PTQ Q2 2026 Issue

Central role of diagnostics in distillation energy transition: Part 2

Part 1, in PTQ, Q4 2025, explored the potential for improving fractionation systems. Part 2 focuses on solving plant problems in water-hydrocarbon stripping and separation

Henry Z. Kister Fluor Corp. Norman P. Lieberman Process Improvement Engineering

T here is an adage, ‘oil and water do not mix’. Based on this, one may think that separating the two will rank among the easiest tasks in the world and have no impact on CO 2 emissions. The following experiences may teach different lessons. Sour water stripper (SWS) optimisation The processes involved in sour water stripping are highly complex and require detailed analysis to achieve the best optimisation. Hatcher and Weiland1 point out that special rate-based models are required to map out the hydrogen sulphide (H₂S) and ammonia composition profiles in SWS. Le Grange² brings insight and a thorough description of the multitude of factors affecting the performance of these towers, including various active fouling and corrosion mech- anisms, source water impurities, bottom specifications, acid - ity, the presence of hydrocarbons, and others. A variety of common design options were described by Das and Singh.3 It appears that with all this enormous complexity, correct optimisation of these units will be elusive. Articles by Lieberman⁴ and Pilling⁵ show that, despite the complexity, engineers can do much to optimise these units and greatly lower their carbon footprints, as described in the following discussion. Stripping naphtha In one presentation, BASF’s Carine Achoundong advised to listen to operators and find out why they say what they say. What is often not appreciated is that Achoundong’s advice can lead to major reductions in carbon footprint. One of the authors attempted to raise the SWS feed rate by 30%. When feed to the stripper goes up, the steam is usually raised in proportion, assuring good bottom product quality. Many strippers maintain a constant steam-to-bottoms ratio (lb steam/barrel bottoms, usually >1,1 typically 1.3- 1.4).⁴ When the author attempted to raise the steam rate to keep the ratio constant, he was confronted by the operators, who were concerned that the higher steam rate would over- load the sulphur plant to which the stripper overhead flowed. Higher steam rate alone does not overload a sulphur plant, but adding hydrocarbons to the overhead does. Le Grange² points out that even a small increase in heavier hydrocarbons can result in a large increase in the amount of air required for combustion in the sulphur-removal unit reaction furnace.

This decreases the sulphur recovery unit (SRU) hydraulic capacity, causes unstable plant operation due to variable air demand, leads to overheating, and has many other adverse effects listed in the Le Grange article. Based on the oper- ators’ input, the author realised that the additional steam stripped the heavy hydrocarbons from the bottoms. The stripper bottoms went to the desalter. Heavy hydrocarbons are desirable in the desalter because they will be recovered mostly as naphtha. In the sulphur plant, they will be burned. Consider a 400 gpm SWS unit, with 0.5% liquid volume (LV) naphtha in the feed. This is 2 gpm of recoverable naph - tha. In one day, this amounts to 2,880 gallons of gasoline, producing 58,000 lb of CO2. Given that cars consume 12 gallons of gasoline per week, this naphtha recovery is equivalent to taking 240 gasoline cars off the road. This, plus the previously noted adverse effects that naphtha has on the SRU. The one concern is that reducing the stripping ratio may increase the ammonia ppm in the stripper bottom. Lieberman points out4 that when the SWS bottom goes to the desalter, the ammonia (NH₃) content should be 10-20 ppm. Higher ammonia content interferes with crude tower corrosion con- trol due to chlorides. 100 ppm NH₃ is excessive for desalter operation. In this case, leaving the naphtha in the bottom still resulted in an NH₃ concentration below 20 ppm. Feed preheat Another question raised was the need to preheat the SWS feed.4 Lieberman questioned the necessity of this universal practice.1 - 3 Energy savings studies6 , 7 show that when the concentration of lights (components that will end up in the tower overhead product) is low, preheating the feed will then load up the condenser with very little reduction in reboiler energy. This is the case with the SWS, where typically the feed is above 95-98% mole water. Liebert⁸ defines preheat efficiency as the reduction in reboiler duty per increase in preheat duty. For instance, if adding 2 MM Btu/h preheat lowers the reboiler duty by 0.8 MM Btu/h, the preheat efficiency is 40%. In Figure 1 , this preheat efficiency is plotted against q (the thermal state of the feed). q is defined as the number of lb moles of liquid generated in the column by the introduction of 1 lb mole of feed. For an all-vapour feed, q is 0; for an all-liquid feed, q is 1. For a subcooled liquid, q is larger than 1 and is given by:

PTQ Q2 2026