Find the real cause of pump gas up

Simply blaming high feed temperature for inadequate suction isn’t enough when diagnosing pump problems. Read this article to get a laundry list of causes for pump gas up.

By Andrew Sloley, contributing editor

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Centrifugal pump suction problems usually are blamed on lack of available net positive suction head, NPSHavailable. While the head may indeed be too low, misunderstanding and plant mythology often obscure the exact source of the problem and, thus, its solution. In particular, many mechanical engineers and nearly all plant maintenance personnel believe that “high” temperature of the feed stream compared to normal operation causes the NPSH problem. Under these conditions, the pump commonly is said to  “gas up.”

Figure 1 shows a pump that draws liquid from a flash drum. This is an extremely common configuration, occurring with phase separators, tower bottoms and reflux drums, to give just a few examples. In flash drums, the temperature of the liquid itself is never the problem.

The head available is found via: <graphic of equation at end but written out version follows
NPSHavailable = Psurface - Pvapor + ΔZ - hf - hv
where Psurface  is the pressure at the surface of the liquid,  Pvapor is the vapor pressure of the liquid at the pump suction,  ΔZ is the elevation change from the liquid surface to the centerline of the pump suction, hf  is the frictional head loss through the system and hv is the velocity head loss through the system.

For a system where the velocity of the liquid in the upstream equipment is low compared to the pump suction velocity,  the velocity head is: hv = V2/2g where V is the velocity at the pump suction and g is the acceleration due to gravity (32.2 ft/sec2).

The NPSH is evaluated as height of flowing fluid at actual conditions.

NPSHrequireddepends upon the pump characteristics and flow rate. The Hydraulic Institute defines NPSHrequired as the NPSH at the pump suction that causes the total head developed across the pump to be reduced by 3% compared to a “no cavitation” operation (For multiple-stage pumps, this test is applied to the first stage only). This is not the point at which cavitation starts, that is, the incipient cavitation point. Incipient cavitation may begin at NPSHavailable heights between 2 and 20 times the NPSHrequired level defined by the Hydraulic Institute.

For an equilibrium liquid in a single phase with no heat gain or loss, the pressure at the surface and the vapor pressure of the liquid are the same. Therefore, those two terms cancel each other. As long as the liquid stays at equilibrium conditions, changes in operation that alter the pressure or temperature of the drum do not affect NPSH.

If a check of the hydraulic evaluation of the system does not identify an NPSH problem and the pump definitely isn’t providing sufficient suction, immediately check:

  • if NPSHavailable has been properly evaluated;
  • if there are other suction problems such as with suction specific speed; and
  • whether the pumping system really looks the way you think it does.

To troubleshoot the pump, start by investigating common causes of gas up:

  1. Localized restrictions in the pump suction — Examine the system pressure drop element-by-element instead of using an overall piping head loss. Constrictions in the system can cause problems.
  2. Suction blockages.
  3. Improper calculation of head losses.Verify that head losses due to velocity gains are included (see the velocity head term).
  4. Vortex breakers not accounted for in nozzle losses. Pressure drop caused by vortex breakers rarely is included in calculations; these losses are a significant source of NPSH problems.
  5. Suction specific speed. This is a common problem at low flow rates with pumps designed with low NPSH requirements.
  6. Chemical reactions in the feed creating vapor. While this frequently is temperature related, temperature itself is not the problem.
  7. Leaking seal flush. Leaking seal flush fluid could be vaporizing in the feed; again, often temperature related but temperature itself is not the culprit.
  8.  Wrong volume used in calculations. Was flowing instead of standard volume employed to determine pressure drop and NPSH requirements?
  9. Inaccurate flow metering. Is the flow what you think it is? Verify the accuracy of flow meters.
  10. Incorrect upstream-vessel sizing. Could vapor be entrained at higher rates?
  11. Poor upstream separation. Improper sizing of a liquid/liquid separator can lead to liquids not separating properly.
  12. Instrument problems. Upstream-vessel level indicators may show a level where none exists.
  13. Control response. Slower control systems may not deal adequately with rapidly increasing rates, causing level inventory in the vessel to drop faster than expected and leading to unstable operation.
  14. Mistakes in recirculation loops. Do minimum flow loops have the correct restriction orifices? Have minimum-flow-loop rates been included in the NPSHrequired and NPSHavailable calculations?
  15. Pipe sizing errors. Has piping been field verified? Pipe fittings under insulation may be of a smaller diameter than expected.
  16. Too high a pump margin. Damage, sometimes severe, can occur at NPSH levels higher than the stated This often is true of high-energy pumps and ones with large impeller inlet areas. Verify that NPSHrequired the NPSH margin does not exceed that necessary for “reliable” operation above the quotedNPSHrequired.

This is only a partial list, but it includes the most common situations and is a good starting point.

Andrew Sloley, contributing editor
Asloley@putman.net

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