Archive | 2006


6:00 am
December 1, 2006
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Utilities Manager: Cutting Costs With Energy Auditing

An experienced power quality engineer reveals how he goes about finding energy savings in a facility. It all begins with an energy audit.

“Using energy efficiently is cool again,” says Paul Twite, referring to the current high cost of energy.Twite is a power quality engineer, a Level II certified thermographer and a co-owner of 24-7 Power, an electrical consulting and engineering service company in the business of helping other companies discover and fix their energy inefficiencies. 24-7 Power is also a full service manufacturers’ representative for many of the instruments Twite uses in energy audits. Twite uses a three-step approach to help a company lower its energy bills.With the right tools and knowledge, your company can follow the same process using your own personnel.Here’s how it works.

Step 1: Energy Accounting
This step consists of at least three parts: 1) reviewing utility bills; 2) scanning the electrical, mechanical, process and HVAC (heating, ventilation and air-conditioning) systems as well as the building envelope using thermography; and 3) monitoring for power consumption, power quality, power factor and other relevant aspects of energy use.

1206_um_usingtherighttools1Reviewing utility bills reveals what your utility is charging for the electricity they say you used, but it will also reveal any utility demand charges and/or power factor penalties assessed. Any and all of these charges require follow-up monitoring to confirm that the utility’s metering is accurate and that you are getting what you’re paying for and not paying excessive penalties. “Utility meters have been known to drift out of calibration or malfunction over time, so we feel it’s good to double check the utility once in awhile,” Twite reports.

Scanning systems and building envelope using thermography can reveal overloaded or imbalanced circuits, loose connections, overheating motors on process or HVAC equipment, malfunctioning steam traps, problems in HVAC systems, and a host of other conditions that might signal an inefficient use of energy.

Twite compares using a thermal imager (infrared camera) in energy auditing to your doctor’s use of a stethoscope during an annual checkup: “If you go in for a physical exam, the first tool the health care provider will pull out is a stethoscope.While this tool is not sufficient for the health care provider to say, ‘I’m sorry, you have a serious problem,’ it is sufficient for a determination such as, ‘Hmm, that sounds odd.Maybe we should order some more tests.’ In my opinion, thermography is like that stethoscope. It is an extremely powerful tool, but it is most potent when it is used in combination with several other tools.”

So, Twite has a host of diagnostic equipment at his disposal when he does a commercial energy audit. “Typically, I travel with a fourwheeled utility cart loaded with tools and Personal Protective Equipment (PPE),” he explains. “It carries my thermal imager, three-phase power logger, vibration analysis equipment, ultrasonic listening equipment, and a digital auto-ranging multimeter.When I find what appears to be a problem with my thermal imager, I have several resources to fall back on.”

Monitoring for power consumption, power quality and power factor can be used to follow up on issues or unusual anomalies identified by thermography. The appropriate meter can also identify harmonics and other internally caused power interruptions that may affect machine performance as well as measure peak demand and power factor, which are the focus of what follows.

Utilities set demand charges. Often they are higher in the summer and at certain times of day. A utility also typically sets demand intervals; 15 minutes is common. Based on these, your utility will monitor the amount of power your facility consumes several times an hour based on the average demand for each interval. Peak demand is the highest average demand during all of the intervals in a billing cycle. If, for example, your facility’s normal demand is about 500kW, but three large process pumps start at once and your demand hits 600kW at 4:00 p.m. on a weekday in July, the episode could be costly. If the utility’s demand charge is $100, then peak demand penalties for July would be (600kW – 500kW) x $100 = $10,000. A three phase power logger like the Fluke 1735, or a three-phase power quality analyzer like the Fluke 434, can measure demand over time, pinpointing large loads operating concurrently and verifying readings for individual loads.

Some utilities also penalize for a low power factor (PF), which indicates the customer is not efficiently using the power supplied to it. Twite says that by using a thermal imager, in conjunction with other power analyzing instruments, you can quickly identify power consumption and inefficiency issues if any of the feeders or neutral conductors appears warmer than ambient temperature conditions. This thermal imbalance also may be due to a high harmonic content on the circuit or could be indicative of broken rotor bars, windings or failing bearings on a motor circuit. “That’s why it’s important to blend thermal imaging and power analysis to gain a clear perspective on what is happening with the electrical distribution,” says Twite.

Twite explains power factor this way: “Suppose you are a machine shop and you have a lot of arc welding and machine tools—end mills, CNC machines and the like—that cycle on and off. A high current load cycling on and off on a regular basis, could lead to a significant PF problem. The difference between how energy is delivered to you and how you use it is the power factor. It’s just a ratio between the apparent power and the applied power (Power/VA=PF).”

A purely resistive linear load can have a perfect PF of 1.00, but your utility may charge a healthy penalty for a PF that dips below a certain level, say 0.90. For example, the utility might add one percent of demand charge for each hundredth (0.01) your facility averages below a PF of 0.90. So, if your operations have an average PF of 0.88 each month and your demand charge is $6,000, then you will pay $5,400 in PF penalties annually.With a good power quality meter, you can measure and validate your average PF over time.

Twite emphasizes that all he does during the first step in an energy audit is collect data from utility bills, thermal imagers and meters; then blend the data from those three sources and do a “roll call” of the power-consuming equipment and devices inside the plant. “The goal of Step 1,” he says, “is to come up with an energy accounting spread sheet which addresses the question of where all the energy is going.”

The power quality engineer says that inhouse personnel usually can perform the accounting phase of an energy audit as long as they have a little electrical savvy along with training in using the monitoring equipment safely. It is, of course, critical always to keep in mind arc flash hazards and awareness of high energy potentials.

“There is no certification or college degree required, and it’s usually not necessary to be a licensed electrician, ” Twite notes. “You should, however, consult with your company’s safety manager if you plan on self-performing this work,” he says.

1206_um_usingtherighttools2Step 2: Analysis and Identifying Problems
In the second step of an energy audit, Twite analyzes the data collected in Step 1, asking questions such as: Do I have an overloaded circuit? Do I have a loose connection? Do I have phase imbalance? Why is the circuit overloaded? Is that motor running hot because of an alignment problem, a lubrication problem or a bad bearing? Often the auditor must look at the bigger picture: What process does this circuit feed? What about the process is causing power factor problems or peak demand problems?

Also in this step, the auditor assesses the age and efficiency of lighting systems, HVAC systems, motors and drives and other plant equipment and systems. “By reviewing the nameplate data on equipment, or metering the point load or checking for unusual hot spots with a thermal imager – or better yet, a combination of the three – you can make a pretty solid determination of the useful life of the equipment. Sometimes the quickest route to the biggest energy savings is simply replacing old, inefficient equipment with new,more efficient versions,”Twite adds.

Step 3: Proposing and Prioritizing Solutions
The third step is not really auditing. It consists of engineering solutions to problems uncovered in Steps 1 and 2.

“In Step 3, I’m trying to figure out different strategies to lower the energy bills,” Twite says. “To be effective in this step you (or your auditor) have to have an engineering background or at least have been in the energy business for a while. You need to understand how everything affects your energy costs.”

Step 3, then, is proposing and prioritizing ways to lower your energy bills. There are at least three kinds of things that might be done to achieve that goal: 1) adjust processes; 2) repair faulty equipment; and 3) replace inefficient systems and equipment. Once the action items for improvement are identified, then traditional return on investment (ROI) calculations can be used to help prioritize them. In what follows, some typical payback periods are included. Most come from Paul Twite’s years of experience helping companies cut their energy bills.

Adjusting processes is often the most expedient way to eliminate demand charges and power factor penalties.Maybe process controls can be set to disallow those three large process pumps mentioned earlier from all kicking on at the same time. Or maybe there are electric water heaters that tend to run during peak demand periods, but you have enough waterheating capacity to allow you to push the water heating until after 10:00 p.m., when electric rates are lower. The calculations you did using energy bills and the confirmation of their correctness using a power quality analyzer will provide the data required for calculating the ROI for such strategies.

In another kind of process adjustment, you can immediately improve PF by the installation of power-factor capacitors either at the entrance of your service or at the point load. Twite uses the following analogy: As your big machines are cycling on and off, the capacitors act much like sponges that soak up water, except capacitors “soak up” electricity. Then, just as water comes out when you squeeze the sponge, a capacitor “squeezes out” electricity when your voltage starts to dip. It fills in the low spots and trims off the high spots of your electricity profile.

Twite says that in many cases with very steep power factor penalties, capacitors can pay for themselves within 30 to 60 days. “In fact, we have seen manufacturing customers with low power factor getting charged over $1,000 a month on their energy bills. For those manufacturers, 24-7 Power has installed correctlysized capacitor banks and verified an immediate improvement in the overall power factor and resulting drop in kW demand. In some cases, the entire installation was paid for in 60 days by energy savings.”

Repairing faulty equipment should follow from listing the problems that thermography uncovered in the electrical distribution system. Such problems might include loose or corroded connections, phase imbalance or worn insulation. Similarly, misaligned sheaves might be revealed by overheating. Laser alignment equipment can help fix that problem. In some cases, a motor bearing that is starved for lubrication can cause the motor to run hotter and use more energy. In that case, simple lubrication can significantly cut temperatures and full load current.

Of course, the repairs that should take priority are those that threaten a production stoppage followed by those with low cost of repair and/or quick payback. Twite points out, for example, that building-envelope problems (except for some roof problems) have relatively long payback periods. Typically, these will get a much lower priority in Step 3 than, say, installing power-factor capacitors.

Replacing inefficient systems and equipment goes far beyond peak shaving. Often, following an audit, Twite recommends replacing an old HID or other inefficient lighting system with a new, high-efficiency compact or linear fluorescent system.He points out that the U.S. Department of Energy lists the two biggest energy consumers in most plants as the HVAC and lighting systems.”Upgrading to an energy-efficient lighting system can offer the easiest and quickest payback,” he says. “In many cases, it’s usually less than a year, especially if your utility company participates in the form of rebates.”

According to Twite, other recommendations he often makes to his clients include adding new premium efficient motors that have 94% NEMA ratings as opposed to 80% ratings.”Many motors from the 1930s and 1940s are built like tanks, and are still running today.However, new motors with the same horsepower rating use a lot less energy,” he says.

Looking for rebates paid by utilities for the installation of energy efficient equipment and systems is something every company should do. Twite notes that to build a new coal-fired generating plant can take 12 to 14 years. One of the simplest ways that large, power-generating utilities can continue to run profitably is to lower demand by encouraging companies to cut energy consumption through the use of equipment that is more efficient.

Finally, Twite notes that not all rebate programs are the same and suggest that you check with your utility to see what is available.

Paul Twite is tactical engineering director of 24-7 Power, Inc., a full service electrical consulting, contracting and manufacturer’s rep firm. 24-7 Power specializes in critical power delivery, power quality investigation and mitigation and on-site training with highly specialized tools of the trade. For more information on the types of products referenced in this article, log on to



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6:00 am
December 1, 2006
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Utilities Manager: Reducing Energy Costs In Municipal Pumping Systems

1206_um_systemoptimization1It’s everybody’s job to save energy. Simple solutions to help optimize your pumping systems, like those outlined in this article, often can pay off more than you might think.

The facts speak for themselves and they’re not very encouraging for consumers across the country. The cost of energy is skyrocketing, and with it, the cost of electricity. As a result, countless organizations are putting special emphasis on efforts to optimize their equipment and processes—which, in turn, will reduce energy costs and increase reliability and uptime. If not, they need to be doing so. And the sooner the better.

For most operations, pumping systems can be one of the best places to begin looking for energy savings. In fact, the U.S. Department of Energy (DOE) has estimated these possible savings could exceed $6 billion annually for industrial applications, which includes municipal operations.

Big opportunities
Municipal water and wastewater, one of the larger applications for pumps, is responsible for about 2% of the nation’s electrical energy use. The good news is that an estimated 20% reduction of the energy use in the municipal sector seems quite feasible. Municipal pumping stations are generally designed following guidelines that take into account how many people live in the area, what the peak flow rates will be over a specified time period, etc. These peak flow rates depend on both the anticipated number of customers that eventually will be hooked up to the system and on weather-related additional flow rates.

Normally, a pump station is designed with multiple pumps so that it can handle peak flow rates even if one pump is down. It also is common that pumps run on/off—which means that peak flow-rates are produced as soon as the pumps are turned on. Unfortunately, this type of operation generates high energy losses through friction.


It is a given that a pump station will have to be able to cope with peak flow rates and have redundancy if a pump fails. This practice, however, leads to higher-thannecessary energy use. It has been demonstrated that substantial savings can be achieved by using smaller or speed-regulated pumps for average flow conditions. Fig. 1 shows a typical duration curve for a wastewater lift station. Each point on the curve shows how many hours per year the flow exceeds a certain value. For example, the inflow is larger than 1,000 gpm for about 1,000 hours per year. The rest of the time, it is lower. A typical pump configuration for a pump station with this inflow characteristic would be two installed pumps that can each handle close to 3,000 gpm. It is evident that such pumps are much larger than needed most of the time.

Improving the situation
One popular solution to the problem is to install variable speed drives (VSDs) so that the pump capacity can be matched to the inflow. Many times, a VSD can be an excellent solution, assuring that the pumped volume is never larger than needed.On the other hand, in many cases involving lift stations, this “solution” can actually lead to increased energy usage. The main reason for this is that pump efficiency can deteriorate rapidly in systems exhibiting high static head when the speed is lowered. (For more information on this topic, refer to Variable Speed Pumping: A Guide to Successful Applications, by Europump and the Hydraulic Institute.1)

When static head is low (a fixed percentage is hard to give, but it’s usually lower than 30-50% of total head),VSDs typically can be used with good result. If the static head is higher, a thorough study should be conducted before VSDs are installed. In some cases, a simple impeller trimming might be a better way to adjust supply to demand.

Another possible solution could be to use pumps of different sizes. There are several ways this can be done. One method, described in a DOE report2, suggests using a “Pony pump” in parallel with larger full-size pumps. Fig. 2 shows


how the larger pump is run for a couple of hundred hours a year, while the smaller pump is operating over 5,000 hours. The areas under the respective curves represent volumes pumped. The sum of the areas in the rectangles is the same as the area under the duration curve. As can be seen most of the flow is pumped by the smaller pump. The savings come from operating at lower flow rates and heads (see Fig. 3). The energy usage per unit volume is proportional to the head. In this case the pumps are chosen so that the operating points are close to the best efficiency point (BEP) for each flow rate. In the project referenced in the previously mentioned DOE report, energy savings of close to 40% were achieved using this method.

It is important to know that pumps which operate close to BEP not only use less energy, they also have substantially lower maintenance costs than pumps that are not operated this way. Fig. 4 shows such data from DuPont.

It is of the utmost importance that pumps operate close to their BEP, both from an energy and maintenance point of view. One can say that if the energy usage is optimized, the maintenance savings come for free. Interestingly, in many cases, the maintenance savings can actually be greater than the energy savings.

Other possible improvements could be to split the peak flow rate on two pumps and have a third pump as standby.Most of the time, only one pump would run and the station would exhibit lower operating costs.

To determine the best solution for the problem, a life-cycle cost calculation can be done. A simple calculation of the difference in energy cost for a hypothetical situation is shown in the sidebar above.

Calculating the Difference in Energy Costs
Assume a lift station with a static head of 35′. The station is equipped with two pumps that alternate. At the duty point (6,000 gpm and 55′ head) they are 74% efficient and require 112.6 horsepower. A 94.5% efficient motor draws 89 kW. The pumps operate 3,000 hours/year, pumping 18 million gallons while consuming 267,000 kWh. If a smaller pump operating at 2,500 gpm is added to the station, the big pumps only have to be run at peak flow conditions—let’s say 250 hours/year. They would pump 1.5 million gallons during this time. The small pump would have to run an additional 6,600 hours/year to pump the same total amount as the two larger pumps (18 MG). Assume that the smaller pump operates at 66% combined motor/pump efficiency. The total energy used would then be 205,000 kWh per year, a reduction of 23%–or close to $5,000/ year at 8 cents/kWh. It is, of course, necessary to put in real values if you contemplate such a solution, but the example shows how to calculate the savings. DOE’s PSAT (Pump System Assessment Tool) program is useful for this kind of calculation. You might also realize savings from lower demand charges and lower maintenance costs that should be included in your calculations. In the DOE project mentioned in this article, those savings were actually larger than the energy savings in dollars.

A call to action
There are many reasons for our current energy situation being what it is. Historically, energy costs have been low and organizations have put more emphasis on lower initial purchase costs for equipment than on lower overall life-cycle (cradle to grave) costs of that equipment. No matter the cause, higher energy costs are, in all likelihood, here to stay. Therefore, it behooves both end users and design engineers—across all industry sectors—to rethink how they design all of their equipment systems. In some cases, guidelines and regulations will have to be reevaluated in order to pave the road for more efficient engineered systems. In the meantime, we must all do our best to use energy more efficiently than in the past. It is vitally important now, and will be even more so in the future, to identify and implement successful energy-saving strategies and solutions throughout industry— both at home and around the globe.


  1. Variable Speed Pumping, A Guide to Successful Applications, Europump and Hydraulic Institute, 2004.
  2. Szady, Andrew J., P.E., “Independent Performance Validation, Reservoir Ave. Pump Station, Town of Trumbull, Connecticut,” report by Oak Ridge National Laboratory, U.S. Department of Energy Motor Challenge Program Showcase Demonstration, August 1997.

Gunnar Hovstadius is a world renowned expert in pumps and energy systems. After a long and illustrious career as the director of technology for the largest pump company in the world, he now consults for companies, governments and NGOs around the globe. E-mail:; telephone: (203) 434-4840.

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6:00 am
December 1, 2006
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Utilities Manager: Extend MTBR while decreasing costs and increasing performance. . .Custom Hydraulic Solutions: “Reliability Engineering PLUS"

Everyone wants to cut their energy costs, even utility companies. Some of the biggest energy hogs in these operations can be found among the many pumps required to run these plants. Yet, in many cases, the big pumps (especially the older ones) can be updated to achieve some or all of the following advantages: increased performance, lower utility requirements, reduced Net Positive Suction Head Required (NPSHR), reductions in cavitation and upgrades in metallurgy.

1206_um_efficientsolutions_img1One example of a Standard Alloys Custom Hydraulic Solution (CHS) involved a large circulating water system pump (one of six) for a utility company in the Northeast.While impeller damage due to cavitation dictated the overhaul of at least one of these pumps each year, during warm summer months the power station would periodically become load limited based on condenser backpressure. Thus, while eliminating cavitation was the primary objective of the CHS study, additional capacity also was requested. Fortunately, because Standard Alloys had reverse-engineered the impeller on this pump years earlier, the current impeller design was known. A redesign effort was initiated that resulted in a change in the number of vanes and a change in the vane shape. This redesign was double-checked by an outside consultant and verified.

Next, a new pattern and core boxes were made for the foundry. The new impeller was cast and machined, then verified against the design prior to shipment. Once installed, the performance was checked and the improvements were verified against pre-CHS tests utilizing ultrasonic flowmeters and other plant instrumentation.

The payback
The redesigned 46” impeller, custom-designed and built for this particular application, increased the capacity of the Worthington pump from 88,000 gpm at 100 ft Total Developed Head (TDH) to 94,000 gpm. It also decreased the NPSHR from 22 ft at the rated 88,000 gpm, to 17 ft at the new 94,000 gpm rating.A byproduct of the pump operating without cavitation was a significant reduction in the noise levels measured around the pump with the new impeller. Furthermore, the energy requirement for the 2500 hp motor was reduced from 329 amps to 319 amps. (Remember, too, that with the 329 amps of the old design, the unit was only pumping 88,000 gpm. The upgraded design, requiring only 319 amps, is pumping 94,000 gpm.) Finally, just for good measure, Standard Alloys also upgraded the material to CD- 4MCu, which means it will be years before a replacement is needed.

Subsequent to the first impeller being installed, the remaining pumps underwent upgrades. Today, all six units are continuing to operate well.

Elimination of the cavitation will increase the life of the impeller, bearings and seal, thus extending the Mean Time Between Repairs (MTBR).Adding the value of the increased pump output to the energy reduction savings and the savings due to the longer life of the part and pump system makes this type of project easy to cost justify.

Standard Alloys, Inc.
Port Arthur, TX




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6:00 am
December 1, 2006
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Utilities Manager: Invest In Energy Management With Intelligent Motor Control Solutions

1206_um_smartvfds_img1Tasked with selecting the most reliable motor control solution with the lowest total cost of ownership? You’ll want to remember that it really pays to buy “smart” in this case.

Rising energy prices are motivating industry to explore any number of new methods to reduce operating costs. Energy-efficient motor control solutions are one such method—and a particularly attractive one at that.

Since over 80% of pump and fan applications require control methods to reduce flow to meet demand, these applications can be especially good hunting grounds in the search for savings. Process engineers commonly use fixed speed controllers and throttling devices such as dampers and valves, but these are not very energy efficient.Variable frequency drives (VFDs), also known as adjustable speed drives, offer an alternative that will both vary the motor speed and greatly reduce energy losses.


Advancements in drive topology, careful selection of the hardware and power system configuration and intelligent motor control strategies will produce better overall operating performance, control capability and energy savings. Things to consider when choosing a motor control solution include peak-demand charges, operating at optimized efficiency, power factor, isolation transformer cost and losses, regeneration capabilities, synchronous transfer options and specialized intelligent motor control energy-saving features.

Beat peak-demand charges
It’s important to be aware that utility companies charge higher peak-demand electricity prices when companies exceed a preset limit or base load of electricity. Peak demand charges often occur when industrial motors draw large peaks of current when started across-the-line.VFDs help reduce the peaks by supplying the power needed by the specific application, and gradually ramping the motor up to speed to reduce the current drawn. The VFD also automatically controls the motor frequency (speed), enabling it to run at full horsepower only when necessary. Running at lower speeds and power levels during peak times contributes to a reduction in energy costs and increased operating efficiency.

Consider the following documented real-world successes
Kraftwerke Zervreila, a hydroelectric power generation plant in Switzerland, was causing a 20% under-voltage condition and line flicker on the electrical grid every time it started its 3.5 MW synchronous water pump motors that drew 1,600 Amps in full-voltage starting conditions. In 2000, Zervreila retrofitted its 40-year-old motors with Allen- Bradley® PowerFlex® 7000 medium voltage drives, which limited their starting current to 200 Amps, greatly reducing its peak energy demand.

1206_um_smartvfds_img3The Monroe County Water Authority, in Rochester, NY, invested in a 4160 V, 750 hp Allen-Bradley PowerFlex 7000 medium voltage drive for one of its centrifugal pumps in 2003. In doing so, the Authority achieved annual savings in energy use and peak demand charges of over $23,000. These types of returns are not unusual.

Optimize power usage
In addition to starting the motor, also consider how energy-efficiently the pump or motor operates. In applications where motors are unloaded or lightly loaded, VFDs can deliver additional energy savings and performance capabilities. Centrifugal loads, such as pumps and fans, offer the greatest potential for energy savings when applications require less than 100% flow or pressure. For example, significant energy savings can be gained by using VFDs to lower speed or flow by just 20%. If this reduction doesn’t impact the process, it can reduce energy use by up to 50%, which, in many operations, can translate into substantial energy savings.

Energy consumption in centrifugal fan and pump applications follows the affinity laws—meaning that flow is proportional to speed, pressure is proportional to the square of speed and horsepower is proportional to the cube of speed. For example, if an application only needs 80% flow, the fan or pump will typically run at 80% of rated speed. But, at 80% speed, the application only requires 50% of rated power. In other words, reducing speed by 20% requires only 50% of the power needed at full speed. It’s this cubed relationship between flow and power that makes VFDs such energy savers.

Take, for example, what happened at the Lewis County General Hospital in Lowville, NY. Management wanted to reduce the amount of energy consumption in the facility’s HVAC system while assuring patients that care and comfort would remain high. Rockwell Automation helped the hospital install a computerbased energy management system to track temperatures and energy use throughout the facility. The system collected data to help assess where the hospital could improve and identified the fans responsible for moving cool air through the HVAC system. Engineers installed Allen-Bradley PowerFlex 400 AC Drives in the system to optimize fan and pump performance throughout the facility. Installing the drives helped the hospital reduce HVAC-related energy costs by 15%.

Energy savings also can be realized by managing input power based on system demand.

Germany’s Vattenfall Europe Mining AG modernized the overburden conveyor systems of its open pit coal mine with 6.6 kV Allen-Bradley PowerFlex 7000 medium voltage VFDs. The drive’s inherent regenerating capability allows fast, coordinated deceleration without the need of braking components and without wasting energy. The optimized conveyor loading (OCL) ensures system efficiency by using a material tracking system across an array of conveyors to continuously adjust speeds so that the conveyor belts are fully and uniformly loaded. A partly loaded conveyor wastes energy and causes unnecessary wear.


Vattenfall’s biggest benefit comes from the reduced amount of installed drive power. Before modernization, the conveyor required six fixed-speed controllers at 1.5 MW each, totaling 9 MW to start the motor. The conveyor with a variable speed solution now uses installed power of only three units at 2 MW each, for a total of 6 MW to generate a smooth start.

The power factor difference
Power factor and how it affects displacement and harmonic distortion is an important consideration in drive selection. Drives that are near-unity true power factor translate to reduced energy use. Leading drives produce a .95 power factor or greater throughout a wide operating speed range. An example of the effect of power factor on energy cost compares two 4,000 hp drives, one with a true power factor of .95 and one with a true power factor of .98. The annual operating cost for 8,760 hours of use at $0.07 per KW hr results in savings of $63,173 annually using the .98 power factor drive system compared to the .95 power factor drive system.

The hidden cost of transformers
Every drive creates harmonic distortion, which creates extra heat in the plant power system and losses to the drive system. Manufacturers can reduce harmonics by using either a phase-shifting and multipulse rectifier transformer or an active front-end rectifier.

Transformers have long contributed to costs of the overall drive system. Some of the negative issues include increasing the size, cost, weight and complexity of the drive system. Transformers produce losses that generate heat and contribute to energy loss. Extra air conditioning is necessary to cool the transformer, which adds to initial capital costs, but also consumes excess power on an ongoing basis.

Engineers can now take advantage of transformerless medium voltage drives. These drives use an active front-end rectifier (AFE) with a line reactor and integral common-mode voltage protection that has a simpler power structure. They help reduce drive system size by 30-50% and lower drive system weight by 50-70%.

Since transformerless medium voltage drives produce fewer losses due to less magnetic components in the line reactor, they also eliminate the need for extra air conditioning.A transformer is about 98.5 – 99% efficient while an AFE line reactor is about 99.5% efficient. This difference of 0.5–1% sounds small, but it can add up to big savings. Engineers can retrofit AFE drives with existing motors, making the drives ideal for process improvement or energy savings projects with existing motors, switches and control rooms, where space is often limited.

Consider the example of a 4,000 hp drive using a 4,000 KVA isolation transformer that resulted in $154,804 in monthly energy costs. After installing a transformerless line reactor drive at the same power rating, energy cost was reduced to only $153,249 per month—an annual savings of $18,660 at an average rate of 7 cents per kW.

Generate your own energy
Another consideration in selecting a drive is regeneration capabilities. Some VFD applications enable users not only to save energy, but to regenerate power, which can be routed back to the system or sold to utilities for additional revenue.

La Union, S.A. sugar mill in Guatemala uses its waste energy to produce power for its factory by burning the sugar cane bagasse in boilers to generate steam. In 2002, La Union expanded its generation capabilities to sell its excess energy to the local utility market.

La Union replaced its steam turbines with more efficient electrical motors and used Allen-Bradley PowerFlex 7000 2300V, 1000 hp, medium voltage variable speed AC drives in the boiler fans and pumps. The new drive and motor set uses 66% less steam to create the equivalent power, and now provides 1,420 kW of electrical power with the same 23,000 lbs. of steam. This brought in additional revenue of $158,480.

Use one drive for multiple motors
Synchronous transfer capability is another way to reduce energy costs. The synchronous bypass method uses only one drive to start and synchronize multiple motors through the process of transferring a load from one source to another by matching the voltage waveform frequency, amplitude and phase relation between the two sources. Using a VFD to start a motor, bring it up to speed and then synchronize it, causes a reduction in full-load current and optimizes the process.

In 2001, Conoco Inc. built a new crude oil pipeline origination/injection station in Montana to pump a wide range of crude oil types at various flow rates, viscosity and density. Operators had five different pumping scenarios to consider. Conoco used two centrifugal pumps at 2,500 hp and 1,500 hp to accommodate the differing flows, and one 2,500 hp Allen- Bradley PowerFlex 7000 VFD with synchronous bypass to control both of the motors.

The economic advantages of the VFD with a synchronous bypass are in both installation and operating costs. A synchronous system for two motors costs 33% less in initial capital outlay compared to multiple drives. It also reduces drive efficiency losses when compared to multiple drive systems.

Extra energy-saving potential
Not all drives have the same capabilities. Intelligent motor control today takes advantage of advanced networking and diagnostic capabilities to better control performance, increase productivity and perform diagnostics, while reducing energy use. Additionally, software features and programmability can further contribute to a drive’s energy savings potential.

  • Programmability
    Users can now program their VFD to adjust the total acceleration time and current limit and adjust the speed to the load requirement. Current limit on drives is normally set between 105 and 110 percent, whereas using the across-the-line starting method produces current limits of approximately 650 percent. Reducing the inrush current requirements of the plant equals reduced energy use.
  • SGCTs
    Advances in power semiconductor switches like SGCTs (symmetrical gatecommutated thyristors) are designed for high-voltage operation and ensure the lowest switching and conduction losses while maintaining a high switching frequency.
  • Power optimization
    Power optimizing features optimize the power usage when operating fans and pumps by adjusting the required voltage to the application. This reduces losses for improved motor and drive efficiency.
  • Communication software
    Software features enable torque limit and integrated architecture through communication connectivity between the drives, starters and soft starters for greater control and optimization.

ROI from energy management
Industry has many energy-saving opportunities. Intelligent motor control solutions, including high-efficiency VFDs, are an important part of an energy efficiency program to optimize equipment and processes and reduce electric energy bills.

Careful evaluation of your facility, your application(s) and the different VFDs available to you are the keys to investing well. Look for drives that use intelligent motor control through advanced technological features, including regeneration, synchronous bypass, transformerless options, software and communications to optimize energy consumption. As the savvy operators of the facilities referenced in this article will attest, making the right decisions can result in significant returns.

The right energy management solutions– like those described here—are investment strategies for long-term reduced operating costs that have typically provided users payback within one to three years.

Richard Piekarz is an electrical engineering technologist and project solutions manager with Rockwell Automation in Cambridge, ON, Canada. A large-horsepower drive specialist with over 20 years experience in the industry, he has written numerous papers on the subject. Internet:

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6:00 am
December 1, 2006
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Utilities Manager: Is It Time For A Standby Generator In Your Facility?

Selection, sizing, installation and maintenance of these units can impact your energy efforts.

1206_um_standbypower1In many facilities, the process of selecting a standby generator can either go relatively quickly or painfully slow.How you approach the specification, purchase, installation and maintenance issues will ultimately influence the speed and agony factors of your new genset.

Why would you need a generator for backup power?
What happens in your facility when the power goes off? Do the employees simply go home to wait out the event? What do you have to do to start the facility or get the process back up? Are there machines that need to run off the excess material in order to start anew? Does some equipment need to be cleaned out in order to be restarted? How much material did you consume in waste or scrap because the process wasn’t completed in time? How long does it take to get started again–and do you know what the resulting costs are? Is it possible that lives could be at risk when power goes away and people are stuck in elevators or automatic access areas?


If you have answers to these questions– or if you are asking even more probing questions–then you probably need a backup power source for your facility.

Backup power could bring elevators full of people to safety, keep your cash registers ringing, the phones in your call center up and available and your worldwide computer network operating.Or, it could simply help ensure that a site is getting the most out of its operators and machinery, even when a storm hits or the power company blips. These are just a few of the things that backup power can do for you.

How many generator choices do you have?
The short answer is a lot! But, like most systems you deal with every day, when you break your selection process into pieces, your decision-making task becomes easier. Before you specify a standby generator system, or genset, for your operations, you’ll need to make sure you know want you’re going to be doing with it. You have quite a number of questions to answer.

When are you expecting to run your genset?
In an emergency…during a storm…when the power company lets you down or doesn’t want to supply all your usage during high-demand periods? Are you trying to save energy costs by running when utility costs are high, or do you have free fuel to use up from another part of your operations? Do you want to power your entire facility or just the part of it that is costly to live without when the power goes away? Are you expecting the genset to supply power for future facility expansion(s)?

What does it cost to operate a generator?
How much maintenance will you need to supply on an ongoing basis? Are there any permits required before placeing the genset in service? Are there any environmental impacts of locating a genset on site?

Which fuel is right for you?
The answers to some basic questions will lead you to some reasonable cost analyses of using engine-driven gensets and the associated fuel consumption and delivery charges. Whoa! “Hold on there,” you say, “while I’m expecting to burn some fuel, what’s that ‘delivery charge’ stuff all about?”

There are three major types of fuel used for standby generators: diesel, liquid propane (LP) and natural gas. (Fig. 2 reflects estimated installation and operating costs of a typical standby rated dieselpowered unit. )

Diesel and LP are certainly the most popular choices if you’re trying to operate independently of the fuel supplier in times of disaster or emergency. In both cases, you already have the fuel in a holding tank, ready to run. Diesel is probably the most preferred option, since, unlike LP, you can store it unpressurized. In some locations, such as hospitals or nursing homes, pressurized storage may not be acceptable or preferable.

If you select natural gas as your fuel, you’ll typically be dependent on your local gas company in time of disaster. And, there’s usually no holding tank to supply the fuel if the gas company can’t pump it to you. If, however, during a disaster you aren’t expected to power your facility, natural gas is probably the most convenient fuel to use with a backup power system, especially if the pipe from the gas company comes close to your location. Once the natural gas fuel connection is made, there’s no reason to call the diesel or LP truck to come fill up the tank!

By the way, what size tank did you specify for your diesel or LP genset? Can you imagine what would happen if a big storm were to blow in and the fuel truck couldn’t get to your facility to refill the tank for a couple of days?

Should you have contracted with your fuel supplier to be one of its high-priority customers in times of disaster? Or, were you just planning to call the supplier when you needed fuel? Oops…

How big a generator do you need?
There’s a short answer to this question: that depends…on what electrical loads you want to power and how you sequence the load applications. Are you planning to power only lights, industrial machinery that uses electric motors, heating or air conditioning, water pumps or emergency equipment?

Lighting, for example, is a somewhat linear load. You need little more power to turn on the lights than to operate them continuously. Be aware, though, that some lights may have increased starting characteristics. Check with your lighting supplier just to make sure–before you get too far along in your genset selection process.

Machinery that uses electrical motors with inductive style loads typically will have an increased starting power requirement as compared to the continuous power required for normal running. (Note, the word “typically” is used here because if the motors utilize motor controls (drives) or soft starts, starting power requirements will be somewhat reduced as compared to flipping a switch for acrossthe- power-line starting.)

A typical motor starting across the line can draw as much as five or six times the normal running power in kVA. If the typical genset will supply about three times its rating for a short amount of time, it’s easy to see that it will start a motor across the line that’s about one-third the size of the generator rating. You might want to consider using a modern motor controller that may cause the motor to only draw 1.5 times the normal running kVA or less during starting. You might also want to consider staggering the start sequences of motor loads as seen by the generator, to give the generator a chance to recover from a motor start before another motor is connected. Otherwise a genset as big as the normal power grid supplied to your facility would need to be considered. Whew. . . that would be a darn big generator!

Don’t let all this sizing stuff worry you too much. Most genset manufacturers have a sizing program available to help you understand electrical loads and select what size generator you need for your facility. Before you start the sizing program, you might want to survey your facility and write down the nameplate data for all the loads you expect the generator to run. Also, think how you might sequence the loads if necessary to get the genset to be a little smaller or to provide additional overhead for future expansion.

Speaking of overhead, when you drive your car, do you floor it all the time going down the interstate? Probably not! So, when you size your generator, you probably don’t want to size it to be floored all the time, either.

Sizing for 80% of the capability of the genset usually provides a reasonable margin and additional overhead, unless you’re thinking of expanding your facility.

Besides, the additional overhead may be needed when the filters clog a little, or the fuel is a little stale, or the oil is a little dirty, or Murphy shows up one hot, dry day. Electric motors usually power heating, air conditioning and pumps somewhere in a system.Make sure you take all of these components into consideration when sizing a genset. If any comfort or safety systems are considered to be “emergency,” in nature, special operating considerations may apply when powered from a genset. It’s best to check with the local authority having jurisdiction over these types of systems to make sure you meet any emergency requirements for your location.

Are all my worries over, once it’s installed?
Yes, absolutely! But…if…as long as…you may want to…Few things are ever really that simple, are they?

Your power worries may be over. And the resulting difficulties from a power outage in your facility also may be over! But, can you be sure your standby generator is going to run when you need it?

How about when you need it really, really bad? Naw, come on, they always work. . . my car never, ever really left me stranded. Even when the oil was low and really dirty–even when that neighbor kid put sugar in the tank! On the other hand, there was that one time that I forgot to fill up the tank…

Maintenance? You’ll need some! Poor maintenance—or, even worse, no maintenance— could turn all your hard work (to properly select, size and install a genset) into a wasted effort if the unit doesn’t power up when you need it.Most stationary generators are used with automatic transfer switches that monitor the utility power and automatically start the genset if the utility power goes away. The transfer switch also contains the high power contacts to disconnect the utility from the building and connect the genset to the building when needed. Slightly more sophisticated transfer switches also can be set up with a built-in timer to automatically start up the genset on a regular time schedule in order to verify that the unit is operational. If it doesn’t start up and run, an alarm usually goes off to warn you of the failure. If the genset were not going to run properly, when would you rather find out about it…during the scheduled equipment exercise period, or during a power outage?

So, plan on some exercising of your genset.Yes, you’re going to burn some fuel, and, yes, you’re going to use up some life of the engine consumables (i.e., oil, coolant, filters, etc.). But, it will be worth it to have confidence the genset will run when requested.

You probably need to make sure that you plan for scheduled exercising and maintenance of your genset in your maintenance budget.How much? It depends… The bigger the genset, the bigger the engine and expense for operation and consumables.

Most genset manufacturers recommend exercising these units for about half an hour of run time, once a week. The schedule is up to you and any local codes that may affect operation and yearly run time of the equipment.What you’re shooting for is to ensure that your standby generator starts and runs long enough to heat up all of its components.

So, what’s the most important question?
It was estimated that in the aftermath of the 2005 hurricanes along the U.S. Gulf Coast that as many as one-third of the backup generators in the region didn’t start and operate when needed. Most of those units reportedly had undergone little or no maintenance since being installed. Perhaps their owners had considered the cost of regular maintenance to be too high.

Rather than ask how much a genset “costs,” a better question is what the cost would be to your operations if you didn’t have such a unit when you needed it–and if you did have one, what would happen if it didn’t work when you expected it to…

Roddy Yates is generator products marketing manager for Baldor. Telephone: (479) 646- 4711; e-mail:

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6:00 am
December 1, 2006
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Utilities Manager: Should You pay For An Energy Assessment?


Christopher Russell, Principal, Energy Pathfinder Management Consulting, LLC

A particularly destructive hurricane season in 2005 wreaked havoc on oil and gas production infrastructure in the Gulf Coast region. This damage, in addition to what were already tight global fuel markets, drove U.S. energy prices to unprecedented heights. In the aftermath of price spikes, even “stable” prices remain high enough to threaten the profitability of U.S. based manufacturing facilities. The industrial sector, which is widely dependent on natural gas, pressed the Bush Administration for relief. U.S. Department of Energy Secretary Sam Bodman responded by introducing the Save Energy Now initiative on October 3, 2005:

“America’s businesses, factories, and manufacturing facilities use massive amounts of energy. To help them during this period of tightening supply and rising costs, our Department is sending teams of qualified efficiency experts to 200 of the nation’s most energy-intensive factories. Our Energy Saving Teams will work with on-site managers on ways to conserve energy and use it more efficiently.”

On a broader level, DOE is attempting to distribute a portfolio of “Best Practices” information to 50,000 facilities.DOE’s BestPractices pertain to plant systems commonly found in industry, such as steam, process heating, motor drives, compressed air and insulation.

The DOE very quickly identified 200 forwardthinking participants for energy assessments (and actually had to turn away eager applicants). As of August 16, 2006, the results were in for the first 105 Save Energy Now assessments. In all, the 200 plants selected for energy assessments represent a variety of industries and are located in at least 39 different states. Experts at DOE have projected the anticipated savings for all 200 plants based on the results from the first 105.According to these projections:

  • The average plant presents $2.6 million in annual energy savings.
  • The total energy-cost-saving opportunities recorded for the first 105 plants total $273.8 million.
  • The 200 plants are projected to attain more than $522 million in annual potential energy savings in aggregate.
  • The total potential natural gas savings for first 105 plants assessed are estimated at 30.3 trillion Btu annually– enough to serve 421,000 typical houses per year.
  • Not every improvement recommendation will be implemented. DOE expects a 40% implementation.
  • 47% of the identified savings can be achieved with a payback of nine months or less. Improvement measures include insulation upgrades, steam trap programs and the cleaning of heat transfer surfaces.
  • 13 plants reported more than $1.9 million in immediate savings implemented in the first 30 days following the assessment.
  • 46% of the potential savings in the assessed plants can be achieved with a payback between nine months and two years. These opportunities include heat recovery and combustion optimization.

There’s one final statistic worth mentioning. If one were to pay market value for one of these assessments, it would range anywhere from $5,000 to $12,000, depending on the size and complexity of the facility. Recall that the average value of identified savings potential per plant is $2.6 million. Assume that only 40% of the recommendations will be implemented. That’s an average of about $1,000,000 in savings per facility.What’s the return on investment (ROI) for an energy assessment if someone actually paid for it? Let’s be conservative and use the higher cost assessment value ($12,000). The ROI would be about 83:1.

Industrial facilities that secure an energy assessment will learn about their energy savings potential. So,why aren’t more facilities doing this? Companies and sites that refuse energy assessments may end up paying much,much more through energy waste and lost productivity.

You can get more information about this program, including summaries of individual plant assessments, at

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6:00 am
October 1, 2006
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When you can’t vary the speed of the driven load…

Don’t give up. You have options. Other control technologies can take up the flag when a VFD won’t work for your application.

It used to be that you managed your company’s facilities and all of the machines and technology in it. Today, if you’re like so many other facilities and maintenance managers, you’ve been assigned another area of responsibility: managing your company’s energy consumption.

Soaring energy prices have business and industry scrambling for solutions— with motor solutions at the top of the list. That’s because electric motors play such a significant role in our energy problems. The true workhorses of our industrial and commercial facilities, they consume roughly a quarter of all electricity produced in the U.S. and more than 60% of all electricity used in industrial facilities.

Unfortunately, electric motors often operate very inefficiently, consuming more electricity than required to maintain full speed (RPM). Overpowered motors waste substantial energy when they are lightly loaded or idling.Whether they are driving unloaded conveyor belts, plastic granulators with empty hoppers or jaw crushers with no boulders to break, these motors are doing nothing but sitting there generating heat and squandering electricity. (And we all know how heat can kill a motor–and how difficult those wee-hour-of-the-morning emergency calls to replace failed motors can be.)

Until recently, when looking for ways to reduce energy usage on motors, users typically have relied on solutions such as:

  • The ON/OFF Switch–Of course, the best energy-saving device around is still the On/Off switch. But, shutting off an idling motor isn’t always an option.
  • Right-Sizing Motors–A recent U.S. Department of Energy (DOE) study determined that 44% of industrial motors operate consistently at <40% of full load, the point at which efficiency drops off precipitously.While the DOE recommends that these motors be replaced with smaller motors, this is not an option if the motor is sized to accommodate a much larger peak load, however infrequently it may be required.
  • Variable Frequency Drives (VFDs)–A VFD can positively impact energy consumption– in applications for which they are a fit. VFDs, however, won’t help when you can’t vary the speed of the driven load.
  • Premium Efficiency Motors–While they are effective in applications when the motor is sized appropriately for the load, high-efficiency motors, just like standard- efficiency motors, are highly inefficient when they are lightly loaded.

Another alternative
One technology that is demonstrating its ability to conserve energy on constantspeed, variable-load applications is the Power Genius™. It incorporates state-of-the-art electronic circuits that constantly monitor the workload of the motor as represented by the amount of lag between the current and voltage. These circuits sense the power factor and reduce voltage in order to supply the precise amount of energy required to maintain a motor at full speed. Although the core technology has existed since a NASA engineer named Frank Nola invented it in the late 1970s, Power Efficiency Corporation has made proprietary and patented improvements to its fast-response and phasebalancing circuitry that make it more effective.

The Nola technology works by measuring the phase lag between the voltage and the current waveforms at the terminals of an AC induction motor and reducing the voltage accordingly. The lower voltage reduces the magnetizing current and the flux, effectively matching the motor load capacity to the driven load. Note that by lowering the current, the I2R losses to heat also are reduced. Because of this, the motor runs cooler.

Despite a somewhat uncertain reputation in industry, Nola technology really does work quite well-in the proper application. The problem arises in the implementation. In fact, in the wrong application, Nola technology actually can increase power usage.

The right application
The Power Genius line of energy-saving motor controllers is targeted at motors that spend a significant percentage of time at 20% load or less (indicated by a low power factor).Applications run the gamut from escalators and elevators to big jaw crushers, stamping presses, plastic granulators, lathes, mills and enormous aggregate conveyor belts in rock-crushing plants. The bigger the motor–and the more time that motor spends idling or lightly loaded–the bigger the payoff and the faster the payback. Energy savings of 20-40% are not unusual in vertical transportation equipment. Even a 15% savings on a 300 hp jaw crusher that averages 50 kilowatts will save 7.5 kW. Based on a 16-hour/6-day-a-week run time, that’s more than 37,000 kWh a year.1006_um_solutionspotlight_img1

A recent test of the Power Genius by Nevada Power Company (the electric utility in southern Nevada) on a 40 hp escalator motor at a major Las Vegas Strip casino showed a reduction in average power consumption of 32% (from 6.4 kW to 4.3 kW–a savings of 2.1 kW). The utility report stated,“Results show a significant reduction in average motor demand for the periods with the (technology) “On”.

In another test, conducted at Check-mate Industries on a 60- ton stamping press (similar to the machinery shown here), the Power Genius reduced energy consumption during a normal work cycle by 23%. With these kinds of savings, a two- or three-year payback on investment easily can be achieved.When rebates from utility companies and higher electricity rates in regions like California and much of the Northeast are factored in, the paybacks grow shorter, with one- to two-year ROIs quite common.

As you audit your facility with an eye toward energy-efficiency options for your electric motors, remember that choices well-suited for constant speed/variable load applications do exist. VFDs are good for numerous situations–but not every situation.Under many circumstances, other technologies can be a better fit.

John Hurst is director of engineering with Power Efficiency Corporation. For more information about the Power Genius, contact him directly. Telephone: (702) 697-0377; e-mail:

Power Efficiency Corporation
Las Vegas, NV


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