Heat Exchangers / Water/steam

Take A Cold-Eyed Look At A Cooling Problem

A methodical approach should pinpoint the culprit behind recurring difficulties

This Month’s Puzzler
Cooling problems plague our chemical plant, especially on days when the temperature rises above 95°F and the humidity exceeds 85%.

Corporate engineering completed a plant expansion a couple of winters ago; since then, cooling has become a recurring problem every summer starting in June and going on until late September.

In response, at the suggestion of corporate, we put in larger batch reactors and distillation towers and added a cooling tower to supplement the old 1970s one that has served us so well.

It’s probably worth mentioning that we changed our feedstock source. We had been making it ourselves but several near-misses at the feedstock unit prompted corporate to close it down. Now, we import feedstock from offshore; we’re still waiting to establish quality control procedures on the new feedstock.

I’m concerned about the low temperature differential across the ammonia refrigeration system: the vaporizer (NH3/feedstock) and condenser (NH3/tower water) don’t have the same differential temperature as before. Before the expansion, we saw a 17°F change in feedstock temperature, now it’s only 10°F. The ammonia differential had been 12°F but currently is 7°F. Also, I noticed that the ammonia compressor is running hotter and the inlet temperature to the ammonia condenser also is a little hotter. What does all this mean? What can we do?

Check Cooling Capacity

What amazes me is that all this has not been reviewed internally. Where is corporate engineering? They should have been part of the solution-seeking process.

Based on the description, it seems when larger reactors and distillation towers were added corporate engineering overlooked the cooling needs. They should have increased the cooling capacity. Obviously the cooling load has increased but not the capacity, resulting in the lower temperature differential cited.

How long ago was the feed changed? The fact that quality specifications have not been established on the imported feed is a major concern. A company should not use an imported raw material without knowing its specifications. Importing a raw material without the import documents containing a certificate of analysis essentially breaks the law of the United States (and other countries).

Consider the following points in seeking a solution:

1. The raw material likely is partly to blame. Batch logs can easily verify this. Test the current raw material and compare it to the specifications of the previous material. Also review the batch cycle times. The lower ammonia differential temperature suggests the reactor temperature is higher than before the raw material was changed and the reactor size increased. This would validate my speculation.

2. An alternative is to slow production during hot months and extend batch cycle times to avoid the overheating and get back to the earlier temperature differentials.

3. If refrigeration unit expansion was overlooked, add capacity to the refrigeration unit.

I believe a stepwise approach will resolve the issues with the least investment.
Girish Malhotra, president
EPCOT International, Pepper Pike, Ohio

Begin With The Exchangers

Let’s proceed in a methodical manner starting with the ammonia system first.

Fouling likely has occurred on the product side in the evaporator and on the cooling-water side of the condenser. Look at the baseline data for the heat exchangers, presuming you collected these during commissioning. If not, perhaps your local heat exchanger shop has better records.

During the next outage, clean both exchangers. Inspect the tubes. If you can look at the exchanger in the field before the tube sheet is removed, try to estimate the thickness of the fouling so you can re-run the heat exchanger data sheet for Udirty and effective area.

After the outage, measure the temperature differentials across both exchangers. Monitor for reductions. You’ll want to establish a cleaning cycle.

Perhaps someone changed out the ammonia during the last outage? If so, purge gas might remain in the shell, effectively insulating part of the tube sheet exterior; this typically can reduce heat transfer by 10–15%. A non-condensable gas might explain a hotter compressor.

As for cooling tower, do a hydraulic study. You must determine if the cooling water is getting where it needs to go. Also, look at tower siting. Towers work best when they are elevated where they can catch a breeze.

A proper hydraulic study will take several weeks. Minimize costs by using pressure gauges instead of flow meters where possible. Once you’re done with the analysis, balance the flows with orifices, or perhaps control valves and even booster pumps. Cooling demand should never exceed 75% of capabilities.
Dirk Willard, consultant
Wooster, Ohio

January’s Puzzler

We circulate 50% caustic through the tubes of a vertical 1-1 shell-and-tube condenser using 50% steam reduced from 400-psig steam. The exchanger contains 60 tubes, each ½-in. diameter with 0.083-in. walls, but 20 have been blocked off. The caustic enters the bottom of the exchanger and, after exiting, dumps into the top of a storage tank. Regular deliveries ensure that tank is seldom below 75% full. A 3-in. globe valve controls the steam flow. The worst-case ambient temperature is -15°F.

Recently, after almost a decade of service, a single 316L stainless steel tube failed, causing caustic to flow into the condensate return pump. An inspection revealed no fouling in the tubes. However, trend data show temperature spikes that go above the 200°F top value of the chart.

The carbon steel caustic tank exhibits severe corrosion above the normal liquid level and only minor weld pitting below. The roof is strongly corroded.

Inspection of the failed tube revealed erosion a few inches around the hole. The tube wall thickness was about 0.015 in. at the edge of the ¾-in.-long lens-shaped hole. The hole is about 1¼ in. from tube sheet on the outside of the sheet. We were surprised the failure occurred at that spot and there wasn’t any sign of stress corrosion cracking.

What do you think caused the failure? What can we do to avoid this problem in the future? Since we got nine years out of the tubes, is this really a significant problem?

Send us your comments, suggestions or solutions for this question by December 14, 2018. We’ll include as many of them as possible in the January 2019 issue and all on ChemicalProcessing.com. Send visuals — a sketch is fine. E-mail us at ProcessPuzzler@putman.net or mail to Process Puzzler, Chemical Processing, 1501 E. Woodfield Rd., Suite 400N, Schaumburg, IL 60173. Fax: (630) 467-1120. Please include your name, title, location and company affiliation in the response.

And, of course, if you have a process problem you’d like to pose to our readers, send it along and we’ll be pleased to consider it for publication.


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