Archive | January, 2007


6:00 am
January 1, 2007
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Utilities Manager: Steam Trap Testing Made Easy

Installing new equipment or retrofitting old provides you with a great opportunity to simplify and optimize your steam trap PMs.

Even when a plant has a small population of steam traps-and little or no inspection taking place-significant money can be recovered by eliminating steam losses. Whether there is one trap failure out of 100 traps, or 10 failures out of 1,000, the same failure percentage exists. In any case, because of their relentless 24/7 nature, day after day after day, these failures are constantly eating away at an organization’s profits. No steam plant operation can really afford such losses.

0207_um_steamtrap1There are countless suppliers ready to sell you the most sophisticated stateof- the-art testing system available. But, can you really justify the expense? You probably have no idea of the magnitude of your losses in the first place. Although you may have a fair number of traps, you might only have a “run and fix it” maintenance system. If that’s the case, whenever you identify a trap failure, it’s probably because you just stumble on to it.

No doubt, you’ve heard the old saying, “you have to creep before you walk.” It’s a good one to keep in mind when it comes to steam trap testing. In other words, it’s best to start out simple and grow into a super test system. Here’s one way to do it.

The basic steam trap testing station
This type of station has no sophisticated components. They are all readily available and inexpensive. Chances are that most any maintenance department will already have them in stock, ready to install.

I came across the steam trap test station layout detailed in the following box, in an old steam engine manual with an 1875 copyright date. This was the state-of-the-art 130 years ago. In 1875, people evidently had a need to test steam traps for the very same reasons we do today. Their simple solution may lack modern hi-tech glitter, but it is better to have low-tech know-how than no tech at all.


Testing station installation
Since 80% of all the steam equipment is not in use at some time, you have ample opportunities to complete this modification. The other 20% may not be down long enough to work on it-or not down very often at all. Unfortunately, this 20% may very well cause 80% of your steam losses, primarily because of their long periods of continuous use and the inevitable wear that results from it. These pieces require some planned downtime and coordination that could have the biggest savings and result in the most improvement in their operation. It’s best to tackle these units first, which will help gain credibility in the program and recover pocket change to continue other installations.

Trap station set-up and uses
For normal steam trap operation…

  • The steam side block valve is left open.
  • The strainer blow-off valve is left shut.
  • The test tee valve is left shut.
  • The check valve should be set in the line to allow condensate to fl ow from the trap to the condensate block valve. This prevents condensate from other traps fl owing backward through the trap.
  • The condensate return valve is left open.

The steam and condensate mixture fl ows through the block valve through the strainer leaving the dirt behind-and not into the steam trap.The steam trap blocks the steam and allows the condensate to pass through. The test tee, check valve and the condensate return see only condensate and some fl ash steam. The check valve prevents any back fl ow of condensate from the return system. Other traps discharging in the system and vertical rise of liquid can threaten to overpower a trap and force condensate backwards, especially when shut down.

For steam trap strainer cleaning…

  • The steam side block valve is left open.
  • The test tee valve is left shut.
  • The condensate return valve is left open.
  • A suitable container is placed to receive the fl ow from the strainer blow-off valve.
  • The strainer blow-off valve is briefl y opened full and then shut.
  • Dirt that was in the strainer is now in the container.

The live steam and condensate mixture effectively scours the strainer screen and fl ows rapidly to the container. Such debris could plug or damage the trap if the strainer were not installed. Many traps are factory-installed with strainers and no blow-off plugs. As a result, lengthy equipment shutdown and dismantling are required just to clean the screen. Adding the blow-off valve allows online cleaning without incurring any equipment downtime.

For trap operational testing…

  • The steam side block valve is left open.
  • The strainer blow-off valve is left shut.
  • The condensate return valve is shut.
  • The test tee valve is opened.

The steam and condensate mixture fl ows through the steam side block valve, strainer and into the trap when the equipment is operating normally. The condensate return valve is left shut to prevent condensate from other sources interfering with the test.The test tee valve is left open and any fl ow is seen and caught in a suitable container.

The steam trap is supposed to block steam and pass condensate. Simply put, if there is steam going into the container, the trap is leaking and should be replaced. Be careful, as there now are two types of steam here. If you don’t know what to look for, you will do a lot of unnecessary work. Hot condensate from any trap has a fl ash steam component. This fl ash steam has little pressure and fl ows away in a lazy, wispy meandering motion. Live steam that has passed through a failed trap, however, produces a cone-shape fl ow with a steady velocity. This is the point where you call it a trap failure.

Thermodynamic traps may throw you a bit of a curve because of their quick pulsing operation. Quick machine-gun pulses will produce a steam cone. Wait and observe closely during the brief off time. If the cone doesn’t exist, the trap is OK.

Diagnosis of just what has failed in the trap depends on the trap design and operational conditions. Don’t worry about that, at this point. Replace this money waster and carefully inspect it on the rebuild bench later. That’s where and how you’ll learn about what fails and why. Fast trap replacement can be achieved using traps that have a body mounted in the line and active parts that can be completely replaced by switching covers, modules or capsules, leaving the body in the line untouched. In many cases, you may be able to shut the steam and condensate valves, open the test tee valve to relieve any pressure, remove and replace the cover, module or capsule, shut the test tee valve and open the valves again, all without affecting the process.

Once you have all the traps working, keep an eye on the return line pH and the amount of amines you are feeding into the system. If a trap suddenly blows through, the pH will drop and the amines (your return line treatment) will go up to try to keep the pH in the proper range. That’s the little red fl ag that tells you to go check for a leaky trap if you are between PMs. The live steam keeps the amines in vapor form, and will vaporize any that are left in the return line path all the way to the return tank vent, effectively blowing your treatment to the four winds.

A trap that tests “OK” when the discharge is vented to atmosphere, but blows through for some reason, may have excessive back pressure causing it to perform improperly. Our basic trap station configuration can give you a place to screw a pressure gauge and a steam pigtail into the test tee and open the test tee valve. Without closing any other valves, the gauge should show you what is happening with the back pressure. The gauge reading should be under 20% of the main line pressure. Usually, when new equipment is added to the original return lines, the existing piping becomes too small for the heavier condensate load. Steam trap manufacturers have engineering experts who can help you with the upgrade at no cost to you.

Steam fl ow measurement…an added bonus
The previously detailed steam trap test station can be used to measure the actual load that the equipment is experiencing.


Close the return line block valve and open the test tee valve. Allow the fl ow to drain into a pail for a couple of minutes. This eliminates any condensate that fills the piping, and the fl ow will then only be the amount of condensate that has passed through the trap under load.

Collect the fl ow into a second empty container of a known volume Make it easy for yourself by using a 1-gallon can and note the time it takes to fill it. Now, take the container volume (V) and the time (T) it took to fill it, and plug it into the following formula:

It was decided 130 years ago that this trap station was important enough to put in print. Thanks to a bunch of long-dead individuals, this is quite a gift across time-and, if we take the time to heed it, one that will keep on giving when it comes to stopping steam losses.

Gary Burger worked himself up through the ranks of Canadian Occidental Petroleum, Durez Plastics Division, to become maintenance supervisor and chief engineer. He then joined the Stevenson Memorial Hospital maintenance team in Alliston, ON, Canada, as chief engineer. Over the past 10 years, he has helped lower this facility’s energy consumption by over 64 %, while keeping it all within budget. E-mail:

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6:00 am
January 1, 2007
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Utilities Manager: Cavitation Is Increasing Your Utility Cost

Show me a cavitating pump and I’ll show you an energy hog.

Most operating facilities in today’s marketplace are aware of the effects that cavitation has on mechanical pump reliability. Reduced rotor stability, shorter bearing life and the ever-popular premature mechanical seal failure are just a few of the more common manifestations. If, however, we were to look at the total cost of ownership for a cavitating pump, including its reduced efficiency and subsequent higher utility costs, we would see that this daily operating expense mounts up to a huge waste of both energy and money.

0207_um_pumpingefficiencies1Unraveling the issue
“Best in Class” companies evaluate the purchase of a pump based on Total Life Cycle Cost (TLCC). Pump efficiency will be one of the variables that weigh into this calculation. A specified margin for Net Positive Suction Head Required (NPSHR) and a range for Suction Specific Speed will be specified in their engineering guides. Again, these pump characteristics weigh into the purchasing decision, but can ultimately be overridden during the project development cycle due to delivery schedules and initial purchase price. The TLCC philosophy applies to new pumps being purchased today.

What about the large population of pumps in service today that are 20, 30 or even 40-plus years old. TLCC and pump reliability were not even on the map when these units were purchased and commissioned. Their inefficiencies and diminished reliability are further aggravated by being operated at off-design conditions resulting from process demand changes that occurred after the pump was installed.

Further confusion is added by the term NPSHR. Keep in mind that the design goal of a pump manufacturer is to design a pump that meets the broadest range of operating conditions possible rather than designing a pump to meet your specific hydraulic needs.

A manufacturer’s certified performance curve will list the NPSHR for the pump. This curve is not the point at which incipient cavitation occurs in the pump. Rather, it is the point at which cavitation is significant enough that the pump head is reduced by 3%. This is determined by testing the performance of the pump with the suction fully fl ooded. The pump is later retested at known fl ow rates and the suction valve is pinched off. The NPSHR curve is then plotted once the head meets a 3% reduction at the target fl ows. This is accepted in industry because the 3% condition is typically repeatable independent of process conditions (fl uid, temperature, etc.). Consequently, many pumps in service today are being operated within the prescribed NPSHR margin, yet cavitation still exists-as evidenced by the damage found on their impellers during a pump repair.

Reliability teams fight to keep the pump available, but rarely get the opportunity to affect real change, since the cost of a design modification is thought to be too high. Pumps are pulled for maintenance. Cavitation is evident, as seen in Fig. 1. The affected area of the impeller is weld-repaired or, occasionally, the impeller is replaced with a more cavitationresistant metallurgy. The pump is reassembled and placed back in service. If a design change is considered, it usually is dismissed due to price-without the energy savings ever having been considered.


This is cavitation
The published or known efficiency of the pump includes the hydraulic inefficiencies that are sufficient to cause this kind of mechanical damage to the impeller. As the fl uid being pumped drops below the fl uid’s vapor pressure, it rapidly fl ashes from a liquid to a gas and back to a liquid. This is cavitation. The subsequent shock waves carry enough energy to literally rip a minute piece of metal from the impeller vane. Over the course of operating, these minute pieces of removed metal compound upon each other, leading to the damage shown in Fig. 1. Additionally, the vibration associated with these shock waves is transmitted down the shaft and its cumulative effect wipes out the mechanical seals and bearings. This is well known and discussed. One common solution is to install larger diameter or stiffer shafts with bigger bearings to try to extend the mean time between repairs (MTBR). API-610 has taken this approach in the last few revisions, which places a greater emphasis on the L/D ratios and other shaft stiffness design criteria.

Dealing with hydraulic inefficiencies
What we often fail to recognize is that hydraulic inefficiency from cavitation is costing us horsepower (HP) every time the pump is placed in service. In other words, pump users often are literally paying to tear up their equipment. With the availability of Computational Fluid Mechanics (CFM) and Computation Fluid Dynamics (CFD), the existing inherent inefficiency in a pump’s hydraulic development can be reduced-and in many cases eliminated.

CFM and CFD allows a qualified individual to evaluate the suction characteristics of the impeller before any manufacturing takes place. Adjustments can be made to the inlet eye diameter and/or the inlet vane angles that can dramatically improve these characteristics. Multiple modeling runs can be examined to optimize the impeller geometry around your specific desired hydraulic condition.

There are many different ways to calculate the annual savings, but for this discussion we will use the following equation:

Assigning some values to the above variables, we can use a typical pump efficiency of 69% and assume a modest 4% efficiency increase. Let’s say that we have a 200 HP motor with a rate load of 175 HP. Using a unit availability of 96% will give us 8,410 hours of operation. From the Energy Information Administration [Ref. 1], we find that in October 2006, the average retail price of electricity for an industrial user in the United States was 6.12¢ per kilowatt hour. Thus, the annual utility savings would be $6,098. By itself, for a single pump, that’s a nice piece of change. Think, though, what this type of savings could add up to for operations with multiple pumps.

What to do with about your hogs
If you have a cavitating pump, don’t just upgrade the metallurgy, stiffen the shaft and move on. Instead, eliminate or minimize the cavitation by redesigning the suction characteristics of the impeller. 0207_um_pumpingefficiencies3The savings detailed in this article are strictly a reduction in the cost of plant utilities for one pump. They do not take into account the overhead to maintain additional HP consumption. If the impeller needs to be replaced because of cavitation damage, then that cost should be removed from the incremental cost of a design modification. Once you couple in the increased MTBR and reduction in the maintenance budget, the total savings often make design changes practical.


  1. Energy Information Administration ( http:// table5_6_a.html )

Richard E. Martinez is vice president of operations with Standard Alloys, in Port Arthur, TX, a company he joined in 1989 as director of engineering, following several years working with the Lower Colorado River Authority (LCRA). Under his direction, Standard Alloys developed the capacity to perform custom design of impellers, volutes/diffusers and return guide vanes. Promoted to his current position in 2006, he now is responsible for operation of Standard Alloys Engineering, Pattern Shop, Foundry and Machine Shop/Repair Center. Martinez, who holds a B.S.M.E. from Lamar University, has published a number of articles related to pump performance, modifications and enhancements. For more information, telephone: (800) 231-8240 x 312; e-mail: richardm@standardalloys. com; Internet:

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6:00 am
January 1, 2007
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Utilities Manager: Energy Cost Control: How Much Will You Save?

The question that industrial decision-makers will most frequently ask about energy cost control is “How much can I save?” The question that really should be asked is, “How much am I likely to save?”

How much can I save?
The average industrial facility can expect to reduce its energy consumption somewhere within a range of 10% to 20%. Keep in mind that this describes an average range of expectations. Some facilities can capture more savings, some less. If you want a more precise number, you will need to conduct an energy audit—a facilitywide study of energy inputs, uses and losses.

Keep in mind that energy audits are a very human process, refl ecting the skills and experience of the team that conducts them. Ten different audit teams can examine the same facility—and develop 10 different sets of recommendations. Their findings may generally overlap, but each report will present different cost-benefit evaluations, suggested priorities or even unique findings. I say “10% to 20%” because of the following sources:

  1. Refer to the U.S Department of Energy fact sheet entitled “Save Energy Now in Your Motor Systems.” It includes comments about all potential sources of industrial energy savings, not just motors. According to this document, plants with an energy management program already in place can save an additional 10% to15% by using best practices, as recommended by the U.S. Department of Energy. Remember, that’s in addition to an existing energy management program.
  2. Refer to “Energy Loss Reduction and Recovery in Industrial Energy Systems.” This U.S. DOE document claims, on page 22, that industry’s overall energy consumption can be reduced by 24% through efficient technologies and practices. Several appendices in this report share industry-specific claims for energy savings potential. This cannot be overemphasized: no single industrial facility is “average.” Each facility features a unique design, purpose, product mix, operating schedule, maintenance history and work habits. Savings potential varies accordingly.

How much am I likely to save?
I wish more people would ask this question. My answer involves the following checklist. The more times you can answer with a “yes” to these questions, the more likely you are to achieve savings (or the higher you will be on that range of potential savings). 

0207_um_outsidethebox1Will you conduct an energy audit?

0207_um_outsidethebox1 Will your staff know the purpose of the audit and not be intimidated by it?

0207_um_outsidethebox1 Will your facility support energy cost control as an ongoing process rather than as a one-time project?

0207_um_outsidethebox1 Will your top management stand behind the goals and accountabilities set by an energy management plan, or ignore them after a year has passed? 

0207_um_outsidethebox1 Will your staff be responsive to energy awareness training?

0207_um_outsidethebox1 Will operations, maintenance and procurement be willing to change the way they do things by incorporating energy best practices into their work habits? Take heart. No one answers “yes” to all of these points. But, as you achieve more “yes” answers, the more you are likely to save.

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6:00 am
January 1, 2007
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Utilities Manager: How to…Bring Life Back To Your Ailing Boilers

What can you do when you are expected to generate steam efficiently, but you have to do it with aging, inefficient equipment? Think retrofits.

0307_boiler_img1As a utilities manager, you know how critical steam is to an operation’s power, process heat and indoor climate-control needs. With almost one-third of your energy bill being run up by the boiler room, system inefficiency—a leading factor in increased boiler operating costs—simply can’t be ignored.

According to the Department of Energy, almost 80% of boilers in the United States today are nearly 30 years old or older. This means the chances are pretty good that you’re working with a unit that is not operating at optimal efficiency—possibly only in the 75% to 80% range. Making your job even harder, tight budgets are putting increased scrutiny on capital spending, often leading to the postponement of necessary infrastructure upgrades such as new boilers. You’re left with aging, inefficient equipment.


Don’t give up. There is another way to effi- cient operation. You can retrofit your old boiler to bring its performance nearly up to par with today’s new systems. This article discusses the major retrofit options available to minimize energy loss and maximize fuel dollars.

Identifying the real culprit

To improve boiler efficiency, you first must identify your efficiency problems. The main cause of energy inefficiency is system heat loss. The average level of efficiency for industrial boilers is only 75% to 77%, with roughly onequarter of fuel producing heat and energy that is never harnessed. Examples of heat loss are shown in Fig. 1.

Taking control

The first place to look for improvements is in your control system. New developments in boiler controls create opportunities for substantial efficiency gains.

Boilers must operate with an excess supply of oxygen in the combustion gases to ensure complete combustion of the fuel, thereby yielding maximum heat energy. Too much oxygen cools the flame, and too little leads to incomplete combustion. Consequently, control of the air and fuel levels is paramount to optimal efficiency. The following control options are available for retrofitting an existing system to produce measurable efficiency increases and fuel-cost decreases.

Parallel positioning…
Many boiler burners are controlled by a single modulating motor with jackshafts to the fuel valve and air damper (commonly referred to as “jackshaft control”). This arrangement, set during startup, fixes the air-to-fuel ratio over the firing range. Unfortunately, environmental changes such as temperature, pressure and relative humidity alter the fixed air-to-fuel ratio, making combustion inefficient. To account for these conditions, boilers with jackshaft systems are typically set up with 4% to 7% oxygen in
the stack. This oxygen level reduces boiler effi- ciency and, over time, linkages wear—making repeatability impossible.

To solve this problem, incorporate parallel positioning into your control system. It’s a process using dedicated actuators for the fuel and air valves. Air and fuel position curves are programmed into the PLC for each actuator, and repeatability is excellent. Boilers that incorporate parallel positioning need only 2% to 5% excess oxygen in the stack to ensure complete combustion.

As a general rule, boiler efficiency increases by 1% for each 2% reduction in excess oxygen. Using this rule, a 600 HP boiler with parallel positioning and 2.5% excess oxygen will be approximately 2% more efficient than a similar boiler operating at 6.5% excess oxygen. That equates to a savings of $10,700 per year (based on operation at 50% average load for 12 hours per day, 365 days per year and a fuel cost of $10/MM BTU).

O2 trim…
Another way to ensure peak efficiency is to use an oxygen sensor/transmitter in the exhaust gas. The sensor/transmitter continuously senses oxygen content and provides a signal to the controller, which “trims” the air damper and/or gas valve, maintaining a consistent oxygen concentration. This minimizes excess air while optimizing the air-to-fuel ratio.

O2 trim systems typically increase efficiency by 1% to 2%. Using the same scenario as above, incorporating an O2 trim system can save $5,000 – $10,000 annually.

Variable speed drives…
Variable speed drives (VSDs) allow a motor to operate only at its required speed, rather than a constant 3,600 RPM as the drive would typically run. This speed variance results in the elimination of unnecessary energy consumption. A VSD can be used on any motor, but is most common on pumps and combustion air motors above 5 HP. These drives also produce quieter operation compared to a standard motor, and reduce maintenance costs by decreasing the stress on the impeller and bearings.

The energy saved by running at variable frequencies translates easily to dollars. For example, a 50 HP motor operating at a slower speed and utilizing only 40 HP, 12 hours per day, 365 days per year, with a load factor of one and motor efficiency of 86%, will save $3,360 per year (based on $0.10/kWh).

Another way to please budget scrutinizers while improving energy efficiency is to incorporate heat recovery retrofits into your boiler system. The following three “post-combustion” retrofit devices are designed to recover heat loss.

Economizers transfer energy from the boiler exhaust gas to the boiler feed water in the form of “sensible heat.” Sensible heat is created by the transfer of the heat energy of one body, in this case exhaust gas, to another, cooler body—the boiler feed water. This, in turn, reduces the boiler exhaust temperature while preheating the boiler feed water, increasing overall efficiency.

Economizers typically increase boiler effi- ciency by 2.5% to 4%, depending on the type of heat transfer surfaces and the allowable pressure drop. As a general rule, for every 40 F degree reduction in boiler gas temperature, 1% efficiency is gained.

Based on our referenced 600 HP boiler example, adding an economizer to your boiler system would result in a savings of $13,000 – $21,000 per year in fuel costs.

Air preheaters…
Air preheaters transfer sensible heat from the boiler exhaust gas to the combustion air required by the burner. This reduces the boiler exhaust temperature while preheating the combustion air, once again increasing overall system efficiency.

Most heater designs use plate heat exchangers to maximize surface area. Factors to consider when choosing the right air preheater include pressure drop and materials. Pressure drops will cause a reduction in boiler output unless compensated for by a larger fan motor.


Materials of construction are also critical, especially for applications where condensation and/or oil firing may occur. That’s why many preheaters are built of stainless steel or incorporate a bypass to avoid premature failures.

Combustion air, required by all burners, requires energy to heat it up to combustion temperatures. Preheated air requires less energy, so overall boiler efficiency is increased. For each 40 F degree drop in boiler exhaust temperature, the overall boiler system effi- ciency increases by about 1%.

Again using our 600 HP boiler example, the addition of an air preheater for a 1.5% effi- ciency gain would result in a savings of $8,000 per year in fuel costs.

Transport membranes…
Although transport membranes aren’t commercially available today, these recovery tools are in the final stages of development and will be coming on the market within the next year. Thus, they’re an important option to understand for the future.

Transport membranes recover both latent and sensible heat from the boiler exhaust and dehumidify it at the same time. At a recent beta site, the combining of this type of membrane with an economizer and controls detailed in this article, created system efficiencies greater than 94%, far surpassing the average 75% to 77% discussed earlier.

Using our 600 HP boiler example one last time, the addition of a transport membrane condenser, in combination with an economizer and updated controls, can create 10% efficiency gains, or save $53,000 annually in fuel costs.

Getting it done
The retrofits discussed in this article represent most of the major boiler energy savings available to utility managers today. Others include insulating steam piping and blow-down heat recovery. To learn more, it’s a good idea to discuss your retrofitting options with a boiler professional. UM

Dan Willems is vice president of product development at Cleaver-Brooks, headquartered in Milwaukee, WI. Celebrating its 75th anniversary, the company provides boiler room products and systems to both the industrial and commercial markets. For more information, e-mail:

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6:00 am
January 1, 2007
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Utilities Manager: Impacting Energy And The Environment Through Compressed Air Leak Management

Powering up for the new year. . .

1206_um_harnessing1Leaking compressed air systems can be some of the biggest energy hogs in industrial operations. Proper monitoring and maintenance of these systems should be one of your top priorities.

Compared to water, electricity and gas, pneumatic processes are a necessary utility and an important source of converted energy. In use well before the beginning of the Industrial Revolution, pneumatics derive their name from the Greek word “pneumatikos,” which translates as “coming from the wind.” In today’s modern industrial operations few processes rank higher in terms of importance than compressed air, and no process places a higher demand on energy consumption. As a key utility, its uses include running machinery, conveyance in handling systems and switching for instrumentation and electrical systems, among others.Unfortunately, energy demand is negatively impacted when poor compressed air maintenance practices allow inefficiencies to spiral out of control-with the single biggest culprit coming in the form of system leaks.

Calculating your compressed air investment
Today’s compressed air systems are clearly more complex than those from ancient times and (let us hope) far more efficient. Fig. 2. shows a simple breakdown of the typical investment a company would need to make for a simple compressed air system. As this chart reveals, energy accounts for as much as 75% of the total system cost. 1206_um_harnessing2That’s a rather surprising statistic, as conventional logic would have us believe that upfront capital costs and ongoing maintenance costs should dominate.

True, capital costs for compressors and delivery systems are significant, but they are not ongoing. If a system is specified correctly and maintained well over time, its capital costs can be depreciated.Yet, a poorly maintained and leaking system will never fulfill demand, continually drain resources and have a negative impact on energy. Furthermore, an inefficient energy-wasting compressed air system hurts our environment through additional and unnecessary greenhouse gas emissions.

The true cost of leak complacency
The fact that we don’t always think of compressed air in terms of energy consumption explains why, even now, so little attention typically is given to finding and fixing leaks in these systems. Such leaks, however, are expensive–very, very.

According to the U.S. Department of Energy, average systems waste between 25% and 35% of their air to leaks alone. In a 1,000 SCFM system, a 30% leakage translates into 300 SCFM. Eliminating that type of leak is equivalent to saving more than $45,000 annually. (Note: depending on where your plant is located and your region’s energy costs, the amount saved can be three to four times higher!)

Getting to the core of the problem
A better understanding of leak complacency is needed if we are to get to the core of the problem.Why do some companies pay so much attention to energy-efficient lighting, yet continue to ignore their vastly inefficient compressed air systems? One explanation is that unlike lighting, compressed air leaks are not seen. Another explanation is rooted in how we were raised.Most of us grew up listening to our parents tell us to “turn off the lights,” so our interest in lighting efficiency was ingrained early and reinforced regularly. On the other hand, while some of us might vaguely recall airlines in our fathers’workshops, most parents probably never said much about leaks.

In the factory setting, a steam leak is obvious and an oil leak even more so.Air leaks, however, don’t create a visible plume, nor do they make a dangerous and slippery mess on the floor.They don’t have an unpleasant odor and, for the most part, we simply ignore (or can’t hear) their continual hissing. Is this merely a case of “out of sight, out of mind?” Is energy waste/system inefficiency still too low a priority for manufacturers? Could it be that compressed air is a background process taken for granted?

Consider your compressed air system and all the areas where pneumatics are employed at your facility. Expand your thinking beyond the factory walls-compressed air makes possible so many things in science, technology and everyday living. From the jackhammers for road repairs to the drills in your dentist’s office; from the tires that roll you to and from work, school and play, to your children’s inflated footballs and basketballs , compressed air is all around you. And, yes, you take it for granted.

Dual challenge and dual opportunity
A culture change finally is occurring where it’s needed most–the industrial sector–and it’s not a minute too soon. Industry is the biggest consumer of compressed air, therefore it represents the area of largest potential gain. In effect, we’re faced with a dual challenge and a dual opportunity.

  • The challenge is to invest in more efficient energy-and environmentallyconscious practices.
  • The opportunity is to improve profitability and slow the effects of global warming.

We have an insatiable thirst for electricity and the fossil fuels necessary to quench it are being used up at rates we can’t afford. The diminishing supply of non-renewable fuel sources and the effect that increased levels of CO2 have on global climate change concern everyone on the planet.Dwindling fossil fuel supplies mean that we will be faced with continued higher energy costs for decades to come. Global climate change, however, represents something much more expensive.

Taking a proactive approach
Not all companies are sitting idly by waiting for others to take action. Many have already begun programs that address energy efficiency and specifically target the compressed air system.

AFG Glass is one company that is taking this type of proactive approach.The second largest flat glass manufacturer in North America, AFG is the largest supplier to the construction and specialty glass market. Founded in 1978, the company is headquartered in Kingsport, TN.With its three divisions, it is a fully integrated supplier.One AFG division is responsible for flat glass manufacturing; another for advanced energy efficient coatings; a third fabrication division adds value to its finished product through tempering, laminating and insulating.

In total, AFG has nine glass production operations, 34 fabrication/distribution centers, four sputter coating lines, five insulating plants and one laminating facility. The company has more than 4,800 employees working in its North American operations.

Some of AFG’s manufacturing divisions implemented airborne ultrasound programs in 2006. Ultrasound had been considered primarily because of its reputation as an overall predictive maintenance and troubleshooting tool. But, when several of the company’s technicians later attended ultrasound certification training, they learned that the technology they had invested in could be used for much more than troubleshooting.

How ultrasound works
Ultrasonic leak detectors work like simple microphones that are sensitive to high-frequency sounds ranging beyond the human ear. Early detectors enabled users to hear problems with machinery on the factory floor, regardless of background noise. As the technology has grown, though, so has its form and function.

Today’s ultrasound detectors can be simple leak detectors or advanced data collectors capable of trending and diagnosing machine failures and plant inefficiencies. The technology utilitizes a sensitive piezoelectric crystal element as a sensing element. Small high-frequency sound waves excite or “flex” the crystal, creating an electrical pulse that is amplified and then translated into an audible frequency that an ultrasound inspector can hear through high-quality noise attenuating headphones.

As a leak passes from a high pressure to a low pressure, it creates turbulence. The turbulence generates a high-frequency sound component that’s detected by the crystal element. Higher frequency sounds are directional by nature.By detecting only the ultrasound component of a turbulent leak, the technician is able to quickly guide the instrument to the loudest point and pinpoint the problem.

A typical compressed air system can be surveyed for leaks in one or two days. Larger plants may take longer, but the benefits of finding and fixing leaks are well worth the investment in time.

Several ultrasonic detectors use parabolic reflectors or elliptical reflectors to enhance and concentrate the leak signal–which can be useful when detecting small leaks or scanning at a great distance. Imagine scanning all the overhead piping in your facility without ever again having to climb a ladder or scissor lift. Parabolic accessories associated with ultrasonic technology can be a key element in enhanced productivity and operator safety.

AFG success
Douglas Bowker is the plant maintenance superintendent at AFG Industries’ Greenland, TN, operations. He has been instrumental in the implementation of ultrasound testing to improve the well being of his site’s equipment.

“Compressed air is not free,” notes Bowker. “It costs Greenland approximately $137,000 per year to supply compressed air to the plant. Air leaks, therefore, cost us money. A small leak that is undetected by the human ear can typically contribute to $3,000 of cost per year. The ultrasonic equipment can now be utilized in a cost saving manner to detect such leaks and fix them proactively.”

Bowker points out that ultrasonic technology allowed an air leak the size of a pinhole to be detected from a distance of 40 feet. In addition,AFG technicians can detect natural gas, nitrogen and hydrogen leaks. They’re also finding that their ultrasound equipment is useful in detecting leaky or malfunctioning valves and helping determine flow in pipelines from a distance.

Allan Rienstra is general manager of SDT North America. Telephone: (905) 377-1313 ext. 221; Internet:

(EDITOR’S NOTE: AFG Industries is in the early stages of its compressed air efficiency journey. We’ll be checking back with this proactive company in 2007 to learn about other ultrasound wins at its Greenland, TN facility.)

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6:00 am
January 1, 2007
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Utilities Manager: Is It Time For A Standby Generator In Your Facility?

Questions and answers. . .

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
January 1, 2007
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Utilities Manager: Invest In Energy Management With Intelligent Motor Control Solutions

Tasked 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.

1206_um_smartvfds1Rising 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_smartvfds3The 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
January 1, 2007
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Utilities Manager: How Waste Raises The "Price" Of Energy


Christopher Russell, Principal, Energy Pathfinder Management Consulting, LLC, Contributing Editor

Reacting to rising energy costs, many managers will naturally focus on what they pay for fuel and power. A “price-centric” approach seeks lower prices for the same fuel, or if possible, a switch to a different, lowercost fuel. That’s not a bad idea, but it recognizes only one side of the energy equation:


Of course, any reduction in energy waste will reduce the total quantity of energy consumed. The companies that understand this concept proactively change the way they consume energy.

Other companies-especially those that remain focused on prices-fail to grasp this opportunity. Industry’s price-focused decision-makers are asked to consider this concept: they can reduce their expenditure per unit of energy available to do useful work.

Understanding the relationship
The relationship between fuel and the work it performs is noteworthy. Industry buys fuel that must be converted several times before it does the work for which it is intended. Take, for example, the steam systems that consume over half of total industrial fossil fuel purchases. Almost all manufacturing processes require heat, and steam is an effective medium for heat supply. Fuel is transformed to heat in several stages:

Fuel Input to Boilers is combusted to
Generate Steam
, which carries heat to a variety of
Heat Exchangers
,which apply heat
to transform materials.

Each stage allows some energy loss–the volume of which depends on the quality of technology, procedures and behavior of a facility and its staff. The U.S. Department of Energy’s “Energy Use, Loss and Opportunities Report” describes overall industry average losses incurred at each stage of the process.While figures vary across and within industries, it’s useful to use the following aggregate industry measures:

Fuel Combustion experiences ~8% fuel energy loss.
Heat Distribution sustains ~16% loss.
Conversion of Heat to Work sustains
an additional 16% loss.

In other words, only about 60% of industry’s energy purchases performs the work for which it is intended. The other 40% includes waste that can potentially (and economically) be avoided.

Running the numbers
So, just how does this type of waste “impact”fuel prices? The following example illustrates it clearly.

A plant purchased 100,000 units of natural gas (units are million Btu, or MMBtu). The price per MMBtu was $8.00, for a total outlay of $800,000 for fuel delivered “to the fence.” By the time the fuel was put to work, however, energy losses due to the various stages of conversion totalled a whopping 40%.

As a result, our example facility effectively spent $800,000 for only 60,000 MMBtu–or $13.33 per available MMBtu. (Go to industry/energy_systems/pdfs/energy_use_loss_opportunities_ analysis.pdf to review these calculations in their entirety.)

There’s yet another way to look at this situation. Energy changes hands several times after it is delivered to a facility. At each step in the conversion sequence, the “handler”incurs energy waste that effectively “marks up” the “price” of the energy that is eventually applied to do useful work.

The results shown here are based on industry averages. Naturally, some facilities are better than others. Still, virtually all industrial facilities have the potential- through reduced energy waste-to improve their energy expense performance.

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