NPSH calculation question 7

[charmquark]

Hello,

Mcnally institute gives a bunch of examples regarding calculating NPSH.

http://www.mcnallyinstitute.com/11-html/11-12.html

The example I had a question regards the vacuum tank example.

The example states the tank is under -20 inches of mercury vacuum (-22.7 ft head).

Thus the absolute pressure in the tank is 34-22.7= 11.3 ft

The fluid in the tank (water) is given as 180 deg F with a vapor pressure of 16.7 ft of head.

The vapor pressure of the fluid is higher than that of the pressure in the tank. Shouldn't the fluid be boiling/flashing in this case? If so why doesn't the fluid vapor pressure and tank pressure reach an equillibrium? With either the fluid cooling down as it flashes and/or the vacuum in the tank decreasing?

 

[UmeshMathur]

I agree wholeheartedly with the comments by Montemayor. Normally, I work with saturated liquids that come from a distillation column or reactor where the option to add an inert into the vapor space does not exist.

However, Montemayor's method is certainly a GREAT way to take a saturated liquid to an unsaturated condition, when it is physically feasible to do so, by pressurizing the vessel with an inert gas.

In reviewing this thread, I think the discussion has been very pointed and well reasoned. It should be valuable to all practitioners who solve tough problems, even those that seem to be "intractable".

 

[rmw]

If NPSH was easy to understand, everybody would be a pump engineer.

I want to point out for anyone who might be struggling to follow the concept (as I have already mentioned that I once did) that in a steady state process (Montemayor, I am leaving your bag of tricks out of this one) that the saturated fluid only exists at the surface of the fluid/vapor interface in the reservoir.

If one were to take pressure and temperature measurements at increments down through the fluid between the surface of the reservoir to the pump suction we see that the fluid begins to subcool with depth by the amount of the static head of the fluid at the depth at which you are making the measurement.

In other words, if we do a "freeze frame" and stop the process for a snapshot, you will have a fluid that is saturated at the surface, and if that surface is located, lets say, 10 ft. above the pump suction, then the fluid is subcooled by a measurable amount which is the vessel pressure at the surface plus 10 ft of static head of the fluid at the pump suction. So, at this instant in this "freeze frame" the pump is pumping a fluid subcooled by a 10 foot margin.

So what is the problem?

Process is a dynamic situation, so that one has to take into account the head losses in getting the fluid to the suction of the pump, and if those losses exceed the amount of static head that is acting to subcool the fluid, then the fluid becomes saturated again, and the bubble point is reached which is a terrible thing to have happen in a pump suction.

So, for pumping situations where the NPSHa is only a matter of a foot or two from the NPSHr, then the fluid is only subcooled by that foot or two as it enters the pump. Or, if the flow of the pump changes so that it runs way out on it's curve and "eats up" all the margin built into the design, then the pump cavitates, or worse, flashes.

Which, in a lot of words brings us back to the statement made by TD2K on 18 July.

So, the moral of the discussion is; don't design saturated fluid pumping systems with close margins in the NPSH.

rmw

 

[UmeshMathur]

Upon reflection, Montemayor's suggestion of 28 Jul 05 21:27 is logically similar to the case that I had discussed on 28 Jul 05 19:18 under the item "(1) LIQUIDS BELOW BUBBLE POINT". By adding an inert gas (obviously of low solubility), the total pressure in the reservoir is increased by an amount equal to the partial pressure of the inert, thereby increasing NPSHa, as fluid vapor pressure is unchanged.

Based on Montemayor's caveat no. (3), as long as you can get the boiling liquid into the reservoir at the higher pressure, presumably by pumping, you are OK. For storage situations, it is very likely that you already have a transfer pump. The small increase in discharge pressure (caused by higher downstream reservoir pressure) should not present a problem for the upstream transfer pump.

rmw's last sentence of 28 Jul 05 23:56 should be required reading for all pump designers! Can we all agree that violators should promptly be dispatched to chemical engineering purgatory (repeat the undergraduate fluid mechanics class?).

Cheers.

 

[Latexman]

Most aspects of NPSH are covered here, except the loss due to acceleration which can become important with certain PD pumps, unless I missed it in one of the many threads.

Good luck,
Latexman

 

[25362]

Latexman:

You're right. Although it wasn't specifically noted, I believe the above threads dealt with pulsation-free, irrotational flow of Newtonian fluids.

 

[25362]

By chance I came upon an article by T. Henshaw on the Hydrocarbon Processing issue of October 2004, titled NPSHA- how much is enough ?, under the pump/reliability heading, where it is stated that, at least for water services, when the NPSHA is two to three times the NPSHR, impellers may be damaged by erosion, and gives a formula to estimate the safe NPSHA for continued operation of 40,000 hrs for stainless steel impellers.