THIS MONTH'S PUZZLER
My refinery is grappling with how to set up the coolers for reducing oil sample temperatures for safe handling. These coolers usually consist of a U-tube inside a water jacket. The tubing is rated for 2,000 psig at 600°F; the shell maximum allowable working pressure is 75 psig at 600°F. We're working with heavy gas oil from a coker at 400°F. An alternative that's been suggested is to use a tube inside a tube: ¼-in. tubing for the oil within 1-in.tubing for the cooling-tower water. The project engineer wants hydrostatic pressure relief valves (PSVs) installed for blocked-in water. The maintenance engineer is pushing for the tube-in-tube approach because he insists it won't need a PSV; he claims it is protected under ASME code because the cooler diameter is less than 6-inch. Who's right? How should we proceed?
PUT IN A PSV
Most mechanical integrity engineers will insist on a PSV regardless of the size of the vessel because of liquid expansion. The unfired vessel code cited should be applied strictly to residential water heaters. OSHA 1910 comes into play, not the ASME code. It's not hard to see the damage that could be wrought by thermal expansion in an external fire.
What's the best design — oil inside or oil outside the tubes — depends on your perspective. Oil inside would be the best despite poor heat transfer that would require additional cooling water in the shell side. Baffling, even if added in the field, could improve water-side heat transfer, which has the greatest effect on reducing heat exchanger surface area. The heat transfer coefficient for water, dirty or clean, is ~50–150 BTU/hr-°F-ft2, compared to the 70 BTU/hr-°F-ft2 common for heavy oil, although 15 BTU/hr-°F-ft2 has been reported. A typical overall coefficient for water/oil would be 20–60 BTU/hr-°F-ft2 (fouled service).
From a safety perspective, the water in the shell provides some protection against evaporation of the oil in the tubing. However, there's a risk of vacuum failure from cold water flow. This will add another complication to safe design. Let's consider the fire case and thermal expansion of the oil and water. (Routine thermal expansion is a minor relief scenario and not worthy of further consideration here.)
As the heat of the fire radiates to the outside tubing or the shell of the cooler, the water quickly will boil in the inlet piping to the PSV. I'm assuming the PSV is within a few equivalent lengths of the shell discharge. When the PSV begins to relieve at about 85% of maximum allowable working pressure, the flow will consist of droplets of water carried by steam. This quickly will become steam but then will revert to saturated water. The PSV will continue to burp until the fire is out or the water is gone. Initially, the water flow will be two phase — so check the sizing of the PSV for this case; it likely will be more than adequate.
Things get more interesting if the fire isn't put out. The water starts to evaporate, making the shell or inside tube into a furnace. The hot oil expands. If its flow is constrained, the oil will pop a weld at an elbow and hot vapor and liquid will spill into the hot shell. Because it's lean in terms of air/fuel ratio, the risk of fire isn't great. Such an eruption may occur even before the water has completely evaporated, producing a potential fire hazard at the PSV outlet. For this reason, both the water and oil should be evaluated for pressure relief, depending on the design pressure and temperature of the shell and tube. Because of the low latent heat of the oil, the PSV calculations for the tubing must consider two-phase flow (flashing case). It may be that you will want to specify for vacuum relief for the tubing while designing the oil in the tubing to relieve to the higher rated shell. In any case, don't ignore these sample coolers because they become potential bombs in a fire scenario.
Dirk Willard, senior engineer
Ambitech Engineers, Downer's Grove, Ill.
We recently commissioned a new polypropylene plant. We had modified our earlier design to include internal cyclones in the fluidized beds to keep dust from going to the recycle compressor and cooler (see Figure 1). However, the fluid bed reactors don't perform as expected. We're seeing: 1) fines carried over from the first to the second reactor; 2) fouling of the second recycle compressor and cooler; 3) poor distribution in the tubes at the bottom of the second fluid-bed reactor; 4) spikes of excessive heat from the second reactor; 5) plugging in the air locks carrying the product to the purge tank; and 6) temperature and pressure fluctuation in both beds that make it difficult to maintain a steady bed height. Our bed pressure taps and thermowells foul — we've tried heat tracing and purge nitrogen to reduce fouling but without success. What did we do wrong and are there any simple solutions?
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