run lengths, and frequent shutdowns, all with a negative car- bon footprint. Hauser and Kirkey9 describe a case of two parallel SWS containing sieve trays with 0.5in holes. Both suffered chronic fouling with salts and insoluble organics, with typical five- month run lengths. Retrofitting with large fixed valves greatly improved fouling resistance and run lengths. Le Grange,2 Lieberman,4 and the authors of this article echo these rec - ommendations, advocating for fouling-resistant trays, such as large-opening fixed valves for SWS service. Unless it is known that a specific SWS is non-fouling, mov - ing valves, small-opening fixed valves, or packings do not belong in this service. The floats of moving valve trays tend to stick to the decks, while packings and distributors tend to plug in the fouling environment of most SWS. Packings are the worst choice for SWS service, as they not only plug but also gum, coke, polymer, and pyrophoric deposits are diffi - cult to clean and prone to catching fire upon column opening at the turnaround. 10 For a 400 gpm SWS unit, a seven-day cleaning turna - round means 4.0 million gallons of water are sent to waste treatment rather than to the desalter. The average water usage in the US for one household is 300 gallons per day (www.epa.gov), which amounts to 110,000 gallons per year. So one unnecessary outage of the SWS unit is equivalent to the water consumed by 37 households in an entire year. Building on classic work is key There is a large body of distillation know-how developed over the last century. Unfortunately, some of this work is often ignored or overlooked by designers. Engineers who wish to reduce their carbon footprint should familiarise themselves with this work and apply it in their design and troubleshooting. After the start-up of a grassroots crude preflash tower (a tower that separates naphtha overhead product from crude oil bottoms), it was observed that the top naphtha product became coloured at crude feed rates exceeding 85% of the design. An investigation found that the most likely cause was foaming in the stripping trays below the feed inlet, which in turn caused the top trays to flood, resulting in crude oil entrainment in the naphtha. As part of their work on sizing preflash towers and drums, Barber and Wijn11 determined that the most important siz - ing criterion for the drum (or the tower bottom section) is the flashed crude downward superficial velocity. This should be low enough to allow the foam to remain beneath the feed nozzle, so it is retained inside the drum or in the bot- tom of the tower. The smaller the cross-sectional area for the flashed crude, the higher the foam level inside. Based on work by Barber and Wijn, the crude oil downward superficial liquid velocity should be in the range of 15 to 30 gpm/ft2. In this tower, the stripping trays consumed much of the cross-sectional area, raising the downward liquid velocity to well above the velocity that would back the foam all the way to the inlet nozzle. The ‘fix’ was to remove the stripping tray panels. Once back online, the tower has operated at 100% capacity with no further issues with naphtha quality. There were no adverse effects.
C , C
MED
LC
LC
Water
HVY
Figure 3 Tower overhead system that accumulated water
Preventing water accumulation in hydrocarbon towers Returning to the adage that water and oil do not mix, the following cases show the trouble and high carbon footprint associated with water-oil separation when basic principles are overlooked in the design or an unsuccessful solution is applied. One chemical tower separated a medium (MED) from a heavy (HVY) water-insoluble organics. The tower had a pasteurising section that separated C 1 and C 2 hydrocarbons as a vapour vent stream from MED, which came out of the side draw. Small amounts of water and chlorides entered the tower and ended up at the top. The water condensed in the overhead loop, hydrolysing the chlorides and forming acid. There was a boot on the reflux drum (see Figure 3 ), but it was mislocated downstream from the reflux draw (it should have been upstream of the draw). Not much water was picked up by it, so the water draw valve was only opened intermittently. With this operation, the water draw line was frequently plugged by corrosion products, which was a maintenance nightmare. The boot was therefore removed. It was expected that the water would end up in the vent vapour. This did not quite work as intended. With the boot out of operation, the bulk of the water was refluxed to the tower, causing accu - mulation in the overhead loop and corrosion in the exchang - ers, as well as in the dip leg from the water condenser to the drum. Increasing the vent rate helped but fell far short of solving the problem. The higher venting rate incurred a loss of MED to the vent. A much better solution would be to reinstate the boot, this time in the correct location upstream of the reflux draw, and to connect a water source introducing water on flow control to the boot outlet. This would keep the valve open, which would prevent plugging by corrosion products. Reducing the venting rate and mitigating water accumulation and corro- sion have a positive impact on the carbon footprint. Figure 4 shows the correct configuration of the reflux drum boot. The condensate enters at one end of the drum, the boot is located at the opposite end, and the reflux/prod - uct draw line is located downstream of the boot. The reflux/ product draw line has a standpipe that typically rises about
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