Geothermal System Design

Part 2: Design techniques

 By Ed Butts, PE, CPI

We kicked off a two-part series on the fundamentals and design of high and low temperature geothermal well and pumping systems last month. This month concludes with an overview on the design of low temperature geothermal wells and well pumps.

Design of Low Temperature Extraction (Source) and Injection (Return) Wells

Low temperature production (extraction) and return (injection) wells are as likely to require a water use permit and follow applicable water well construction codes as a water supply well. This is due to the parallel use of groundwater from an aquifer at the same ambient temperature as that of the background aquifer water, and the same potential and exposure to possible contamination and abuse of the resource as a water supply well.

There are three primary considerations for constructing an extraction type of well: required flow rate (quantity), temperature (difference), and water quality.

For an injection well, additional considerations include aquifer interface and open area and the ability to accept water in a recharge mode, as well as thermal and chemical compatibility with the parent water, and spacing between the extraction and injection wells.

Obviously, unless dedicated to a domestic heat pump use, the required flow rate for a water source heat pump is dependent on the heat pump capacity plus any required flow needed for other uses. This can create a situation where the stable capacity from a low yield well (< 5 GPM) must be prioritized for the heat pump first with other uses stored into and obtained from other sources.

Although a groundwater source heat pump can theoretically be designed for intermittent well or water system flows, this is a risky proposition that could result in shortages in water when needed for domestic purposes or heating. In most cases for an open loop system, the system should be designed to allow continuous operation of the production well. This is often accomplished using a variable speed controller or control valve.

Schematic of a typical standing column well.

Dedication of the safe continuous flow rate from the well should be applied to heat pump usage first with intermittent household uses supplied from alternate storage methods, including atmospheric or pressurized storage vessels. For wells in bedrock formations or those with marginal production, consideration of standing column injection (Figure 1) is warranted.

A standing column injection scheme simply means the returned water from a heat pump is reinjected back into the same source well where the water originated. This is an economical alternative to a closed-loop system or use of a separate injection well, especially in cases with limited land area needed for installation of a closed-loop piping network, lack of required spacing between wells, or those without an alternative for water disposal.

While construction of a water supply well that includes geothermal uses must follow all applicable state and local zoning regulations and well construction standards, construction of an injection well for geothermal purposes should also follow general and state regulated well construction standards with a few additions.

The principal consideration is to provide adequate spacing between the extraction well and injection well. This requirement is a case-by-case decision and depends on various factors related to flow rate, aquifer type and mixing, well depth and aquifer interface, and temperature stabilization with a typical minimum spacing between 100 to 800 feet usually required between the two wells.

In many residential or urban settings this degree of well spacing is not possible—therefore an alternate method of disposal must be considered.

The next difference is water temperature, as water returned to an aquifer will contain either an elevated or lowered water temperature depending on the operational mode. This temperature difference can create chemical changes in the injection water, resulting in possible precipitation and deposition of iron or manganese, which can lead to plugging of screens or other open areas. This potential should be evaluated in every case with a complete chemical analysis initially conducted on the source and injection water along with the projected changes following heat pump use.

In some cases, treatment of the supply or injection water must be performed before use with a heat pump or injection occurs to avoid potential problems. This is particularly true for naturally corrosive groundwater (pH <6.5) since excessively corrosive water can also impact the copper coils and piping in a heat pump.

In many closed-loop or standing column installations, an additional set of tests should be conducted to determine the thermal conductivity of the receiving soil and water. This will help determine the required spacing and length of the piping loop. Next, when designing an injection well in alluvial formations with a well screen or rock formation with a liner, the screen or liner should be designed and constructed to permit an average cross-sectional velocity of 0.05 feet per second, 50% of the maximum value of 0.10 FPS generally applied to entrance velocity for a production well.

The next consideration is the water level response in the injection well during injection of water. This factor, often incorrectly referred to as drawup, can generally be approximated through a pumping rate flow test on the injection well. Typically, the specific capacity of an injection well during injection will closely mirror the specific capacity of the well in a pumping (withdrawal) state, with an added compensatory factor included for the head losses that occur from water exiting the well into the surrounding aquifer. In some cases, flanged sealing of the wellhead and injection pipe may be needed to provide a pressurized or shut-in condition for injection.

This same potential occurrence can also impact the well’s surface seal due to the possibility of pushing injection water out of the wellbore and into shallower formations during recharge, especially in upper uncased zones. This can be a real potential that can lead to contamination of a shallower zone and must be considered on every injection well, especially those with a high injection rate commensurate with a high static water level or significant drawdown. This must be carefully evaluated during planning and construction of an injection well with adequate casing and sealing depth and use of the proper material as required to preclude this possibility.

To provide accurate data for this possible event, an injection test of adequate duration should be conducted with the proposed injection well in advance of the final design. In lieu of an actual injection test, for rock and alluvial wells I have used drawdown from a standard constant rate well test and then applied a 15%-20% loss factor to the well’s drawdown as an estimate of the projected injection water level at the same flow rate.

For example, a 300 GPM constant rate well test on an 8-inch injection well with a 30-foot static water level (SWL) may demonstrate a 50-foot pumping water level (PWL) (50-foot PWL – 30-foot SWL = 20-foot drawdown = 15 GPM/foot of drawdown). This would equate to an estimated injection water level of a 20-foot drawdown + 20 feet × .15 = 23-foot rise or 30-foot SWL – 23 feet = a 7-foot projected water level at 300 GPM injection rate.

Although not true for every application, particularly for tighter semi-consolidated formations such as sandstone and shale, this method has proven to be fairly accurate for many formations. In some cases, a single injection well cannot handle the total injection rate, so two or more wells may be needed.

Typical geothermal extraction/injection well system.

As an element of the injection system, the setting of the injection pipe must be placed at a sufficient depth to avoid cascading of the return water and provide adequate intra-well mixing of the injection water with the natural water. This is particularly needed when mixing dissimilar waters and is generally more of a factor during a cooling mode when the return water is at a higher temperature. However, this should be observed for all downhole injection applications so the returned water into the aquifer is at as much of a stable temperature as possible. This also helps prevent oxidation and precipitation of minerals onto well screen openings, lessening plugging potential. Typically, a minimum submergence of 20 to 40 feet is adequate to provide mixing. A typical low temperature geothermal extraction and injection well system for multiple heat pumps is shown in Figure 2.

Required Flow and Performance Characteristics

The continuous flow and daily volume requirement for a water source heat pump (WSHP) is dependent on its size, specific design characteristics, water flow per extracted BTU/hour of heating, hours per day of operation, and the temperature of the local ground water supply.

As a general rule of thumb, you can assume a minimum flow rate of about 2.5 to 3 GPM is required for every 12,000 BTU/hour (1 ton) of heating and cooling using a water source heat pump (though some units specify flows as low as 1.5 GPM/ton for open-loop systems and 3 GPM/ton for closed-loop systems).

A typical unit can operate within a flow rate between 5 to 15 GPM or a total of roughly 8000 to 22,000 gallons per day, depending on the design of the specific equipment, area of the heated structure, and groundwater temperature.

For example, a typical WSHP manufacturer states with a groundwater temperature of 55°F, the company’s 3-ton (36,000 BTU) unit requires a flow rate of 2.5 to 3 GPM/ton or 7.5-9.0 GPM total. If the water temperature drops to 50°F, the required flow rate for this equipment in the heating mode expands to 5 GPM/ton (= 15 GPM total). With a 45°F source water, the same unit now requires a flow rate of 10 GPM/ton (= 30 GPM total).

Water temperature has the opposite effect in a cooling mode. The instantaneous flow requirement for a typical geothermal heat pump sized to provide 48,000 BTU/hour of space heating output (typical for a modern average sized home) requires approximately 4 tons of heat pump output or a total flow rate of 10-15 GPM with 55°F source water.

Geothermal heat pumps can require even higher water flows during the summer if equipped with groundwater heat exchangers for space cooling along with an additional water flow of 1 to 3 GPM (1440 to 4320 GPD) if used for supplemental water heating within the home.

The required instantaneous water flow rate for a geothermal heat pump alone can exceed 20 GPM, much more than the range of 5 to 10 GPM needed to provide domestic water to a typical residence. The consumption of geothermal heat pumps supplying 75, 20, and 15 million BTU/year of space heating, hot water heating, and space cooling can range between 500,000 to 2 million gallons per year, depending on the characteristics of the specific equipment and installation. If possible, the system should be designed to handle the peak water consumption (including any groundwater used for other domestic needs), whether peak consumption occurs during a cooling or heating mode.

The projected range of flows and related pressure loss through a typical residential heat pump system varies between 3-20 GPM with an associated pressure loss between 3 psi to a maximum of 12 psi for a single installation. When considering the pressure drop through a heat pump system, always remember to include the additional losses from the distribution and recovery systems, including inlet and outlet piping, backflow prevention devices, isolation/solenoid valves, and water meters (if present).

These pressure losses are often disregarded with a water source heat pump system, but this additional pressure drop of up to 3-7 psi can be significant to a system with a marginal difference between the supply (inlet) and outlet (discharge) system pressures, and in some cases, can interrupt or drop the required flow rate through the heat pump or require a booster pump to inject the return water.

Maximum heat loss or gain between the source and return water can be as much as –15°F during the heating cycle to an addition as high as 25°F-plus during the cooling cycle, respectively. With a typical well water temperature of 55°F, this equates to a range of injection water temperature between about 40°F to 45°F during peak heating loads to a high of about 75°F to 80°F during the maximum projected cooling loads.

In a larger parallel system with multiple heat pumps, the ratio of simultaneous online units can vary from 100% in operation with 3-4 parallel units to a low of 50% to 60% for 10 or more units due to the expected diversity from intermittent operation of the various heat pump units within the system. However, this factor is not universal in nature and can vary significantly depending on locality, occupancy, environmental factors, and time of day.

This factor also relates to the temperature of injection (return) water, since due to intersystem mixing the actual variation in the previous example is expected to generally range between 48°F to 70°F. After passing through the heat pumps, the water leaves the building or home and enters a return piping system located adjacent to the supply source. Once in the return piping system, the water is often available for use by zoned irrigation systems during the summer or direct injection into a suitable disposal site. The three most common methods include:

  1. Water disposal, into a nearby surface water body/creek, which is usually adjacent to or runs through the site. (Often referred to as pump and dump, this is not permitted in many jurisdictions due to groundwater loss.)
  2. Water well disposal, either through a new or existing injection water well
  3. Water well disposal, using reinjection back into the original source well (standing column disposal).

Head and Hydraulic Considerations

Although the required flow rate is the primary design consideration for an open-loop groundwater supplied heat pump system (WSHP), hydraulic factors must also receive attention. The primary design issue for head is obviously the required total pumping head needed.

The calculation of head for a low temperature hydraulic system is fundamentally conducted in the same fashion as a typical water well installation with a few variables. The pumping water level (PWL) commensurate with the required flow rate to generate the well lift plus riser pipe and wellhead friction loss is added to the required system dynamic and static head, which should include all individual factors relative to elevation, friction losses, and needed residual (or leftover system) pressure (in psi) at the point of delivery to generate the total dynamic head (TDH) of the system.

Generally, for a typical domestic water system including a WSHP, an operational pressure range between 50 to 70 psi will suffice. The primary variable with a water source heat pump, however, is the need for any pressure for injection well service. This varies greatly system to system due to several factors—namely heat pump dynamics and pressure drop, injection well static and dynamic water levels, return side elevation and friction losses, and any additional required recharge head. However, my experience has shown a residual pressure of no less than 40 psi is usually adequate for gravity injection purposes, assuming 20 psi is consumed through the heat pump supply side with a 60 psi design operating pressure. This generally provides enough residual pressure for domestic uses along with the 10 psi +/– needed for operation of control valves and system frictional head loss with gravity injection.

Injection systems may require higher pressures although well, well pump, and aquifer conditions, elevation, or excessive system loss may require higher residual pressure, or in extreme cases, additional pressure through use of a booster pump at the injection wellhead.

There are three other hydraulic considerations, all associated with properties of water at elevated temperatures. The first issue involves the specific gravity of water. As the water temperature increases, the specific gravity decreases. While this may not have an impact to a geothermal water source below 90°F, it does impact the specific gravity and therefore resulting pump brake horsepower at higher temperatures. Every pumping application with a groundwater temperature exceeding 90°F should be examined for the declining effect on brake horsepower from the increased water temperature, which can be as much as 5% in some cases.

The second hydraulic factor is the absolute vapor pressure. The vapor pressure is a critical parameter of water and pumping hydraulics that contrary to specific gravity increases at elevated fluid temperature. Ensuring a pump or piping system operates at a sufficient condition to avoid lowering the vapor pressure below the associated value for its temperature is essential to avoid fluid vaporization that can lead to liquid flashing and vaporization (cavitation).

Although most commonly associated with the Net Positive Suction Head-Available (NPSHA) for a pump under a suction lift, a high value of vapor pressure can also lead to severe problems with a pump with a high NPSHR (required) value or a piping system with a large pressure drop across a throttle valve. In addition to the above steps, the designer should also verify the pump’s required NPSH vs. the available NPSH at the elevated temperature and verify adequate submergence over the pump inlet exists to avoid cavitation. Although this factor is generally more critical with a VTP under a suction lift, a submersible unit can also be impacted from insufficient submergence needed to prevent vortexing (water rotation) within the wellbore. In many cases, this may necessitate over 20 feet of minimum pump submergence over the pump inlet to avoid vaporization at high groundwater temperatures.

The last factor related to water at an elevated temperature is the kinematic viscosity. The viscosity of a fluid is the property of the fluid at various temperatures and consistency and describes the flowing (fluid motion) characteristics through a transfer media, such as a pipe, by the fluid’s resistance to a shearing velocity. The kinematic viscosity for water (in centistokes) can be used when determining the frictional head loss, mainly through the return or injection piping system. As a guide, the data shown in Table 1 is included to determine the specific gravity, vapor pressure, and kinematic viscosity of water at various fluid temperatures between 32°F (freezing) and 212°F (boiling).

Design of Low Temperature Well Pumping Systems: Introduction

Basically, there are two types of deep well pumps most commonly used in high capacity (>100 GPM) geothermal wells: vertical turbine or lineshaft pumps (VTP) and submersible pumps with the difference being the location of the driver.

For a VTP, the driver is usually an electrical motor mounted above the wellhead which drives the pump through a long continuous shaft. With a submersible pump, the driver (a small diameter electric motor) is located directly below the pump itself. The pump is coupled to the driver through a short shaft and coupling inside a screened inlet section also dividing the motor from the pump.

Vertical lineshaft turbine pumps in deep well settings have two definite limitations: they must be installed in relatively straight wells of adequate diameter and the economical setting limit is usually no more than 800 feet.

In geothermal wells, the temperature and chemical content of water are the main problems in selecting the proper material for pump components. For a VTP the material generally used for the lineshaft is carbon steel (AISI Type C-1045), but in some cases the lineshaft material must be revised due to the condition or chemistry of the geothermal water.

Chrome journals or 300 or 400 series stainless steel lineshaft are sometimes used in exceptionally abrasive or corrosive water. The bowl unit material generally used is ASTM Class A-48 cast iron, but special materials can also be used. Impellers are generally made from bronze (B 584-838), ductile iron, or cast iron.

The most critical part of the pump for geothermal applications are usually the bowl/shaft bearings which are commonly made of bronze, rubber, or Teflon (PTFE). With most low temperature groundwater source systems with groundwater temperatures under 85°F, the design of a geothermal water supply pumping system is close to a regular water system pump. Although a geothermal application with typical groundwater temperatures can usually be designed following generally accepted practices, applications with water temperatures exceeding 85°F, abrasives, and corrosive or encrusting chemistry should be carefully considered since higher temperature fluids, steam, and geothermal brines often present difficult challenges for pumps and mechanical seals, including:

  • Lineshafts for vertical turbine pumps can greatly stretch under high temperatures or thrust from high head, resulting in shaft breakage or misalignment and reducing critical pump running clearances, often causing interference between the impeller and bowl and a loss in pump (bowl) efficiency. This is a particular hazard when using 1.25-inch and smaller lineshaft with deep sets or high thrust.
  • Iron, manganese, silica, and calcite fouling can obstruct or degrade critical pump clearances, dramatically impacting pump efficiency as well as increasing future maintenance and reducing reliability.
  • Chloride-rich brines or severely corrosive (low pH) water can induce stress-related corrosion cracking.
  • High-velocity, superheated steam is highly erosive to internal pump components, surfaces, and bearings.
  • Submersible motors in higher fluid temperatures require additional cooling velocity and HP/cable derate.
  • Pumps used as booster pumps for injection boosting are subject to many of the same concerns.

Well Pump Design

The greater the temperature and water quality concerns, the more important it becomes to enlist the services of an engineer or pump manufacturer with the requisite mechanical design and materials expertise to successfully address the possible high temperature, scaling, corrosion, and erosion issues related to geothermal well pumping. Although a water-lubricated VTP can be used for geothermal applications, when groundwater temperatures exceed 90°F or the water contains a severe volume or size of abrasives, use of an oil-lubricated lineshaft VTP is often the better choice.

In addition to ensuring adequate lubrication to all lineshaft bearings at a uniform 3- to-5-inch spacing, the use of an enclosed oil tube allows use of an isolated shaft environment with bronze bearings, avoiding issues associated with elevated temperature and abrasives common to liquid exposure to lineshaft and flexible rubber bearings with product-lubricated (open) VTP pumps.

In geothermal applications, another consideration is thermal expansion or contraction. Because of their individual differences in thickness, material, and mass, the column, shaft-enclosing tube, and lineshaft will each expand or contract at different rates and reach thermal equilibrium at different intervals following initial startup.

Additionally, the shaft in an enclosed lineshaft VTP is somewhat thermally isolated from the water in the column by the space between the shaft and the inside diameter of the tube. Once thermal equilibrium is reached, thermal expansion has no direct effect on relative shaft elongation, but it must be compensated for as it occurs, either by readjusting the impellers or by allowing extra lateral (axial) adjustment (end play) in the bowl.

Obviously, in a system that cycles, it must be allowed for in extra lateral adjustment. Axial end play is accommodated through the vertical space between the impeller and the bowl. This is the distance between the bottom of the impeller eye skirt and matching bore in the corresponding opening in each bowl. These areas may have wear or sealing rings on or in the bowls, impeller, or both.

VTP section.

Standard cold-water end play typically varies from as little as 3/16 of an inch in a 4-inch-diameter bowl up to 2 inches or more in a 30-inch-diameter bowl. Corresponding maximum axial end play using standard castings is usually around ¼-inch to 1¾ inches, respectively; any additionally required end play is obtained by deeper machining of the bowl/impeller eye (Figure 3).

For example, thermal expansion alone for a 400-foot static water level, 200°F well can be as much as 4.75 inches, which far surpasses the maximum end play for most standard fit pumps. This illustrates why standard pumps are sometimes unsuitable for geothermal service, especially in higher temperatures or cycling situations. Failure to consider this has led to broken lineshafts along with premature wear and failure of impellers, bowls, and bearings and electric motors.

Proper end play and lineshaft sizing requires adequate experience and an understanding of relative shaft stretch and a full knowledge of the potential impact from the pump’s head and setting vs. thrust and shaft elongation. To be safe, the relative shaft stretch (factoring the combined effects from column and lineshaft stretch against the developed thrust during operation) must be evaluated for every water well installation operating at 600 feet or greater of TDH or with a pump setting exceeding 500 feet.

The second most critical factor in high and low temperature geothermal applications is material selection and metallurgy. Although this can obviously apply to the riser pipe (column), lineshaft, and oil tube, the primary concern is generally vested in the bowl assembly and the materials used in it, especially if dissimilar materials are used throughout the bowl.

The next concern lies with the use of a deep well pump for geothermal service in a well that produces significant abrasives. In this case, a complete evaluation comparing the probable service life and cost of a VTP vs. a submersible pump should be conducted. Although a submersible pump usually costs much less than a comparably sized VTP, the presence of abrasives can compromise the service life of a submersible pump. They can be four times less than a VTP, largely due to the higher speed of 3600 RPM over a typical VTP that operates at 1800 RPM.

The final concern for geothermal pump design is often the discharge or shutoff pressure developed by the bowl. In situations with extreme well lifts or head requirements, a standard cast iron bowl with flanged mating surfaces may not be adequate to resist the head developed by the bowl. In these cases, use of a ductile iron bowl with O-ring seals and flanged connections between stages and the upper case and discharge case may be necessary.

This is most common with head applications or pump setting depths exceeding 600 feet TDH. If required for temperature, abrasive, and chemistry concerns, special or hardened materials or coatings, machining, and construction methods can be used for a VTP or submersible pump. In all cases, the intended geothermal well pump manufacturer should be consulted before proceeding with this step and only knowledgeable and experienced personnel should design and adjust a VTP well pump’s impeller settings.

Column/Riser Pipe and Check Valve Selection

Selection of the column (for a VTP) or riser (for a submersible) drop pipe for a geothermal well installation is generally the same as for a normal well pump. As opposed to a typical well pump, however, the frictional loss should be designed for a general value between 2-7 feet per 100 feet of riser pipe length with the primary goal of maintaining the uphole velocity to more than 3 FPS but less than 8 FPS.

Remember this value will be different for a submersible than with a VTP which has the lineshaft and enclosing tube (for oil lube pumps) situated inside the pipe’s center, resulting in a reduced internal area of flow and dynamic (“C” value). This lower velocity will still provide transport of solids to the wellhead without inflicting excessive velocity that could lead to premature wear and failure.

Steel pipe and lineshaft (when used) should be checked for linear expansion on high temperature wells or deep sets and a Hazen-Williams friction loss value of 80 to 100 should be used to calculate the friction loss. In many cases, the use of extra-heavy (Schedule 80) wall thickness steel pipe and couplings may be needed to withstand the pressures or suspended weight upon the threads.

In these installations always double check the velocity and resulting friction loss as the inside diameter of the pipe is reduced, increasing the friction loss. When check valves are used, I recommend heavy duty check valves always be used. In addition, the internal components, particularly rubber, in some valves are not rated for the higher service temperatures or setting depths associated with geothermal applications. This factor should also be examined.

Submersible Motor Design

Even though a standard type of water cooled and lubricated submersible motor is rated for and can be used in most geothermal applications up to a groundwater temperature of 86°F (30°C) without derating or system modifications, the need for an adequate velocity and direct passage of pumped water past the motor during operation becomes more important with increasing temperatures.

Some manufacturers offer an elevated temperature rated (194°F/90°C) water cooled or alternate oil cooled/lubricated submersible motor for extreme temperatures or environments. Many of these motors are based on past service in oil wells which can often be directly transferred to geothermal applications.

In geothermal applications with groundwater temperatures below 140°F (60°C), a standard type of submersible motor can generally be used with a few corrections and derating required for the fluid temperature. The primary correction involves the use of a higher velocity past the motor during operation. This velocity, typically .50 to .80 feet per second for standard applications, is increased to 3 FPS for elevated temperatures (see Table 2).

The second criteria for using a standard submersible motor in elevated temperatures require derating of the motor horsepower at various increments based on the fluid temperature. This basic derating is from the 2015 edition of the Franklin Electric Service Manual. However, after personal investigation, I have made a few adjustments to the tabular derate values plus I recommend not exceeding 10% of the allowable 15% service factor available for most three-phase motors. This provides an additional safety factor for common operational issues, such as low or unbalanced voltage, higher ambient and operating temperatures, extreme depth, and fluid flashing unique to water well and geothermal applications. Table 3 and Table 4 can be used to determine the required motor size for a water temperature less than 140°F.

For example, assume a 10-inch-diameter × 600-foot pump setting low temperature geothermal well (water temperature of 131°F (55°C, S.G. = 0.9857, from Table 1). The required duty point is 350 GPM at 425 feet TDH. What size of submersible motor is required?

  1. Use pump curves to select bowl from selection chart (Figure 4): 350 GPM at 428 feet TDH-P.E. = 80.3%
  2. Determine brake horsepower: 350 GPM × 428 feet TDH × 0.9857 (S.G.) = 46.435 BHP

3960 × .803

  1. Verify adequate velocity past motor (from Table 2): 8-inch motor in 10-inch well = 340 GPM ~ 350 GPM
  2. Correct for temperature (from Table 3): multiplier for >30 HP at 131°F = 1.65 × 46.435 BHP = 76.62 HP
  3. Determine required motor size (from Table 4): 75 HP motor × 1.10 S.F. = 82.50 HP ≥76.62 required HP
  4. Select 75 HP, 8-inch-diameter standard submersible motor for use with the 8-inch, 5 stage bowl assembly (Figure 4).

The designer can also consider use of a high-temperature motor, which may allow continuous operation in fluid temperatures as high as 194°F (90°C) without derating or modification. In either case the designer must also examine the motor thrust capacity vs. the actual thrust along with the available NEMA mounting to the intended pump end.

Curve for 8-inch-diameter × 5 stage, 3450 rpm pump.

The final design step involves selection of the submersible drop cable, which includes the ambient temperature of the source water plus insulation and operating characteristics and rating of the cable. For this example, even though the calculated load is just under 50 BHP, I think in order to comply with the National Electric Code the designer must calculate and design the drop cable voltage drop for a fully loaded 75 HP submersible motor operating at a +15% service factor load and NEC compliance to a 75 HP motor:

Motor data: 75 HP, 460 VAC, 3ϕ, 8-inch-diameter standard submersible motor, use FLA = 94 for NEC circuit design

Use SFA = 107 (94 FLA × 1.15) for drop cable size (for ΔV of 5%).

Drop cable: Use copper (cu) conductors with 90°C rated insulation (cu resistance = 13.3 ohms/per cm/100 feet)

RE: 2017 NEC Adjustment Factor #2: derate 90°C cable ampacity × .76 for ambient temperature at 55°C

  1. Required circular mils (cm) = 13.3 × 600′ × 107 SFA × 1.732 = 64,300 cm (#2 cu = 66,360 cm = 130 A)

460 VAC × .05 (5% Vd)

  1. Check minimum conductor size (RE: NEC Table 310.15): 94 FLA × 1.25 = 117.50 amps ≤130 amps
  2. Check NEC derate: #2 cu with 90°C rating: 130 amps × .76 derate = 98.8 amps <117.5 required amps
  3. Check use of #1/0 cu: NEC amps at 90°C rating = 170 A × .76 = 129.2 A ≥117.5 required amps

For this example, I would select a #1/0 × 4 copper conductor (three phases + motor ground) drop cable. I don’t need to recheck the voltage drop since we already determined that a smaller #2 copper cable would work, so compliance with the NEC Code was the default decision.

Obviously, I am making certain assumptions here. First, that a 90°C rated insulation class will be permitted by the inspector. This will require uniform use of 90°C rated terminals and motor equipment, which for this size of motor and type of application is probable. Second, this example is based on my personal experience with engineering, NEC application, and local inspectors and is generally quite conservative—especially as the motor amperage design is concerned.

It is always incumbent upon each designer to check and verify with their local jurisdictions if their cable selection procedure is allowed. In some cases, special jacketed or armored submersible cable may be required to accommodate the water temperature and associated higher operating temperature of the conductors.

In some installations, derating of the conductor current capacity (90°C to 75°C), necessitating a larger size of conductor or use of a higher rated conductor insulation (EPDM rating >140°C) may be needed. However, for most lower temperature geothermal applications using a submersible pump and motor, a cable consisting of a 90°C or 205°F (96°C) rated ethylene-propylene rubber (EPR) (Type MV-105) or polypropylene insulation with an outer PVC or nitrile jacket is adequate and can be used.

In others with higher water temperatures, armored, braided, or sheathed cable manufactured for oil and gas service is available for temperatures up to 450°F (232°C). Use of a motor with a greater operating voltage (460V vs. 230V or 2300V vs. 460V by using a step-up transformer) on larger HP motors (>100 HP) is often an alternative and may be warranted to lower motor current and thus, the drop cable size. This is often an excellent choice with deep sets or high HP applications.

Finally, to assist the designer with the selection and design steps for a geothermal well pump system, I have included a basic step by step flowchart shown in Figure 5.

This concludes this installment of Engineering Your Business. We will outline the various methods to design an efficient pumping plant next month.

though the calculated load is just under 50 BHP, I think in order to comply with the National Electric Code the designer must calculate and design the drop cable voltage drop for a fully loaded 75 HP submersible motor operating at a +15% service factor load and NEC compliance to a 75 HP motor:

Motor data: 75 HP, 460 VAC, 3ϕ, 8-inch-diameter standard submersible motor, use FLA = 94 for NEC circuit design

Use SFA = 107 (94 FLA × 1.15) for drop cable size (for ΔV of 5%).

Drop cable: Use copper (cu) conductors with 90°C rated insulation (cu resistance = 13.3 ohms/per cm/100 feet)

RE: 2017 NEC Adjustment Factor #2: derate 90°C cable ampacity × .76 for ambient temperature at 55°C

  1. Required circular mils (cm) = 13.3 × 600′ × 107 SFA × 1.732 = 64,300 cm (#2 cu = 66,360 cm = 130 A)

460 VAC × .05 (5% Vd)

  1. Check minimum conductor size (RE: NEC Table 310.15): 94 FLA × 1.25 = 117.50 amps ≤130 amps
  2. Check NEC derate: #2 cu with 90°C rating: 130 amps × .76 derate = 98.8 amps <117.5 required amps
  3. Check use of #1/0 cu: NEC amps at 90°C rating = 170 A × .76 = 129.2 A ≥117.5 required amps

For this example, I would select a #1/0 × 4 copper conductor (three phases + motor ground) drop cable. I don’t need to recheck the voltage drop since we already determined that a smaller #2 copper cable would work, so compliance with the NEC Code was the default decision.

Well pump selection flow chart.

Obviously, I am making certain assumptions here. First, that a 90°C rated insulation class will be permitted by the inspector. This will require uniform use of 90°C rated terminals and motor equipment, which for this size of motor and type of application is probable. Second, this example is based on my personal experience with engineering, NEC application, and local inspectors and is generally quite conservative—especially as the motor amperage design is concerned.

It is always incumbent upon each designer to check and verify with their local jurisdictions if their cable selection procedure is allowed. In some cases, special jacketed or armored submersible cable may be required to accommodate the water temperature and associated higher operating temperature of the conductors.

In some installations, derating of the conductor current capacity (90°C to 75°C), necessitating a larger size of conductor or use of a higher rated conductor insulation (EPDM rating >140°C) may be needed. However, for most lower temperature geothermal applications using a submersible pump and motor, a cable consisting of a 90°C or 205°F (96°C) rated ethylene-propylene rubber (EPR) (Type MV-105) or polypropylene insulation with an outer PVC or nitrile jacket is adequate and can be used.

In others with higher water temperatures, armored, braided, or sheathed cable manufactured for oil and gas service is available for temperatures up to 450°F (232°C). Use of a motor with a greater operating voltage (460V vs. 230V or 2300V vs. 460V by using a step-up transformer) on larger HP motors (>100 HP) is often an alternative and may be warranted to lower motor current and thus, the drop cable size. This is often an excellent choice with deep sets or high HP applications.

Finally, to assist the designer with the selection and design steps for a geothermal well pump system, I have included a basic step by step flowchart shown in Figure 5.

This concludes this installment of Engineering Your Business. We will outline the various methods to design an efficient pumping plant next month.

Until then, as always, work safe and smart.