Remove dissolved hydrogen sulfide (H2S) and ammonia (NH3) from sour water (H2O) before conveying it to waste H2O treatment. Sour H2O comes from many sources such as catalytic cracking units, hydrocrackers, flare seal drums, etc. Normally, refinery SWS are designed for feed concentration ranging from 500 to 15,000 ppmw each of NH3 and H2S. The molar ratio of NH3 to H2S generally ranges between 0.75 to 2, and averages about 1.2. pH is commonly from 7 to 9.3. The process can also be designed to take account of mercaptans, phenols and some aromatics. There are several SWSs types, all of them operate by passing sour H2O through a multistage stripping tower.
SWS contains a fractionating tower, which removes H2S and NH3 from sour H2O along with some mercaptans, aromatics and phenols. The tower is normally refluxed to reduce H2O in the overhead offgas and reduce downstream processing units (i.e. sulfur plants) size and cost. Steam is the most commonly used stripping medium, but flue gas, fuel gas and natural gas can also be used.
Typically, the sour H2O feed stream is preheated by heat exchange with hot stripped H2O prior to tower entry. Stripping steam is introduced into the tower bottom. H2S and NH3 are stripped out by counter-current contact with the steam. Typically, H2S and NH3 are stripped to ppm level.
Operating conditions: Operating pressure is generally set at a level to provide enough pressure to deliver offgas to its destination. A tower top pressure of 1.3–1.7 barg is typically enough when the offgas is sent to a sulfur recovery plant.
Overhead separator operating temperature should be set in the range of 82°C–90°C. A lower temperature can lead to plugging problems due to the formation of ammonium hydrosulfide, while a higher temperature results in more H2O vapor in the offgas affecting downstream equipment size. Fluids handled in SWS facilities are corrosive. Proper construction materials selectionis an important aspect in SWS design.
Licensor: SIIRTEC NIGI