Your questions answered: Vertical Turbine Sump Design
Jimmy Scroggins, technical training expert at Grundfos Pumps Corp. in Lubbock, Texas, tackled unanswered questions from the Oct. 21, 2015, webcast on vertical turbine sump design.
Q: What is your experience in vibration analysis testing for vertical turbine pumps when the motor is mounted on the side of the vertical pump assembly?
Jimmy Scroggins: In my more than 20 years of experience, I have never seen a side-mounted motor on a vertical turbine pump. I have seen horizontal applications where both motor and pump are horizontal, and in that, reed-frequency calculations were fairly straightforward. The best bet would be to use a finite element analysis (FEA) to determine natural resonant frequencies of the driver/pump combination compared to job speeds. I would make sure to have good 3D models (IGS or STP formats) of the pump, foundation, motor, and attached piping with supports to give to the engineer or firm conducting the FEA (saves time and money).
Q: In NPSH available calculations, what are typical values for Ha, Hst, and Hfs that ensures optimum NPSH required?
Scroggins: Those values vary widely based on a number of factors:
- Ha (absolute head or atmospheric in open pits) at sea level and 60 F, Ha is 14.7 psia. At a 3,300-ft elevation and the same temperature, it would be 12.7 psia. And in Denver (5,280-ft elevation) and same the temperature, the value is 11.7 psia. Also, if you have a pressurized tank, you would take the gage pressure and add the local barometric pressure (do not call the weather service; they adjust it for sea level).
- Hst (static head) should be designed for submergence and per NPSH (whichever is greater), but usually sumps are 10- to 20-ft deep with a "typical" water level 1 ft below datum, and a low water level around 4- to 5-ft deep. So, I would suppose that a typical Hst would be 8 ft (3.5 psi) for a 10-ft sump, and 18 ft (7.8 psi) for a vertical turbine pump in an open wet pit.
- The Hfs (friction losses at suction) would be negligible (0.0 psia). So I would venture a typical NPSHA value for water at sea level and 60 F with a 10-ft sump would be 17.9 psia (41.3 ft) and the 20-ft sump would be 22.2 psia (51.3 ft).
- NPSHr will be obtained from the pump curve and is usually in feet, like I stated in the webcast. If NPSHr is less than NPSHA, you're good to go.
Q: What steps would you recommend when you are retrofitting a new pump into an existing installation where the installation has been operating for many years and the same pumps are no longer available?
Scroggins: This is a tricky situation. Hopefully, you can get a bill of materials—especially a general-arrangement drawing—and anything else that would be provided in a typical submittal package. Please note that many pump manufacturers provide leaded red bronze impellers and bearings in the not-too-distant-past, but may not offer those same materials anymore. If you don't have the submittal data, you might want to treat this as a new application and request installation data, such as sump dimensions, electrical data, pumping information (to get correct pump materials), and any special design requirements (parallel operation, VFD, secondary and tertiary design points, shutoff head, and runout flow limits, etc). Good luck.
Q: Does Grundfos have computational fluid dynamics (CFD) analysis software to aid engineers in analyzing intake structure design?
Scroggins: Yes we do. Contact your salesman or distributor.
Q: In which cases must we use a can pump?
Scroggins: Can pumps are fantastic for low NPSHA and high pressure applications. You can (pun intended) increase NPSHA by simply lengthening the can-and-column assembly to squeeze more Hst out of the application when confronted with low NPSH applications. Also, the can serves as a secondary pressure device, sparing special material and geometry bowls in high pressure applications (the pressure inside the can helps offset the pressure produced by the bowl assembly).
Q: Why do we always use a vortex suppressor as a strainer on can pumps?
Scroggins: The amount of space between the bottom of the can and the bell lip is very limited in a can type application. A regular basket strainer is usually very long and designed to fit in an open sump. Also, ANSI/HI and AWWA dictate the size of the basket strainer, making them cumbersome in a can-type application. ANSI/HI allows for a very short basket strainer to be used in can applications—what you correctly called a vortex suppressor. Can applications, without straightening vanes, have a tendency to allow the pumpage to swirl around during operation and will feed the suction device in one area, which creates problems hydraulically for the pump with subsurface vortices and pre-swirl. The vortex suppressor breaks up the flow as it enters the pump suction, reducing or eliminating vortices and swirl (less noise, less wasted motion, better flow, better efficiency, less vibration, etc.).
Q: Which is the preferred analysis of pump sump: physical scale modeling or CFD?
Scroggins: If money is no object and there is plenty of time for a physical scale model, it is the best. Otherwise, CFD analysis works very well with clear liquids like water with no suspended solids. A CFD is not cheap (usually $5 to $15,000), but is much less expensive than a scale model. I hope that helps.
Q: What are the most common problems with vertical turbine sumps from an operational standpoint?
Scroggins: There are a few disadvantages with vertical turbines (it pains me to say that). But a VTP requires high headroom, and they can be challenging to install or remove. In addition, meeting the minimum fluid level for priming, NPSH, and submergence can sometimes be interesting. Also, because they are usually long and thin, vertical pumps are susceptible to high vibration. But in my opinion, the advantages of vertical turbines far outweigh their disadvantages.
Q: For a vertical turbine pump in a water well, can we consider the well casing the same as a sump?
Scroggins: Not exactly. For well pumps, flow usually comes from the bottom up. Sump pumps draw in water in horizontal planes. This is a very subtle difference, but it's huge hydraulically when dealing with vortices, uniform flow, stagnant zones, etc.
Q: Should the pump intake be no closer than 5 pump diameters from the well screen?
Scroggins: Actually, ANSI/HI 9.8-2012: Rotodynamic Pumps for Pump Intake Design sets a screen at four suction bell diameters from the suction bell centerline for clear liquid rectangular intakes.
Q: If you suspect that cavitation is occurring, are there any signs that can be observed when near the motor?
Scroggins: That is a good question. I will check with one of our field service representatives and provide a follow up. Typically, cavitation increases vibration and load fluctuations, which would have to manifest themselves in the driver. This gets back to the same symptom for many different diseases.
Q: Can you use variable speed motors on vertical turbine pumps?
Scroggins: Yes, very much so on short sets, such as in a vertical sump. But on deep sets or wherever there is a high lift, the pump must overcome, I would not recommend using a variable frequency drive (VFD).
Q: What are the advantages of a vertical turbine pump vs. submersible sump or other type of pump?
Scroggins: The advantages for a vertical turbine pump are: a smaller footprint, no priming issues, low NPSHr impellers are available, submergence and NPSHA issues are eliminated by simply lengthening the pump, pressure flexibility by adding or removing stages, reduced noise, and vertical turbines readily lend themselves to customization to meet existing system needs. The disadvantages or what I like to call opportunities are few. But a vertical turbine requires unusually high headroom: they can be a bit challenging during installation and removal; they must meet a minimum fluid level for priming, NPSH, and submergence; and they are susceptible to high vibration.
Q: How do you take into account pressure drop caused by flow straighteners? Is there data available to include that pressure drop in the NPSHA calculation?
Scroggins: At this point, you would need to run a CFD analysis to determine the pressure drop. And I do not know that any pump company has addressed this issue, nor have ANSI/HI or AWWA. But you do pose an interesting question.