Discusión y conclusiones

Let's assume that all four trays in the AGO steam stripper are designed with the same hole area or number of caps. Typically, this is the case, even though it represents poor design practice. The vapor flow through the bottom

stripping tray shown in Figure 7-1 is 400 lb/hr of steam. The vapor flow from the top tray is:

400 lb/hr stm + 2,000 lb/hr hydrocarbons = 2,400 lb/hr of vapor

The 2,000 lb/hr of hydrocarbons is the difference between the stripper feed and the stripper bottoms. The vapor flow at the top of the stripper is then seven times higher than the vapor flow through the bottom tray. Taking into account molecular weight, pressure, and temperature effects, I have

calculated that the hole area at the top tray should be about three or four times greater than the hole area on the bottom tray for good vapor–liquid contacting. But if the hole area is the same for all trays, as I've assumed above, then the top tray will flood first, or the bottom tray will dump. This is not the only reason for top tray flooding. If there are corrosion

the top tray. If the process stream contains salts (typically NH4Cl), these salts tend to sublime out on the top tray (sublime = change from a vapor to a

solid). The problem of salt accumulation on the top tray of a side stream stripper is pretty universal on hydrodesulferizers and FCUs that are running on a high content nitrogen feed. If neutralizing or filming amines are used in the fractionator, then dry amine chloride salts (a white substance with a strong ammonia odor) will accumulate on the side stripper top tray. As I've discussed in Chapter 1, "Distillation Tray Malfunctions," flooding progresses up a tower, but not down a tower. Therefore, if only the top tray floods, then the bottom three trays will not flood. And the overall stripper pressure drop will not become unusually large.

But the consequences of top tray flooding are particularly severe. I first noted this problem on a gas oil HDS unit (hydrodesulferizer) at the Coastal refinery in Corpus Christi, Texas. The unit had a fractionator designed to produce a small diesel product as a side draw, as is shown in Figure 7-3. Fractionation between diesel and naphtha was bad in the sense that the naphtha was contaminated with diesel and had a high end point. When the stripping steam was stopped, the naphtha end point was fine. But the diesel oil product no longer met its flash specification of 150°F (Note: A rough

approximation of flash point temperature can be obtained by taking the

ASTM D-86 Distillation 5% point temperature and subtracting 200°F). Without stripping steam, the diesel oil product was contaminated with naphtha.

Figure 7-3. Top tray flooding ruins fractionation in fractionator between trays 3 and 6.

With the stripping steam in service, I checked the delta P across the four stripping trays. The delta P was very low, which indicated that the stripping trays were not flooding. Yet, when I opened valve A on the top of the stripper, liquid diesel squirted out. Venting liquid from the top of a tower is proof that the tower is flooded. But how can a tower flood with a low pressure drop across its trays?

The answer is top tray flooding. In a steam stripper, the top tray will almost always flood first because of:

High vapor rates.

Salt sublimation (chloride or bisulfide salts). Fouling deposits from the feed.

If the top tray floods, the feed to the stripper will be lifted up the vapor outlet line above the fractionator tray #3 (Figure 7-3). The steam acts as lift gas, in the same way that vapor generated in a reboiler promotes natural or

thermosyphon circulation. The steam acts as lift gas in the same way that air is used in a lift gas pump. The steam actually pumps the liquid, which is flooding on the top tray of the stripper, up onto tray #3 of the fractionator. Large volumes of liquid now circulate from tray #6 in the fractionator back onto tray #3 in the fractionator.

At best, trays 3 through 6 may act like one tray due to the recirculation of the diesel. With diesel being pumped back up to tray #3, the naphtha product becomes contaminated with diesel oil.

At the Coastal refinery in Corpus Christi, we corrected this problem by adding water to the stripper feed for several minutes. This dissolved the accumulated salts from the top tray of the stripper.

The root cause of this problem was upstream of the fractionator. The HDS reactor effluent water wash flow injected into the reactor heat exchanger train was far too small to remove the NH Cl salts from the fractionator feed. At the Chevron refinery in El Segundo, they had essentially the same

problem on their coker kerosene stripper. There the problem was solved by eliminating the amine corrosion control chemical injection into the coker fractionator. On FCU LCO strippers, periodic on-steam water washing is my preferred solution. LCO blowing out of the stripper top vent indicates when such water washing is needed.