Reliable design of sour water strippers

A simulation model aims to raise confidence in the reliability of sour water stripper design. Oil refining always generates sour water, and within a refinery there are numerous sources.

Nathan Hatcher and Ralph Weiland
Optimized Gas Treating

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Article Summary

Most refinery sour water systems contain very little CO2. The H2S content makes water “sour”, and H2S levels can become very high. The capacity of ammonia solutions for H2S is a direct result of ammonia’s alkalinity, which neutralises the hydrogen ion liberated by H2S dissociation when it dissolves into the solution. Although not the usual case, in principle, and with enough H2S partial pressure, there can even be more H2S than ammonia. The potentially very high H2S content can make sour water extremely foul and, if the H2S is not recovered, pollution levels would be completely out of hand. Many sour4 water sources have been noted.1 Sources include the following:
• Many refining units use live steam and heat for fractionation, and live steam for velocity assist and temperature control in fired heaters. Nitrogen in the presence of heat and a hydrogen source (such as a hydrocarbon) forms ammonia. The steam is condensed and recovered in the overhead circuit of the crude unit, FCC unit or coker unit
• In the case of refinery hydrotreating, hydrogen gas and a metal catalyst are used to saturate olefins. Hydrotreating also converts sulphur-containing hydrocarbons to H2S, and nitrogen-bearing hydrocarbons to ammonia
• Although ammonia is considerably more volatile than most alkanolamines, it has a high affinity for water. Ammonia is removed from hydrocarbon products by injecting wash water into the gas and cooling the mixture at an elevated pressure to condense the water. This provides an irresistible invitation for ammonia to enter the aqueous phase
• Wash water prevents the accumulation of salts and the corrosion of heat exchange surfaces, especially in areas where there are gas liquid interfaces and where there are sudden temperature changes on heat transfer surfaces, such as when heat transfer is controlled by liquid level in an exchanger
• Amine regenerator reflux water purges can also be a significant source of ammonia.

The sour water generated in refineries is generally classified as being either phenolic or non-phenolic. Non-phenolic water contains almost exclusively NH3, H2S and possibly a trace of CO2; it is generated by refinery hydrotreating (hydrodesulphurisation, or HDS) units. When stripped of contaminants, non-phenolic water can typically be recycled for reuse in the HDS as wash water, or it can be used as make-up water to the crude desalting process. This article considers only non-phenolic water. Phenolic (or, more broadly, non-HDS) water contains compounds that can harm upstream units if used as wash water in them. Typical contaminants include salts, phenols and caustic. However, make-up water to processing units must first be treated, so maximising water reuse is desirable to minimise attendant operating costs. Other sources of water to sour water stripping units are process drums, crude desalting units, scrubbing of hydrocarbons following caustic treatment for mercaptans, COS and final H2S removal, TGU quench columns, and various effluent drains for removing the water used to prevent salt deposition in equipment.1

It may be useful to point out that ammonia and hydrogen sulphide have almost unlimited solubility in water when they are present together. This is a possibly interesting consequence of the fact that the reactive component of the solvent, ammonia, is volatile and, if present in the gas phase, it will continue to absorb as long as it becomes protonated as a result of H2S co-absorption. Thus, it is conceivable that a particular sour water stream may be a lot more concentrated in both ammonia and hydrogen sulphide than the solubility of either component alone would suggest.

Basic sour water stripping process
At first glance, sour water stripping is a simple process in which either external steam, steam generated by a reboiler, or even a hot hydrocarbon stripping vapour is used to shift chemical reaction equilibria by heating the sour water. Stripping vapour is the “gaseous solvent” used to remove and carry the ammonia and H2S out of the system. In other words, the application of heat generates internal stripping steam (equivalently, live steam injection or stripping gas can be used) and removes ammonia, H2S and CO2 from the water by:
• Heating the sour water feed to boiling point
• Reversing chemical reactions
• Diluting the partial pressure of the gases stripped by furnishing excess steam.

The process is very similar to amine regeneration. Figure 1 shows a typical sour water stripper column with heating by the injection of live steam. Since a sour water stripper does not form a closed loop in the same sense that an amine regenerator does, maintaining a water balance is unnecessary. This means that live steam can be used as a stripping agent either alone or in conjunction with a conventional reboiler, and the additional water added by the condensate is simply added to the refinery’s water inventory. Typical energy usage in the stripping process is in the range 1.0-1.5 lb of 50 psig equivalent saturated steam per gallon of sour water.

When an external reboiler is used, steam pressure can often be higher than in an amine regenerator to minimise the heat exchange surface. In an amine regenerator, amine degradation limits temperatures. In a sour water stripper, there is little or no ammonia in the stripped water in the reboiler, so these concerns do not exist. However, there is a practical limit of 400-450°F, where coking heavy hydrocarbons can lead to fouling and solids deposition in the reboiler. Corrosion is always a concern.

Higher NH3 and H2S concentrations require more stripping energy. Since H2S solubility relies on the presence of ammonia, the molar concentration of H2S very rarely exceeds that of ammonia, and then usually only in dilute systems. A typical molar ratio of H2S to ammonia is 0.5-0.8 in the combined sour water stripper feed water of a typical refinery. Ammonia levels in the water are often determined by upstream process conditions, and they can be highly specific to the process licensor and crude slate in operation. Obviously, higher concentrations of NH3 and H2S are preferred from a water consumption perspective. However, there is a practical limit of between one and several weight per cent ammonium bisulphide equivalent in the sour water feed before metallurgy must be upgraded.

Trays have historically been used in sour water strippers, but random packing is beginning to see use in units processing relatively clean water. Trays with directional, fixed valves have been reported to be more resistant to fouling, because the horizontal velocity imparted as the gas leaves each valve tends to sweep clean the area near the valves.2

Stripped sour water specifications for NH3 and H2S can be highly dependent upon the locale where the unit is installed and the final discharge requirements. NH3 is harder to strip than H2S, and typical targets for NH3 are 30-80 ppmw in the stripped water versus undetectable to less than 0.1 ppmw for H2S. Typical recent installations3,4 involve 35-45 actual trays, with overall tray efficiencies quoted anywhere from 25 to 45%.

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