Sour Water Corrosion | Materials And Corrosion Control
| Damage Mechanism | Sour Water Corrosion – SWC (Acidic) |
| Damage Description | · 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.
· Sour waters containing significant amounts of ammonia, chlorides or cyanides may significantly affect pH. · Normally general corrosion but can be localized. |
| Affected Materials | Primarily Carbon Steel. Stainless steels, copper alloys and nickel base alloys are usually resistant. |
| Control Methodology | · H2S content, pH, temperature, velocity and oxygen concentration are all critical factors.
· Keep pH between 4.5 and 7.0. Above a pH of about 4.5, a protective, thin iron sulfide layer limits the corrosion rate. · 300 Series SS can be used at temperatures below about 140°F (60°C) where Chloride Stress Corrosion Cracking (CSCC) is not likely. · 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. |
| Monitoring Techniques | · Scanning UT and profile RT.
· Check areas where water phase is condensing for localized thinning. · Monitor pH periodically. · OSI · Corrosion probes and coupons. |
| Inspection Frequency | · Monitor temperature, pH trends every shift
· UT, coupons and visual inspection at T&I |
| KPIs | · Comply with pH range between 4.5 to 7.0 |
| Reference Resources (Standards/GIs/BPs) | · API RP 571 (DM #13) |
Additional Information
Sour water is a term loosely used in refineries for the process water that is separated and removed from any hydrocarbon stream in the refinery but it can have different properties depending on the source. In general, sour water in refining process is alkaline, meaning pH of 8 or higher basically because of the presence of ammonia (NH3). Let’s describe some examples to illustrate the differences.
If a crude unit overhead stream were not neutralized with either NH3 or amine Neutralizers, the sour water would be acidic because of the presence of hydrochloric acid due to the presence of HCl. We would not classify this corrosion mechanism twice as HCl Corrosion and Sour Water Corrosion, we refer to only HCl Corrosion.
For most of the cases in oil refining where the sour water is alkaline rather than acidic, the corrosion mechanism is NH4HS corrosion. We would not classify this corrosion mechanism twice as NH4HS Corrosion and Sour Water Corrosion, we refer to only NH4HS corrosion.
Likewise, there could be sour water with H2S but without NH3. In this case the main corrosion mechanism would be wet H2S corrosion. We would not classify this corrosion mechanism twice as wet H2S Corrosion and Sour Water Corrosion, we refer to only wet H2S Corrosion.
The case of unit J80 HCU in RTR could also be used to illustrate that the sour water from the fractionator overhead receiver and the naphtha splitter receiver should have no H2S no NH3.
So the corrosion mechanism should be aqueous corrosion. Since there should be no chloride and since the source of this water is exclusively from steam, I decided to see it as condensate corrosion that solely depends on oxygen and CO2 content. In any case, we would not classify this corrosion mechanism twice as Aqueous Corrosion and Sour Water Corrosion, we refer to only Aqueous Corrosion or Condensate Corrosion, whichever fit best the mechanism.