Suction Cavitation - NPSHA and NPSHR Margins

Larger margins will require more energy to induce cavitation thereby causing more damage to pump parts during phase changes.

Having said that, I must admit that I am speculating and welcome any corrections from more learned participants.

I've never heard of that. I've always assumed the more NPSHav the better. In any case it's often outside the designer's control, determined by plant layout.

Cheers........Codey

It does not sound right but the writer must have had a specific case in mind.

For example with the failure on the delivery side the larger NPSHA will allow the pump to exceed the design capacity by more and allow the losses to rise on the suction side having a the new NPSHA to drop to far below NPSHR, and maybe cause more damage as when the initial NPSHA were lower.

Editing the piece may be better.

Hendrik,

Although you sound hesitant, you are absolutely correct in reasoning.

With high NPSHa and fully open discharge condition any centrifugal pump will operate at far too right of BEP. This leads to high flow rate .This in turn will lead to high friction losses in the suction piping and lead to new NPSHa conditions below the required values (NPSHr).

Cavitation damage due to denser liquids ( cold water) will be worse than that which happens while handling lighter liquids (hot water).This should not be difficult to figure out!

Chuck Cowlagi

Go further in the site you mentioned to

http://www.irrigationcraft.com/n.htm#Net%20Positive%20Suction%20Head%20%28NPSH%20%29

Scroll down to the last 4 paragraphs just above the figure of a pump curve. He gets deeper into the reasons and they make some sense to me.

Ed Weldon

I agree with Ed on this one. If you go further into his threads it does all get explained and they do make sense. My initial thoughts were into the density issue of the pumped fluid and the big difference between a homogeneous fluid like water and the hydrocarbon mixes that comprise a petroleum fluid as in refineries.

The aspect of having too much NPSHA does seem like an antithesis of your normal plant design but if it means that you are essentially creating a situation where a "perfect storm" of conditions can reek havoc on your equipment then I see the writer's point.

The fact that the water is dense (1.0 S.G.) and homogeneous so then a low pressure area or cavitation can create sudden vapor formation and substantial changes in fluid velocities whereas a mixed hydrocarbon will have partial vaporization from the lighter components which are often around a .7 to .78 S.G.. The amount of energy released will probably be much greater with the water.

Most pump motors are only sized to carry a certain amount of extra capacity such as 20% over the nominal requirement. A Service Factor on the motor over the Nameplate HP will often provide an extra safety factor. Overloads may protect the motor but cavitation can kill the impeller, seals or bearings long before an overload kicks in. Very few installations will allow running out too far past the BEP not to mention there won't be enough head developed due to the system requirements.

The use of maximum diameter impellers is generally frowned upon. If there are any miscalculations in piping losses, fluid densities, increases in fluid temperatures or additional needs most plants want the option to increase the impeller diameter to make up necessary head requirements or increased fluid densities that may occur without having to remove the pump. It may or may not require a larger motor but that is less of an issue than changing the pump.

Spinco, I can not find any statement on the quoted site that explains the statement "larger margins of NPSHA over NPSHR often produce more damage in a pump than lower margins, especially when dealing with cool water ". Maybe I have missed something.

As for water and hydrocarbons, all NPSHR testing is done with water anyway.

I do agree that cavitation damage is often more severe in water service than in hydrocarbon service which is why we limit the operating window for high Nss pumps more for water than for hydrocarbons. (In this case we are concerned more about recirculation cavitation than suction condition induced.)

Another puzzling part of the statement is the reference to "cool water". For the life of me I can not see why cool water would cause more damage than warm or hot water as a result of suction condition induced cavitation or with high NPSH margins.

Kaisan,

I pasted the explanation that was further down on the initial page. I did go out to a few explanations on Google concerning suction specific speed because it has been a while since it was in my run of the day topics.

I am not even sure of his reference below to BFW pumps in the same vane as chilled water and cool water except I do recall a 1400psi BFW service for a NH3 plant and I believe that the specified inlet temp was 140-150 degree F. Higher than that would have been problematical due to inlet flashing and loss of suction which in the case of a 1400psi boiler cause be a real issue.

My thinking would be that the higher temperature with the higher vapor pressure will produce the cavitation and associated noise to alert operators of a problem earlier. With the colder water it might not manifest itself as early resulting in more damage due to the fact that the excess NPSHA over NPSHR will allow the pump to be further out on its operating curve hence more HP is being inputed when the problem develops. So instead of pop-pop it could be bang-boom. And you are right, the NPSH tests and curves are based on water and corresponding curves based on S.G. must be utilized for proper pump selection. I also see your point about recirculation with hydrocarbons. It was generally easier to weld or braze a repair to the cutwater than the inlet vanes. Many a time when I had to file-repair cavitation damage on the impeller eye I wondered what the impact was to the NPSH.

This was the explanation on that page.

"Incipient Cavitation is then defined as: that cavitation occurring inside a pump, from the NPSH_R 3% value, up to the incipient point.

Incipient cavitation occurs in most pumps at all times. The cause is turbulence created by the impeller, resulting in localized pressure below the vapor pressure of the pumpage. In the general pump market, the ubiquitous presence of incipient cavitation appears to cause little damage and little loss of performance, therefore the concept is not commonly discussed. Although this fact may partially be due to under-reporting, the fact remains that incipient cavitation damage is not a common topic except in specific markets. The topic is interesting to those markets where high energy suction pumps are used. HVAC cooling towers, chilled water systems, and boiler feed pumps are well known to have serious incipient cavitation problems.

High margins of NPSH_A over NPSH_R can result in increasingly severe incipient cavitation damage, the higher the margin, the more damage that will occur, until the NPSHi value is reached, which is usually unachievable. The cooler the water, the more damaging the cavitation. The Hydraulic Institute and others have established general recommended margins of NPSH_A for specific markets."

Spinco

Thanks, but I must admit that I still do not get it. Please shoot down the comments below if I have got it wrong.

"Incipient Cavitation is then defined as: that cavitation occurring inside a pump, from the NPSH_R 3% value, up to the incipient point.

Incipient from incipere - to begin. So he says it occurs from the 3% head loss value up to the point at which cavitation begins. That is by definition from the NPSHR point to some point at a higher NPSHA at which there is no longer a problem. That means that higher NPSH margin is better. He then goes on to say that "Incipient cavitation occurs in most pumps at all times." How can this be if it occurs between two points?

He then says "The topic (incipient cavitation) is interesting to those markets where high energy suction pumps are used. HVAC cooling towers, chilled water systems, and boiler feed pumps are well known to have serious incipient cavitation problems." He is now talking only of pumps that by the nature of their duties have small NPSH margins and therefore are susceptible to suction condition (low NPSHa) cavitation damage.

Based on this, the next statement becomes difficult to understand "High margins of NPSH_A over NPSH_R can result in increasingly severe incipient cavitation damage, until the NPSHi value is reached, which is usually unachievable." How is this possible when high NPSH margins reduce the risk of "incipient" cavitation by the authors own definition earlier, and why would things improve when cavitation begins?(NPSHi value is reached).

In order to get any sort of cavitiaton we have to, at some local point in the pump, reach apressure that is low enough for a vapour bubble to be formed. At very high NPSHA this is less likely (maybe even impossible) to occur, not more likely.

The Hydraulic Institute and others have established general recommended margins of NPSH_A for specific markets." Yes, this is true, they recommend minimum margins, I do not remember ever seeing anyone recommending maximum margins. If they did, we would not be able to use things like booster pumps that have NPSHA margins of hundreds of meters and never ever suffer from cavitation damage, unless run far to the left or the right of their BEP's which is a different subject altogether.

"corresponding curves based on S.G. must be utilized for proper pump selection." Pump curves show differential head in meters (feet) against flow. The only thing that changes with SG is the power, everything else on the curve remains the same never mind what the SG.

" excess NPSHA over NPSHR will allow the pump to be further out on its operating curve" - I interpret this to refer to an increase in suction head (pressure) - if so then it is true only if the discharge head is not allowed to increase so that the differential head gets lower. Centrifugal Pumps only create differential head, which must not be confused with either NPSHA or NPSHR. _{put soapbox away - need a beer!}

I'm not here to shoot anything down just to kibitz in a good sort of way I hope. I did go out and find what I thought was a fair explanation of some of the terms and some explanation as to the 3% term which wasn't around when I was into pumps and drives in refinery and petrochemical plant engineering-construction. I read it quickly and found it basic but informative.I put the thread below.

As far as your comment on incipient cavitation I consider that to be the point where you're tip-toeing across the point where there-is and there-is-not enough NPSHA. Since you're not really dealing with absolutely pure Newtonian fluids in the sense that water often contains a certain amount of entrained air or gases and the hydrocarbons are generally not a pure substance but rather an approximate mix or blend of lighter and heavier components a 3% differential is not a lot. Vapor pressures in those mixes are often dependent of the lightest ends entrained and can vary based on what levels the take off from trays are set at in fractional distillation columns.

His explanation of the damage caused by small amounts of cavitation would be typical for incipient or for minor downstream disruptions to the supply.

While basically correct I do disagree with your comment concerning power and TDH. Pumps are selected for applications not for the head they can produce but for the differential pressure required for the system balance. Using the delta P AND the S.G. the requirement for TDH is then calculated. Based on the flow requirement of the process, with any reserve requirements added in, pump selection based on BEP at the design GPM and TDH are generally preferred. Power requirement is based on S.G. and more than once a chemical engineer has provided incorrect data as to that.

I do agree with your last comment because unless there is a main rupture downstream of the pump the increase in volume alone through the piping would probably increase system resistance and throttle back the flow to the corresponding head needed to get through the system. With a rupture the overloads should probably kick out. Of course now that does go back to the initial question of excessive NPSHA in that normally when the flow tries to increase dramatically over the design then would the lack of sufficient NPSH at that higher flow "suction throttle" the system assuming enough power? With compressors, suction throttling is an appropriate control means. With pumps it's a no-no, we throttle down by closing the outlet valve. Bit of a conundrum when you think about it. Would the sudden increase in flow (unlimited by the NPSHA), with sufficient power available, be more dangerous to the installation then the inability to get the fluid through the eye of the impeller (less NPSHA over NPSHR)?

www.pumped101.com/cavitation.pdf