Part 15(a)—Booster Pumping–Parallel Pump Systems
By Ed Butts, PE, CPI
In the October column, we completed our discussion on the two most common types and design of pumping equipment used for deep and shallow well applications.
The next three columns will outline how vertical turbine, submersible, and centrifugal pumps can be used for parallel or series configurations and booster pumping systems in general.
This month we explore the mechanics and design associated with parallel pumping installations. The second part in April will outline the design of series (booster) pump systems. The July column will be dedicated to open (atmospheric) and closed (pressurized) booster pump applications.
Note although much of what I will be outlining is universally required to produce a safe and effective design, other people may have a differing and just as valid opinion on how to design and set up a parallel, series, or booster pumping installation. Please accept and apply the following information as a recommended guideline, not an edict.
Parallel and Series Pumping Systems:
Introduction and Overview
Although a very simplistic definition, in theory, when using two identical pumping units, a parallel pumping system essentially doubles the flow rate at the same head, while a series pumping installation doubles the head at the same capacity.
As an illustration, these relationships are shown using a graphical method with a typical single pump curve along with parallel and series performance in Figure 1. The common design thread with both applications is the desire to apply each unit to operate, if possible, at its best efficiency point (BEP) or, at the very least, within its respective best efficiency window (BEW) at matched heads.
Either of these applications can be in the basic form of a fixed hydraulic destination such as an atmospheric water storage reservoir (Figure 2a) or a variable pressure zone (closed loop)
at or above the pump’s elevation.
For a parallel pumping system, the type of discharge condition shown in Figure 2a is typically the simplest to design since the discharge point or destination is at a fixed and established location with a single transmission line serving it from the pump(s), and therefore static head, with the only variable in discharge head between the respective pumps as the additional frictional losses generated from the higher pipeline flow during simultaneous operation.
As an example, referring again to the curves in Figure 1 and assuming there is no variation in friction loss at different flow rates, for pumps in parallel operation the single pump performance of 500 GPM is essentially doubled (2×Q) by using two identical units to 1000 GPM at the same head of 102 feet of total dynamic head (TDH).
Conversely, as a series pumping example, the submersible well pump and vertical turbine booster pump operating in a closed loop pressure zone shown in Figure 2b is one in which the pump’s net discharge head is based on an arbitrary pressure that can conceivably vary within the allowable range of normal system pressure (in the example, between 45 to 52 psi). However, a maximum system pressure (52 psi) must also be established as the maximum pumping head to guarantee a measure of continued delivery from the well pump alone under all head conditions.
As shown in Figures 1 and 2b, the submersible well pump in a closed loop water well system with a well pumping lift of 15 feet at 300 GPM of average demand may be designed to normally operate at a primary condition of service (COS) of 300 GPM at 123 feet TDH—which translates to a discharge pressure of 47 psi (108 feet net or 123 feet TDH minus 15 feet PWL) using the well pump only.
Additionally, the combined flow and discharge pressure from both pumps in series can also be established for a secondary COS of 600 GPM of fire flow against the maximum discharge pressure of 52 psi while simultaneously operating at a lower pumping water level (PWL) of 60 feet. For the well pump, this results in an adjusted discharge head of 30 feet or 13 psi (90 feet TDH minus 60 feet PWL).
This means while the submersible well pump may be designed for peak performance and efficiency (at BEP or within BEW) at the more typical primary flow rate of 300 GPM routed through the piping/check valve bypass, it is also capable of producing 600 GPM at 60 feet PWL while producing a minimum (residual) discharge pressure of 10 psi or more at the wellhead (booster pump inlet pressure), even if the higher flow rate drops either pump’s efficiency outside the BEW.
Since the developed head from both units at a common flow rate in series is additive, this means the identical VTP booster pump shown in Figure 2b will have to accept 600 GPM from the well pump at 30 feet of residual delivery head (13 psi) and boost this same volume to the required discharge pressure of 52 psi by doubling the head (2×H). This is performed by adding 90 feet more (39 psi) of head at 600 GPM to generate a total of 120 feet TDH or 52 psi (13 pounds from submersible well pump plus 39 pounds from VTP booster pump).
A parallel pumping system applies to any pumping system consisting of two or more units designed and configured to operate together in order to pump to a common destination or discharge pressure.
Although this is the most common arrangement, and contrary to popular misconception, parallel pumping does not necessarily infer all units must be situated at the same site or derive their source fluid (usually water) from the same source. It only means they have the capability of operating together against a common system discharge head.
In a water well application, this permits the use of different well pumps from different wells with varying well lifts, and therefore TDH values to work against the head from other units to a common delivery point or system. Although not as commonly associated with the term “booster pumping,” a strict definition of the term applies to parallel pumping systems as well as series installations. A parallel pumping system can consist of an installation as small as two units up to 20 or more.
Generally, I regard a parallel pumping system to fit into one of three basic categories or conditions:
(#1) Common location, source, flow rate, and discharge head conditions; with two or more identical units operating in parallel (the classic definition)
(#2) Common location, source, and discharge head; but with different service conditions of flow rate and horsepower
(#3) Different sources and location; pumping to a common discharge elevation or static pressure, but not necessarily at the same flow rate or against the same TDH or horsepower. This most closely describes the typical parallel pump operation using multiple well sites.
As with most elements of engineering, there are variables within each of these three categories, but I have found these three definitions comprise the majority of parallel pumping systems. However, did you notice the one common characteristic with each category? It is each one is assumed to pump to a common discharge condition.
As shown on the system head/pump curve in Figure 3, the most common parallel pumping scenario is based on the premise two or more identical units are used to each deliver their individual and proportional part of the total flow. When combined, this creates a doubled flow rate (capacity: 1 + 1 = 2).
However, this is somewhat an “idealized” assumption since the TDH typically increases geometrically with a proportional increase in flow rate due to the increased friction in most piping systems.
Therefore, the fundamental concept that each matched pump in a two-pump parallel operation will produce exactly 50% of the total flow rate to generate a total of 100% is usually misleading and incorrect. Generally, for most water systems and depending on the hydraulic characteristics of the system and pumps, the increase in flow rate due to the increased online operation from one to two identical units in parallel operation will typically increase the combined flow rate between 125%-185% at most, rather than truly doubling the flow.
This relationship also holds true for parallel pumping installations with multiple (≥ 3) units, although the combined flow rate tends to become greater and closer to 100% total with more units in operation. Typically, the lower range of increased flow values are most common with a flatter pump curve than with a steep curve, such as those for most multistage VTP or submersible pumps.
However, for the simple purposes of illustration, the curves shown in Figure 3 are indicative of a single pump performance of 1000 GPM at 150 feet TDH increased to a two-pump parallel system while effectively doubling the total flow rate to 2000 GPM at the same head of 150 feet TDH.
For our next example of parallel pumping, consider the following for condition (#2).
As evidenced in Figure 4, the system’s total required flow rate of 2000 GPM is being delivered from three separate pumping units in parallel from a single site, each contributing their specific design flow toward the total duty of 2000 GPM against a common discharge head of 208 feet TDH. In this example, although there may be slight differences between units due to variances in each pump’s suction lift or head, we are assuming these variables have been factored into the design to result in a net value of discharge head (TDH) of 208 feet, each unit with different capacities and motor horsepower, as shown below:
Flows at 208 feet TDH:
Pump 1:1000 GPM (75 HP)
Pump 2: 600 GPM (40 HP)
Pump 3: 400 GPM (30 HP)
Finally, the third example, condition (#3), shown in Figure 5 applies to most common water well scenarios:
Required total COS: 2000 GPM at 150 feet TDH (65 psi discharge pressure)
The design conditions of service (COS) for each well pump are:
Well 1: 100 HP, maximum rate: 1100 GPM at 109 feet APWL (includes riser pipe hf)—24 feet SWL
Required TDH: 109 feet APWL + 150 feet system head = 259 feet TDH
COS: 1100 GPM at 259 feet TDH (Figure 6)
Well 2: 75 HP, maximum rate: 900 GPM at 146 feet APWL (includes riser pipe hf)—75 feet SWL
Required TDH: 146 feet APWL + 150 feet system head = 296 feet TDH
COS: 900 GPM at 296 feet TDH (Figure 7)
This type of application not only uses pumps with two different flow rates at two different sites, but with two different static water levels (SWL) and pumping water levels (PWL) and motor horsepower as well.
In cases with these variables, I have found an initial correction for the primary variable of well lift (PWL) plus all riser/column pipe and discharge head friction losses to create the “adjusted pumping water level” (APWL) results in a common (net) system discharge head. This allows the direct comparison of each pump against the only common parameter of head—the system’s discharge head at the pump’s (or wellhead) discharge.
Also note the adjusted shutoff head for each well pump (~ 290′) is virtually the same after correction for the well’s static water level. This adjustment falls to the system designer and is important when applying supplementary or multiple wells or booster pumps from reservoirs or other sources that must also deliver water against the same system head and makes it much easier and more reliable to plot a system head curve against well or booster pumps that deliver into a common water system or grid.
This also provides assurance all units will be capable of operating (pumping) at all conceivable head conditions up to shutoff head. In some installations, a frictional or elevation head factor must also be adjusted (added or subtracted) to the pump’s TDH for different or unique system dynamics such as remote well sites, varying well discharge assemblies or transmission pipe lengths or sizes from one site to the system or grid, or for sites originating from different higher or lower elevations.
Note that both pump curves demonstrate the same rough but steady head rise as the flow rate declines towards shutoff head. Even with a variable well lift, this helps ensure one operating well pump cannot effectively overrun and shut down the other operating units at a reduced flow or increased discharge head condition.
Obviously, the most accurate method, especially for well systems designed to operate at differing flow rates and widely ranging pumping water levels, would include factoring of the varying well lifts against the various flow rates through a step-drawdown well test generating specific capacities and then plotting these values on the system head curve. But as long as the designer considers and includes this variable in the design, particularly in wells with different initial (startup) conditions (static water levels) or vastly different pumping water levels, this procedure has shown to be reasonably accurate and reliable.
Parallel Pumping Red Flags
As with any type of pumping system, there are various precautions or potential red flags with a parallel pump system that a prudent designer should recognize and observe to avoid any serious operating issues, including:
Ensure all units can effectively work together.
This is undoubtedly the primary concern with any parallel pumping system. Even if the head at the design conditions match, if the unit curves demonstrate significantly different or lower head values as their individual curves rise towards a no-flow or shutoff condition, a single unit can easily become overrun by the other units during simultaneous operation, effectively shutting down flow from the lower head unit. This can result in a possible thermal rise of fluid or components in the pump from continued operation.
If this potential exists, it is essential a careful system head analysis be conducted as a portion of the overall system design to ensure each unit will deliver flow throughout all discharge head conditions. In any situation where the head rise or curve shape of a particular unit does not match the other units, the designer must verify the unit will nonetheless continue to deliver fluid, albeit at a reduced rate, or alternatively provide a means to shut down the unit.
Finally, unless the pumps are designed to always operate together, it is essential both units are equipped with check valves on each discharge to prevent backfeeding through the disabled pump while the other is operating.
Use pumps with stable curves and match the general curve shape with all other units.
This simply means all pumping units should be designed to permit the pump to effectively operate along its entire pump curve with all other parallel units in simultaneous operation. Use of a stable performance (H-Q) curve, one that continually rises toward shutoff head, with the maximum developed head occurring at shutoff (no-flow conditions) are highly recommended for pumps in parallel operation and all pump curves should demonstrate a uniform (or approximate) shutoff head with a minimum 15%-20% rise in head from the design capacity to shutoff head.
Be cautious when using mismatched head units where the shutoff head actually drops from a higher value associated with a flow rate. While one unit will obviously be more efficient at a given flow rate than another unit, the designer must recognize the individual safe maximum and minimum flow rates associated with each unit—and when continued operation becomes risky, inefficient, or unnecessary. It is at this point the unit should be disabled or replaced with a different unit of higher efficiency at the required flow rate. This becomes exceptionally important when pumps may operate at or below the minimum continuous safe flow.
Be careful with VFD units.
Although the use of a variable frequency drive (VFD) with a parallel pumping unit can greatly extend the operating range and efficiency of the unit, it can also result in a situation where the lowest motor (and pump) speed is not adequate to generate the minimum level of required operating head, especially when expected to operate against full speed units.
This is particularly true for pumps with flatter or mismatched curves and can lead to a condition where the pump continually operates against shutoff head and eventually discontinues pumping completely, which can lead to thermal heating of the fluid or lack of adequate cooling over a submersible motor. This warning relates to all potential conditions and is expressed to remind the designer to calculate and plot the minimum and revised speed H-Q curves against the system curve conditions and incorporate the allowable minimum operating speed or frequency into the design to ensure each unit is always generating enough speed to overcome all static and frictional heads.
In some cases, the same VFD can be used to control multiple pumps, while in others a common “analog” reference signal is used to control speed with identical units to a common level. In still others, a speed band or setting rejection setting in the VFD software program or keypad is used to ensure the unit is always operating at a speed sufficient to generate this minimum head. This potential issue can also apply to many systems using control valves for pressure reducing and control.
Consider using multiple units with varying capacities.
Even though the technology associated with modern pump design and variable speed controls or pressure control devices greatly extends the efficiency and allowable flow range of most centrifugal pumps, prolonged or continued operation of a larger unit at a reduced speed or flow rate, even when permitted, is not necessarily as efficient as using a smaller unit at full speed and rated capacity operating within its best efficiency window.
In addition, for most water systems where the maximum system demand is assumed to coincide with 100% rated pump flow, a design using three units, each rated at a proportional flow rate of 50% of 100% total design capacity, provides greater redundancy and operating flexibility than using a less expensive alternative of a single unit at 100%-150% of demand or two units, each rated for 66% or 75% of 100% of the total design capacity. This is often true even though each scenario may demonstrate the same maximum flow range of 150% over the required maximum capacity.
In the next column in April, we will continue this topic with an overview on series pumping systems.
Until then, keep them pumping!
Ed Butts, PE, CPI, is the chief engineer at 4B Engineering & Consulting, Salem, Oregon. He has more than 40 years of experience in the water well business, specializing in engineering and business management. He can be reached at email@example.com.