NPSHA pumping two liquid phases 3

[onepotato]

I am trying to specify a pump that will handle 5% caustic solution with small amounts of disulfide oil present. The water based caustic phase is pressurized well above it's vapor pressure, and thus has around 30 meters of NPSHA. The disulfide phase is at it's vapor pressure and thus has around 2 Meters NPSHA. The disulfide phase represents about 0.2 volume precent of the total stream. How should I specify the NPSHA for this application? Will standard centrifugal pumps perform adequately with small amounts of vapor cavitation?

 

[Montemayor]

Onepotato:

I would specify the NPSHa based on the most volatile liquid, assuming that the two liquids are not a perfect, miscible mixture. This would mean that the disulfide oil’s Vapor Pressure would control. What do you mean by "The disulfide phase is at it's vapor pressure"? All liquids are found at their corresponding vapor pressure. Do you mean to say that the disulfide oil is "saturated" or at its boiling point?

Simply stated, the Net Positive Suction Head Available (NPSHa) is the pressure exerted on the liquid at the pump suction minus the liquid’s vapor pressure. The NPSHa is the result of the following arithmetic:

*The pressure above the source liquid level;
*plus the elevation of the liquid level above the pump’s suction inlet nozzle;
*minus the elevation of the pump’s suction inlet nozzle;
*minus the fluid’s friction loss in the suction line;
*minus the vapor pressure of the liquid fluid.

All the above values should be consistent in absolute pressure units.

Note that the liquid’s Vapor Pressure (V.P.) is a function of the liquid’s temperature. When the V.P. equals the environmental pressure (or the vapor space pressure inside a "pressurized tank"), the liquid is at its boiling point – and is considered "in equilibrium". When this is the case, then the first and the last items above effectively cancel out. What you are left with in the "equation" is the liquid height above the pump’s eye minus the liquid’s friction loss in the suction piping connection.

Most well-engineered centrifugal pumps will handle a small degree of cavitation (liquid vaporization with subsequent, spontaneous condensation) during their performance. However, it is ill-advised to design or plan on such a continuous event. All centrifugal pumps should be designed and installed such that their suction has adequate NPSHa. I have always endeavored to apply the "rule" given me by an old DuPont pump guru, Bob Hart:

NPSHa > NPSHr + 5 feet;
or,
NPSHa > (NPSHr) (1.35)

-whichever is greater.

The above rule has always yielded success. I hope this helps you out.


Art Montemayor
Spring, TX

 

[25362]

Some thoughts: 0.2% is indeed a small proportion. Would this oily fluid be suspended in the major watery phase as an O/W emulsion ? Is there a chance that it may segregate out of the suspension by the impeller's centrifugal action possibly collecting around the impeller's eye ?

I'd like to repeat I'm not a pump expert, as made evident by my questions above.

 

[Scipio]

I agree with Montemayor, NPSHA is calculated based on the component with the highest vapour pressure. Where I normally see it is pumping multi-cut hydrocarbon condensates, where the NPSHA has to be calculated based on methane, ethane, etc., even if the bulk of the condensate is heavier fractions far below their vapour pressure. In fact the recommended test for vapour pressure in a combination like that isn't even checking component pressures, but actually performing a bubble test on the condensate to see where liquids start flashing off.

In your case, 0.2% isn't likely to be enough to cause any major impact on pump performance - I doubt you'd even notice a drop in differential. Cavitation damage is a little more tricky, I'm not really sure how long it would take that small a quantity to cause any noticeable damage. If I were in your position, I'd consider the NPSHA as 2 meters unless I could find someone with definite experience to the contrary, but I might relax the margin requirements between NPSHA and NPSHR somewhat. At least 75% of the pumps I've worked on are very low NPSHA services, so there are pumps our there that could work under 2 meters NPSHA, depending on your rated flow and differential requirements. I would, however, recommend either a cooled seal flush or an external flush, as I suspect there could easily be enough cavitation to cause damage to any seal faces.

 

[onepotato]

Thanks for the input.

Montemayor,
I intended to say that the pressure on the disulfide oil is equal to the vapor pressure, therefore there is only the static head of two meters to provide NPSH.

25362,
The liquids should not segregate, as they have nearly identical specific gravities, both slightly over 1.

Scipio,
I understand how to do the calculations for mixtures, like condensates. I was doubtful for this case, as the phases are seperate. I guess I was hoping that the vapor pressure to enter into the NPSHA calculation would be the liquid fraction of each phase, times the vapor pressure of each phase. Another possibility is to add the vapor pressures of the two phases together, that is how we estimated vapor pressure in storage tanks with a seperate hydrocarbon and water phase.

I concure, with Scipio, in that unless we can find someone with specific experience, we will use the vapor pressure of the disulfide oil phase in the NPSHA calculation. I was hoping someone on this forum had the specific experience to justify a less conservative approach.
Regards, Onepotato

 

[25362]

As a comparison: LPG is usually stored at a temperature close to vaporization, so the available suction pressure is essentially only the head of the liquid in the storage tank, and the NPSHa is less than 2 m, and centrifugal pumps work OK.

If needed a short inducer should keep the pump fully protected from such a small amount of potentially cavitating liquid even if air is entrained or dissolved in the caustic solution as in a typical Merox treater.

 

[checman]

onepotato.
Its hard not to mostly agree with what has already been said. But you have left out two major condition which will determine the type and amount of damage you will have. Temperature and differential pressure. The hotter a fluid is, the less energy it takes to flash it. The less energy it takes to flash it, the less energy it gives up when it phases back. But before you flash off a light end you will probably release some of the dissolved gases in your product. The differential pressure determines how much of the liquid will phase back and how much compression the released gases will be exposed to. The expansion and contraction of gas bubbles in your product can make allot of noise/vibration and is responsible for what is known as sudo cavitation. It can produce damaging vibration. It is not unusual in hydrocarbon service to have a small amount of cavitation. The energy that goes into flashing some of the lighter ends off is so small that when they change phase back into a liquid very little energy is given off. It becomes more of a problem for mechanical seals then for the pump. Phasing fluids do not have the lubricating properties seals need.

Regards checman

 

[scalleke]

Onepotato,

I believe you are looking at too great a detail.

Since there is uncertainty about whether the light fraction will separate and flash off simply take the NPSHA of the lightest fraction as the NPSHA for the system and spec the pump out as such.

2 m NPSHA should not be a problem unless you have a specific make and brand in mind that you know will have an issue with this.

2m NPSHA is ample and most pump manusfacturers should be able to accomodate this.

Best regards.

Scalleke

 

[onepotato]

Thanks for the comments.

It seems that there is significant experience that 2 meters NPSHA should be no problem. I accept that information and will specify the pumps that way. I appreciate all of you pointing out that the seals will be a problem. I believe we can install external flushed seals.

Thanks to all of you.

 

[25362]

Condensate self-regulated removal pumps (in power stations) are sometimes very carefully designed without any NPSH consideration.

They are supposed to work cavitating at all flow rates under submergence control working on the break point where the pump curve meets the system's.

It appears that the flowing water has insufficient energy for the shock wave generated by the collapsing bubbles to reach the intensity needed to damage the pump internals.

 

[onepotato]

25362 Chemical,
I am not sure I understand your post. I am surprised that any pump would be designed without consideration of NPSH. Are you sure that the NPSH consideration is not imbedded in the standard design calculations of the very specific situation you describe? The part in your post about submergence control in fact sounds like a NPSH consideration, given that the fluid and conditions of temperature and pressure are known, NPSH considerations could be reduced to submergence.

In any case, thanks for your post.

 

[25362]

Onepotato. You are absolutely right regarding NPSH. The NPSH available would be the submergence plus any gain from a subcooled condensate, less friction drops.

For these cases the pump is practically attached to the hotwell to minimize friction drops on the suction side.

The following paragraph is taken from Karassik's Pump Handbook on the subject condensate pump regulation:

...Operating in the break, or "submergence control" as it has often been called, has been applied very succesfully in a great many installations.

Condensate pumps designed for submergence control require specialized hydraulic design, correct selection of operating speeds, and limitation of stage pressures.

The pump is operating in the break (i.e., cavitates) at all capacities. However, this cavitation is not severely destructive because the energy levl of the fluid at the point where the vapor bubbles collapse is insufficient to create a shock wave of a high enough intensity to inflict physical damage on the pump parts.

If, however, higher values of NPSH were required -as for instance with vertical-can condensate pumps because of their generally higher operating speed- operation in the break would result in rapid deterioration of the impellers.

It is for this reason that submergence control is not applicable to can-type condensate pumps.

Spacing between sentences for easier reading is mine.