Operational challenges in sour water stripping
How to keep a sour water stripper at optimum performance between shutdowns.
PHILIP LE GRANGE
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Sour water strippers (SWS) are used primarily to remove ammonia (NH3) and hydrogen sulphide (H2S) from refinery wastewater streams. As with any industrial process, there are challenges to keeping a SWS unit on stream and on specification between shutdowns. These can be grouped as follows:
• Limiting fouling
• Maintaining treated water ammonium (NH4+) and total sulphur specification
• Managing corrosion
• Limiting hydrocarbon content of the off-gas
• Managing feed water quality.
Challenge 1: Fouling
Sour water stripping is considered ‘fouling service’ and thus it is generally recommended that fouling-resistant trays be installed in the column. In some instances, improved run time has been achieved by replacing conventional trays with fouling-resistant trays1 and installing bypasses around individual feed/effluent exchangers (there are often several in series) to allow for on-stream cleaning.
Several types of fouling have been observed historically in SWS units and the nature of the fouling can broadly be divided into five categories:
• Elemental sulphur
Hydrocarbon based fouling often occurs when a large volume of naphtha and heavy boiling-range hydrocarbon material is carried into a sour water stripper. The hydrocarbon will tend to agglomerate to small particulates in the unit feed water or particulates generated by corrosion in the stripper. This tends to result in a sticky, black, sludge-like substance that frequently accumulates in the exchangers. A common example of this type of fouling is shown in Figure 1. A more gum-like texture is also possible and is often associated with heavy hydrocarbon wax fractions or cracked feeds entering the unit.
This sort of fouling is the most prevalent. Mitigation is usually achieved by:
• Improving maintenance and control on upstream water boots to prevent bulk carry-under of hydrocarbons with the sour water
• Ensuring good control of the oil-water interface in the three phase separator on the sour water feed (normally a liquid level of 50-60% is optimal)
• Using appropriate technology to remove emulsified hydrocarbon (This can take the form of a long-residence time feed tank with skimming facilities or an inlet filter coalescer system.) Some water-oil emulsions can take several days to separate into distinct phases so the separation can be challenging
• Periodically washing the column if sufficient storage capacity for sour water exists (normally 48 hours is required). Various procedures exist, often with multiple washes. Broadly, weak acid and base washes are used to remove scaling (precipitated salts) with detergent washes (or in some cases, just as effectively, vapour phase naphthenic hydrocarbon with steam) being used to remove hydrocarbons.
The stability of a hydrocarbon emulsion can be strongly affected by pH. In a typical refinery SWS, the pH rises as the water passes down through the column (in the absence of un-neutralised strong-base contaminants) because H2S is more readily stripped from the sour water than NH3. This effect can result in a hydrocarbon phase forming in the lower part of the stripper column and on the effluent side of a feed/effluent exchanger, preferentially fouling the effluent rather than the feed side of the feed effluent exchanger.
Particulate based fouling is normally a result of coke (from thermal cracking units), catalyst fines, upstream corrosion products, or corrosion products generated in the SWS unit. In many cases, this type of fouling is seen in conjunction with hydrocarbon or salt precipitation fouling as the particulate fines provide a nucleus for hydrocarbon agglomeration or salt crystallisation. This type of fouling is usually mitigated by:
• Locating the source of the particles and addressing the issues causing their generation
• Filtering the feed water (While this is not always required, it is in some cases necessary, especially if the column is packed. Most conventional and high performance packings can become plugged by high particulate loads.)
One example of the many possible variations of this fouling type is shown in Figure 2.
Salt based fouling is typically a result of the presence of calcium or magnesium ions in the feed water to the stripper. To avoid this type of fouling, the water feed to the SWS should not have appreciable water hardness (a standard test for Ca and Mg). Typically, this sort of fouling occurs because of low quality wash water, a problem with the refinery’s water treatment plant, or an ingress of poor quality water into the system (for example, through a leaking water cooler on an upstream unit).
Sour water from coal gasification plants typically contains CaCO3 which requires a pH of 6 to 6.5 to prevent precipitation. Hydrochloric acid is typically used to adjust the water pH to the acceptable range. Unfortunately, the use of a strong acid often results in difficulty meeting ammonia specification in the treated water, thus the acid method should be avoided. Sulphuric acid should be avoided as it will result in sulphur forming side reactions with H2S.
Selenium can precipitate out in a SWS column and is typically grey in colour (this form of selenium normally requires temperatures of 180⁰C (355⁰F), but the presence of amine catalyses its formation.20 It has also in some cases resulted in pink coloured stripped water.
In some rare instances crude oils contain complex chemical scavengers, such as triazine, that can precipitate out of solution. The only prevention for this problem is to avoid adding these chemicals upstream.
While other salts are possible, generally they must be present at much higher concentrations to precipitate than are normally found at steady operating conditions. For example, if very large volumes of caustic enter the system this can create a salt precipitation problem, as seen in Figure 3, and should be kept out of the SWS feed as far as possible. SWS units are (generally) not suitable for treating caustic effluents.
Ammonium carbonate and bicarbonate will sublime from the SWS off-gas in the temperature range 55-75°C (130-167°F). When the gas cools excessively, a solid forms that fouls instruments, control valves and lines. A minimum gas temperature of 85°C should be maintained to prevent sublimation. Checking overhead lines for cold spots should be done on a regular basis. These lines should be insulated and steam traced as a minimum, but steam jacketing is preferred.
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