Puzzler: Slurry Seals Pump’s Fate

March 13, 2019
Inadequate attention to slurry particulars and seal plan impair performance

This Month’s Puzzler:

We use an axially split centrifugal pump to handle a catalyst slurry in naphtha. We were running with one pump on, one on standby, until the one in service tripped a high temperature alarm on the bearings. Flow fell drastically. We switched to the standby pump; it also developed low flow but the thermal sensors didn’t trip. Both incidents resulted in a serious leak around the shaft seal of each pump.

Doing a post-mortem on the incident, we’ve run into an impasse. The maintenance manager suspects the seals were the culprit. He flushes the seals with a clean light oil. He never has been a fan of using an API Plan 62 with an oil quench. He would prefer a Plan 32 and has been working with the seal salesman for years to change the seal arrangement. However, production likes things just the way they are. Projects says they don’t have the money. And the corporate environmental engineer wants to reduce emissions by installing a double seal plan plantwide.

Do you think the maintenance engineer is right? Did the seals cause the failure? Is this a problem we should be worrying about, given the money crunch? What do you think?

Come At It From Both Ends

Pumping of slurries is a challenge regardless of the type of pump. There are two types of slurries: non-settling (particles with equivalent diameters less than 75 microns); and settling (particles with equivalent diameters greater than 75 microns). The situation can get complicated if these particles are trying to dissolve or are friable. Non-settling slurries tend to be highly non-Newtonian, perhaps shear-thickening or shear-thinning; in my experience, centrifugal pumps usually aren’t used with these fluids. Settling slurries tend to behave — provided the particles’ settling velocity is stable and the liquid in the piping doesn’t slow down, which can cause quite a mess. Always perform sampling before selecting a pump; ideally, sample the fluid at different places and times in the process. It’s worth a trip to the lab and the maintenance shop to do a change analysis of the pumps and process.

Usually something like a bearing failure occurs because someone took some shortcuts in pump selection. Because both pumps were affected, that person must have missed something in the fluid being pumped. So, there’s more to solving the problem than the choice of the API seal plan.

API seal plans all have their flaws: high cost; a lot of instrumentation; inadequate seal protection to save cost; and over-reliance on a “clean” fluid. If one plan has worked well for many of the pumps, you may face resistance in changing, even if the maintenance manager and seal salesman can see a clear benefit in this case. Your best bet is to find comparable sites that have used a particular plan successfully.

API Plan 62, which is called a quench single seal, has a significant cost advantage over Plan 32. Plan 62 uses a clean, cooled liquid to prevent particulates from getting into the seal and scratching the pump shaft. However, if the liquid is dirty, hot, contaminated or a two-phase liquid mixture, or if it contains a gas or vapor, this seal choice could be a disaster.

API Plan 32 is an improvement on Plan 62 because of added instrumentation: a flow indicator, temperature gauge or transmitter, and a pressure gauge or transmitter.

Filtration, cooling and perhaps an additional instrument — a colorimeter — can improve both plans. A colorimeter can detect particulates and mixed liquid streams. At the very least, a sight gauge with a background light could bolster either plan and allow operators to inspect the flowing quench stream to the seal.

As for the thermal switches that didn’t trip, check the commissioning. It should have included a trip check but that might have been overlooked. In addition, it’s possible that the switches melted or malfunctioned from overheating.
Dirk Willard, consultant
Wooster, Ohio

Editor's Note

A reader challenged the question in this puzzler. Here is the reader response and Dirk Willard's followup.

Reader Response: I just read the Puzzler: Slurry Seals Pump’s Fate article and the question has an error. I am not sure if it is a typo error but it is consistent during the text.

Plan 32 and plan 62 are two completely different plans were the Plan 32 is internal injection inside the stuffing box and the product mixes with the pumped product. Pan 62 is a quench on the atmospheric side of the seal, that is after the seal faces and using oil there is not correct since it will leak into the atmosphere.

Please review the text. Also look into the API 682 pages 208 and 222 to see the injection point for each plan 32 and 62 to see the big difference between them.
Carlos Chacin
Group Leader
Reliability Rotating Equipment
Citgo Petroleum Corporation

Dirk Willard: Not being an expert, I can suggest that Plan 62, a quench is nearly always a bad choice, except for clean systems or where extremely high temperatures are required. I have seen the plan used in several chemical applications. That's why the maintenance engineer wants to replace it with Plan 32. If the maintenance engineer had any guts he'd push for a tandem or double seal with a cooled, filtered purge but that would raise a red flag because other pumps in the refinery also get away with single seals and he doesn't want a fight.

The point is that Plan 62 is a bad choice and the maintenance engineer wants to replace it for good reason. The second point, perhaps, is that Plan 32 probably isn't good enough.

You can refer to Annex A (download it here) for selecting the right seal.

May’s Puzzler

At one of our gas/oil separation stations, we have an old reciprocating compressor that operates with a knockout drum at the inlet. This past winter, it started giving us problems, which is strange because it has outlasted the centrifugal compressors at our other stations. The temperature gauges on the inner-stage coolers are showing a high temperature. The after-cooler for the product gas at the station also is running way too hot. We must ensure smooth operation before the high-demand winter season arrives.

Walking around the old compressor, I notice a lot of corrosion. I can’t read any of the equipment nameplates. Our data files are incomplete, compounding the problem if I must order a new compressor. I also see that one of the foundation anchor bolts is loose.

What do you think caused the problems with this old reliable unit? Do they relate to a seasonal factor or a capacity issue? Is it worth rebuilding the compressor or should we replace it — if so, how should I approach the replacement?

Send us your comments, suggestions or solutions for this question by April 12, 2019. We’ll include as many of them as possible in the May 2019 issue and all on ChemicalProcessing.com. Send visuals — a sketch is fine. E-mail us at [email protected] 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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