Sour waters containing significant amounts of ammonia, chlorides or cyanides may significantly affect pH but are outside the scope of this section.

5.1.1.10.2 Affected Materials

a) Primarily affects carbon steel.
b) Stainless steels, copper alloys and nickel base alloys are usually resistant.

5.1.1.10.3 Critical Factors

a) H2S content, pH, temperature, velocity and oxygen concentration are all critical factors.

b) The H2S concentration in the sour water is dependent on the H2S partial pressure in the gas phase as well as temperature and pH.

c) At a given pressure, the H2S concentration in the sour water decreases as temperature increases.

d) Increasing concentrations of H2S tend to decrease solution pH down to about 4.5. Streams with a Ph below 4.5 indicate the presence of a strong acid which would be the main corrosion concern (see 5.1.1).

e) Above a pH of about 4.5, a protective, thin iron sulfide layer limits the corrosion rate.

f) In some instances at a pH above 4.5, a thicker, porous sulfide film layer can form. This can promote pitting under sulfide deposits. Typically, this does not affect the general corrosion rate.

g) Other contaminants have a significant affect on water pH. For example, HCl and CO2 lower pH (more acidic). Ammonia significantly increases pH and is more often associated with alkaline sour water where the main concern is ammonia bisulfide corrosion (see 5.1.1.2).

h) The presence of air or oxidants may increase the corrosion and usually produces pitting or underdeposit attacks.

5.1.1.10.4 Affected Units or Equipment

Acid sour water corrosion is a concern in overhead systems of FCC and coker gas fractionation plants with high H2S levels and low NH3 levels.

5.1.1.10.5 Appearance or Morphology of Damage

a) Corrosion damage from acidic sour water is typically general thinning. However, localized corrosion or localized underdeposit attack can occur, especially if oxygen is present. Corrosion in CO2 containing environments may be accompanied by carbonate stress corrosion cracking (see 5.1.2.5).

b) 300 Series SS are susceptible to pitting attack and may experience crevice corrosion and/or chloride stress corrosion cracking (see 4.5.1).


5.1.1.10.6 Prevention / Mitigation

a) 300 Series SS can be used at temperatures below about 140oF (60oC) where Chloride Stress Corrosion Cracking (CSCC) is not likely.

b) Copper alloys and nickel alloys are generally not susceptible to acid sour water corrosion. However, copper alloys are vulnerable to corrosion in environments with ammonia”

Reference

Damage Mechanisms Affecting
Fixed Equipment in the
Refining Industry
RECOMMENDED PRACTICE 571
FIRST EDITION, DECEMBER 2003

 

[strider6]

I think that the most important issue here is the presence of CO2 and following corrosion.
If you can be sure that water does not condense in normal operation, using the heat tracing, you can use safely the carbon steel.
You can calculate the corrosion rate using the De Waard -Milliams Model and recent improvements, to include the effect fo H2S on the CO2 corrosion mechanisms, so you can have an idea of the corrosion that you can have when the temperature drop, eg during the shut down, and calculate the corrosion allowance for you carbon steel pipe.
Hope this help

Regards

Vict

Corrosion & Materials Engineer

http://xoomer.alice.it/corrosion

 

[dcasto]

Do the economics. CS with steam tracing will have 15 year life total cost will be of the line, tracing, insulation, condensate return , condensate pumps,steam traps, maintenance, steam use.....

SS line, install it, forget it, next ..........