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Process Puzzler: Preempt Pump Problems

Feb. 1, 2013
Readers suggest several options to improve reliability

Preempt Pump Problems Readers suggest several options to improve reliability

The seals of the lean amine pump serving our fluid catalytic cracker unit suffer a very short mean time between failure (MTBF). We are using tandem seals with an API Plan 52. The buffer fluid is a light lube oil recommended by our pump salesman. The amine is 21% by weight monoethanolamine (MEA). The 3×2 centrifugal pump was designed for 190 gpm at about 160 psig. The impeller is a mixed-flow type. The nominal suction specific speed is about 7,500 rpm; the suction diameter is 4 in., schedule 40. The difference between the net positive suction head available and required is about 6 ft water at nominal. Unfortunately, the pump usually runs above the nominal rate, at around 205 gpm at about 145 psi head. Inspection after failure shows severe crystallization and scoring of the shaft seal. In addition, the pump seems to run rough even when it's operating at 60–70% of the best efficiency point, which is at around 185 gpm. The cavitation grows worse over time so we pull the pump after six months to avoid potential failure. We followed the pump manufacturer's recommendation and installed a minimum flow loop that operates continuously with an orifice; the flow is about 60% of the nominal flow. Any suggestions on how we can improve the MTBF?

Here're a few suggestions:

1. Use a back-to-back mechanical seal instead, to pressurize the buffer liquid to achieve a small leakage into the product liquid (if acceptable). This should keep the seal rings more or less clean. Maintain the buffer liquid vessel under pressurized nitrogen or even install a small auxiliary pump.

2. If possible, use an inducer to reduce the net positive suction head required (NPSHR) of the pump. Since it might be necessary to keep flow rate within an inducer's operating range, you may have to convert the fixed (minimum flow) bypass into a controlled one: i.e., replace the orifice with a control valve with measured flow. This split-range control ensures that the pump will be operating within the acceptable range. Watch out for proper setting of the control parameter!

3. If an inducer can't be installed, still utilize split-range control. However, it might be impossible to exceed the best efficiency point (BEP) by much.

4. Reduce the pump's rpm, which reduces its NPSHR. However, from the information provided, it's impossible to decide whether or not this alternative is valid.
W. Schicketanz, director
W. Schicketanz and Partner, Rosenheim, Germany

It appears there are two separate problems to be addressed in this Puzzler — pump cavitation and pump seal/shaft wear. Each needs to be addressed slightly differently.

First, pump cavitation is an issue of having sufficient pressure and flow at the pump suction to prevent vapor formation at the pump impeller. The problem indicates there is sufficient NPSH at "nominal" flow rate, but does not indicate whether any determination of NPSH has been made or measured at the actual flow rate. If indeed there is a cavitation issue, suction piping and/or pump suction level or pressure will likely need to be adjusted to improve performance and eliminate the cavitation.

Second, as far as the severe crystallization and shaft scoring, based on somewhat similar experience with a hot oil system that had severe coking issues with related shaft damage, I would suggest a couple of areas for investigation. One area is to investigate ways to reduce or eliminate crystallization. If the crystallization is temperature related, provide better control of fluid temperature. In my case, we changed the seal cooling media from water to steam to prolong seal life and eliminate coking. Because you are already circulating a clean oil, I would look at possibly circulating it at a higher temperature to avoid over-cooling the seal area and causing crystallization to occur. If the crystallization is caused by the reduced pressure in the pump suction, increasing the liquid level or pressure at the pump suction could reduce the crystal formation. Coincidently, this would also reduce the cavitation.
Ried Jacobsen, engineer
Parsons Corp., Chicago

This problem has two main components: corrosion and pump operation. Let's consider corrosion first.

I've heard where synthetic oil has been used in amine pumps but this seems counter-intuitive — that doesn't make it wrong, though, unless you can explain why. I don't think all of the typical components in a lean amine stream are compatible with synthetic oil.

I assume there's a filter at the inlet to the lean amine tank. Amine solutions break down. I had similar problems with a caustic pump 30 years ago. Originally, the double seal was set up with 15% caustic solution. A lot of solids accumulated in that tank. I switched it to process water and our problems went away. You need a buffer fluid that will dissolve the amine crystals but will also be compatible with water and other components. Ethylene glycol and water might be a choice or perhaps deionized water might fit the bill.

Corrosion could be the culprit for your pump problems. A 21% lean amine solution is a little strong. We have to be careful here because spent or recycled amine will have different properties than new solution. Dow showed that a concentration above 18% is a problem for streams containing CO2 where MEA can react with CO2 to produce carbamates that contribute to corrosion: oilandgas.dow.com/pdf/rio/h2s_removal.pdf.

Another choice would be a different seal plan or perhaps a different seal. A dry gas seal has been tried elsewhere.

Now, let's consider the pump operation. The lean amine pump is operating 10% above its BEP. The suction energy, based on nominal flow rate, is: 0.9×suction diameter×pump shaft speed×suction specific speed×specific gravity. If we assume water, the suction energy becomes: 0.9×3.068×3,550×7,500×10-6 = 74. (I divided by 10-6 to make the number manageable.) A value greater than 150 would be a problem — so, the design is adequate. I assumed a coefficient for the suction. Based on this crude estimate, the suction energy is high but not very high. The NPSH margin is probably inadequate at the actual operating point for the pump. The Hydraulic Institute recommends a ratio of NPSHA/NPSHR > 1.2. The Institute recommends a maximum ratio of 1.7. It's hard to say what the actual NPSHA is but in typical situations when a pump is drawing from an atmospheric tank the NPSHA is in the 15–30 ft-water range. Let's assume 15 ft to be conservative. That puts the NPSHR at 9 ft. The ratio then would be 15/9, or 1.7. This isn't telling us anything is wrong.

What's the solution? Increase the NPSH ratio further by reducing the suction flow to the pump. Consider ratio control of the flow through the pump, thereby relieving the suction line of high pressure losses. The NPSHA [actual] should increase significantly since the actual flow through the suction line is then only 65% of the current flow rate: "minimum flow" (spillback) + nominal flow. If this pump is critical to the operation, consider installing a minimum thermal flow through an orifice, which is typically 20% of the BEP flow; this will protect the pump from serious danger if the spillback valve should fail closed. Then, the suction flow would only be decreased to 77% of the current flow rate. Still, this might be sufficient to buy back more NPSH.
Dirk Willard, consultant
Wooster, Ohio

We bought a used parallel (cocurrent) direct rotary dryer to dry beet pulp. The heating medium is oil passed through a furnace. The feed comes in at 82% water by weight and is supposed to leave at 10%. The nameplate capacity of the dryer is 42,500 pounds per hour (pph); the operating rate at present is only 40,000 pph. A 100-hp fan supplies 45,000 standard cubic feet of air, which is heated to 1,560°F. The fan is taxed, although just 70 hp should be required. The pulp is only dried to 15% when we operate the dryer at full capacity, so we're forced to recycle pulp some of the time. The efficiency, i.e., BTUs required per pound of water evaporated, is supposed to be 1,420 but is about 1,600! Can you suggest why we're using so much heat and what we can do to allow us to limp through the next few weeks until a planned shutdown? What is the long-term solution?

Send us your comments, suggestions or solutions for this question by March 11, 2013. We'll include as many of them as possible in the April 2013 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, 555 W. Pierce Road, Suite 301, Itasca, IL 60143. 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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